Rep. Kevin A. McCarthy

Filed: 5/25/2011

 

 


 

 


 
09700SB1652ham001LRB097 09323 ASK 56228 a

1
AMENDMENT TO SENATE BILL 1652

2    AMENDMENT NO. ______. Amend Senate Bill 1652 by replacing
3everything after the enacting clause with the following:
 
4    "Section 5. The Illinois Power Agency Act is amended by
5adding Sections 1-56A and 1-76 as follows:
 
6    (20 ILCS 3855/1-56A new)
7    Sec. 1-56A. Distributed renewable energy generation
8devices.
9    (a) Of the renewable energy resources procured pursuant to
10Section 1-56 of this Act, at least the following percentages
11shall come from distributed renewable energy generation
12devices: 0.5% by June 1, 2013, 0.75% by June 1, 2014, and 1% by
13June 1, 2015 and thereafter. To the extent available, half of
14the renewable energy resources procured from distributed
15renewable energy generation shall come from devices of less
16than 25 kilowatts in nameplate capacity. Renewable energy

 

 

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1resources procured from distributed renewable energy
2generation devices may also count towards the required
3percentages for wind and solar photovoltaics. Procurement of
4renewable energy resources from distributed renewable energy
5generation devices shall be done on an annual basis through
6multi-year contracts of no less than 5 years and shall consist
7solely of renewable energy credits.
8    The Agency shall create credit requirements for suppliers
9of distributed renewable energy. In order to minimize the
10administrative burden on contracting entities, the Agency
11shall solicit the use of third-party organizations to aggregate
12distributed renewable energy into groups of no less than one
13megawatt in installed capacity. These third-party
14organizations shall administer contracts with individual
15distributed renewable energy generation device owners. An
16individual distributed renewable energy generation device
17owner shall have the ability to measure the output of his or
18her distributed renewable energy generation device.
19    For purposes of this subsection (a), "distributed
20renewable energy generation device" means a device that is: (1)
21powered by wind, solar thermal energy, photovoltaic cells and
22panels, biodiesel, crops and untreated and unadulterated
23organic waste biomass, tree waste, and hydropower that does not
24involve new construction or significant expansion of
25hydropower dams; (2) interconnected at the distribution system
26level of an electric utility as defined in Section 1-10 of this

 

 

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1Act, an alternative retail electric supplier as defined in
2Section 16-102 of the Public Utilities Act, a municipal utility
3as defined in Section 3-105 of the Public Utilities Act, or a
4rural electric cooperative as defined in Section 3-119 of the
5Public Utilities Act; (3) located on the customer side of the
6customer's electric meter and is primarily used to offset that
7customer's electricity load; and (4) limited in nameplate
8capacity to no more than 2,000 kilowatts.
9    (b) The Agency's procurement of renewable energy resources
10pursuant to subsection (c) of Section 1-56 of this Act shall,
11whenever possible, include entering into long-term contracts
12on an annual basis for a portion of the incremental requirement
13for the given procurement year.
14    (c) If Section 16-108.5 of the Public Utilities Act becomes
15inoperative with respect to one or more participating utilities
16as set forth in subsection (g) or (h) of that Section, then
17Sections 1-56A and 1-76 of this Act and Sections 8-103A,
1816-108.5, 16-108.6, 16-108.7, 16-108.8, and 16-111.5B of the
19Public Utilities Act shall become inoperative as to each
20affected utility and its service area on the same date as
21Section 16-108.5 becomes inoperative.
 
22    (20 ILCS 3855/1-76 new)
23    Sec. 1-76. Distributed renewable energy generation
24devices.
25    (a) Of the renewable energy resources procured pursuant to

 

 

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1Section 1-75 of this Act, at least the following percentages
2shall come from distributed renewable energy generation
3devices: 0.5% by June 1, 2013, 0.75% by June 1, 2014, and 1% by
4June 1, 2015 and thereafter. To the extent available, half of
5the renewable energy resources procured from distributed
6renewable energy generation shall come from devices of less
7than 25 kilowatts in nameplate capacity. Renewable energy
8resources procured from distributed renewable energy
9generation devices may also count towards the required
10percentages for wind and solar photovoltaics. Procurement of
11renewable energy resources from distributed renewable energy
12generation devices shall be done on an annual basis through
13multi-year contracts of no less than 5 years and shall consist
14solely of renewable energy credits.
15    The Agency shall create credit requirements for suppliers
16of distributed renewable energy. In order to minimize the
17administrative burden on contracting entities, the Agency
18shall solicit the use of third-party organizations to aggregate
19distributed renewable energy into groups of no less than one
20megawatt in installed capacity. These third-party
21organizations shall administer contracts with individual
22distributed renewable energy generation device owners. An
23individual distributed renewable energy generation device
24owner shall have the ability to measure the output of his or
25her distributed renewable energy generation device.
26    For purposes of this subsection (a), "distributed

 

 

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1renewable energy generation device" has the same meaning as set
2forth in Section 1-56A of this Act.
3    (b) If Section 16-108.5 of the Public Utilities Act becomes
4inoperative with respect to one or more participating utilities
5as set forth in subsection (g) or (h) of that Section, then
6Sections 1-56A and 1-76 of this Act and Sections 8-103A,
716-108.5, 16-108.6, 16-108.7, 16-108.8, and 16-111.5B of the
8Public Utilities Act shall become inoperative as to each
9affected utility and its service area on the same date as
10Section 16-108.5 becomes inoperative.
 
11    Section 10. The Public Utilities Act is amended by changing
12Sections 8-103, 16-107.5, 16-111.5, 16-111.7, and 16-128 and by
13adding Sections 8-103A, 16-108.5, 16-108.6, 16-108.7,
1416-108.8, 16-111.5B, and 16-128A as follows:
 
15    (220 ILCS 5/8-103)
16    Sec. 8-103. Energy efficiency and demand-response
17measures.
18    (a) It is the policy of the State that electric utilities
19are required to use cost-effective energy efficiency and
20demand-response measures to reduce delivery load. Requiring
21investment in cost-effective energy efficiency and
22demand-response measures will reduce direct and indirect costs
23to consumers by decreasing environmental impacts and by
24avoiding or delaying the need for new generation, transmission,

 

 

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1and distribution infrastructure. It serves the public interest
2to allow electric utilities to recover costs for reasonably and
3prudently incurred expenses for energy efficiency and
4demand-response measures. As used in this Section,
5"cost-effective" means that the measures satisfy the total
6resource cost test. The low-income measures described in
7subsection (f)(4) of this Section shall not be required to meet
8the total resource cost test. For purposes of this Section, the
9terms "energy-efficiency", "demand-response", "electric
10utility", and "total resource cost test" shall have the
11meanings set forth in the Illinois Power Agency Act. For
12purposes of this Section, the amount per kilowatthour means the
13total amount paid for electric service expressed on a per
14kilowatthour basis. For purposes of this Section, the total
15amount paid for electric service includes without limitation
16estimated amounts paid for supply, transmission, distribution,
17surcharges, and add-on-taxes.
18    (b) Electric utilities shall implement cost-effective
19energy efficiency measures to meet the following incremental
20annual energy savings goals:
21        (1) 0.2% of energy delivered in the year commencing
22    June 1, 2008;
23        (2) 0.4% of energy delivered in the year commencing
24    June 1, 2009;
25        (3) 0.6% of energy delivered in the year commencing
26    June 1, 2010;

 

 

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1        (4) 0.8% of energy delivered in the year commencing
2    June 1, 2011;
3        (5) 1% of energy delivered in the year commencing June
4    1, 2012;
5        (6) 1.4% of energy delivered in the year commencing
6    June 1, 2013;
7        (7) 1.8% of energy delivered in the year commencing
8    June 1, 2014; and
9        (8) 2% of energy delivered in the year commencing June
10    1, 2015 and each year thereafter.
11    (c) Electric utilities shall implement cost-effective
12demand-response measures to reduce peak demand by 0.1% over the
13prior year for eligible retail customers, as defined in Section
1416-111.5 of this Act, and for customers that elect hourly
15service from the utility pursuant to Section 16-107 of this
16Act, provided those customers have not been declared
17competitive. This requirement commences June 1, 2008 and
18continues for 10 years.
19    (d) Notwithstanding the requirements of subsections (b)
20and (c) of this Section, an electric utility shall reduce the
21amount of energy efficiency and demand-response measures
22implemented in any single year by an amount necessary to limit
23the estimated average increase in the amounts paid by retail
24customers in connection with electric service due to the cost
25of those measures to:
26        (1) in 2008, no more than 0.5% of the amount paid per

 

 

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1    kilowatthour by those customers during the year ending May
2    31, 2007;
3        (2) in 2009, the greater of an additional 0.5% of the
4    amount paid per kilowatthour by those customers during the
5    year ending May 31, 2008 or 1% of the amount paid per
6    kilowatthour by those customers during the year ending May
7    31, 2007;
8        (3) in 2010, the greater of an additional 0.5% of the
9    amount paid per kilowatthour by those customers during the
10    year ending May 31, 2009 or 1.5% of the amount paid per
11    kilowatthour by those customers during the year ending May
12    31, 2007;
13        (4) in 2011, the greater of an additional 0.5% of the
14    amount paid per kilowatthour by those customers during the
15    year ending May 31, 2010 or 2% of the amount paid per
16    kilowatthour by those customers during the year ending May
17    31, 2007; and
18        (5) thereafter, the amount of energy efficiency and
19    demand-response measures implemented for any single year
20    shall be reduced by an amount necessary to limit the
21    estimated average net increase due to the cost of these
22    measures included in the amounts paid by eligible retail
23    customers in connection with electric service to no more
24    than the greater of 2.015% of the amount paid per
25    kilowatthour by those customers during the year ending May
26    31, 2007 or the incremental amount per kilowatthour paid

 

 

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1    for these measures in 2011.
2    No later than June 30, 2011, the Commission shall review
3the limitation on the amount of energy efficiency and
4demand-response measures implemented pursuant to this Section
5and report to the General Assembly its findings as to whether
6that limitation unduly constrains the procurement of energy
7efficiency and demand-response measures.
8    (e) Electric utilities shall be responsible for overseeing
9the design, development, and filing of energy efficiency and
10demand-response plans with the Commission. Electric utilities
11shall implement 100% of the demand-response measures in the
12plans. Electric utilities shall implement 75% of the energy
13efficiency measures approved by the Commission, and may, as
14part of that implementation, outsource various aspects of
15program development and implementation. The remaining 25% of
16those energy efficiency measures approved by the Commission
17shall be implemented by the Department of Commerce and Economic
18Opportunity, and must be designed in conjunction with the
19utility and the filing process. The Department may outsource
20development and implementation of energy efficiency measures.
21A minimum of 10% of the entire portfolio of cost-effective
22energy efficiency measures shall be procured from units of
23local government, municipal corporations, school districts,
24and community college districts. The Department shall
25coordinate the implementation of these measures.
26    The apportionment of the dollars to cover the costs to

 

 

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1implement the Department's share of the portfolio of energy
2efficiency measures shall be made to the Department once the
3Department has executed grants or contracts for energy
4efficiency measures and provided supporting documentation for
5those grants and the contracts to the utility.
6    The details of the measures implemented by the Department
7shall be submitted by the Department to the Commission in
8connection with the utility's filing regarding the energy
9efficiency and demand-response measures that the utility
10implements.
11    A utility providing approved energy efficiency and
12demand-response measures in the State shall be permitted to
13recover costs of those measures through an automatic adjustment
14clause tariff filed with and approved by the Commission. The
15tariff shall be established outside the context of a general
16rate case. Each year the Commission shall initiate a review to
17reconcile any amounts collected with the actual costs and to
18determine the required adjustment to the annual tariff factor
19to match annual expenditures.
20    Each utility shall include, in its recovery of costs, the
21costs estimated for both the utility's and the Department's
22implementation of energy efficiency and demand-response
23measures. Costs collected by the utility for measures
24implemented by the Department shall be submitted to the
25Department pursuant to Section 605-323 of the Civil
26Administrative Code of Illinois and shall be used by the

 

 

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1Department solely for the purpose of implementing these
2measures. A utility shall not be required to advance any moneys
3to the Department but only to forward such funds as it has
4collected. The Department shall report to the Commission on an
5annual basis regarding the costs actually incurred by the
6Department in the implementation of the measures. Any changes
7to the costs of energy efficiency measures as a result of plan
8modifications shall be appropriately reflected in amounts
9recovered by the utility and turned over to the Department.
10    The portfolio of measures, administered by both the
11utilities and the Department, shall, in combination, be
12designed to achieve the annual savings targets described in
13subsections (b) and (c) of this Section, as modified by
14subsection (d) of this Section.
15    The utility and the Department shall agree upon a
16reasonable portfolio of measures and determine the measurable
17corresponding percentage of the savings goals associated with
18measures implemented by the utility or Department.
19    No utility shall be assessed a penalty under subsection (f)
20of this Section for failure to make a timely filing if that
21failure is the result of a lack of agreement with the
22Department with respect to the allocation of responsibilities
23or related costs or target assignments. In that case, the
24Department and the utility shall file their respective plans
25with the Commission and the Commission shall determine an
26appropriate division of measures and programs that meets the

 

 

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1requirements of this Section.
2    If the Department is unable to meet incremental annual
3performance goals for the portion of the portfolio implemented
4by the Department, then the utility and the Department shall
5jointly submit a modified filing to the Commission explaining
6the performance shortfall and recommending an appropriate
7course going forward, including any program modifications that
8may be appropriate in light of the evaluations conducted under
9item (7) of subsection (f) of this Section. In this case, the
10utility obligation to collect the Department's costs and turn
11over those funds to the Department under this subsection (e)
12shall continue only if the Commission approves the
13modifications to the plan proposed by the Department.
14    (f) No later than November 15, 2007, each electric utility
15shall file an energy efficiency and demand-response plan with
16the Commission to meet the energy efficiency and
17demand-response standards for 2008 through 2010. No later than
18October 1, 2010, each electric utility shall file an energy
19efficiency and demand-response plan with the Commission to meet
20the energy efficiency and demand-response standards for 2011
21through 2013. Every 3 years thereafter, each electric utility
22shall file, no later than September October 1, an energy
23efficiency and demand-response plan with the Commission. If a
24utility does not file such a plan by September October 1 of an
25applicable year, it shall face a penalty of $100,000 per day
26until the plan is filed. Each utility's plan shall set forth

 

 

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1the utility's proposals to meet the utility's portion of the
2energy efficiency standards identified in subsection (b) and
3the demand-response standards identified in subsection (c) of
4this Section as modified by subsections (d) and (e), taking
5into account the unique circumstances of the utility's service
6territory. The Commission shall seek public comment on the
7utility's plan and shall issue an order approving or
8disapproving each plan within 5 3 months after its submission.
9If the Commission disapproves a plan, the Commission shall,
10within 30 days, describe in detail the reasons for the
11disapproval and describe a path by which the utility may file a
12revised draft of the plan to address the Commission's concerns
13satisfactorily. If the utility does not refile with the
14Commission within 60 days, the utility shall be subject to
15penalties at a rate of $100,000 per day until the plan is
16filed. This process shall continue, and penalties shall accrue,
17until the utility has successfully filed a portfolio of energy
18efficiency and demand-response measures. Penalties shall be
19deposited into the Energy Efficiency Trust Fund. In submitting
20proposed energy efficiency and demand-response plans and
21funding levels to meet the savings goals adopted by this Act
22the utility shall:
23        (1) Demonstrate that its proposed energy efficiency
24    and demand-response measures will achieve the requirements
25    that are identified in subsections (b) and (c) of this
26    Section, as modified by subsections (d) and (e).

 

 

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1        (2) Present specific proposals to implement new
2    building and appliance standards that have been placed into
3    effect.
4        (3) Present estimates of the total amount paid for
5    electric service expressed on a per kilowatthour basis
6    associated with the proposed portfolio of measures
7    designed to meet the requirements that are identified in
8    subsections (b) and (c) of this Section, as modified by
9    subsections (d) and (e).
10        (4) Coordinate with the Department to present a
11    portfolio of energy efficiency measures proportionate to
12    the share of total annual utility revenues in Illinois from
13    households at or below 150% of the poverty level. The
14    energy efficiency programs shall be targeted to households
15    with incomes at or below 80% of area median income.
16        (5) Demonstrate that its overall portfolio of energy
17    efficiency and demand-response measures, not including
18    programs covered by item (4) of this subsection (f), are
19    cost-effective using the total resource cost test and
20    represent a diverse cross-section of opportunities for
21    customers of all rate classes to participate in the
22    programs.
23        (6) Include a proposed cost-recovery tariff mechanism
24    to fund the proposed energy efficiency and demand-response
25    measures and to ensure the recovery of the prudently and
26    reasonably incurred costs of Commission-approved programs.

 

 

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1        (7) Provide for an annual independent evaluation of the
2    performance of the cost-effectiveness of the utility's
3    portfolio of measures and the Department's portfolio of
4    measures, as well as a full review of the 3-year results of
5    the broader net program impacts and, to the extent
6    practical, for adjustment of the measures on a
7    going-forward basis as a result of the evaluations. The
8    resources dedicated to evaluation shall not exceed 3% of
9    portfolio resources in any given year.
10    (g) No more than 3% of energy efficiency and
11demand-response program revenue may be allocated for
12demonstration of breakthrough equipment and devices.
13    (h) This Section does not apply to an electric utility that
14on December 31, 2005 provided electric service to fewer than
15100,000 customers in Illinois.
16    (i) If, after 2 years, an electric utility fails to meet
17the efficiency standard specified in subsection (b) of this
18Section, as modified by subsections (d) and (e), it shall make
19a contribution to the Low-Income Home Energy Assistance
20Program. The combined total liability for failure to meet the
21goal shall be $1,000,000, which shall be assessed as follows: a
22large electric utility shall pay $665,000, and a medium
23electric utility shall pay $335,000. If, after 3 years, an
24electric utility fails to meet the efficiency standard
25specified in subsection (b) of this Section, as modified by
26subsections (d) and (e), it shall make a contribution to the

 

 

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1Low-Income Home Energy Assistance Program. The combined total
2liability for failure to meet the goal shall be $1,000,000,
3which shall be assessed as follows: a large electric utility
4shall pay $665,000, and a medium electric utility shall pay
5$335,000. In addition, the responsibility for implementing the
6energy efficiency measures of the utility making the payment
7shall be transferred to the Illinois Power Agency if, after 3
8years, or in any subsequent 3-year period, the utility fails to
9meet the efficiency standard specified in subsection (b) of
10this Section, as modified by subsections (d) and (e). The
11Agency shall implement a competitive procurement program to
12procure resources necessary to meet the standards specified in
13this Section as modified by subsections (d) and (e), with costs
14for those resources to be recovered in the same manner as
15products purchased through the procurement plan as provided in
16Section 16-111.5. The Director shall implement this
17requirement in connection with the procurement plan as provided
18in Section 16-111.5.
19    For purposes of this Section, (i) a "large electric
20utility" is an electric utility that, on December 31, 2005,
21served more than 2,000,000 electric customers in Illinois; (ii)
22a "medium electric utility" is an electric utility that, on
23December 31, 2005, served 2,000,000 or fewer but more than
24100,000 electric customers in Illinois; and (iii) Illinois
25electric utilities that are affiliated by virtue of a common
26parent company are considered a single electric utility.

