Sen. Don Harmon

Filed: 10/24/2011

 

 


 

 


 
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1
AMENDMENT TO HOUSE BILL 3036

2    AMENDMENT NO. ______. Amend House Bill 3036 by replacing
3everything after the enacting clause with the following:
 
4    "Section 1. Findings. The General Assembly finds that:
5        (1) subsection (b-10) of Section 16-108.5 of this
6    amendatory Act of the 97th General Assembly provides
7    substantial customer assistance programs for low-income
8    customers, senior citizens, active members of the armed
9    services and reserved forces, and disabled veterans;
10        (2) subsection (b) of Section 16-108.5 of this
11    amendatory Act of the 97th General Assembly provides for
12    infrastructure improvements designed to reduce outages due
13    to storms;
14        (3) subsections (f) and (f-5) of Section 16-108.5 of
15    this amendatory Act of the 97th General Assembly require
16    improvement in a variety of performance metrics and impose
17    penalties on the electric utilities for failure to achieve

 

 

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1    the statutorily set goals;
2        (4) Black & Veatch, a global engineering, consulting
3    and construction company, performed an independent
4    evaluation of Commonwealth Edison Company's Advanced
5    Metering Infrastructure ("AMI") pilot program and
6    concluded that the cost savings and benefits to ComEd
7    customers of full AMI deployment are nearly 3 times greater
8    than the cost to deploy AMI, and further that AMI
9    deployment is estimated to result in a net savings to ComEd
10    customers of $2.8 billion over 20 years; and
11        (5) this amendatory Act of the 97th General Assembly
12    confers substantial benefits upon the State's electric
13    utility customers.
 
14    Section 5. If and only if Senate Bill 1652 of the 97th
15General Assembly becomes law, then the Public Utilities Act is
16amended by changing Section 16-107.5, 16-108.5, 16-108.6,
1716-108.7, and 16-128 as follows:
 
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

 

 

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

 

 

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1    and measured on a kilowatt-hour basis and electric supply
2    service is not provided based on hourly pricing, this shall
3    typically be accomplished through use of a single,
4    bi-directional meter. If the eligible customer's existing
5    electric revenue meter does not meet this requirement, the
6    electricity provider shall arrange for the local electric
7    utility or a meter service provider to install and maintain
8    a new revenue meter at the 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, the electricity
23    provider may arrange for the local electric utility or a
24    meter service provider to install and maintain metering
25    equipment capable of measuring the flow of electricity both
26    into and out of the customer's facility at the same rate

 

 

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

 

 

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

 

 

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1        (2) If the amount of electricity produced by a customer
2    during any hourly period exceeds the amount of electricity
3    used by the customer during that hourly period, the energy
4    provider shall apply a credit for the net kilowatt-hours
5    produced in such period. The credit shall consist of an
6    energy credit and a delivery service credit. The energy
7    credit shall be valued at the same price per kilowatt-hour
8    as the electric service provider would charge for
9    kilowatt-hour energy sales during that same hourly period.
10    The delivery credit shall be equal to the net
11    kilowatt-hours produced in such hourly period times a
12    credit that reflects all kilowatt-hour based charges in the
13    customer's electric service rate, excluding energy
14    charges.
15    (e) An electricity provider shall measure and charge or
16credit for the net electricity supplied to eligible customers
17whose electric service has not been declared competitive
18pursuant to Section 16-113 of this Act and whose electric
19delivery service is provided and measured on a kilowatt demand
20basis and electric supply service is not provided based on
21hourly pricing in the following manner:
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, then the electricity provider
25    shall charge the customer for the net electricity supplied
26    to and used by the customer as provided in subsection (e-5)

 

 

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

 

 