 

 

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1    (j) If, after 3 years, or any subsequent 3-year period, the
2Department fails to implement the Department's share of energy
3efficiency measures required by the standards in subsection
4(b), then the Illinois Power Agency may assume responsibility
5for and control of the Department's share of the required
6energy efficiency measures. The Agency shall implement a
7competitive procurement program to procure resources necessary
8to meet the standards specified in this Section, with the costs
9of these resources to be recovered in the same manner as
10provided for the Department in this Section.
11    (k) No electric utility shall be deemed to have failed to
12meet the energy efficiency standards to the extent any such
13failure is due to a failure of the Department or the Agency.
14(Source: P.A. 95-481, eff. 8-28-07; 95-876, eff. 8-21-08;
1596-33, eff. 7-10-09; 96-159, eff. 8-10-09; 96-1000, eff.
167-2-10.)
 
17    (220 ILCS 5/8-103A new)
18    Sec. 8-103A. Energy efficiency analysis.
19    (a) Beginning in 2013, an electric utility subject to the
20requirements of Section 8-103 of this Act shall include in its
21energy efficiency and demand-response plan submitted pursuant
22to subsection (f) of Section 8-103 an analysis of additional
23cost-effective energy efficiency measures that could be
24implemented, by customer class, absent the limitations set
25forth in subsection (d) of Section 8-103. In seeking public

 

 

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1comment on the electric utility's plan pursuant to subsection
2(f) of Section 8-103, the Commission shall include, beginning
3in 2013, the assessment of additional cost-effective energy
4efficiency measures submitted pursuant to this Section. For
5purposes of this Section, the term "energy efficiency" shall
6have the meaning set forth in Section 1-10 of the Illinois
7Power Agency Act, and the term "cost-effective" shall have the
8meaning set forth in subsection (a) of Section 8-103 of this
9Act.
10    (b) If Section 16-108.5 of this Act becomes inoperative
11with respect to one or more participating utilities as set
12forth in subsection (g) or (h) of that Section, then Sections
131-56A and 1-76 of the Illinois Power Agency Act and Sections
148-103A, 16-108.5, 16-108.6, 16-108.7, 16-108.8, and 16-111.5B
15of this Act shall become inoperative as to each affected
16utility and its service area on the same date as Section
1716-108.5 becomes inoperative.
 
18    (220 ILCS 5/16-107.5)
19    Sec. 16-107.5. Net electricity metering.
20    (a) The Legislature finds and declares that a program to
21provide net electricity metering, as defined in this Section,
22for eligible customers can encourage private investment in
23renewable energy resources, stimulate economic growth, enhance
24the continued diversification of Illinois' energy resource
25mix, and protect the Illinois environment.

 

 

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1    (b) As used in this Section, (i) "eligible customer" means
2a retail customer that owns or operates a solar, wind, or other
3eligible renewable electrical generating facility with a rated
4capacity of not more than 2,000 kilowatts that is located on
5the customer's premises and is intended primarily to offset the
6customer's own electrical requirements; (ii) "electricity
7provider" means an electric utility or alternative retail
8electric supplier; (iii) "eligible renewable electrical
9generating facility" means a generator powered by solar
10electric energy, wind, dedicated crops grown for electricity
11generation, agricultural residues, untreated and unadulterated
12wood waste, landscape trimmings, livestock manure, anaerobic
13digestion of livestock or food processing waste, fuel cells or
14microturbines powered by renewable fuels, or hydroelectric
15energy; and (iv) "net electricity metering" (or "net metering")
16means the measurement, during the billing period applicable to
17an eligible customer, of the net amount of electricity supplied
18by an electricity provider to the customer's premises or
19provided to the electricity provider by the customer.
20    (c) A net metering facility shall be equipped with metering
21equipment that can measure the flow of electricity in both
22directions at the same rate.
23        (1) For eligible residential customers whose electric
24    service has not been declared competitive pursuant to
25    Section 16-113 of this Act and whose electric delivery
26    service is provided and measured on a kilowatt-hour basis

 

 

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1    and electric supply service is not provided based on hourly
2    pricing, this shall typically be accomplished through use
3    of a single, bi-directional meter. If the eligible
4    customer's existing electric revenue meter does not meet
5    this requirement, the electricity provider shall arrange
6    for the local electric utility or a meter service provider
7    to install and maintain a new revenue meter at the
8    electricity provider's expense.
9        (2) For eligible customers whose electric service has
10    not been declared competitive pursuant to Section 16-113 of
11    this Act and whose electric delivery service is provided
12    and measured on a kilowatt demand basis and electric supply
13    service is not provided based on hourly pricing, this shall
14    typically be accomplished through use of a dual channel
15    meter capable of measuring the flow of electricity both
16    into and out of the customer's facility at the same rate
17    and ratio. If such customer's existing electric revenue
18    meter does not meet this requirement, then the electricity
19    provider shall arrange for the local electric utility or a
20    meter service provider to install and maintain a new
21    revenue meter at the electricity provider's expense.
22        (3) For all other eligible customers, For
23    non-residential customers, the electricity provider may
24    arrange for the local electric utility or a meter service
25    provider to install and maintain metering equipment
26    capable of measuring the flow of electricity both into and

 

 

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1    out of the customer's facility at the same rate and ratio,
2    typically through the use of a dual channel meter. If the
3    eligible customer's existing electric revenue meter does
4    not meet this requirement, then the costs of installing
5    such equipment shall be paid for by the customer. For
6    generators with a nameplate rating of 40 kilowatts and
7    below, the costs of installing such equipment shall be paid
8    for by the electricity provider. For generators with a
9    nameplate rating over 40 kilowatts and up to 2,000
10    kilowatts capacity, the costs of installing such equipment
11    shall be paid for by the customer. Any subsequent revenue
12    meter change necessitated by any eligible customer shall be
13    paid for by the customer.
14    (d) An electricity provider shall measure and charge or
15credit for the net electricity supplied to eligible customers
16or provided by eligible customers whose electric service has
17not been declared competitive pursuant to Section 16-113 of the
18Act and whose electric delivery service is provided and
19measured on a kilowatt-hour basis and electric supply service
20is not provided based on hourly pricing in the following
21manner:
22        (1) If the amount of electricity used by the customer
23    during the billing period exceeds the amount of electricity
24    produced by the customer, the electricity provider shall
25    charge the customer for the net electricity supplied to and
26    used by the customer as provided in subsection (e-5) (e) of

 

 

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1    this Section.
2        (2) If the amount of electricity produced by a customer
3    during the billing period exceeds the amount of electricity
4    used by the customer during that billing period, the
5    electricity provider supplying that customer shall apply a
6    1:1 kilowatt-hour credit to a subsequent bill for service
7    to the customer for the net electricity supplied to the
8    electricity provider. The electricity provider shall
9    continue to carry over any excess kilowatt-hour credits
10    earned and apply those credits to subsequent billing
11    periods to offset any customer-generator consumption in
12    those billing periods until all credits are used or until
13    the end of the annualized period.
14        (3) At the end of the year or annualized over the
15    period that service is supplied by means of net metering,
16    or in the event that the retail customer terminates service
17    with the electricity provider prior to the end of the year
18    or the annualized period, any remaining credits in the
19    customer's account shall expire.
20    (e) An electricity provider shall measure and charge or
21credit for the net electricity supplied to eligible customers
22whose electric service has not been declared competitive
23pursuant to Section 16-113 of this Act and whose electric
24delivery service is provided and measured on a kilowatt demand
25basis and electric supply service is not provided based on
26hourly pricing in the following manner:

 

 

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1        (1) If the amount of electricity used by the customer
2    during the billing period exceeds the amount of electricity
3    produced by the customer, then the electricity provider
4    shall charge the customer for the net electricity supplied
5    to and used by the customer as provided in subsection (e-5)
6    of this Section, provided that the electricity provider
7    shall assess and the customer remains responsible for all
8    taxes, fees, and utility delivery charges that would
9    otherwise be applicable to the gross amount of
10    kilowatt-hours supplied to the eligible customer by the
11    electricity provider.
12        (2) If the amount of electricity produced by a customer
13    during the billing period exceeds the amount of electricity
14    used by the customer during that billing period, then the
15    electricity provider supplying that customer shall apply a
16    1:1 kilowatt-hour credit that reflects the kilowatt-hour
17    based charges in the customer's electric service rate to a
18    subsequent bill for service to the customer for the net
19    electricity supplied to the electricity provider. The
20    electricity provider shall continue to carry over any
21    excess kilowatt-hour credits earned and apply those
22    credits to subsequent billing periods to offset any
23    customer-generator consumption in those billing periods
24    until all credits are used or until the end of the
25    annualized period.
26        (3) At the end of the year or annualized over the

 

 

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1    period that service is supplied by means of net metering,
2    or in the event that the retail customer terminates service
3    with the electricity provider prior to the end of the year
4    or the annualized period, any remaining credits in the
5    customer's account shall expire.
6    (e-5) An electricity provider shall provide electric
7service to eligible net metering customers whose electric
8service has not been declared competitive pursuant to Section
916-113 of this Act and whose electric supply service is not
10provided based on hourly pricing who utilize net metering
11electric service at non-discriminatory rates that are
12identical, with respect to rate structure, retail rate
13components, and any monthly charges, to the rates that the
14customer would be charged if not a net metering customer. An
15electricity provider shall not charge net metering customers
16any fee or charge or require additional equipment, insurance,
17or any other requirements not specifically authorized by
18interconnection standards authorized by the Commission, unless
19the fee, charge, or other requirement would apply to other
20similarly situated customers who are not net metering
21customers. The customer will remain responsible for all taxes,
22fees, and utility delivery charges that would otherwise be
23applicable to the net amount of electricity used by the
24customer. Subsections (c) through (e) of this Section shall not
25be construed to prevent an arms-length agreement between an
26electricity provider and an eligible customer that sets forth

 

 

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1different prices, terms, and conditions for the provision of
2net metering service, including, but not limited to, the
3provision of the appropriate metering equipment for
4non-residential customers.
5    (f) Notwithstanding the requirements of subsections (c)
6through (e-5) (e) of this Section, an electricity provider must
7require dual-channel metering for customers operating eligible
8renewable electrical generating facilities with a nameplate
9rating up to 2,000 kilowatts and to whom the provisions of
10neither subsection (d) nor (e) of this Section apply
11non-residential customers operating eligible renewable
12electrical generating facilities with a nameplate rating over
1340 kilowatts and up to 2,000 kilowatts. In such cases,
14electricity charges and credits shall be determined as follows:
15        (1) The electricity provider shall assess and the
16    customer remains responsible for all taxes, fees, and
17    utility delivery charges that would otherwise be
18    applicable to the gross amount of kilowatt-hours supplied
19    to the eligible customer by the electricity provider.
20        (2) Each month that service is supplied by means of
21    dual-channel metering, the electricity provider shall
22    compensate the eligible customer for any excess
23    kilowatt-hour credits at the electricity provider's
24    avoided cost of electricity supply over the monthly period
25    or as otherwise specified by the terms of a power-purchase
26    agreement negotiated between the customer and electricity

 

 

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1    provider.
2        (3) For all eligible net metering customers taking
3    service from an electricity provider under contracts or
4    tariffs employing time of use rates, any monthly
5    consumption of electricity shall be calculated according
6    to the terms of the contract or tariff to which the same
7    customer would be assigned to or be eligible for if the
8    customer was not a net metering customer. When those same
9    customer-generators are net generators during any discrete
10    time of use period, the net kilowatt-hours produced shall
11    be valued at the same price per kilowatt-hour as the
12    electric service provider would charge for retail
13    kilowatt-hour sales during that same time of use period.
14    (g) For purposes of federal and State laws providing
15renewable energy credits or greenhouse gas credits, the
16eligible customer shall be treated as owning and having title
17to the renewable energy attributes, renewable energy credits,
18and greenhouse gas emission credits related to any electricity
19produced by the qualified generating unit. The electricity
20provider may not condition participation in a net metering
21program on the signing over of a customer's renewable energy
22credits; provided, however, this subsection (g) shall not be
23construed to prevent an arms-length agreement between an
24electricity provider and an eligible customer that sets forth
25the ownership or title of the credits.
26    (h) Within 120 days after the effective date of this

 

 

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1amendatory Act of the 95th General Assembly, the Commission
2shall establish standards for net metering and, if the
3Commission has not already acted on its own initiative,
4standards for the interconnection of eligible renewable
5generating equipment to the utility system. The
6interconnection standards shall address any procedural
7barriers, delays, and administrative costs associated with the
8interconnection of customer-generation while ensuring the
9safety and reliability of the units and the electric utility
10system. The Commission shall consider the Institute of
11Electrical and Electronics Engineers (IEEE) Standard 1547 and
12the issues of (i) reasonable and fair fees and costs, (ii)
13clear timelines for major milestones in the interconnection
14process, (iii) nondiscriminatory terms of agreement, and (iv)
15any best practices for interconnection of distributed
16generation.
17    (i) All electricity providers shall begin to offer net
18metering no later than April 1, 2008.
19    (j) An electricity provider shall provide net metering to
20eligible customers until the load of its net metering customers
21equals 1% of the total peak demand supplied by that electricity
22provider during the previous year. Electricity providers are
23authorized to offer net metering beyond the 1% level if they so
24choose. The number of new eligible customers with generators
25that have a nameplate rating of 40 kilowatts and below will be
26limited to 200 total new billing accounts for the utilities

 

 

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1(Ameren Companies, ComEd, and MidAmerican) for the period of
2April 1, 2008 through March 31, 2009.
3    (k) Each electricity provider shall maintain records and
4report annually to the Commission the total number of net
5metering customers served by the provider, as well as the type,
6capacity, and energy sources of the generating systems used by
7the net metering customers. Nothing in this Section shall limit
8the ability of an electricity provider to request the redaction
9of information deemed by the Commission to be confidential
10business information. Each electricity provider shall notify
11the Commission when the total generating capacity of its net
12metering customers is equal to or in excess of the 1% cap
13specified in subsection (j) of this Section.
14    (l) Notwithstanding the definition of "eligible customer"
15in item (i) of subsection (b) of this Section, each electricity
16provider shall consider whether to allow meter aggregation for
17the purposes of net metering on:
18        (1) properties owned or leased by multiple customers
19    that contribute to the operation of an eligible renewable
20    electrical generating facility, such as a community-owned
21    wind project, a community-owned biomass project, a
22    community-owned solar project, or a community methane
23    digester processing livestock waste from multiple sources;
24    and
25        (2) individual units, apartments, or properties owned
26    or leased by multiple customers and collectively served by

 

 

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1    a common eligible renewable electrical generating
2    facility, such as an apartment building served by
3    photovoltaic panels on the roof.
4    For the purposes of this subsection (l), "meter
5aggregation" means the combination of reading and billing on a
6pro rata basis for the types of eligible customers described in
7this Section.
8    (m) Nothing in this Section shall affect the right of an
9electricity provider to continue to provide, or the right of a
10retail customer to continue to receive service pursuant to a
11contract for electric service between the electricity provider
12and the retail customer in accordance with the prices, terms,
13and conditions provided for in that contract. Either the
14electricity provider or the customer may require compliance
15with the prices, terms, and conditions of the contract.
16(Source: P.A. 95-420, eff. 8-24-07.)
 
17    (220 ILCS 5/16-108.5 new)
18    Sec. 16-108.5. Infrastructure investment and
19modernization; regulatory reform.
20    (a) The General Assembly recognizes that for well over a
21century Illinois residents and businesses have been
22well-served by and have benefitted from a comprehensive
23electric utility system. The General Assembly finds that
24electric utilities are now entering a new construction cycle
25that is needed to refurbish, rebuild, modernize, and expand

 

 

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1systems to continue to provide safe, reliable, and affordable
2service to the State's current and future utility customers in
3this newly digitized age. In particular, the General Assembly
4finds that it is the policy of this State that significant
5investments must be made in the State's electric grid over the
6next decade to modernize and upgrade transmission and
7distribution facilities in the State. These investments will
8ensure that the State's electric utility infrastructure will
9promote future economic development in the State and that the
10State's electric utilities will be able to continue to provide
11quality electric service to their customers, including
12innovative technological offerings that will enhance customer
13experience and choice such as smart meters that are dependent
14on a modernized or Smart Grid. These investments, including
15programs to reinforce the safety and security of high voltage
16transmission lines, will also ensure that the State's electric
17utility infrastructure continues to be safe and reliable. The
18introduction of performance metrics will further ensure that
19reliability and other indicators are not just maintained but
20improved over the next decade.
21    The General Assembly further recognizes that, in addition
22to attracting capital and businesses to the State, these
23investments will create training opportunities for the
24citizens of this State, all of which will create new employment
25opportunities for Illinoisans at a time when they are most
26needed, especially for minority-owned and female-owned

 

 

09700SB1652ham001- 31 -LRB097 09323 ASK 56228 a

1business enterprises. The General Assembly further finds that
2regulatory reform measures that increase predictability,
3stability, and transparency in the ratemaking process are
4needed to promote prudent, long-term infrastructure investment
5and to mutually benefit the State's electric utilities and
6their customers, regulators, and investors.
7    (b) For purposes of this Section, "participating utility"
8means an electric utility or a combination utility that
9voluntarily elects and commits to undertake the infrastructure
10investment program consisting of the commitments and
11obligations described in this subsection (b), notwithstanding
12any other provisions of this Act and without obtaining any
13approvals from the Commission or any other agency other than as
14set forth in this Section, regardless of whether any such
15approval would otherwise be required. "Combination utility"
16means a utility that, as of January 1, 2011, provided electric
17service to at least one million retail customers in Illinois
18and gas service to at least 500,000 retail customers in
19Illinois. A participating utility shall recover the
20expenditures made under the infrastructure investment program
21through the ratemaking process, including, but not limited to,
22the performance-based formula rate and process set forth in
23this Section.
24    During the infrastructure investment program's peak
25program year, a participating utility other than a combination
26utility shall create 2,000 full-time equivalent jobs, and a

 

 

09700SB1652ham001- 32 -LRB097 09323 ASK 56228 a

1participating utility that is a combination utility shall
2create 450 full-time equivalent jobs, including direct jobs,
3contractor positions, and induced jobs. For purposes of this
4Section, "peak program year" means the consecutive 12-month
5period with the highest number of full-time equivalent jobs
6that occurs between the beginning of investment year 2 and the
7end of investment year 4.
8    A participating utility shall meet one of the following
9commitments, as applicable:
10        (1) Beginning no later than 180 days after a
11    participating utility other than a combination utility
12    files a performance-based formula rate tariff pursuant to
13    subsection (c) of this Section, or, beginning no later than
14    January 1, 2012 if such utility files such
15    performance-based formula rate tariff within 14 days of the
16    effective date of this amendatory Act of the 97th General
17    Assembly, the participating utility shall, except as
18    provided in subsection (b-5):
19            (A) over a 5-year period, invest at least
20        $1,100,000,000 in electric system upgrades,
21        modernization projects, and training facilities,
22        including, but not limited to:
23                (i) distribution infrastructure improvements
24            totaling at least $1,000,000,000, including
25            underground residential distribution cable
26            injection and replacement and mainline cable

 

 