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1    (e-5) An electricity provider shall provide electric
2service to eligible customers whose electric service has not
3been declared competitive pursuant to Section 16-113 of this
4Act and whose electric supply service is not provided based on
5hourly pricing who utilize net metering at non-discriminatory
6rates that are identical, with respect to rate structure,
7retail rate components, and any monthly charges, to the rates
8that the customer would be charged if not a net metering
9customer. An electricity provider shall not charge net metering
10customers any fee or charge or require additional equipment,
11insurance, or any other requirements not specifically
12authorized by interconnection standards authorized by the
13Commission, unless the fee, charge, or other requirement would
14apply to other similarly situated customers who are not net
15metering customers. The customer will remain responsible for
16all taxes, fees, and utility delivery charges that would
17otherwise be applicable to the net amount of electricity used
18by the customer. Subsections (c) through (e) of this Section
19shall not be construed to prevent an arms-length agreement
20between an electricity provider and an eligible customer that
21sets forth different prices, terms, and conditions for the
22provision of net metering service, including, but not limited
23to, the provision of the appropriate metering equipment for
24non-residential customers.
25    (f) Notwithstanding the requirements of subsections (c)
26through (e-5) of this Section, an electricity provider must

 

 

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1require dual-channel metering for customers operating eligible
2renewable electrical generating facilities with a nameplate
3rating up to 2,000 kilowatts and to whom the provisions of
4neither subsection (d), (d-5), nor (e) of this Section apply.
5In such cases, electricity charges and credits shall be
6determined as follows:
7        (1) The electricity provider shall assess and the
8    customer remains responsible for all taxes, fees, and
9    utility delivery charges that would otherwise be
10    applicable to the gross amount of kilowatt-hours supplied
11    to the eligible customer by the electricity provider.
12        (2) Each month that service is supplied by means of
13    dual-channel metering, the electricity provider shall
14    compensate the eligible customer for any excess
15    kilowatt-hour credits at the electricity provider's
16    avoided cost of electricity supply over the monthly period
17    or as otherwise specified by the terms of a power-purchase
18    agreement negotiated between the customer and electricity
19    provider.
20        (3) For all eligible net metering customers taking
21    service from an electricity provider under contracts or
22    tariffs employing time of use rates, any monthly
23    consumption of electricity shall be calculated according
24    to the terms of the contract or tariff to which the same
25    customer would be assigned to or be eligible for if the
26    customer was not a net metering customer. When those same

 

 

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1    customer-generators are net generators during any discrete
2    time of use period, the net kilowatt-hours produced shall
3    be valued at the same price per kilowatt-hour as the
4    electric service provider would charge for retail
5    kilowatt-hour sales during that same time of use period.
6    (g) For purposes of federal and State laws providing
7renewable energy credits or greenhouse gas credits, the
8eligible customer shall be treated as owning and having title
9to the renewable energy attributes, renewable energy credits,
10and greenhouse gas emission credits related to any electricity
11produced by the qualified generating unit. The electricity
12provider may not condition participation in a net metering
13program on the signing over of a customer's renewable energy
14credits; provided, however, this subsection (g) shall not be
15construed to prevent an arms-length agreement between an
16electricity provider and an eligible customer that sets forth
17the ownership or title of the credits.
18    (h) Within 120 days after the effective date of this
19amendatory Act of the 95th General Assembly, the Commission
20shall establish standards for net metering and, if the
21Commission has not already acted on its own initiative,
22standards for the interconnection of eligible renewable
23generating equipment to the utility system. The
24interconnection standards shall address any procedural
25barriers, delays, and administrative costs associated with the
26interconnection of customer-generation while ensuring the

 

 

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1safety and reliability of the units and the electric utility
2system. The Commission shall consider the Institute of
3Electrical and Electronics Engineers (IEEE) Standard 1547 and
4the issues of (i) reasonable and fair fees and costs, (ii)
5clear timelines for major milestones in the interconnection
6process, (iii) nondiscriminatory terms of agreement, and (iv)
7any best practices for interconnection of distributed
8generation.
9    (i) All electricity providers shall begin to offer net
10metering no later than April 1, 2008.
11    (j) An electricity provider shall provide net metering to
12eligible customers until the load of its net metering customers
13equals 5% of the total peak demand supplied by that electricity
14provider during the previous year. Electricity providers are
15authorized to offer net metering beyond the 5% level if they so
16choose.
17    (k) Each electricity provider shall maintain records and
18report annually to the Commission the total number of net
19metering customers served by the provider, as well as the type,
20capacity, and energy sources of the generating systems used by
21the net metering customers. Nothing in this Section shall limit
22the ability of an electricity provider to request the redaction
23of information deemed by the Commission to be confidential
24business information. Each electricity provider shall notify
25the Commission when the total generating capacity of its net
26metering customers is equal to or in excess of the 5% cap