09700SB1652ham001- 33 -LRB097 09323 ASK 56228 a

1            system refurbishment and replacement projects;
2                (ii) training facility construction or upgrade
3            projects totaling at least $10,000,000, provided
4            that, at a minimum, one such facility shall be
5            located in a municipality having a population of
6            more than 2 million residents and one such facility
7            shall be located in a municipality having a
8            population of more than 150,000 residents but
9            fewer than 170,000 residents; any such new
10            facility located in a municipality having a
11            population of more than 2 million residents must be
12            designed for the purpose of obtaining, and the
13            owner of the facility shall apply for,
14            certification under the United States Green
15            Building Council's Leadership in Energy Efficiency
16            Design Green Building Rating System; and
17                (iii) wood pole inspection, treatment, and
18            replacement programs; and
19            (B) over a 10-year period, invest at least
20        $1,500,000,000 to upgrade and modernize its
21        transmission and distribution infrastructure and in
22        Smart Grid electric system upgrades, including, but
23        not limited to:
24                (i) additional smart meters;
25                (ii) distribution automation;
26                (iii) associated cyber secure data

 

 

09700SB1652ham001- 34 -LRB097 09323 ASK 56228 a

1            communication network; and
2                (iv) substation micro-processor relay
3            upgrades.
4        (2) Beginning no later than 180 days after a
5    participating utility that is a combination utility files a
6    performance-based formula rate tariff pursuant to
7    subsection (c) of this Section, or, beginning no later than
8    January 1, 2012 if such utility files such
9    performance-based formula rate tariff within 14 days of the
10    effective date of this amendatory Act of the 97th General
11    Assembly, the participating utility shall, except as
12    provided in subsection (b-5):
13            (A) over a 10-year period, invest at least
14        $265,000,000 in electric system upgrades,
15        modernization projects, and training facilities,
16        including, but not limited to:
17                (i) distribution infrastructure improvements
18            totaling at least $245,000,000, which may include
19            bulk supply substations, transformers,
20            reconductoring, and rebuilding overhead
21            distribution and sub-transmission lines,
22            underground residential distribution cable
23            injection and replacement and mainline cable
24            system refurbishment and replacement projects;
25                (ii) training facility construction or upgrade
26            projects totaling at least $1,000,000; any such

 

 

09700SB1652ham001- 35 -LRB097 09323 ASK 56228 a

1            new facility must be designed for the purpose of
2            obtaining, and the owner of the facility shall
3            apply for, certification under the United States
4            Green Building Council's Leadership in Energy
5            Efficiency Design Green Building Rating System;
6            and
7                (iii) wood pole inspection, treatment, and
8            replacement programs; and
9            (B) over a 10-year period, invest at least
10        $360,000,000 to upgrade and modernize its transmission
11        and distribution infrastructure and in Smart Grid
12        electric system upgrades, including, but not limited
13        to:
14                (i) additional smart meters;
15                (ii) distribution automation;
16                (iii) associated cyber secure data
17            communication network; and
18                (iv) substation micro-processor relay
19            upgrades.
20    For purposes of this Section, "Smart Grid electric system
21upgrades" shall have the meaning set forth in subsection (a) of
22Section 16-108.6 of this Act.
23    If a participating utility other than a combination utility
24serves less than 3 million electric distribution customers in
25Illinois, then the infrastructure investment program
26commitments and obligations described in this subsection (b)

 

 

09700SB1652ham001- 36 -LRB097 09323 ASK 56228 a

1shall be reduced proportionately, based on the number of
2customers, for the utility.
3    The investments in the infrastructure investment program
4described in this subsection (b) shall be incremental to the
5participating utility's annual capital investment program, as
6defined by, for purposes of this subsection (b), the
7participating utility's average capital spend for calendar
8years 2008, 2009, and 2010 as reported in the applicable
9Federal Energy Regulatory Commission (FERC) Form 1; provided
10that where one or more utilities have merged, the average
11capital spend shall be determined using the aggregate of the
12merged utilities' capital spend reported in FERC Form 1 for the
13years 2008, 2009, and 2010.
14    Within 60 days after filing a tariff under subsection (c)
15of this Section, a participating utility shall submit to the
16Commission its plan, including scope, schedule, and staffing,
17for satisfying its infrastructure investment program
18commitments pursuant to this subsection (b). The submitted plan
19shall include a schedule and staffing plan for the next
20calendar year. The plan shall also include a plan for the
21creation, operation, and administration of a Smart Grid test
22bed as described in subsection (c) of Section 16-108.8. The
23plan need not allocate the work equally over the respective
24periods, but should allocate material increments throughout
25such periods commensurate with the work to be undertaken. No
26later than April 1 of each subsequent year, the utility shall

 

 

09700SB1652ham001- 37 -LRB097 09323 ASK 56228 a

1submit to the Commission a report that includes any update to
2the plan, a schedule for the next calendar year, the
3expenditures made for the prior calendar year and cumulatively,
4and the number of full-time equivalent jobs created for the
5prior calendar year and cumulatively. If the utility is
6materially deficient in satisfying a schedule or staffing plan,
7then the report must also include a corrective action plan to
8address the deficiency. The fact that the plan, implementation
9of the plan, or a schedule changes shall not imply the
10imprudence or unreasonableness of the infrastructure
11investment program, plan, or schedule.
12    With respect to the participating utility's peak job
13commitment, if, after considering the utility's corrective
14action plan and compliance thereunder, the Commission enters an
15order finding, after notice and hearing, that a participating
16utility did not satisfy its peak job commitment described in
17this subsection (b) for reasons that are reasonably within its
18control, then the Commission shall also determine, after
19consideration of the evidence, including, but not limited to,
20evidence submitted by the Department of Commerce and Economic
21Opportunity and the utility, the deficiency in the number of
22full-time equivalent jobs during the peak program year due to
23such failure. The Commission shall notify the Department of any
24proceeding that is initiated pursuant to this paragraph. For
25each full-time equivalent job deficiency during the peak
26program year that the Commission finds as set forth in this

 

 

09700SB1652ham001- 38 -LRB097 09323 ASK 56228 a

1paragraph, the participating utility shall, within 30 days
2after the entry of the Commission's order, pay $1,500 to a fund
3for training grants administered under Section 605-800 of The
4Department of Commerce and Economic Opportunity Law.
5    With respect to the participating utility's investment
6amount commitments, if, after considering the utility's
7corrective action plan and compliance thereunder, the
8Commission enters an order finding after notice and hearing,
9that a participating utility is not satisfying its investment
10amount commitments described in this subsection (b), then the
11utility shall no longer be eligible to annually update the
12performance-based formula rate tariff pursuant to subsection
13(d) of this Section. In such event, the then current rates
14shall remain in effect until such time as new rates are set
15pursuant to Article IX of this Act, subject to retroactive
16adjustment, with interest, to reconcile rates charged with
17actual costs.
18    If the Commission finds that a participating utility is no
19longer eligible to update the performance-based formula rate
20tariff pursuant to subsection (d) of this Section, or the
21performance-based formula rate is otherwise terminated, then
22the participating utility's voluntary commitments and
23obligations under this subsection (b) shall immediately
24terminate, except for the utility's obligation to pay an amount
25already owed to the fund for training grants pursuant to a
26Commission order.

 

 

09700SB1652ham001- 39 -LRB097 09323 ASK 56228 a

1    In meeting the obligations of this subsection (b), to the
2extent feasible and consistent with State and federal law, the
3investments under the infrastructure investment program should
4provide employment opportunities for all segments of the
5population and workforce, including minority-owned and
6female-owned business enterprises.
7    (b-5) Nothing in subsection (b) of this Section shall
8prohibit the Commission from investigating the prudence and
9reasonableness of the expenditures made under the
10infrastructure investment program. The fact that a
11participating utility invests more than the minimum amounts
12specified in subsection (b) of this Section or its plan shall
13not imply imprudence or unreasonableness.
14    If the participating utility finds that it is implementing
15its plan for satisfying the infrastructure investment program
16commitments described in subsection (b) of this Section at a
17cost below the minimum amounts specified in subsection (b) of
18this Section, then the utility may file a petition with the
19Commission requesting that it be permitted to satisfy its
20commitments by spending less than the minimum amounts specified
21in subsection (b) of this Section. For the infrastructure
22investment program commitments described in subparagraph (A)
23of paragraph (1) of subsection (b) of this Section, the
24participating utility may file such a petition no earlier than
25in year 4 of the 5-year period. For the infrastructure
26investment program commitments described in subparagraph (B)

 

 

09700SB1652ham001- 40 -LRB097 09323 ASK 56228 a

1of paragraph (1) and subparagraphs (A) and (B) of paragraph (2)
2of subsection (b) of this Section, the participating utility
3may file such a petition no earlier than in year 8 of the
410-year period. The Commission shall, after notice and hearing,
5enter its order approving or denying each such petition within
6150 days after the filing of the petition.
7    In no event, absent General Assembly approval, shall the
8capital investment costs incurred by a participating utility
9other than a combination utility in satisfying its
10infrastructure investment program commitments described in
11subsection (b) of this Section exceed $3,000,000,000 or, for a
12participating utility that is a combination utility,
13$720,000,000. If the participating utility's updated cost
14estimates for satisfying its infrastructure investment program
15commitments described in subsection (b) of this Section exceed
16the limitation imposed by this subsection (b-5), then it shall
17submit a report to the Commission that identifies the increased
18costs and explains the reason or reasons for the increased
19costs no later than the year in which the utility estimates it
20will exceed the limitation. The Commission shall review the
21report and shall, within 90 days after the participating
22utility files the report, report to the General Assembly its
23findings regarding the participating utility's report. If the
24General Assembly does not amend the limitation imposed by this
25subsection (b-5), then the utility may modify its plan so as
26not to exceed the limitation imposed by this subsection (b-5),

 

 

09700SB1652ham001- 41 -LRB097 09323 ASK 56228 a

1and the metrics and incremental savings goals established
2pursuant to subsection (f) of this Section shall be modified
3accordingly.
4    (c) A participating utility may elect to recover its
5delivery services costs through a performance-based formula
6rate approved by the Commission, which shall specify the cost
7components that form the basis of the rate charged to customers
8with sufficient specificity to operate in a standardized manner
9and be updated annually with transparent information that
10reflects the utility's actual costs to be recovered during the
11applicable rate year, which is the period beginning with the
12first billing day of January and extending through the last
13billing day of the following December. In the event the utility
14recovers a portion of its costs through automatic adjustment
15clause tariffs on the effective date of this amendatory Act of
16the 97th General Assembly, the utility may elect to continue to
17recover these costs through such tariffs, but then these costs
18shall not be recovered through the performance-based formula
19rate.
20    The performance-based formula rate shall be implemented
21through a tariff filed with the Commission consistent with the
22provisions of this subsection (c) that shall be applicable to
23all delivery services customers. The Commission shall initiate
24and conduct an investigation of the tariff in a manner
25consistent with the provisions of this subsection (c) and the
26provisions of Article IX of this Act to the extent they do not

 

 

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1conflict with this subsection (c). Except in the case where the
2Commission finds, after notice and hearing, that a
3participating utility is not satisfying its investment amount
4commitments under subsection (b) of this Section, the
5performance-based formula rate shall remain in effect at the
6discretion of the utility. The performance-based formula rate
7approved by the Commission shall do the following:
8        (1) Provide for the recovery of the utility's actual
9    costs of delivery services that are prudently incurred and
10    reasonable in amount consistent with Commission practice
11    and law. The fact that a cost differs from that incurred in
12    a prior calendar year or that an investment is different
13    from that made in a prior calendar year shall not imply the
14    imprudence or unreasonableness of that cost or investment.
15        (2) Reflect the utility's actual capital structure for
16    the applicable calendar year, excluding goodwill, subject
17    to a determination of prudence and reasonableness
18    consistent with Commission practice and law.
19        (3) Include a cost of equity, which shall be calculated
20    as the sum of the following:
21            (A) the average for the applicable calendar year of
22        the monthly average yields of 30-year U.S. Treasury
23        bonds published by the Board of Governors of the
24        Federal Reserve System in its weekly H.15 Statistical
25        Release or successor publication; and
26            (B) 600 basis points.

 

 

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1        At such time as the Board of Governors of the Federal
2    Reserve System ceases to include the monthly average yields
3    of 30-year U.S. Treasury bonds in its weekly H.15
4    Statistical Release or successor publication, the monthly
5    average yields of the U.S. Treasury bonds then having the
6    longest duration published by the Board of Governors in its
7    weekly H.15 Statistical Release or successor publication
8    shall instead be used for purposes of this paragraph (3).
9        (4) Permit and set forth protocols, subject to a
10    determination of prudence and reasonableness consistent
11    with Commission practice and law, for the following:
12            (A) recovery of incentive compensation expense
13        that is based on the achievement of operational
14        metrics, including metrics related to budget controls,
15        outage duration and frequency, safety, customer
16        service, efficiency and productivity, and
17        environmental compliance. Incentive compensation
18        expense that is based on net income or an affiliate's
19        earnings per share shall not be recoverable under the
20        performance-based formula rate;
21            (B) recovery of pension and other post-employment
22        benefits expense, provided that such costs are
23        supported by an actuarial study;
24            (C) recovery of severance costs, provided that if
25        the amount is over $3,700,000 for a participating
26        utility that is a combination utility or $10,000,000

 

 

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1        for a participating utility that serves more than 3
2        million retail customers, then the full amount shall be
3        amortized consistent with subparagraph (F) of this
4        paragraph (4);
5            (D) investment return on pension assets net of
6        deferred tax benefits equal to the utility's long-term
7        debt cost of capital as of the end of the applicable
8        calendar year;
9            (E) recovery of the expenses related to the
10        Commission proceeding under this subsection (c) to
11        approve this performance-based formula rate and
12        initial rates or to subsequent proceedings related to
13        the formula, provided that the recovery shall be
14        amortized over a 3-year period; recovery of expenses
15        related to the annual Commission proceedings under
16        subsection (d) of this Section to review the inputs to
17        the performance-based formula rate shall be expensed
18        and recovered through the performance-based formula
19        rate;
20            (F) amortization over a 5-year period of the full
21        amount of each charge or credit that exceeds $3,700,000
22        for a participating utility that is a combination
23        utility or $10,000,000 for a participating utility
24        that serves more than 3 million retail customers in the
25        applicable calendar year and that relates to a
26        workforce reduction program's severance costs, changes

 

 

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1        in accounting rules, changes in law, compliance with
2        any Commission-initiated audit, or a single storm or
3        other similar expense, provided that any unamortized
4        balance shall be reflected in rate base. For purposes
5        of this subparagraph (F), changes in law includes any
6        enactment, repeal, or amendment in a law, ordinance,
7        rule, regulation, interpretation, permit, license,
8        consent, or order, including those relating to taxes,
9        accounting, or to environmental matters, or in the
10        interpretation or application thereof by any
11        governmental authority occurring after the effective
12        date of this amendatory Act of the 97th General
13        Assembly;
14            (G) recovery of existing regulatory assets over
15        the periods previously authorized by the Commission;
16            (H) historical weather normalized billing
17        determinants; and
18            (I) allocation methods for common costs.
19        (5) Provide that if the participating utility's earned
20    return on common equity related to the provision of
21    delivery services for the prior rate year (calculated on a
22    ratemaking basis after adjusting for any disallowances
23    ordered by the Commission and adjusting for taxes) is more
24    than 50 basis points higher than the return on equity
25    calculated pursuant to paragraph (3) of this subsection (c)
26    (after adjusting for any adjustments to the return on

 

 

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1    equity applied pursuant to the performance metrics
2    provision of subsection (f) of this Section), then the
3    participating utility shall apply a credit through the
4    performance-based formula rate that reflects an amount
5    equal to the value of that portion of the earned return on
6    equity that is more than 50 basis points higher than the
7    return on equity calculated pursuant to paragraph (3) of
8    this subsection (c) for the prior rate year, adjusted for
9    taxes. If the participating utility's earned return on
10    common equity related to the provision of delivery services
11    for the prior rate year (calculated on a ratemaking basis
12    after adjusting for any disallowances ordered by the
13    Commission and adjusting for taxes) is more than 50 basis
14    points less than the return on equity calculated pursuant
15    to paragraph (3) of this subsection (c) (after adjusting
16    for any adjustments to the return on equity applied
17    pursuant to the performance metrics provision of
18    subsection (f) of this Section), then the participating
19    utility shall apply a charge through the performance-based
20    formula rate that reflects an amount equal to the value of
21    that portion of the earned return on equity that is more
22    than 50 basis points less than the return on equity
23    calculated pursuant to paragraph (3) of this subsection (c)
24    for the prior rate year, adjusted for taxes.
25        (6) Provide for an annual reconciliation, with
26    interest as described in subsection (d) of this Section, of

 

 

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1    the revenue requirement reflected in rates for each
2    calendar year, beginning with the calendar year in which
3    the utility files its performance-based formula rate
4    tariff pursuant to subsection (c) of this Section, with
5    what the revenue requirement would have been had the actual
6    cost information for the applicable calendar year been
7    available at the filing date.
8    The utility shall file, together with its tariff, final
9data based on its most recently filed FERC Form 1, plus
10projected plant additions and correspondingly updated
11depreciation reserve and expense for the calendar year in which
12the tariff and data are filed, that shall populate the
13performance-based formula rate and set the initial delivery
14services rates under the formula.
15    After the utility files its proposed performance-based
16formula rate structure and protocols and initial rates, the
17Commission shall initiate a docket to review the filing. The
18Commission shall enter an order approving, or approving as
19modified, the performance-based formula rate, including the
20initial rates, as just and reasonable within 270 days after the
21date on which the tariff was filed, or, if the tariff is filed
22within 14 days after the effective date of this amendatory Act
23of the 97th General Assembly, then by March 31, 2012. Such
24review shall be based on the same evidentiary standards,
25including, but not limited to, those concerning the prudence
26and reasonableness of the costs incurred by the utility, the

 

 

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1Commission applies in a hearing to review a filing for a
2general increase in rates under Article IX of this Act. The
3initial rates shall take effect within 30 days after the
4Commission's order approving the performance-based formula
5rate tariff.
6    Until such time as the Commission approves a different rate
7design and cost allocation pursuant to subsection (e) of this
8Section, rate design and cost allocation across customer
9classes shall be consistent with the Commission's most recent
10order regarding the participating utility's request for a
11general increase in its delivery services rates.
12    Subsequent changes to the performance-based formula rate
13structure or protocols shall be made as set forth in Section
149-201 of this Act, but nothing in this subsection (c) is
15intended to limit the Commission's authority under Article IX
16and other provisions of this Act to initiate an investigation
17of a participating utility's performance-based formula rate
18tariff, provided that any such changes shall be consistent with
19paragraphs (1) through (6) of this subsection (c). Any change
20ordered by the Commission shall be made at the same time new
21rates take effect following the Commission's next order
22pursuant to subsection (d) of this Section, provided that the
23new rates take effect no less than 30 days after the date on
24which the Commission issues an order adopting the change.
25    Beginning 11 years after the effective date of this
26amendatory Act of the 97th General Assembly, the Commission may

 

 

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1upon petition or its own initiative, but with reasonable
2notice, enter upon a hearing concerning proposed changes to the
3performance-based formula rate, including those protocols
4established under paragraph (4) of this subsection (c),
5provided that there shall be a rebuttable presumption that the
6protocols are just and reasonable. These proposed changes shall
7be stated with particularity and accompanied by clear and
8convincing evidence that the changes are just and reasonable.
9No such change adopted by the Commission shall be applied to
10the calculation of the utility's rates until the next calendar
11year, with the rates to become effective on January 1 of the
12year following that calendar year, provided that the next
13calendar year begins no less than 90 days after the date on
14which the Commission issues an order adopting the change.
15    A participating utility that files a tariff pursuant to
16this subsection (c) must submit a one-time $200,000 filing fee
17at the time the Chief Clerk of the Commission accepts the
18filing, which shall be a recoverable expense.
19    In the event the performance-based formula rate is
20terminated, the then current rates shall remain in effect until
21such time as new rates are set pursuant to Article IX of this
22Act, subject to retroactive rate adjustment, with interest, to
23reconcile rates charged with actual costs. At such time that
24the performance-based formula rate is terminated, the
25participating utility's voluntary commitments and obligations
26under subsection (b) of this Section shall immediately