 

 

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1specified in subsection (j) of this Section.
2    (l) Notwithstanding the definition of "eligible customer"
3in item (i) of subsection (b) of this Section, each electricity
4provider shall consider whether to allow meter aggregation for
5the purposes of net metering on:
6        (1) properties owned or leased by multiple customers
7    that contribute to the operation of an eligible renewable
8    electrical generating facility, such as a community-owned
9    wind project, a community-owned biomass project, a
10    community-owned solar project, or a community methane
11    digester processing livestock waste from multiple sources;
12    and
13        (2) individual units, apartments, or properties owned
14    or leased by multiple customers and collectively served by
15    a common eligible renewable electrical generating
16    facility, such as an apartment building served by
17    photovoltaic panels on the roof.
18    For the purposes of this subsection (l), "meter
19aggregation" means the combination of reading and billing on a
20pro rata basis for the types of eligible customers described in
21this Section.
22    (m) Nothing in this Section shall affect the right of an
23electricity provider to continue to provide, or the right of a
24retail customer to continue to receive service pursuant to a
25contract for electric service between the electricity provider
26and the retail customer in accordance with the prices, terms,

 

 

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1and conditions provided for in that contract. Either the
2electricity provider or the customer may require compliance
3with the prices, terms, and conditions of the contract.
4(Source: P.A. 95-420, eff. 8-24-07; 09700SB1652enr.)
 
5    (220 ILCS 5/16-108.5)
6    Sec. 16-108.5. Infrastructure investment and
7modernization; regulatory reform.
8    (a) (Blank). The General Assembly recognizes that for well
9over a century Illinois residents and businesses have been
10well-served by and have benefitted from a comprehensive
11electric utility system. The General Assembly finds that
12electric utilities are now entering a new construction cycle
13that is needed to refurbish, rebuild, modernize, and expand
14systems to continue to provide safe, reliable, and affordable
15service to the State's current and future utility customers in
16this newly digitized age. In particular, the General Assembly
17finds that it is the policy of this State that significant
18investments must be made in the State's electric grid over the
19next decade to modernize and upgrade transmission and
20distribution facilities in the State. These investments will
21ensure that the State's electric utility infrastructure will
22promote future economic development in the State and that the
23State's electric utilities will be able to continue to provide
24quality electric service to their customers, including
25innovative technological offerings that will enhance customer

 

 

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1experience and choice such as smart meters that are dependent
2on a modernized or Smart Grid. These investments, including
3programs to reinforce the safety and security of high voltage
4transmission lines, will also ensure that the State's electric
5utility infrastructure continues to be safe and reliable. The
6introduction of performance metrics will further ensure that
7reliability and other indicators are not just maintained but
8improved over the next decade.
9    The General Assembly further recognizes that, in addition
10to attracting capital and businesses to the State, these
11investments will create training opportunities for the
12citizens of this State, all of which will create new employment
13opportunities for Illinoisans at a time when they are most
14needed, especially for minority-owned and female-owned
15business enterprises. The General Assembly further finds that
16regulatory reform measures that increase predictability,
17stability, and transparency in the ratemaking process are
18needed to promote prudent, long-term infrastructure investment
19and to mutually benefit the State's electric utilities and
20their customers, regulators, and investors.
21    (b) For purposes of this Section, "participating utility"
22means an electric utility or a combination utility serving more
23than 1,000,000 customers in Illinois that voluntarily elects
24and commits to undertake (i) the infrastructure investment
25program consisting of the commitments and obligations
26described in this subsection (b) and (ii) the customer

 

 