 

 

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1terminate, except for the utility's obligation to pay an amount
2already owed to the fund for training grants pursuant to a
3Commission order issued under subsection (b) of this Section.
4    (d) Subsequent to the Commission's issuance of an order
5approving the utility's performance-based formula rate
6structure and protocols, and initial rates under subsection (c)
7of this Section, the utility shall file, on or before May 1 of
8each year, with the Chief Clerk of the Commission its updated
9cost inputs to the performance-based formula rate for the
10applicable rate year and the corresponding new charges. Each
11such filing shall conform to the following requirements and
12include the following information:
13        (1) The inputs to the performance-based formula rate
14    for the applicable rate year shall be based on final
15    historical data reflected in the utility's most recently
16    filed annual FERC Form 1 plus projected plant additions and
17    correspondingly updated depreciation reserve and expense
18    for the calendar year in which the inputs are filed. The
19    filing shall also include a reconciliation of the revenue
20    requirement that was in effect for the prior rate year (as
21    set by the cost inputs for the prior rate year) with the
22    actual revenue requirement for the prior rate year (as
23    reflected in the applicable FERC Form 1 that reports the
24    actual costs for the prior rate year). Any over-collection
25    or under-collection indicated by such reconciliation shall
26    be reflected as a credit against, or recovered as an

 

 

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1    additional charge to, respectively, with interest, the
2    charges for the applicable rate year. Provided, however,
3    that the first such reconciliation shall be for the
4    calendar year in which the utility files its
5    performance-based formula rate tariff pursuant to
6    subsection (c) of this Section and shall reconcile (i) the
7    revenue requirement or requirements established by the
8    rate order or orders in effect from time to time during
9    such calendar year (weighted, as applicable) with (ii) the
10    revenue requirement for that calendar year calculated
11    pursuant to the performance-based formula rate using (A)
12    actual costs for that year as reflected in the applicable
13    FERC Form 1, and (B) for the first such reconciliation
14    only, the cost of equity approved by the Commission in such
15    order or orders in effect during that year (weighted, as
16    applicable). The first such reconciliation is not intended
17    to provide for the recovery of costs previously excluded
18    from rates based on a prior Commission order finding of
19    imprudence or unreasonableness. Each reconciliation shall
20    be certified by the participating utility in the same
21    manner that FERC Form 1 is certified. The filing shall also
22    include the charge or credit, if any, resulting from the
23    calculation required by paragraph (6) of subsection (c) of
24    this Section.
25        Notwithstanding anything that may be to the contrary,
26    the intent of the reconciliation is to ultimately reconcile

 

 

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1    the revenue requirement reflected in rates for each
2    calendar year, beginning with the calendar year in which
3    the utility files its performance-based formula rate
4    tariff pursuant to subsection (c) of this Section, with
5    what the revenue requirement would have been had the actual
6    cost information for the applicable calendar year been
7    available at the filing date.
8        (2) The new charges shall take effect beginning on the
9    first billing day of the following January billing period
10    and remain in effect through the last billing day of the
11    next December billing period regardless of whether the
12    Commission enters upon a hearing pursuant to this
13    subsection (d).
14        (3) The filing shall include relevant and necessary
15    data and documentation for the applicable rate year that is
16    consistent with the Commission's rules applicable to a
17    filing for a general increase in rates or any rules adopted
18    by the Commission to implement this Section. Normalization
19    adjustments shall not be required. Notwithstanding any
20    other provision of this Section or Act or any rule or other
21    requirement adopted by the Commission, a participating
22    utility that is a combination utility with more than one
23    rate zone shall not be required to file a separate set of
24    such data and documentation for each rate zone and may
25    combine such data and documentation into a single set of
26    schedules.

 

 

09700SB1652ham001- 53 -LRB097 09323 ASK 56228 a

1    Within 45 days after the utility files its annual update of
2cost inputs to the performance-based formula rate, the
3Commission shall have the authority, either upon complaint or
4its own initiative, but with reasonable notice, to enter upon a
5hearing concerning the prudence and reasonableness of the costs
6incurred by the utility to be recovered during the applicable
7rate year that are reflected in the inputs to the
8performance-based formula rate derived from the utility's FERC
9Form 1. During the course of the hearing, each objection shall
10be stated with particularity and substantial evidence provided
11in support thereof, after which the utility shall have the
12opportunity to rebut the evidence. Discovery shall be allowed
13consistent with the Commission's Rules of Practice, which Rules
14shall be enforced by the Commission or the assigned hearing
15examiner. The Commission shall apply the same evidentiary
16standards, including, but not limited to, those concerning the
17prudence and reasonableness of the costs incurred by the
18utility, in the hearing as it would apply in a hearing to
19review a filing for a general increase in rates under Article
20IX of this Act. The Commission shall not, however, have the
21authority in a proceeding under this subsection (d) to consider
22or order any changes to the structure or protocols of the
23performance-based formula rate approved pursuant to subsection
24(c) of this Section. In a proceeding under this subsection (d),
25the Commission shall enter its order no later than the earlier
26of 240 days after the utility's filing of its annual update of

 

 

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1cost inputs to the performance-based formula rate or December
231. The Commission's determinations of the prudence and
3reasonableness of the costs incurred for the applicable
4calendar year shall be final upon entry of the Commission's
5order and shall not be subject to reopening, reexamination, or
6collateral attack in any other proceeding, case, docket, order,
7rule or regulation, provided, however, that nothing in this
8subsection (d) shall prohibit a party from petitioning the
9Commission to rehear or appeal to the courts the order pursuant
10to the provisions of this Act.
11    In the event the Commission does not, either upon complaint
12or its own initiative, enter upon a hearing within 45 days
13after the utility files the annual update of cost inputs to its
14performance-based formula rate, then the costs incurred for the
15applicable calendar year shall be deemed prudent and
16reasonable, and the filed charges shall not be subject to
17reopening, reexamination, or collateral attack in any other
18proceeding, case, docket, order, rule, or regulation.
19    (e) Nothing in subsections (c) or (d) of this Section shall
20prohibit the Commission from investigating, or a participating
21utility from filing, revenue-neutral tariff changes related to
22rate design of a performance-based formula rate that has been
23placed into effect for the utility. Following approval of a
24participating utility's performance-based formula rate tariff
25pursuant to subsection (c) of this Section, the utility shall
26make a filing with the Commission within one year after the

 

 

09700SB1652ham001- 55 -LRB097 09323 ASK 56228 a

1effective date of the performance-based formula rate tariff
2that proposes changes to the tariff to incorporate the findings
3of any final rate design orders of the Commission applicable to
4the participating utility and entered subsequent to the
5Commission's approval of the tariff. The Commission shall,
6after notice and hearing, enter its order approving, or
7approving with modification, the proposed changes to the
8performance-based formula rate tariff within 240 days after the
9utility's filing. Following such approval, the utility shall
10make a filing with the Commission during each subsequent 3-year
11period that either proposes revenue-neutral tariff changes or
12re-files the existing tariffs without change, which shall
13present the Commission with an opportunity to suspend the
14tariffs and consider revenue-neutral tariff changes related to
15rate design.
16    (f) Within 30 days after the filing of a tariff pursuant to
17subsection (c) of this Section, each participating utility
18shall develop and file with the Commission multi-year metrics
19designed to achieve, ratably over a 10-year period, improvement
20over baseline performance values as follows:
21        (1) Twenty percent improvement in the System Average
22    Interruption Frequency Index, using a baseline of the
23    average of the data from 2001 through 2010.
24        (2) Fifteen percent improvement in the system Customer
25    Average Interruption Duration Index, using 2010 as the
26    baseline year.

 

 

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1        (3) For a participating utility other than a
2    combination utility, 20% improvement in the System Average
3    Interruption Frequency Index for its Southern Region,
4    using a baseline of the average of the data from 2001
5    through 2010. For purposes of this paragraph (C), Southern
6    Region shall have the meaning set forth in the
7    participating utility's most recent report filed pursuant
8    to Section 16-125 of this Act.
9        (4) Seventy-five percent improvement in the total
10    number of customers who exceed the service reliability
11    targets as set forth in subparagraphs (A) through (C) of
12    paragraph (4) of subsection (b) of 83 Ill. Admin. Code Part
13    411.140 as of May 1, 2011, using 2010 as the baseline year.
14        (5) Reduction in issuance of estimated electric bills:
15    90% improvement for a participating utility other than a
16    combination utility, and 56% improvement for a
17    participating utility that is a combination utility, using
18    a baseline of the average number of estimated bills for the
19    years 2008 through 2010.
20        (6) Consumption on inactive meters: 90% improvement
21    for a participating utility other than a combination
22    utility, and 56% improvement for a participating utility
23    that is a combination utility, using a baseline of the
24    average unbilled kilowatthours for the years 2009 and 2010.
25        (7) Unaccounted for energy: 50% improvement for a
26    participating utility other than a combination utility

 

 

09700SB1652ham001- 57 -LRB097 09323 ASK 56228 a

1    using a baseline of the non-technical line loss unaccounted
2    for energy kilowatthours for the year 2009.
3        (8) Uncollectible expense: reduce uncollectible
4    expense by at least $30,000,000 for a participating utility
5    other than a combination utility and by at least $3,500,000
6    for a participating utility that is a combination utility,
7    using a baseline of the average uncollectible expense for
8    the years 2008 through 2010.
9        (9) Opportunities for minority-owned and female-owned
10    business enterprises: design a performance metric
11    regarding the creation of opportunities for minority-owned
12    and female-owned business enterprises consistent with
13    State and federal law using a base performance value of the
14    percentage of the participating utility's capital
15    expenditures that were paid to minority-owned and
16    female-owned business enterprises in 2010.
17    The definitions set forth in 83 Ill. Admin. Code Part
18411.20 as of May 1, 2011 shall be used for purposes of
19calculating performance under paragraphs (1) through (3) of
20this subsection (f), provided, however, that the participating
21utility may exclude up to 9 extreme weather event days from
22such calculation for each year. For purposes of this Section,
23an extreme weather event day is a 24-hour calendar day
24(beginning at 12:00 am and ending at 11:59 pm) during which any
25weather event (e.g., storm, tornado) caused interruptions for
2610,000 or more of the participating utility's customers for 3

 

 

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1hours or more. If there are more than 9 extreme weather event
2days in a year, then the utility may choose no more than 9
3extreme weather event days to exclude, provided that the same
4extreme weather event days are excluded from each of the
5calculations performed under paragraphs (1) through (3) of this
6subsection (f).
7    The metrics shall include incremental performance goals
8for each year of the 10-year period, which shall be designed to
9demonstrate that the utility is on track to achieve the
10performance goal in each category at the end of the 10-year
11period. The utility shall elect when the 10-year period shall
12commence, provided that it begins no later than 14 months
13following the date on which the utility begins investing
14pursuant to subsection (b) of this Section.
15    The metrics and performance goals set forth in this
16subsection (f) are based on the assumptions that the
17participating utility may fully implement the technology
18described in subsection (b) of this Section, including
19utilizing the full functionality of such technology and that
20there is no requirement for personal on-site notification.
21    (f-5) The financial penalties applicable to the metrics
22described in subparagraphs (1) through (8) of subsection (f) of
23this Section, as applicable, shall be applied through an
24adjustment to the participating utility's return on equity as
25follows:
26        (1) With respect to each of the incremental annual

 

 

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1    performance goals established pursuant to paragraph (1) of
2    subsection (f) of this Section, for each year that a
3    participating utility other than a combination utility
4    does not achieve at least 95% of the annual goal, the
5    participating utility's return on equity shall be reduced
6    by no more than 5 basis points for such unachieved goal for
7    the following 12-month period, and for each year that a
8    participating utility that is a combination utility does
9    not achieve at least 95% of the annual goal, the
10    participating utility's return on equity shall be reduced
11    by no more than 10 basis points for each such unachieved
12    goal for the following 12-month period.
13        (2) With respect to each of the incremental annual
14    performance goals established pursuant to subparagraphs
15    (2), (3), (4), and (5) of subsection (f) of this Section,
16    as applicable, for each year that the participating utility
17    does not achieve at least 95% of each such goal, the
18    participating utility's return on equity shall be reduced
19    by no more than 5 basis points for each such unachieved
20    goal for the following 12-month period.
21        (3) With respect to each of the incremental annual
22    performance goals established pursuant to paragraphs (6),
23    (7), and (8) of subsection (f) of this Section, as
24    applicable, the performance under each such goal shall be
25    calculated in terms of the percentage of the goal achieved.
26    The percentage of goal achieved for each of the goals shall

 

 

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1    be aggregated, and an average percentage value calculated,
2    for each year of the 10-year period. If the utility does
3    not achieve an average percentage value in a given year of
4    at least 95%, the participating utility's return on equity
5    shall be reduced by no more than 5 basis points for the
6    following 12-month period.
7    The financial penalties shall be applied as described in
8this subsection (f-5) through a separate tariff mechanism,
9which shall be filed by the utility together with its metrics.
10In the event the formula rate tariff established pursuant to
11subsection (c) of this Section terminates, the utility's
12obligations under subsection (f) of this Section and this
13subsection (f-5) shall also terminate, provided, however, that
14the tariff mechanism established pursuant to subsection (f) of
15this Section and this subsection (f-5) shall remain in effect
16until any penalties due and owing at the time of such
17termination are applied.
18    The Commission shall, after notice and hearing, enter an
19order within 120 days after the metrics are filed approving, or
20approving with modification, the metrics and tariff mechanism.
21On June 1 of each subsequent year, each participating utility
22shall file a report with the Commission that includes
23performance under each metric, identification of any
24extraordinary events that adversely impacted the utility's
25performance, and any proposed financial penalties to be applied
26through the approved tariff mechanism or any revised future

 

 

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1incremental annual performance goals to address a shortfall.
2Each such filing shall include documentation and data
3supporting any proposed financial penalties to be applied, and
4the Commission shall, after notice and hearing, enter an order
5approving, or approving with modification, any proposed
6financial penalties within 180 days after the filing. The
7Commission-approved financial penalties shall be applied
8beginning with the next rate year.
9    (g) On or before July 31, 2014, a participating utility
10shall file a report with the Commission demonstrating whether
11the average increase in the amounts paid per kilowatthour by
12residential eligible retail customers, or the weighted average
13aggregate increase in the amounts paid by all residential
14eligible retail customers for a participating utility that is a
15combination utility with more than one rate zone, in connection
16with electric service was limited to, during the period June 1,
172013 through May 31, 2014, no more than 2.5%, compounded
18annually, of the amount paid per kilowatthour by those
19customers during the period June 1, 2010 through May 31, 2011,
20and exclusive of the effects of energy efficiency programs. The
21report shall be filed together with a statement from an
22independent auditor attesting to the accuracy of the report.
23    In the event that the average annual increase exceeds 2.5%
24as calculated pursuant to this subsection (g), then Sections
251-56A and 1-76 of the Illinois Power Agency Act and Sections
268-103A, 16-108.5, 16-108.6, 16-108.7, 16-108.8, and 16-111.5B

 

 

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1of this Act, other than this subsection, shall be inoperative
2as they relate to the utility and its service area as of the
3date of the report due to be submitted pursuant to this
4subsection and the utility shall no longer be eligible to
5annually update the performance-based formula rate tariff
6pursuant to subsection (d) of this Section. In such event, the
7then current rates shall remain in effect until such time as
8new rates are set pursuant to Article IX of this Act, subject
9to retroactive adjustment, with interest, to reconcile rates
10charged with actual costs, and the participating utility's
11voluntary commitments and obligations under subsection (b) of
12this Section shall immediately terminate, except for the
13utility's obligation to pay an amount already owed to the fund
14for training grants pursuant to a Commission order issued under
15subsection (b) of this Section.
16    In the event that the average annual increase is 2.5% or
17less as calculated pursuant to this subsection (g), then the
18performance-based formula rate shall remain in effect as set
19forth in this Section.
20    For purposes of this Section, the amount per kilowatthour
21means the total amount paid for electric service expressed on a
22per kilowatthour basis, and the total amount paid for electric
23service includes without limitation amounts paid for supply,
24transmission, distribution, surcharges, and add-on-taxes
25exclusive of any increases in taxes or new taxes imposed after
26the effective date of this amendatory Act of the 97th General

 

 

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1Assembly. For purposes of this Section, "eligible retail
2customers" shall have the meaning set forth in Section 16-111.5
3of this Act.
4    The fact that this Section becomes inoperative as set forth
5in this subsection shall not be construed to mean that the
6Commission may reexamine or otherwise reopen prudence or
7reasonableness determinations already made.
8    (h) Sections 1-56A and 1-76 of the Illinois Power Agency
9Act and Sections 8-103A, 16-108.5, 16-108.6, 16-108.7,
1016-108.8, and 16-111.5B of this Act, other than this
11subsection, are inoperative after December 31, 2017 for every
12participating utility, after which time a participating
13utility shall no longer be eligible to annually update the
14performance-based formula rate tariff pursuant to subsection
15(d) of this Section. At such time, the then current rates shall
16remain in effect until such time as new rates are set pursuant
17to Article IX of this Act, subject to retroactive adjustment,
18with interest, to reconcile rates charged with actual costs.
19    By December 31, 2017, the Commission shall prepare and file
20with the General Assembly a report on the change in the average
21amount per kilowatthour paid by residential customers between
22June 1, 2011 and May 31, 2017. If the change in the total
23average rate paid exceeds 2.5% compounded annually, the
24Commission shall include in the report an analysis that shows
25the portion of the change due to the delivery services
26component and the portion of the change due to the supply

 

 

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1component of the rate. The report shall include separate
2sections for each participating utility.
3    The fact that this Section becomes inoperative as set forth
4in this subsection shall not be construed to mean that the
5Commission may reexamine or otherwise reopen prudence or
6reasonableness determinations already made.
7    (i) Notwithstanding anything to the contrary in this
8Section, an electric utility that serves less than 100,000
9retail customers in Illinois may be considered a participating
10utility if it undertakes the voluntary commitments and
11obligations described in subsection (b) of this Section,
12provided, however, that such commitments and obligations, as
13well as amounts set forth in subsection (c) of this Section,
14shall be reduced proportionately, based on the number of
15customers, for the utility. Such participating utility shall be
16permitted to file a performance-based formula rate tariff that
17recovers its total actual Illinois jurisdictional costs to
18provide electric service to its retail customers.
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 in conjunction with providing delivery services to its
24retail customers, including, but not limited to, the
25installation, implementation and maintenance of Smart Grid
26electric system upgrades as defined in Section 16-108.6 of the

 

 

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1Act, a participating utility is not authorized under this
2Section to separately offer to its retail customers broadband
3services or the delivery of broadband services,
4voice-over-internet-protocol services, telecommunications
5services, or cable or video programming services or to recover
6the costs of such separate offerings from retail customers.
7    (k) Nothing in this Section is intended to legislatively
8overturn the opinion issued in Commonwealth Edison Co. v. Ill.
9Commerce Comm'n, Nos. 2-08-0959, 2-08-1037, 2-08-1137,
101-08-3008, 1-08-3030, 1-08-3054, 1-08-3313 cons. (Ill. App.
11Ct. 2d Dist. Sept. 30, 2010).
 
12    (220 ILCS 5/16-108.6 new)
13    Sec. 16-108.6. Provisions relating to Smart Grid Advanced
14Metering Infrastructure Deployment Plan.
15    (a) For purposes of this Section and Sections 16-108.7 and
1616-108.8 of this Act:
17    "Advanced Metering Infrastructure" or "AMI" means the
18communications hardware and software and associated system
19software that enables Smart Grid functions by creating a
20network between advanced meters and utility business systems
21and allowing collection and distribution of information to
22customers and other parties in addition to providing
23information to the utility itself.
24    "Cost-beneficial" means a determination that the benefits
25of a participating utility's Smart Grid AMI Deployment Plan

 

 

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1exceed the costs of the Plan as initially filed with the
2Commission or as subsequently modified by the Commission. This
3standard is met if the net present value of the total benefits
4of the Smart Grid AMI Deployment Plan exceeds the net present
5value of the total costs of the Smart Grid AMI Deployment Plan.
6The total cost shall include all utility costs reasonably
7associated with the Smart Grid AMI Deployment Plan. The total
8benefits shall include the sum of avoided electricity costs,
9including avoided utility operational costs, avoided consumer
10power, capacity, and energy costs, and avoided societal costs
11associated with the production and consumption of electricity,
12as well as other societal benefits, including the greater
13integration of renewable and distributed power resources,
14reductions in the emissions of harmful pollutants and
15associated avoided health-related costs, other benefits
16associated with energy efficiency measures, demand-response
17activities, and the enabling of greater penetration of
18alternative fuel vehicles.
19    "Participating utility" has the meaning set forth in
20Section 16-108.5 of this Act.
21    "Smart Grid" means investments and policies that together
22promote one or more of the following goals:
23        (1) Increased use of digital information and controls
24    technology to improve reliability, security, and
25    efficiency of the electric grid.
26        (2) Dynamic optimization of grid operations and

 

 

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1    resources, with full cyber-security.
2        (3) Deployment and integration of distributed
3    resources and generation, including renewable resources.
4        (4) Development and incorporation of demand-response,
5    demand-side resources, and energy efficiency resources.
6        (5) Deployment of "smart" technologies (real-time,
7    automated, interactive technologies that optimize the
8    physical operation of appliances and consumer devices) for
9    metering, communications concerning grid operations and
10    status, and distribution automation.
11        (6) Integration of "smart" appliances and consumer
12    devices.
13        (7) Deployment and integration of advanced electricity
14    storage and peak-shaving technologies, including plug-in
15    electric and hybrid electric vehicles, thermal-storage air
16    conditioning and renewable energy generation.
17        (8) Provision to consumers of timely information and
18    control options.
19        (9) Development of open access standards for
20    communication and interoperability of appliances and
21    equipment connected to the electric grid, including the
22    infrastructure serving the grid.
23        (10) Identification and lowering of unreasonable or
24    unnecessary barriers to adoption of smart grid
25    technologies, practices, services, and business models
26    that support energy efficiency, demand-response, and

 

 

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1    distributed generation.
2    "Smart Grid Advisory Council" means the group of
3stakeholders formed pursuant to subsection (b) of this Section
4for the purposes of advising and working with participating
5utilities on the development and implementation of a Smart Grid
6Advanced Metering Infrastructure Deployment Plan.
7    "Smart Grid electric system upgrades" means any of the
8following:
9        (1) metering devices, sensors, control devices, and
10    other devices integrated with and attached to an electric
11    utility system that are capable of engaging in Smart Grid
12    functions;
13        (2) other monitoring and communications devices that
14    enable Smart Grid functions, including, but not limited to,
15    distribution automation;
16        (3) software that enables devices or computers to
17    engage in Smart Grid functions;
18        (4) associated cyber secure data communication
19    network, including enhancements to cyber security
20    technologies and measures;
21        (5) substation micro-processor relay upgrades;
22        (6) devices that allow electric or hybrid-electric
23    vehicles to engage in Smart Grid functions; or
24        (7) devices that enable individual consumers to
25    incorporate distributed and micro-generation.
26    "Smart Grid electric system upgrades" does not include

 

 

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1expenditures for: (1) electricity generation, transmission, or
2distribution infrastructure or equipment that does not
3directly relate to or support installing, implementing or
4enabling Smart Grid functions; (2) physical interconnection of
5generators or other devices to the grid except those that are
6directly related to enabling Smart Grid functions; or (3)
7ongoing or routine operation, billing, customer relations,
8security, and maintenance.
9    "Smart Grid functions" means:
10        (1) the ability to develop, store, send, and receive
11    digital information concerning or enabling grid
12    operations, electricity use, costs, prices, time of use,
13    nature of use, storage, or other information relevant to
14    device, grid, or utility operations, to or from or by means
15    of the electric utility system through one or a combination
16    of devices and technologies;
17        (2) the ability to develop, store, send, and receive
18    digital information concerning electricity use, costs,
19    prices, time of use, nature of use, storage, or other
20    information relevant to device, grid, or utility
21    operations to or from a computer or other control device;
22        (3) the ability to measure or monitor electricity use
23    as a function of time of day, power quality characteristics
24    such as voltage level, current, cycles per second, or
25    source or type of generation and to store, synthesize, or
26    report that information by digital means;

 

 

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1        (4) the ability to sense and localize disruptions or
2    changes in power flows on the grid and communicate such
3    information instantaneously and automatically for purposes
4    of enabling automatic protective responses to sustain
5    reliability and security of grid operations;
6        (5) the ability to detect, prevent, communicate with
7    regard to, respond to, or recover from system security
8    threats, including cyber-security threats and terrorism,
9    using digital information, media, and devices;
10        (6) the ability of any device or machine to respond to
11    signals, measurements, or communications automatically or
12    in a manner programmed by its owner or operator without
13    independent human intervention;
14        (7) the ability to use digital information to operate
15    functionalities on the electric utility grid that were
16    previously electro-mechanical or manual;
17        (8) the ability to use digital controls to manage and
18    modify electricity demand, enable congestion management,
19    assist in voltage control, provide operating reserves, and
20    provide frequency regulation; or
21        (9) the ability to integrate electric plug-in
22    vehicles, distributed generation, and storage in a safe and
23    cost effective manner on the electric grid.
24    (b) Within 30 days after the effective date of this
25amendatory Act of the 97th General Assembly, the Smart Grid
26Advisory Council shall be established, which shall consist of 7

 

 

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1total voting members with each member possessing either
2technical, business or consumer expertise in Smart Grid issues
3and each having been the single appointment of one of the
4following: the Governor, the Speaker of the House, the Minority
5Leader of the House, the President of the Senate, the Minority
6Leader of the Senate, the Illinois Science and Technology
7Coalition, and the Citizens Utility Board. The Governor shall
8designate one of the members of the Council to serve as
9chairman, and that person shall serve as the chairman at the
10pleasure of the Governor. The Smart Grid Advisory Council shall
11have the following duties:
12        (1) Serve as an advisor to participating utilities
13    subject to this Section and in the manner described in this
14    Section, and the recommendations provided by the Council,
15    although non-binding, shall be considered by the
16    utilities.
17        (2) Serve as trustees of the trust or foundation
18    established pursuant to Section 16-108.7 of this Act with
19    the duties enumerated thereunder.
20    (c) After consultation with the Smart Grid Advisory
21Council, each participating utility shall file a Smart Grid
22Advanced Metering Infrastructure Deployment Plan ("AMI Plan")
23with the Commission within 180 days after the effective date of
24this amendatory Act of the 97th General Assembly or by November
251, 2011, whichever is later, or in the case of a combination
26utility as defined in Section 16-108.5, by April 1, 2012. The

 

 

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1AMI Plan shall provide for investment over a 10-year period
2that is sufficient to implement the AMI Plan across its entire
3service territory in a manner that is consistent with
4subsection (b) of Section 16-108.5 of this Act. The AMI Plan
5shall contain:
6        (1) the participating utility's Smart Grid AMI vision
7    statement that is consistent with the goal of developing a
8    cost-beneficial Smart Grid;
9        (2) a statement of Smart Grid AMI strategy that
10    includes a description of how the utility evaluates and
11    prioritizes technology choices to create customer value,
12    including a plan to enhance and enable customers' ability
13    to take advantage of Smart Grid functions beginning at the
14    time an account has billed successfully on the AMI network;
15        (3) a deployment schedule and plan that includes
16    deployment of AMI to all customers for a participating
17    utility other than a combination utility, and to 62% of all
18    customers for a participating utility that is a combination
19    utility;
20        (4) annual milestones and metrics for the purposes of
21    measuring the success of the AMI Plan in enabling Smart
22    Grid functions; and enhancing consumer benefits from Smart
23    Grid AMI; and
24        (5) a plan for the consumer education to be implemented
25    by the participating utility.
26    The AMI Plan shall be fully consistent with the standards

 

 

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1of the National Institute of Standard and Technology (NIST) for
2Smart Grid interoperability that are in effect at the time the
3participating utility files its AMI Plan, shall include open
4standards and internet protocol to the maximum extent possible
5consistent with cyber-security, and shall maximize, to the
6extent possible, a flexible smart meter platform that can
7accept remote device upgrades and contain sufficient internal
8memory capacity for additional storage capabilities, functions
9and services without the need for physical access to the meter.
10    The AMI Plan shall secure the privacy of personal
11information and establish the right of consumers to consent to
12the disclosure of personal energy information to third parties
13through electronic, web-based, and other means in accordance
14with State and federal law and regulations regarding consumer
15privacy and protection of consumer data.
16    After notice and hearing, the Commission shall, within 60
17days of the filing of an AMI Plan, issue its order approving,
18or approving with modification, the AMI Plan if the Commission
19finds that the AMI Plan contains the information required in
20paragraphs (1) through (5) of this subsection (c) and further
21finds that the implementation of the AMI Plan is likely to be
22cost-beneficial, giving weight to the results of any
23Commission-approved pilot designed to examine the benefits and
24costs of AMI deployment. A participating utility's decision to
25invest pursuant to an AMI Plan approved by the Commission shall
26not be subject to prudence reviews in subsequent Commission

 

 

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1proceedings. Nothing in this subsection (c) is intended to
2limit the Commission's ability to review the reasonableness of
3the costs incurred under the AMI Plan. A participating utility
4shall be allowed to recover the reasonable costs it incurs in
5implementing a Commission-approved AMI Plan, including the
6costs of retired meters, and may recover such costs through its
7tariffs, including the performance-based formula rate tariff
8approved pursuant to subsection (c) of Section 16-108.5 of this
9Act.
10    (d) The AMI Plan shall secure the privacy of the customer's
11personal information. "Personal information" for this purpose
12consists of the customer's name, address, telephone number, and
13other personally identifying information, as well as
14information about the customer's electric usage. Electric
15utilities, their contractors or agents, and any third party who
16comes into possession of such personal information by virtue of
17working on Smart Grid technology shall not disclose such
18personal information to be used in mailing lists or to be used
19for other commercial purposes not reasonably related to the
20conduct of the utility's business. Electric utilities shall
21comply with the consumer privacy requirements of the Personal
22Information Protection Act.
23    (e) On April 1 of each year beginning in 2013 and after
24consultation with the Smart Grid Advisory Council, each
25participating utility shall submit a report regarding the
26progress it has made toward completing implementation of its

 

 

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1AMI Plan. This report shall:
2        (1) describe the AMI investments made during the prior
3    12 months and the AMI investments planned to be made in the
4    following 12 months;
5        (2) provide sufficient detail to determine the
6    utility's progress in meeting the metrics and milestones
7    identified by the utility in its AMI Plan; and
8        (3) identify any updates to the AMI Plan.
9    Within 21 days after the utility files its annual report,
10the Commission shall have authority, either upon complaint or
11its own initiative, but with reasonable notice, to enter upon
12an investigation regarding the utility's progress in
13implementing the AMI Plan as described in paragraph (1) of this
14subsection (e). If the Commission finds, after notice and
15hearing, that the participating utility's progress in
16implementing the AMI Plan is materially deficient for the given
17Plan year, then the Commission shall issue an order requiring
18the participating utility to devise a corrective action plan,
19subject to Commission approval and oversight, to bring
20implementation back on schedule consistent with the AMI Plan.
21The Commission's order must be entered within 90 days after the
22utility files its annual report. If the Commission does not
23initiate an investigation within 21 days after the utility
24files its annual report, then the filing shall be deemed
25accepted by the Commission. The utility shall not be required
26to suspend implementation of its AMI Plan during any Commission

 

 

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1investigation.
2    The participating utility's annual report regarding AMI
3Plan year 10 shall contain a statement verifying that the
4implementation of its AMI Plan is complete, provided, however,
5that if the utility is subject to a corrective action plan that
6extends the implementation period beyond 10 years, the utility
7shall include the verification statement in its final annual
8report. Following the date of a Commission order approving the
9final annual report or the date on which the final report is
10deemed accepted by the Commission, the utility's annual
11reporting obligations under this subsection (d) shall
12terminate, provided, however, that the utility shall have a
13continuing obligation to provide information, upon request, to
14the Commission and Smart Grid Advisory Council regarding the
15AMI Plan.
16    (f) Each participating utility shall pay $2,500,000 per
17year to the trust or foundation established pursuant to Section
1816-108.7 of this Act for each plan year of the AMI Plan, which
19shall be used for purposes of providing customer education
20regarding smart meters and related consumer-facing
21technologies and services and which shall be a recoverable
22expense.
23    (g) Within 60 days after the Commission approves a
24participating utility's AMI Plan pursuant to subsection (c) of
25this Section, the participating utility, after consultation
26with the Smart Grid Advisory Council, shall file a proposed

 

 

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1tariff with the Commission that offers an opt-in market-based
2peak time rebate program that is designed to provide rebates to
3those residential retail customers that curtail their use of
4electricity during specific periods that are identified as peak
5usage periods. The total amount of rebates shall be the amount
6of compensation the utility obtains through markets or programs
7at the applicable regional transmission organization. The
8utility shall make all reasonable attempts to secure funding
9for the peak time rebate program through markets or programs at
10the applicable regional transmission organization. The rules
11and procedures for consumers to opt-in to the peak time rebate
12program shall include electronic sign-up and be designed to
13maximize participation. The Commission shall monitor the
14performance of programs established pursuant to this
15subsection (g) and shall order the termination or modification
16of a program if it determines that the program is not, after a
17reasonable period of time for development of at least 4 years,
18resulting in net benefits to the residential customers of the
19participating utility.
20    (h) If Section 16-108.5 of this Act becomes inoperative
21with respect to one or more participating utilities as set
22forth in subsection (g) or (h) of that Section, then Sections
231-56A and 1-76 of the Illinois Power Agency Act and Sections
248-103A, 16-108.5, 16-108.6, 16-108.7, 16-108.8, and 16-111.5B
25of this Act shall become inoperative as to each affected
26utility and its service area on the same date as Section

 

 

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116-108.5 becomes inoperative.
 
2    (220 ILCS 5/16-108.7 new)
3    Sec. 16-108.7. Illinois Science and Energy Innovation
4Trust.
5    (a) Within 90 days of the effective date of this amendatory
6Act of the 97th General Assembly, the members of the Smart Grid
7Advisory Council established pursuant to Section 16-108.6 of
8this Act, or a majority of the members thereof, shall cause to
9be established an Illinois science and energy innovation trust
10or foundation for the purposes of providing financial and
11technical support and assistance to entities, public or
12private, within the State of Illinois including, but not
13limited to, units of State and local government, educational
14and research institutions, corporations, and charitable,
15educational, environmental and community organizations, for
16programs and projects that support, encourage or utilize
17innovative technologies or other methods of modernizing the
18State's electric grid that will benefit the public by promoting
19economic development in Illinois. Such activities shall be
20supported through grants, loans, contracts, or other programs
21designed to assist and further benefit technological advances
22in the area of electric grid modernization and operation. The
23trust or foundation shall also be eligible for receipt of other
24energy and environmental grant opportunities, from public or
25private sources.

 

 

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1    (b) Funds received by the trust or foundation pursuant to
2subsection (f) of Section 16-108.6 of this Act shall be used
3solely for the purpose of providing consumer education
4regarding smart meters and related consumer-facing
5technologies and services.
6    (c) Such trust or foundation shall be governed by a
7declaration of trust or articles of incorporation and bylaws
8which shall, at a minimum, provide the following:
9        (1) There shall initially be 7 trustees of the trust or
10    foundation, which shall consist of the members of the Smart
11    Grid Advisory Council established pursuant to Section
12    16-108.6 of this Act. Subsequently, the participating
13    utilities shall appoint one trustee and the Clean Energy
14    Trust shall appoint one non-voting trustee who shall
15    provide expertise regarding early stage investment in
16    Smart Grid projects.
17        (2) All trustees shall be entitled to reimbursement for
18    reasonable expenses incurred on behalf of the trust in the
19    performance of their duties as trustees. All such
20    compensation and reimbursements shall be paid out of the
21    trust.
22        (3) Trustees shall be appointed within 60 days after
23    the creation of the trust or foundation and shall serve for
24    a term of 5 years commencing upon the date of their
25    respective appointments, until their respective successors
26    are appointed and qualified.

 

 

09700SB1652ham001- 80 -LRB097 09323 ASK 56228 a

1        (4) A vacancy in the office of trustee shall be filled
2    by the person holding the office responsible for appointing
3    the trustee whose death or resignation creates the vacancy,
4    and a trustee appointed to fill a vacancy shall serve the
5    remainder of the term of the trustee whose resignation or
6    death created the vacancy.
7        (5) The trust or foundation shall have an indefinite
8    term and shall terminate at such time as no trust assets
9    remain.
10        (6) The allocation and disbursement of funds for the
11    various purposes for which the trust or foundation is
12    established shall be determined by the trustees in
13    accordance with the declaration of trust or the articles of
14    incorporation and bylaws.
15        (7) The trust or foundation shall be authorized to
16    employ an executive director and other employees, or
17    contract management of the trust or foundation in its
18    entirety to an outside organization found suitable by the
19    trustees, to enter into leases, contracts and other
20    obligations on behalf of the trust or foundation, and to
21    incur expenses that the trustees deem necessary or
22    appropriate for the fulfillment of the purposes for which
23    the trust or foundation is established, provided, however,
24    that salaries and administrative expenses incurred on
25    behalf of the trust or foundation shall not exceed 3% of
26    the trust's principal value, or $750,000, whichever is

 

 

09700SB1652ham001- 81 -LRB097 09323 ASK 56228 a

1    greater, in any given year.
2        (8) The trustees may create and appoint advisory boards
3    or committees to assist them with the administration of the
4    trust or foundation, and to advise and make recommendations
5    to them regarding the contribution and disbursement of the
6    trust or foundation funds.
7        (9) All funds dispersed by the trust or foundation for
8    programs and projects to meet the objectives of the trust
9    or foundation as enumerated in this Section shall be
10    subject to a peer-review process as determined by the
11    trustees. This process shall be designed to determine, in
12    an objective and unbiased manner, those programs and
13    projects that best fit the objectives of the trust or
14    foundation. In each fiscal year the trustees shall
15    determine, based solely on the information provided
16    through the peer-review process, a budget for programs and
17    projects for that fiscal year.
18        (10) The trustees shall administer a Smart Grid
19    education fund from which it shall make grants to qualified
20    not-for-profit organizations for the purpose of educating
21    customers with regard to smart meters and related
22    consumer-facing technologies and services. In making such
23    grants the trust or foundation shall strongly encourage
24    grantees to coordinate to the extent practicable and
25    consider recommendations from the participating utilities
26    regarding the development and implementation of customer

 

 

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1    education plans.
2        (11) One of the objectives of the trust or foundation
3    is to remain self-funding. In order to meet this objective,
4    the trustees may sign agreements with those entities
5    receiving funding that provide for license fees,
6    royalties, or other payments to the trust or foundation
7    from such entities that receive support for their product
8    development from the trust or foundation. Such payments,
9    however, shall be contingent on the commercialization of
10    such products, services, or technologies enabled by the
11    funding provided by the trust or foundation.
12    (d) The trustees shall notify each participating utility as
13defined in Section 16-108.5 of this Act of the formation of the
14trust or foundation. Within 90 days after receipt of the
15notification, each participating utility that is not a
16combination utility as defined in Section 16-108.5 of this Act
17shall contribute $15,000,000 to the trust or foundation, and
18each participating utility that is a combination utility, as
19defined in Section 16-108.5 of this Act, shall contribute
20$7,500,000 to the trust or foundation established pursuant to
21this Section.
22    (e) If Section 16-108.5 of this Act becomes inoperative
23with respect to one or more participating utilities as set
24forth in subsection (g) or (h) of that Section, then Sections
251-56A and 1-76 of the Illinois Power Agency Act and Sections
268-103A, 16-108.5, 16-108.6, 16-108.7, 16-108.8, and 16-111.5B

 

 

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1of this Act shall become inoperative as to each affected
2utility and its service area on the same date as Section
316-108.5 becomes inoperative.
 