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1assistance program consisting of the commitments and
2obligations described in subsection (b-10) of this Section,
3notwithstanding any other provisions of this Act and without
4obtaining any approvals from the Commission or any other agency
5other than as set forth in this Section, regardless of whether
6any such approval would otherwise be required. "Combination
7utility" means a utility that, as of January 1, 2011, provided
8electric service to at least one million retail customers in
9Illinois and gas service to at least 500,000 retail customers
10in Illinois. A participating utility shall recover the
11expenditures made under the infrastructure investment program
12through the ratemaking process, including, but not limited to,
13the performance-based formula rate and process set forth in
14this Section.
15    During the infrastructure investment program's peak
16program year, a participating utility other than a combination
17utility shall create 2,000 full-time equivalent jobs in
18Illinois, and a participating utility that is a combination
19utility shall create 450 full-time equivalent jobs in Illinois
20related to the provision of electric service. These jobs may
21include , including direct jobs, contractor positions, and
22induced jobs, but shall not include any portion of a job
23commitment, not specifically contingent on an amendatory Act of
24the 97th General Assembly becoming law, between a participating
25utility and a labor union that existed on the effective date of
26this amendatory Act of the 97th General Assembly and that has

 

 

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1not yet been fulfilled. A portion of the full-time equivalent
2jobs created by each participating utility shall include
3incremental personnel hired subsequent to the effective date of
4this amendatory Act of the 97th General Assembly. For purposes
5of this Section, "peak program year" means the consecutive
612-month period with the highest number of full-time equivalent
7jobs that occurs between the beginning of investment year 2 and
8the end of investment year 4.
9    A participating utility shall meet one of the following
10commitments, as applicable:
11        (1) Beginning no later than 180 days after a
12    participating utility other than a combination utility
13    files a performance-based formula rate tariff pursuant to
14    subsection (c) of this Section, or, beginning no later than
15    January 1, 2012 if such utility files such
16    performance-based formula rate tariff within 14 days of the
17    effective date of this amendatory Act of the 97th General
18    Assembly, the participating utility shall, except as
19    provided in subsection (b-5):
20            (A) over a 5-year period, invest an estimated
21        $1,300,000,000 $1,100,000,000 in electric system
22        upgrades, modernization projects, and training
23        facilities, including, but not limited to:
24                (i) distribution infrastructure improvements
25            totaling an estimated $1,000,000,000, including
26            underground residential distribution cable

 

 

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1            injection and replacement and mainline cable
2            system refurbishment and replacement projects;
3                (ii) training facility construction or upgrade
4            projects totaling an estimated $10,000,000,
5            provided that, at a minimum, one such facility
6            shall be located in a municipality having a
7            population of more than 2 million residents and one
8            such facility shall be located in a municipality
9            having a population of more than 150,000 residents
10            but fewer than 170,000 residents; any such new
11            facility located in a municipality having a
12            population of more than 2 million residents must be
13            designed for the purpose of obtaining, and the
14            owner of the facility shall apply for,
15            certification under the United States Green
16            Building Council's Leadership in Energy Efficiency
17            Design Green Building Rating System; and
18                (iii) wood pole inspection, treatment, and
19            replacement programs; and
20                (iv) an estimated $200,000,000 for reducing
21            the susceptibility of certain circuits to
22            storm-related damage, including, but not limited
23            to, high winds, thunderstorms, and ice storms;
24            improvements may include, but are not limited to,
25            overhead to underground conversion and other
26            engineered outcomes for circuits; the

 

 

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1            participating utility shall prioritize the
2            selection of circuits based on each circuit's
3            historical susceptibility to storm-related damage
4            and the ability to provide the greatest customer
5            benefit upon completion of the improvements; to be
6            eligible for improvement, the participating
7            utility's ability to maintain proper tree
8            clearances surrounding the overhead circuit must
9            not have been impeded by third parties; and
10            (B) over a 10-year period, invest an estimated
11        $1,300,000,000 $1,500,000,000 to upgrade and modernize
12        its transmission and distribution infrastructure and
13        in Smart Grid electric system upgrades, including, but
14        not limited to:
15                (i) additional smart meters;
16                (ii) distribution automation;
17                (iii) associated cyber secure data
18            communication network; and
19                (iv) substation micro-processor relay
20            upgrades.
21        (2) Beginning no later than 180 days after a
22    participating utility that is a combination utility files a
23    performance-based formula rate tariff pursuant to
24    subsection (c) of this Section, or, beginning no later than
25    January 1, 2012 if such utility files such
26    performance-based formula rate tariff within 14 days of the

 

 