4    (220 ILCS 5/16-108.8 new)
5    Sec. 16-108.8. Illinois Smart Grid test bed.
6    (a) Within 180 days after the effective date of this
7amendatory Act of the 97th General Assembly, each participating
8utility, as defined by Section 16-108.5 of this Act, shall
9create or otherwise designate a Smart Grid test bed, which may
10be located at one or more places within the utility's system,
11for the purposes of allowing for the testing of Smart Grid
12technologies. The objectives of this test bed shall be to:
13        (1) provide an open, unbiased opportunity for testing
14    programs, technologies, business models, and other Smart
15    Grid-related activities;
16        (2) provide on-grid locations for the testing of
17    potentially innovative Smart Grid-related technologies and
18    services, including but not limited to those funded by the
19    trust or foundation established pursuant to Section
20    16-108.7 of this Act;
21        (3) facilitate testing of business models or services
22    that help integrate Smart Grid-related technologies into
23    the electric grid, especially those business models that
24    may help promote new products and services for retail
25    customers;

 

 

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1        (4) offer opportunities to test and showcase Smart Grid
2    technologies and services, especially those likely to
3    support the economic development goals of the State of
4    Illinois.
5    (b) The test bed shall reside in one or more locations on
6the participating utility's network. Such locations shall be
7chosen by the utility to maximize the opportunity for real-time
8and real-world testing of Smart Grid technologies and services
9taking into account the safety and security of the
10participating utility's grid and grid operations.
11    (c) The participating utility, with input from the Smart
12Grid Advisory Council established pursuant to Section 16-108.6
13of this Act, shall, as part of its filing under subsection (b)
14of Section 16-108.5, include a plan for the creation,
15operation, and administration of the test bed. This plan shall
16address the following:
17        (1) how the utility proposes to comply with each of the
18    objectives set forth in subsection (a) of this Section;
19        (2) the proposed location or locations of the test bed;
20        (3) the process by which the utility will receive,
21    review, and qualify proposals to use the test bed;
22        (4) the criteria by which the utility proposes to
23    qualify proposals to use the test bed, including, but not
24    limited to safety, reliability, security, customer data
25    security, privacy, and economic development
26    considerations;

 

 

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1        (5) the engineering and operations support that the
2    utility will provide to test bed users, including provision
3    of customer data; and
4        (6) the estimated costs to establish, administer and
5    promote the availability of the test bed.
6    (d) The test bed should be open to all qualified entities
7wishing to test programs, technologies, business models, and
8other Smart Grid-related activities, provided that the utility
9retains control of its grid and operations and may reject any
10programs, technologies, business models, and other Smart
11Grid-related activities that threaten the reliability, safety,
12security, or operations of its network, or that would threaten
13the security of customer-identifiable data in the judgment of
14the utility. The number of technologies and entities
15participating in the test bed at any time may be limited by the
16utility based on its determination of its ability to maintain a
17secure, safe, and reliable grid.
18    (e) At a minimum, the test bed shall have the ability to
19receive live signals from PJM Interconnection LLC or other
20applicable regional transmission organization, the ability to
21test new applications in a utility scale environment (to
22include ramp rate regulations for distributed wind and solar
23resources), critical peak price response, and market based
24power dispatch.
25    (f) At the end of the fourth year of operation the test bed
26shall be subject to an independent evaluation to determine if

 

 

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1the test bed is meeting the objectives of this Section or is
2likely to meet the objectives in the future. The evaluation
3shall include the performance of the utility as test bed
4operator. Subject to the findings, the utility and the trust or
5foundation established pursuant to Section 16-108.7 of this Act
6may choose to continue operating the test bed.
7    (g) The utility shall be entitled to recover all prudently
8incurred and reasonable costs associated with evaluation of
9proposals, engineering, construction, operation, and
10administration of the test bed through the performance-based
11formula rate tariff established pursuant to Section 16-108.5 of
12this Act.
13    (h) The utility is authorized to charge fees to users of
14the test bed that shall recover the costs associated with the
15incremental costs to the utility associated with
16administration of the test bed, provided, however, that any
17such fees collected by the utility shall be used to offset the
18costs to be recovered pursuant to subsection (g) of this
19Section.
20    (i) On a quarterly basis, the utility shall provide the
21trust or foundation established pursuant to Section 16-108.7 of
22this Act with a report summarizing test bed activities,
23customers, discoveries, and other information as shall be
24mutually deemed relevant.
25    (j) To the extent practicable, the utility and trust or
26foundation established pursuant to Section 16-108.7 of this Act

 

 

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1shall jointly pursue resources that enhance the capabilities
2and capacity of the test bed.
3    (k) If Section 16-108.5 of this Act becomes inoperative
4with respect to one or more participating utilities as set
5forth in subsection (g) or (h) of that Section, then Sections
61-56A and 1-76 of the Illinois Power Agency Act and Sections
78-103A, 16-108.5, 16-108.6, 16-108.7, 16-108.8, and 16-111.5B
8of this Act shall become inoperative as to each affected
9utility and its service area on the same date as Section
1016-108.5 become inoperative.
 
11    (220 ILCS 5/16-111.5)
12    Sec. 16-111.5. Provisions relating to procurement.
13    (a) An electric utility that on December 31, 2005 served at
14least 100,000 customers in Illinois shall procure power and
15energy for its eligible retail customers in accordance with the
16applicable provisions set forth in Section 1-75 of the Illinois
17Power Agency Act and this Section. "Eligible retail customers"
18for the purposes of this Section means those retail customers
19that purchase power and energy from the electric utility under
20fixed-price bundled service tariffs, other than those retail
21customers whose service is declared or deemed competitive under
22Section 16-113 and those other customer groups specified in
23this Section, including self-generating customers, customers
24electing hourly pricing, or those customers who are otherwise
25ineligible for fixed-price bundled tariff service. Those

 

 

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1customers that are excluded from the definition of "eligible
2retail customers" shall not be included in the procurement plan
3load requirements, and the utility shall procure any supply
4requirements, including capacity, ancillary services, and
5hourly priced energy, in the applicable markets as needed to
6serve those customers, provided that the utility may include in
7its procurement plan load requirements for the load that is
8associated with those retail customers whose service has been
9declared or deemed competitive pursuant to Section 16-113 of
10this Act to the extent that those customers are purchasing
11power and energy during one of the transition periods
12identified in subsection (b) of Section 16-113 of this Act.
13    (b) A procurement plan shall be prepared for each electric
14utility consistent with the applicable requirements of the
15Illinois Power Agency Act and this Section. For purposes of
16this Section, Illinois electric utilities that are affiliated
17by virtue of a common parent company are considered to be a
18single electric utility. Each procurement plan shall analyze
19the projected balance of supply and demand for eligible retail
20customers over a 5-year period with the first planning year
21beginning on June 1 of the year following the year in which the
22plan is filed. The plan shall specifically identify the
23wholesale products to be procured following plan approval, and
24shall follow all the requirements set forth in the Public
25Utilities Act and all applicable State and federal laws,
26statutes, rules, or regulations, as well as Commission orders.

 

 

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1Nothing in this Section precludes consideration of contracts
2longer than 5 years and related forecast data. Unless specified
3otherwise in this Section, in the procurement plan or in the
4implementing tariff, any procurement occurring in accordance
5with this plan shall be competitively bid through a request for
6proposals process. Approval and implementation of the
7procurement plan shall be subject to review and approval by the
8Commission according to the provisions set forth in this
9Section. A procurement plan shall include each of the following
10components:
11        (1) Hourly load analysis. This analysis shall include:
12            (i) multi-year historical analysis of hourly
13        loads;
14            (ii) switching trends and competitive retail
15        market analysis;
16            (iii) known or projected changes to future loads;
17        and
18            (iv) growth forecasts by customer class.
19        (2) Analysis of the impact of any demand side and
20    renewable energy initiatives. This analysis shall include:
21            (i) the impact of demand response programs, both
22        current and projected;
23            (ii) supply side needs that are projected to be
24        offset by purchases of renewable energy resources, if
25        any; and
26            (iii) the impact of energy efficiency programs,

 

 

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1        both current and projected.
2        (3) A plan for meeting the expected load requirements
3    that will not be met through preexisting contracts. This
4    plan shall include:
5            (i) definitions of the different retail customer
6        classes for which supply is being purchased;
7            (ii) the proposed mix of demand-response products
8        for which contracts will be executed during the next
9        year. The cost-effective demand-response measures
10        shall be procured whenever the cost is lower than
11        procuring comparable capacity products, provided that
12        such products shall:
13                (A) be procured by a demand-response provider
14            from eligible retail customers;
15                (B) at least satisfy the demand-response
16            requirements of the regional transmission
17            organization market in which the utility's service
18            territory is located, including, but not limited
19            to, any applicable capacity or dispatch
20            requirements;
21                (C) provide for customers' participation in
22            the stream of benefits produced by the
23            demand-response products;
24                (D) provide for reimbursement by the
25            demand-response provider of the utility for any
26            costs incurred as a result of the failure of the

 

 

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1            supplier of such products to perform its
2            obligations thereunder; and
3                (E) meet the same credit requirements as apply
4            to suppliers of capacity, in the applicable
5            regional transmission organization market;
6            (iii) monthly forecasted system supply
7        requirements, including expected minimum, maximum, and
8        average values for the planning period;
9            (iv) the proposed mix and selection of standard
10        wholesale products for which contracts will be
11        executed during the next year, separately or in
12        combination, to meet that portion of its load
13        requirements not met through pre-existing contracts,
14        including but not limited to monthly 5 x 16 peak period
15        block energy, monthly off-peak wrap energy, monthly 7 x
16        24 energy, annual 5 x 16 energy, annual off-peak wrap
17        energy, annual 7 x 24 energy, monthly capacity, annual
18        capacity, peak load capacity obligations, capacity
19        purchase plan, and ancillary services;
20            (v) proposed term structures for each wholesale
21        product type included in the proposed procurement plan
22        portfolio of products; and
23            (vi) an assessment of the price risk, load
24        uncertainty, and other factors that are associated
25        with the proposed procurement plan; this assessment,
26        to the extent possible, shall include an analysis of

 

 

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1        the following factors: contract terms, time frames for
2        securing products or services, fuel costs, weather
3        patterns, transmission costs, market conditions, and
4        the governmental regulatory environment; the proposed
5        procurement plan shall also identify alternatives for
6        those portfolio measures that are identified as having
7        significant price risk.
8        (4) Proposed procedures for balancing loads. The
9    procurement plan shall include, for load requirements
10    included in the procurement plan, the process for (i)
11    hourly balancing of supply and demand and (ii) the criteria
12    for portfolio re-balancing in the event of significant
13    shifts in load.
14    (c) The procurement process set forth in Section 1-75 of
15the Illinois Power Agency Act and subsection (e) of this
16Section shall be administered by a procurement administrator
17and monitored by a procurement monitor.
18        (1) The procurement administrator shall:
19            (i) design the final procurement process in
20        accordance with Section 1-75 of the Illinois Power
21        Agency Act and subsection (e) of this Section following
22        Commission approval of the procurement plan;
23            (ii) develop benchmarks in accordance with
24        subsection (e)(3) to be used to evaluate bids; these
25        benchmarks shall be submitted to the Commission for
26        review and approval on a confidential basis prior to

 

 

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1        the procurement event;
2            (iii) serve as the interface between the electric
3        utility and suppliers;
4            (iv) manage the bidder pre-qualification and
5        registration process;
6            (v) obtain the electric utilities' agreement to
7        the final form of all supply contracts and credit
8        collateral agreements;
9            (vi) administer the request for proposals process;
10            (vii) have the discretion to negotiate to
11        determine whether bidders are willing to lower the
12        price of bids that meet the benchmarks approved by the
13        Commission; any post-bid negotiations with bidders
14        shall be limited to price only and shall be completed
15        within 24 hours after opening the sealed bids and shall
16        be conducted in a fair and unbiased manner; in
17        conducting the negotiations, there shall be no
18        disclosure of any information derived from proposals
19        submitted by competing bidders; if information is
20        disclosed to any bidder, it shall be provided to all
21        competing bidders;
22            (viii) maintain confidentiality of supplier and
23        bidding information in a manner consistent with all
24        applicable laws, rules, regulations, and tariffs;
25            (ix) submit a confidential report to the
26        Commission recommending acceptance or rejection of

 

 

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1        bids;
2            (x) notify the utility of contract counterparties
3        and contract specifics; and
4            (xi) administer related contingency procurement
5        events.
6        (2) The procurement monitor, who shall be retained by
7    the Commission, shall:
8            (i) monitor interactions among the procurement
9        administrator, suppliers, and utility;
10            (ii) monitor and report to the Commission on the
11        progress of the procurement process;
12            (iii) provide an independent confidential report
13        to the Commission regarding the results of the
14        procurement event;
15            (iv) assess compliance with the procurement plans
16        approved by the Commission for each utility that on
17        December 31, 2005 provided electric service to a least
18        100,000 customers in Illinois;
19            (v) preserve the confidentiality of supplier and
20        bidding information in a manner consistent with all
21        applicable laws, rules, regulations, and tariffs;
22            (vi) provide expert advice to the Commission and
23        consult with the procurement administrator regarding
24        issues related to procurement process design, rules,
25        protocols, and policy-related matters; and
26            (vii) consult with the procurement administrator

 

 

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1        regarding the development and use of benchmark
2        criteria, standard form contracts, credit policies,
3        and bid documents.
4    (d) Except as provided in subsection (j), the planning
5process shall be conducted as follows:
6        (1) Beginning in 2008, each Illinois utility procuring
7    power pursuant to this Section shall annually provide a
8    range of load forecasts to the Illinois Power Agency by
9    July 15 of each year, or such other date as may be required
10    by the Commission or Agency. The load forecasts shall cover
11    the 5-year procurement planning period for the next
12    procurement plan and shall include hourly data
13    representing a high-load, low-load and expected-load
14    scenario for the load of the eligible retail customers. The
15    utility shall provide supporting data and assumptions for
16    each of the scenarios.
17        (2) Beginning in 2008, the Illinois Power Agency shall
18    prepare a procurement plan by August 15th of each year, or
19    such other date as may be required by the Commission. The
20    procurement plan shall identify the portfolio of
21    demand-response and power and energy products to be
22    procured. Cost-effective demand-response measures shall be
23    procured as set forth in item (iii) of subsection (b) of
24    this Section. Copies of the procurement plan shall be
25    posted and made publicly available on the Agency's and
26    Commission's websites, and copies shall also be provided to

 

 

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1    each affected electric utility. An affected utility shall
2    have 30 days following the date of posting to provide
3    comment to the Agency on the procurement plan. Other
4    interested entities also may comment on the procurement
5    plan. All comments submitted to the Agency shall be
6    specific, supported by data or other detailed analyses,
7    and, if objecting to all or a portion of the procurement
8    plan, accompanied by specific alternative wording or
9    proposals. All comments shall be posted on the Agency's and
10    Commission's websites. During this 30-day comment period,
11    the Agency shall hold at least one public hearing within
12    each utility's service area for the purpose of receiving
13    public comment on the procurement plan. Within 14 days
14    following the end of the 30-day review period, the Agency
15    shall revise the procurement plan as necessary based on the
16    comments received and file the procurement plan with the
17    Commission and post the procurement plan on the websites.
18        (3) Within 5 days after the filing of the procurement
19    plan, any person objecting to the procurement plan shall
20    file an objection with the Commission. Within 10 days after
21    the filing, the Commission shall determine whether a
22    hearing is necessary. The Commission shall enter its order
23    confirming or modifying the procurement plan within 90 days
24    after the filing of the procurement plan by the Illinois
25    Power Agency.
26        (4) The Commission shall approve the procurement plan,

 

 

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1    including expressly the forecast used in the procurement
2    plan, if the Commission determines that it will ensure
3    adequate, reliable, affordable, efficient, and
4    environmentally sustainable electric service at the lowest
5    total cost over time, taking into account any benefits of
6    price stability.
7    (e) The procurement process shall include each of the
8following components:
9        (1) Solicitation, pre-qualification, and registration
10    of bidders. The procurement administrator shall
11    disseminate information to potential bidders to promote a
12    procurement event, notify potential bidders that the
13    procurement administrator may enter into a post-bid price
14    negotiation with bidders that meet the applicable
15    benchmarks, provide supply requirements, and otherwise
16    explain the competitive procurement process. In addition
17    to such other publication as the procurement administrator
18    determines is appropriate, this information shall be
19    posted on the Illinois Power Agency's and the Commission's
20    websites. The procurement administrator shall also
21    administer the prequalification process, including
22    evaluation of credit worthiness, compliance with
23    procurement rules, and agreement to the standard form
24    contract developed pursuant to paragraph (2) of this
25    subsection (e). The procurement administrator shall then
26    identify and register bidders to participate in the

 

 

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1    procurement event.
2        (2) Standard contract forms and credit terms and
3    instruments. The procurement administrator, in
4    consultation with the utilities, the Commission, and other
5    interested parties and subject to Commission oversight,
6    shall develop and provide standard contract forms for the
7    supplier contracts that meet generally accepted industry
8    practices. Standard credit terms and instruments that meet
9    generally accepted industry practices shall be similarly
10    developed. The procurement administrator shall make
11    available to the Commission all written comments it
12    receives on the contract forms, credit terms, or
13    instruments. If the procurement administrator cannot reach
14    agreement with the applicable electric utility as to the
15    contract terms and conditions, the procurement
16    administrator must notify the Commission of any disputed
17    terms and the Commission shall resolve the dispute. The
18    terms of the contracts shall not be subject to negotiation
19    by winning bidders, and the bidders must agree to the terms
20    of the contract in advance so that winning bids are
21    selected solely on the basis of price.
22        (3) Establishment of a market-based price benchmark.
23    As part of the development of the procurement process, the
24    procurement administrator, in consultation with the
25    Commission staff, Agency staff, and the procurement
26    monitor, shall establish benchmarks for evaluating the

 

 

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1    final prices in the contracts for each of the products that
2    will be procured through the procurement process. The
3    benchmarks shall be based on price data for similar
4    products for the same delivery period and same delivery
5    hub, or other delivery hubs after adjusting for that
6    difference. The price benchmarks may also be adjusted to
7    take into account differences between the information
8    reflected in the underlying data sources and the specific
9    products and procurement process being used to procure
10    power for the Illinois utilities. The benchmarks shall be
11    confidential but shall be provided to, and will be subject
12    to Commission review and approval, prior to a procurement
13    event.
14        (4) Request for proposals competitive procurement
15    process. The procurement administrator shall design and
16    issue a request for proposals to supply electricity in
17    accordance with each utility's procurement plan, as
18    approved by the Commission. The request for proposals shall
19    set forth a procedure for sealed, binding commitment
20    bidding with pay-as-bid settlement, and provision for
21    selection of bids on the basis of price.
22        (5) A plan for implementing contingencies in the event
23    of supplier default or failure of the procurement process
24    to fully meet the expected load requirement due to
25    insufficient supplier participation, Commission rejection
26    of results, or any other cause.

 

 

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1            (i) Event of supplier default: In the event of
2        supplier default, the utility shall review the
3        contract of the defaulting supplier to determine if the
4        amount of supply is 200 megawatts or greater, and if
5        there are more than 60 days remaining of the contract
6        term. If both of these conditions are met, and the
7        default results in termination of the contract, the
8        utility shall immediately notify the Illinois Power
9        Agency that a request for proposals must be issued to
10        procure replacement power, and the procurement
11        administrator shall run an additional procurement
12        event. If the contracted supply of the defaulting
13        supplier is less than 200 megawatts or there are less
14        than 60 days remaining of the contract term, the
15        utility shall procure power and energy from the
16        applicable regional transmission organization market,
17        including ancillary services, capacity, and day-ahead
18        or real time energy, or both, for the duration of the
19        contract term to replace the contracted supply;
20        provided, however, that if a needed product is not
21        available through the regional transmission
22        organization market it shall be purchased from the
23        wholesale market.
24            (ii) Failure of the procurement process to fully
25        meet the expected load requirement: If the procurement
26        process fails to fully meet the expected load

 

 

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1        requirement due to insufficient supplier participation
2        or due to a Commission rejection of the procurement
3        results, the procurement administrator, the
4        procurement monitor, and the Commission staff shall
5        meet within 10 days to analyze potential causes of low
6        supplier interest or causes for the Commission
7        decision. If changes are identified that would likely
8        result in increased supplier participation, or that
9        would address concerns causing the Commission to
10        reject the results of the prior procurement event, the
11        procurement administrator may implement those changes
12        and rerun the request for proposals process according
13        to a schedule determined by those parties and
14        consistent with Section 1-75 of the Illinois Power
15        Agency Act and this subsection. In any event, a new
16        request for proposals process shall be implemented by
17        the procurement administrator within 90 days after the
18        determination that the procurement process has failed
19        to fully meet the expected load requirement.
20            (iii) In all cases where there is insufficient
21        supply provided under contracts awarded through the
22        procurement process to fully meet the electric
23        utility's load requirement, the utility shall meet the
24        load requirement by procuring power and energy from the
25        applicable regional transmission organization market,
26        including ancillary services, capacity, and day-ahead

 

 

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1        or real time energy or both; provided, however, that if
2        a needed product is not available through the regional
3        transmission organization market it shall be purchased
4        from the wholesale market.
5        (6) The procurement process described in this
6    subsection is exempt from the requirements of the Illinois
7    Procurement Code, pursuant to Section 20-10 of that Code.
8    (f) Within 2 business days after opening the sealed bids,
9the procurement administrator shall submit a confidential
10report to the Commission. The report shall contain the results
11of the bidding for each of the products along with the
12procurement administrator's recommendation for the acceptance
13and rejection of bids based on the price benchmark criteria and
14other factors observed in the process. The procurement monitor
15also shall submit a confidential report to the Commission
16within 2 business days after opening the sealed bids. The
17report shall contain the procurement monitor's assessment of
18bidder behavior in the process as well as an assessment of the
19procurement administrator's compliance with the procurement
20process and rules. The Commission shall review the confidential
21reports submitted by the procurement administrator and
22procurement monitor, and shall accept or reject the
23recommendations of the procurement administrator within 2
24business days after receipt of the reports.
25    (g) Within 3 business days after the Commission decision
26approving the results of a procurement event, the utility shall

 

 

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1enter into binding contractual arrangements with the winning
2suppliers using the standard form contracts; except that the
3utility shall not be required either directly or indirectly to
4execute the contracts if a tariff that is consistent with
5subsection (l) of this Section has not been approved and placed
6into effect for that utility.
7    (h) The names of the successful bidders and the load
8weighted average of the winning bid prices for each contract
9type and for each contract term shall be made available to the
10public at the time of Commission approval of a procurement
11event. The Commission, the procurement monitor, the
12procurement administrator, the Illinois Power Agency, and all
13participants in the procurement process shall maintain the
14confidentiality of all other supplier and bidding information
15in a manner consistent with all applicable laws, rules,
16regulations, and tariffs. Confidential information, including
17the confidential reports submitted by the procurement
18administrator and procurement monitor pursuant to subsection
19(f) of this Section, shall not be made publicly available and
20shall not be discoverable by any party in any proceeding,
21absent a compelling demonstration of need, nor shall those
22reports be admissible in any proceeding other than one for law
23enforcement purposes.
24    (i) Within 2 business days after a Commission decision
25approving the results of a procurement event or such other date
26as may be required by the Commission from time to time, the

 

 

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1utility shall file for informational purposes with the
2Commission its actual or estimated retail supply charges, as
3applicable, by customer supply group reflecting the costs
4associated with the procurement and computed in accordance with
5the tariffs filed pursuant to subsection (l) of this Section
6and approved by the Commission.
7    (j) Within 60 days following the effective date of this
8amendatory Act, each electric utility that on December 31, 2005
9provided electric service to at least 100,000 customers in
10Illinois shall prepare and file with the Commission an initial
11procurement plan, which shall conform in all material respects
12to the requirements of the procurement plan set forth in
13subsection (b); provided, however, that the Illinois Power
14Agency Act shall not apply to the initial procurement plan
15prepared pursuant to this subsection. The initial procurement
16plan shall identify the portfolio of power and energy products
17to be procured and delivered for the period June 2008 through
18May 2009, and shall identify the proposed procurement
19administrator, who shall have the same experience and expertise
20as is required of a procurement administrator hired pursuant to
21Section 1-75 of the Illinois Power Agency Act. Copies of the
22procurement plan shall be posted and made publicly available on
23the Commission's website. The initial procurement plan may
24include contracts for renewable resources that extend beyond
25May 2009.
26        (i) Within 14 days following filing of the initial

 

 

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1    procurement plan, any person may file a detailed objection
2    with the Commission contesting the procurement plan
3    submitted by the electric utility. All objections to the
4    electric utility's plan shall be specific, supported by
5    data or other detailed analyses. The electric utility may
6    file a response to any objections to its procurement plan
7    within 7 days after the date objections are due to be
8    filed. Within 7 days after the date the utility's response
9    is due, the Commission shall determine whether a hearing is
10    necessary. If it determines that a hearing is necessary, it
11    shall require the hearing to be completed and issue an
12    order on the procurement plan within 60 days after the
13    filing of the procurement plan by the electric utility.
14        (ii) The order shall approve or modify the procurement
15    plan, approve an independent procurement administrator,
16    and approve or modify the electric utility's tariffs that
17    are proposed with the initial procurement plan. The
18    Commission shall approve the procurement plan if the
19    Commission determines that it will ensure adequate,
20    reliable, affordable, efficient, and environmentally
21    sustainable electric service at the lowest total cost over
22    time, taking into account any benefits of price stability.
23    (k) In order to promote price stability for residential and
24small commercial customers during the transition to
25competition in Illinois, and notwithstanding any other
26provision of this Act, each electric utility subject to this

 

 

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1Section shall enter into one or more multi-year financial swap
2contracts that become effective on the effective date of this
3amendatory Act. These contracts may be executed with generators
4and power marketers, including affiliated interests of the
5electric utility. These contracts shall be for a term of no
6more than 5 years and shall, for each respective utility or for
7any Illinois electric utilities that are affiliated by virtue
8of a common parent company and that are thereby considered a
9single electric utility for purposes of this subsection (k),
10not exceed in the aggregate 3,000 megawatts for any hour of the
11year. The contracts shall be financial contracts and not energy
12sales contracts. The contracts shall be executed as
13transactions under a negotiated master agreement based on the
14form of master agreement for financial swap contracts sponsored
15by the International Swaps and Derivatives Association, Inc.
16and shall be considered pre-existing contracts in the
17utilities' procurement plans for residential and small
18commercial customers. Costs incurred pursuant to a contract
19authorized by this subsection (k) shall be deemed prudently
20incurred and reasonable in amount and the electric utility
21shall be entitled to full cost recovery pursuant to the tariffs
22filed with the Commission.
23    (k-5) In order to promote price stability for residential
24and small commercial customers during the infrastructure
25investment program described in subsection (b) of Section
2616-108.5 of this Act, and notwithstanding any other provision

 

 

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1of this Act or the Illinois Power Agency Act, for each electric
2utility that serves more than one million retail customers in
3Illinois the Illinois Power Agency shall procure within 120
4days after the effective date of this amendatory Act of the
597th General Assembly contracts for energy and renewable energy
6credits for the period June 1, 2013 through December 31, 2017.
7These contracts shall be entered into as the result of a
8competitive procurement event, and, to the extent that any
9provisions of this Section or the Illinois Power Agency Act do
10not conflict with this subsection (k-5), such provisions shall
11apply to the procurement event. The energy contracts shall be
12for 24 hour by 7 day supply over a term that runs from the first
13delivery year through December 31, 2017. For a utility that
14serves over 2 million customers, the energy contracts shall be
15multi-year with pricing escalating at 2.5% per annum. The
16energy contracts may be constructed as financial swaps or
17required physical delivery.
18    Within 30 days of the effective date of this amendatory Act
19of the 97th General Assembly, each such utility shall submit to
20the Agency updated load forecasts for the period June 1, 2013
21through May 31, 2017. The megawatt volume of the contracts or
22physical delivery of energy included in the updated load
23forecasts shall be based on the minimum monthly peak and
24off-peak average load requirements shown in the forecasts,
25taking into account any existing energy contracts in effect as
26well as the expected migration of the utility's customers to

 

 

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1alternative retail electric suppliers. The renewable energy
2credit volume shall be based on the number of credits that
3would satisfy the requirements of subsection (c) of Section
41-75 of the Illinois Power Agency Act, subject to the rate
5impact caps and other provisions of subsection (c) of Section
61-75 of the Illinois Power Agency Act. The evaluation of
7contract bids in the competitive procurement event shall
8incorporate price benchmarks set collaboratively by the
9Agency, the procurement administrator, the staff of the
10Commission, and the procurement monitor. If the contracts are
11swap contracts, then they shall be executed as transactions
12under a negotiated master agreement based on the form of master
13agreement for financial swap contracts sponsored by the
14International Swaps and Derivatives Association, Inc. Costs
15incurred pursuant to a contract authorized by this subsection
16(k-5) shall be deemed prudently incurred and reasonable in
17amount and the electric utility shall be entitled to full cost
18recovery pursuant to the tariffs filed with the Commission
19    (l) An electric utility shall recover its costs incurred
20under this Section, including, but not limited to, the costs of
21procuring power and energy demand-response resources under
22this Section. The utility shall file with the initial
23procurement plan its proposed tariffs through which its costs
24of procuring power that are incurred pursuant to a
25Commission-approved procurement plan and those other costs
26identified in this subsection (l), will be recovered. The

 

 

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1tariffs shall include a formula rate or charge designed to pass
2through both the costs incurred by the utility in procuring a
3supply of electric power and energy for the applicable customer
4classes with no mark-up or return on the price paid by the
5utility for that supply, plus any just and reasonable costs
6that the utility incurs in arranging and providing for the
7supply of electric power and energy. The formula rate or charge
8shall also contain provisions that ensure that its application
9does not result in over or under recovery due to changes in
10customer usage and demand patterns, and that provide for the
11correction, on at least an annual basis, of any accounting
12errors that may occur. A utility shall recover through the
13tariff all reasonable costs incurred to implement or comply
14with any procurement plan that is developed and put into effect
15pursuant to Section 1-75 of the Illinois Power Agency Act and
16this Section, including any fees assessed by the Illinois Power
17Agency, costs associated with load balancing, and contingency
18plan costs. The electric utility shall also recover its full
19costs of procuring electric supply for which it contracted
20before the effective date of this Section in conjunction with
21the provision of full requirements service under fixed-price
22bundled service tariffs subsequent to December 31, 2006. All
23such costs shall be deemed to have been prudently incurred. The
24pass-through tariffs that are filed and approved pursuant to
25this Section shall not be subject to review under, or in any
26way limited by, Section 16-111(i) of this Act.

 

 

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1    (m) The Commission has the authority to adopt rules to
2carry out the provisions of this Section. For the public
3interest, safety, and welfare, the Commission also has
4authority to adopt rules to carry out the provisions of this
5Section on an emergency basis immediately following the
6effective date of this amendatory Act.
7    (n) Notwithstanding any other provision of this Act, any
8affiliated electric utilities that submit a single procurement
9plan covering their combined needs may procure for those
10combined needs in conjunction with that plan, and may enter
11jointly into power supply contracts, purchases, and other
12procurement arrangements, and allocate capacity and energy and
13cost responsibility therefor among themselves in proportion to
14their requirements.
15    (o) On or before June 1 of each year, the Commission shall
16hold an informal hearing for the purpose of receiving comments
17on the prior year's procurement process and any recommendations
18for change.
19    (p) An electric utility subject to this Section may propose
20to invest, lease, own, or operate an electric generation
21facility as part of its procurement plan, provided the utility
22demonstrates that such facility is the least-cost option to
23provide electric service to eligible retail customers. If the
24facility is shown to be the least-cost option and is included
25in a procurement plan prepared in accordance with Section 1-75
26of the Illinois Power Agency Act and this Section, then the

 

 

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1electric utility shall make a filing pursuant to Section 8-406
2of this the Act, and may request of the Commission any
3statutory relief required thereunder. If the Commission grants
4all of the necessary approvals for the proposed facility, such
5supply shall thereafter be considered as a pre-existing
6contract under subsection (b) of this Section. The Commission
7shall in any order approving a proposal under this subsection
8specify how the utility will recover the prudently incurred
9costs of investing in, leasing, owning, or operating such
10generation facility through just and reasonable rates charged
11to eligible retail customers. Cost recovery for facilities
12included in the utility's procurement plan pursuant to this
13subsection shall not be subject to review under or in any way
14limited by the provisions of Section 16-111(i) of this Act.
15Nothing in this Section is intended to prohibit a utility from
16filing for a fuel adjustment clause as is otherwise permitted
17under Section 9-220 of this Act.
18(Source: P.A. 95-481, eff. 8-28-07; 95-1027, eff. 6-1-09.)
 
19    (220 ILCS 5/16-111.5B new)
20    Sec. 16-111.5B. Provisions relating to energy efficiency
21procurement.
22    (a) Beginning in 2012, procurement plans prepared pursuant
23to Section 16-111.5 of this Act shall be subject to the
24following additional requirements:
25        (1) The analysis included pursuant to paragraph (2) of

 

 

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1    subsection (b) of Section 16-111.5 shall also include the
2    impact of energy efficiency building codes or appliance
3    standards, both current and projected.
4        (2) The procurement plan components described in
5    subsection (b) of Section 16-111.5 shall also include an
6    assessment of opportunities to expand the programs
7    promoting energy efficiency measures that have been
8    offered under plans approved pursuant to Section 8-103 of
9    this Act or to implement additional cost-effective energy
10    efficiency programs or measures.
11        (3) In addition to the information provided pursuant to
12    paragraph (1) of subsection (d) of Section 16-111.5 of this
13    Act, each Illinois utility procuring power pursuant to that
14    Section shall annually provide to the Illinois Power Agency
15    by July 15 of each year, or such other date as may be
16    required by the Commission or Agency, an assessment of
17    cost-effective energy efficiency programs or measures that
18    could be included in the procurement plan. The assessment
19    shall include the following:
20            (A) A comprehensive energy efficiency potential
21        study for the utility's service territory that was
22        completed within the past 3 years.
23            (B) Beginning in 2014, the most recent analysis
24        submitted pursuant to Section 8-103A of this Act and
25        approved by the Commission under subsection (f) of
26        Section 8-103 of this Act.

 

 

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1            (C) Identification of new or expanded
2        cost-effective energy efficiency programs or measures
3        that are incremental to those included in energy
4        efficiency and demand-response plans approved by the
5        Commission pursuant to Section 8-103 of this Act and
6        that would be offered to eligible retail customers.
7            (D) Analysis showing that the new or expanded
8        cost-effective energy efficiency programs or measures
9        would lead to a reduction in the overall cost of
10        electric service.
11            (E) Analysis of how the cost of procuring
12        additional cost-effective energy efficiency measures
13        compares over the life of the measures to the
14        prevailing cost of comparable supply.
15            (F) An energy savings goal, expressed in
16        megawatt-hours, for the year in which the measures will
17        be implemented.
18        In preparing such assessments, a utility shall conduct
19    an annual solicitation process for purposes of requesting
20    proposals from third party vendors, the results of which
21    shall be provided to the Agency as part of the assessment,
22    including documentation of all bids received. The utility
23    shall develop requests for proposals consistent with the
24    manner in which it develops requests for proposals under
25    plans approved pursuant to Section 8-103 of this Act, which
26    considers input from the Agency and interested

 

 

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1    stakeholders.
2        (4) The Illinois Power Agency shall include in the
3    procurement plan prepared pursuant to paragraph (2) of
4    subsection (d) of Section 16-111.5 of this Act energy
5    efficiency programs and measures it determines are
6    cost-effective and the associated annual energy savings
7    goal included in the annual solicitation process and
8    assessment submitted pursuant to paragraph (3) of this
9    subsection (a).
10        (5) Pursuant to paragraph (4) of subsection (d) of
11    Section 16-111.5 of this Act, the Commission shall also
12    approve the energy efficiency programs and measures
13    included in the procurement plan, including the annual
14    energy savings goal, if the Commission determines they
15    fully capture the potential for all achievable
16    cost-effective savings, to the extent practicable, and
17    otherwise satisfy the requirements of Section 8-103 of this
18    Act.
19        In the event the Commission approves the procurement of
20    additional energy efficiency, it shall reduce the amount of
21    power to be procured under the procurement plan to reflect
22    the additional energy efficiency and shall direct the
23    utility to undertake the procurement of such energy
24    efficiency, which shall not be subject to the requirements
25    of subsection (e) of Section 16-111.5 of this Act. The
26    utility shall consider input from the Agency and interested

 

 

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1    stakeholders on the procurement and administration
2    process.
3        (6) An electric utility shall recover its costs
4    incurred under this Section related to the implementation
5    of energy efficiency programs and measures approved by the
6    Commission in its order approving the procurement plan
7    under Section 16-111.5 of this Act, including, but not
8    limited to, all costs associated with complying with this
9    Section and all start-up and administrative costs and the
10    costs for any evaluation, measurement, and verification of
11    the measures, from eligible retail customers through the
12    automatic adjustment clause tariff established pursuant to
13    Section 8-103 of this Act, provided, however, that the
14    limitations described in subsection (d) of that Section
15    shall not apply to the costs incurred pursuant to this
16    Section or Section 16-111.7 of this Act.
17    (b) For purposes of this Section, the term "energy
18efficiency" shall have the meaning set forth in Section 1-10 of
19the Illinois Power Agency Act, and the term "cost-effective"
20shall have the meaning set forth in subsection (a) of Section
218-103 of this Act. In addition, the estimated costs to acquire
22an additional energy efficiency measure, when divided by the
23number of kilowatt-hours expected to be saved over the life of
24the measure, shall be less than or equal to the electricity
25costs that would be avoided as a result of the energy
26efficiency measure.

 

 

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1    (c) If Section 16-108.5 of this Act becomes inoperative
2with respect to one or more participating utilities as set
3forth in subsection (g) or (h) of that Section, then Sections
41-56A and 1-76 of the Illinois Power Agency Act and Sections
58-103A, 16-108.5, 16-108.6, 16-108.7, 16-108.8, and 16-111.5B
6of this Act shall become inoperative as to each affected
7utility and its service area on the same date as Section
816-108.5 becomes inoperative.
 
9    (220 ILCS 5/16-111.7)
10    Sec. 16-111.7. On-bill financing program; electric
11utilities.
12    (a) The Illinois General Assembly finds that Illinois homes
13and businesses have the potential to save energy through
14conservation and cost-effective energy efficiency measures.
15Programs created pursuant to this Section will allow utility
16customers to purchase cost-effective energy efficiency
17measures, including measures set forth in a
18Commission-approved energy efficiency and demand-response plan
19under Section 8-103 of this Act and that are cost-effective as
20that term is defined by that Section, with no required initial
21upfront payment, and to pay the cost of those products and
22services over time on their utility bill.
23    (b) Notwithstanding any other provision of this Act, an
24electric utility serving more than 100,000 customers on January
251, 2009 shall offer a Commission-approved on-bill financing

 

 

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1program ("program") that allows its eligible retail customers,
2as that term is defined in Section 16-111.5 of this Act, who
3own a residential single family home, duplex, or other
4residential building with 4 or less units, or condominium at
5which the electric service is being provided (i) to borrow
6funds from a third party lender in order to purchase electric
7energy efficiency measures approved under the program for
8installation in such home or condominium without any required
9upfront payment and (ii) to pay back such funds over time
10through the electric utility's bill. Based upon the process
11described in subsection (b-5) of this Section, small commercial
12retail customers, as that term is defined in Section 16-102 of
13this Act, who own the premises at which electric service is
14being provided may be included in such program. After receiving
15a request from an electric utility for approval of a proposed
16program and tariffs pursuant to this Section, the Commission
17shall render its decision within 120 days. If no decision is
18rendered within 120 days, then the request shall be deemed to
19be approved.
20    (b-5) Within 30 days after the effective date of this
21amendatory Act of the 96th General Assembly, the Commission
22shall convene a workshop process during which interested
23participants may discuss issues related to the program,
24including program design, eligible electric energy efficiency
25measures, vendor qualifications, and a methodology for
26ensuring ongoing compliance with such qualifications,

 

 

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1financing, sample documents such as request for proposals,
2contracts and agreements, dispute resolution, pre-installment
3and post-installment verification, and evaluation. The
4workshop process shall be completed within 150 days after the
5effective date of this amendatory Act of the 96th General
6Assembly.
7    (c) Not later than 60 days following completion of the
8workshop process described in subsection (b-5) of this Section,
9each electric utility subject to subsection (b) of this Section
10shall submit a proposed program to the Commission that contains
11the following components:
12        (1) A list of recommended electric energy efficiency
13    measures that will be eligible for on-bill financing. An
14    eligible electric energy efficiency measure ("measure")
15    shall be defined by the following:
16            (A) the measure would be applied to or replace
17        electric energy-using equipment; and either
18            (B) application of the measure to equipment and
19        systems will have estimated electricity savings
20        (determined by rates in effect at the time of
21        purchase), that are sufficient to cover the costs of
22        implementing the measures, including finance charges
23        and any program fees not recovered pursuant to
24        subsection (f) of this Section; to . To assist the
25        electric utility in identifying or approving measures,
26        the utility may consult with the Department of Commerce

 

 

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1        and Economic Opportunity, as well as with retailers,
2        technicians, and installers of electric energy
3        efficiency measures and energy auditors (collectively
4        "vendors"); or .
5            (C) the measure is included in a
6        Commission-approved energy efficiency and
7        demand-response plan under Section 8-103 of this Act
8        and is cost-effective as that term is defined by that
9        Section.
10        (2) The electric utility shall issue a request for
11    proposals ("RFP") to lenders for purposes of providing
12    financing to participants to pay for approved measures. The
13    RFP criteria shall include, but not be limited to, the
14    interest rate, origination fees, and credit terms. The
15    utility shall select the winning bidders based on its
16    evaluation of these criteria, with a preference for those
17    bids containing the rates, fees, and terms most favorable
18    to participants;
19        (3) The utility shall work with the lenders selected
20    pursuant to the RFP process, and with vendors, to establish
21    the terms and processes pursuant to which a participant can
22    purchase eligible electric energy efficiency measures
23    using the financing obtained from the lender. The vendor
24    shall explain and offer the approved financing packaging to
25    those customers identified in subsection (b) of this
26    Section and shall assist customers in applying for

 

 

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1    financing. As part of the process, vendors shall also
2    provide to participants information about any other
3    incentives that may be available for the measures.
4        (4) The lender shall conduct credit checks or undertake
5    other appropriate measures to limit credit risk, and shall
6    review and approve or deny financing applications
7    submitted by customers identified in subsection (b) of this
8    Section. Following the lender's approval of financing and
9    the participant's purchase of the measure or measures, the
10    lender shall forward payment information to the electric
11    utility, and the utility shall add as a separate line item
12    on the participant's utility bill a charge showing the
13    amount due under the program each month.
14        (5) A loan issued to a participant pursuant to the
15    program shall be the sole responsibility of the
16    participant, and any dispute that may arise concerning the
17    loan's terms, conditions, or charges shall be resolved
18    between the participant and lender. Upon transfer of the
19    property title for the premises at which the participant
20    receives electric service from the utility or the
21    participant's request to terminate service at such
22    premises, the participant shall pay in full its electric
23    utility bill, including all amounts due under the program,
24    provided that this obligation may be modified as provided
25    in subsection (g) of this Section. Amounts due under the
26    program shall be deemed amounts owed for residential and,

 

 

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1    as appropriate, small commercial electric service.
2        (6) The electric utility shall remit payment in full to
3    the lender each month on behalf of the participant. In the
4    event a participant defaults on payment of its electric
5    utility bill, the electric utility shall continue to remit
6    all payments due under the program to the lender, and the
7    utility shall be entitled to recover all costs related to a
8    participant's nonpayment through the automatic adjustment
9    clause tariff established pursuant to Section 16-111.8 of
10    this Act. In addition, the electric utility shall retain a
11    security interest in the measure or measures purchased
12    under the program, and the utility retains its right to
13    disconnect a participant that defaults on the payment of
14    its utility bill.
15        (7) The total outstanding amount financed under the
16    program shall not exceed $2.5 million for an electric
17    utility or electric utilities under a single holding
18    company, provided that the electric utility or electric
19    utilities may petition the Commission for an increase in
20    such amount.
21    (d) A program approved by the Commission shall also include
22the following criteria and guidelines for such program:
23        (1) guidelines for financing of measures installed
24    under a program, including, but not limited to, RFP
25    criteria and limits on both individual loan amounts and the
26    duration of the loans;

 

 

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1        (2) criteria and standards for identifying and
2    approving measures;
3        (3) qualifications of vendors that will market or
4    install measures, as well as a methodology for ensuring
5    ongoing compliance with such qualifications;
6        (4) sample contracts and agreements necessary to
7    implement the measures and program; and
8        (5) the types of data and information that utilities
9    and vendors participating in the program shall collect for
10    purposes of preparing the reports required under
11    subsection (g) of this Section.
12    (e) The proposed program submitted by each electric utility
13shall be consistent with the provisions of this Section that
14define operational, financial and billing arrangements between
15and among program participants, vendors, lenders, and the
16electric utility.
17    (f) An electric utility shall recover all of the prudently
18incurred costs of offering a program approved by the Commission
19pursuant to this Section, including, but not limited to, all
20start-up and administrative costs and the costs for program
21evaluation. All prudently incurred costs under this Section
22shall be recovered from the residential and small commercial
23retail customer classes eligible to participate in the program
24through the automatic adjustment clause tariff established
25pursuant to Section 8-103 of this Act.
26    (g) An independent evaluation of a program shall be

 

 

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1conducted after 3 years of the program's operation. The
2electric utility shall retain an independent evaluator who
3shall evaluate the effects of the measures installed under the
4program and the overall operation of the program, including but
5not limited to customer eligibility criteria and whether the
6payment obligation for permanent electric energy efficiency
7measures that will continue to provide benefits of energy
8savings should attach to the meter location. As part of the
9evaluation process, the evaluator shall also solicit feedback
10from participants and interested stakeholders. The evaluator
11shall issue a report to the Commission on its findings no later
12than 4 years after the date on which the program commenced, and
13the Commission shall issue a report to the Governor and General
14Assembly including a summary of the information described in
15this Section as well as its recommendations as to whether the
16program should be discontinued, continued with modification or
17modifications or continued without modification, provided that
18any recommended modifications shall only apply prospectively
19and to measures not yet installed or financed.
20    (h) An electric utility offering a Commission-approved
21program pursuant to this Section shall not be required to
22comply with any other statute, order, rule, or regulation of
23this State that may relate to the offering of such program,
24provided that nothing in this Section is intended to limit the
25electric utility's obligation to comply with this Act and the
26Commission's orders, rules, and regulations, including Part

 

 

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1280 of Title 83 of the Illinois Administrative Code.
2    (i) The source of a utility customer's electric supply
3shall not disqualify a customer from participation in the
4utility's on-bill financing program. Customers of alternative
5retail electric suppliers may participate in the program under
6the same terms and conditions applicable to the utility's
7supply customers.
8(Source: P.A. 96-33, eff. 7-10-09.)
 
9    (220 ILCS 5/16-128)
10    Sec. 16-128. Provisions related to utility employees
11during the mandatory transition period.
12    (a) The General Assembly finds:
13        (1) The reliability and safety of the electric system
14    has depended and depends on a workforce of skilled and
15    dedicated employees, equipped with technical training and
16    experience.
17        (2) The integrity and reliability of the system has
18    also requires depended on the industry's commitment to
19    invest in regular inspection and maintenance, to assure
20    that it can withstand the demands of heavy service
21    requirements and emergency situations.
22        (3) It is in the State's interest to protect the
23    interests of utility employees who have and continue to
24    dedicate dedicated themselves to assuring reliable service
25    to the citizens of this State, and who might otherwise be

 

 

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1    economically displaced in a restructured industry.
2    The General Assembly further finds that it is necessary to
3assure that employees of electric utilities and employees of
4contractors or subcontractors performing work on behalf of an
5electric utility operating in the deregulated industry have the
6requisite skills, knowledge, training, experience, and
7competence to provide reliable and safe electrical service
8under this Act and therefore that alternative retail electric
9suppliers shall be required to demonstrate the competence of
10their employees to work in the industry.
11    The General Assembly also finds that it is necessary to
12assure that employees of alternative retail electric suppliers
13and employees of contractors or subcontractors performing work
14on behalf of an alternative retail electric supplier operating
15in the deregulated industry have the requisite skills,
16knowledge, training, experience, and competence to provide
17reliable and safe electrical service under this Act.
18    To ensure that these findings and prerequisites for
19reliable and safe electrical service continue to prevail, each
20alternative retail electric supplier, electric utility, and
21contractors and subcontractors performing work on behalf of an
22electric utility or alternative retail electric supplier must
23demonstrate the competence of their respective employees to
24work on the distribution system.
25    The knowledge, skill, training, experience, and competence
26levels to be demonstrated shall be consistent with those

 

 

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1generally required of or by the electric utilities in this
2State as of January 1, 2007, with respect to their employees
3and employees of contractors or subcontractors performing work
4on their behalf. Nothing in this Section shall prohibit an
5electric utility from establishing knowledge, skill, training,
6experience, and competence levels greater than those required
7as of January 1, 2007.
8    An adequate Adequate demonstration of requisite knowledge,
9skill, training, experience, and competence shall include, at a
10minimum, such factors as completion or current participation
11and ultimate completion by the employee of an accredited or
12otherwise recognized apprenticeship program for the particular
13craft, trade or skill, or specified and several years of
14employment with an electric utility performing a particular
15work function that is utilized by an electric utility.
16    Notwithstanding any law, tariff, Commission rule, order,
17or decision to the contrary, the Commission shall have an
18affirmative statutory obligation to ensure that an electric
19utility is employing employees, contractors, and
20subcontractors with employees who meet the requirements of
21subsection (a) of this Section when installing, operating, and
22maintaining generation, transmission, or distribution
23facilities and equipment within this State pursuant to any
24provision in this Act or any Commission order, rule, or
25decision.
26    For purposes of this Section, "distribution facilities and

 

 

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1equipment" means any and all of the facilities and equipment,
2including, but not limited to, substations, distribution
3feeder circuits, switches, meters, protective equipment,
4primary circuits, distribution transformers, line extensions
5and service extensions both above or below ground, conduit,
6risers, elbows, transformer pads, junction boxes, manholes,
7pedestals, conductors, and all associated fittings that
8connect the transmission- or distribution system to either the
9weatherhead on the retail customer's building or other
10structure for above ground service or to the terminals on the
11meter base of the retail customer's building or other structure
12for below ground service.
13    To implement this requirement for alternative retail
14electric suppliers, the Commission, in determining that an
15applicant meets the standards for certification as an
16alternative retail electric supplier, shall require the
17applicant to demonstrate (i) that the applicant is licensed to
18do business, and bonded, in the State of Illinois; and (ii)
19that the employees of the applicant that will be installing,
20operating, and maintaining generation, transmission, or
21distribution facilities within this State, or any entity with
22which the applicant has contracted to perform those functions
23within this State, have the requisite knowledge, skills,
24training, experience, and competence to perform those
25functions in a safe and responsible manner in order to provide
26safe and reliable service, in accordance with the criteria

 

 

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1stated above.
2    (b) The General Assembly finds, based on experience in
3other industries that have undergone similar transitions, that
4the introduction of competition into the State's electric
5utility industry may result in workforce reductions by electric
6utilities which may adversely affect persons who have been
7employed by this State's electric utilities in functions
8important to the public convenience and welfare. The General
9Assembly further finds that the impacts on employees and their
10communities of any necessary reductions in the utility
11workforce directly caused by this restructuring of the electric
12industry shall be mitigated to the extent practicable through
13such means as offers of voluntary severance, retraining, early
14retirement, outplacement and related benefits. Therefore,
15before any such reduction in the workforce during the
16transition period, an electric utility shall present to its
17employees or their representatives a workforce reduction plan
18outlining the means by which the electric utility intends to
19mitigate the impact of such workforce reduction on its
20employees.
21    (c) In the event of a sale, purchase, or any other transfer
22of ownership during the mandatory transition period of one or
23more Illinois divisions or business units, and/or generating
24stations or generating units, of an electric utility, the
25electric utility's contract and/or agreements with the
26acquiring entity or persons shall require that the entity or

 

 

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1persons hire a sufficient number of non-supervisory employees
2to operate and maintain the station, division or unit by
3initially making offers of employment to the non-supervisory
4workforce of the electric utility's division, business unit,
5generating station and/or generating unit at no less than the
6wage rates, and substantially equivalent fringe benefits and
7terms and conditions of employment that are in effect at the
8time of transfer of ownership of said division, business unit,
9generating station, and/or generating units; and said wage
10rates and substantially equivalent fringe benefits and terms
11and conditions of employment shall continue for at least 30
12months from the time of said transfer of ownership unless the
13parties mutually agree to different terms and conditions of
14employment within that 30-month period. The utility shall offer
15a transition plan to those employees who are not offered jobs
16by the acquiring entity because that entity has a need for
17fewer workers. If there is litigation concerning the sale, or
18other transfer of ownership of the electric utility's
19divisions, business units, generating station, or generating
20units, the 30-month period will begin on the date the acquiring
21entity or persons take control or management of the divisions,
22business units, generating station or generating units of the
23electric utility.
24    (d) If a utility transfers ownership during the mandatory
25transition period of one or more Illinois divisions, business
26units, generating stations or generating units of an electric

 

 

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1utility to a majority-owned subsidiary, that subsidiary shall
2continue to employ the utility's employees who were employed by
3the utility at such division, business unit or generating
4station at the time of the transfer under the same terms and
5conditions of employment as those employees enjoyed at the time
6of the transfer. If ownership of the subsidiary is subsequently
7sold or transferred to a third party during the transition
8period, the transition provisions outlined in subsection (c)
9shall apply.
10    (e) The plant transfer provisions set forth above shall not
11apply to any generating station which was the subject of a
12sales agreement entered into before January 1, 1997.
13(Source: P.A. 90-561, eff. 12-16-97.)
 
14    (220 ILCS 5/16-128A new)
15    Sec. 16-128A. Certification of Distributed Generation
16Facility Installers.
17    (a) Within 18 months of the effective date of this
18amendatory Act of the 97th General Assembly, the Commission
19shall adopt rules, including emergency rules, establishing
20certification requirements ensuring that entities installing
21distributed generation facilities are in compliance with the
22requirements of subsection (a) of Section 16-128 of this Act.
23    For purposes of this Section, the phrase "entities
24installing distributed generation facilities" shall include,
25but not be limited to, all entities that are exempt from the

 

 

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1definition of "alternative retail electric supplier" under
2item (v) of Section 16-102 of the Act. For purposes of this
3Section, the phrase "self-installer" means an individual who
4(i) leases or purchases a cogeneration facility for his or her
5own personal use and (ii) installs such cogeneration or
6self-generation facility on his or her own promises without the
7assistance of any other person.
8    (b) In addition to any authority granted to the Commission
9under the Act, the Commission is also authorized to: (1)
10determine which entities are subject to certification under
11this Section; (2) impose reasonable certification fees and
12penalties; (3) adopt disciplinary procedures; (4) investigate
13any and all activities subject to this Section, including
14violations thereof; (5) adopt procedures to issue or renew, or
15to refuse to issue or renew, a certification or to revoke,
16suspend, place on probation, reprimand, or otherwise
17discipline a certified entity under this Act or take other
18enforcement action against an entity subject to this Section;
19and (6) prescribe forms to be issued for the administration and
20enforcement of this Section.
21    (c) No electric utility shall provide a retail customer
22with net metering service related to interconnection of that
23customer's distributed generation facility unless the customer
24provides the electric utility with (i) a certification that the
25customer installing the distributed generation facility was a
26self-installer or (ii) evidence that the distributed

 

 

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1generation facility was installed by an entity certified under
2this Section that is also in good standing with the Commission.
3For purposes of this subsection, a retail customer includes
4that customer's employees, officers, and agents. An electric
5utility shall file a tariff or tariffs with the Commission
6setting forth the documentation that a retail customer must
7provide to an electric utility. The provisions of this
8subsection (c) shall apply on or after the effective date of
9the Commission's rules prescribed pursuant to subsection (a) of
10this Section.
 
11    Section 99. Effective date. This Act takes effect upon
12becoming law.".