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1    effective date of this amendatory Act of the 97th General
2    Assembly, the participating utility shall, except as
3    provided in subsection (b-5):
4            (A) over a 10-year period, invest an estimated
5        $265,000,000 in electric system upgrades,
6        modernization projects, and training facilities,
7        including, but not limited to:
8                (i) distribution infrastructure improvements
9            totaling an estimated $245,000,000, which may
10            include bulk supply substations, transformers,
11            reconductoring, and rebuilding overhead
12            distribution and sub-transmission lines,
13            underground residential distribution cable
14            injection and replacement and mainline cable
15            system refurbishment and replacement projects;
16                (ii) training facility construction or upgrade
17            projects totaling an estimated $1,000,000; any
18            such new facility must be designed for the purpose
19            of obtaining, and the owner of the facility shall
20            apply for, certification under the United States
21            Green Building Council's Leadership in Energy
22            Efficiency Design Green Building Rating System;
23            and
24                (iii) wood pole inspection, treatment, and
25            replacement programs; and
26            (B) over a 10-year period, invest an estimated

 

 

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1        $360,000,000 to upgrade and modernize its transmission
2        and distribution infrastructure and in Smart Grid
3        electric system upgrades, including, but not limited
4        to:
5                (i) additional smart meters;
6                (ii) distribution automation;
7                (iii) associated cyber secure data
8            communication network; and
9                (iv) substation micro-processor relay
10            upgrades.
11    For purposes of this Section, "Smart Grid electric system
12upgrades" shall have the meaning set forth in subsection (a) of
13Section 16-108.6 of this Act.
14    The investments in the infrastructure investment program
15described in this subsection (b) shall be incremental to the
16participating utility's annual capital investment program, as
17defined by, for purposes of this subsection (b), the
18participating utility's average capital spend for calendar
19years 2008, 2009, and 2010 as reported in the applicable
20Federal Energy Regulatory Commission (FERC) Form 1; provided
21that where one or more utilities have merged, the average
22capital spend shall be determined using the aggregate of the
23merged utilities' capital spend reported in FERC Form 1 for the
24years 2008, 2009, and 2010. A participating utility may add
25reasonable ramp-up and ramp-down time to the investment periods
26specified in this subsection (b).

 

 

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1    Within 60 days after filing a tariff under subsection (c)
2of this Section, a participating utility shall submit to the
3Commission its plan, including scope, schedule, and staffing,
4for satisfying its infrastructure investment program
5commitments pursuant to this subsection (b). The submitted plan
6shall include a schedule and staffing plan for the next
7calendar year. The plan shall also include a plan for the
8creation, operation, and administration of a Smart Grid test
9bed as described in subsection (c) of Section 16-108.8. The
10plan need not allocate the work equally over the respective
11periods, but should allocate material increments throughout
12such periods commensurate with the work to be undertaken. No
13later than April 1 of each subsequent year, the utility shall
14submit to the Commission a report that includes any updates to
15the plan, a schedule for the next calendar year, the
16expenditures made for the prior calendar year and cumulatively,
17and the number of full-time equivalent jobs created for the
18prior calendar year and cumulatively. If the utility is
19materially deficient in satisfying a schedule or staffing plan,
20then the report must also include a corrective action plan to
21address the deficiency. The fact that the plan, implementation
22of the plan, or a schedule changes shall not imply the
23imprudence or unreasonableness of the infrastructure
24investment program, plan, or schedule. Further, no later than
2545 days following the last day of the first, second, and third
26quarters of each year of the plan, a participating utility

 

 

09700HB3036sam001- 23 -LRB097 05714 CEL 59004 a

1shall submit to the Commission a verified quarterly report for
2the prior quarter that includes (i) the total number of
3full-time equivalent jobs created during the prior quarter,
4(ii) the total number of employees as of the last day of the
5prior quarter, (iii) the total number of full-time equivalent
6hours in each job classification or job title, (v) the total
7number of incremental employees and contractors in support of
8the investments undertaken pursuant to this subsection (b) for
9the prior quarter, and (vi) any other information that the
10Commission may require by rule.
11    With respect to the participating utility's peak job
12commitment, if, after considering the utility's corrective
13action plan and compliance thereunder, the Commission enters an
14order finding, after notice and hearing, that a participating
15utility did not satisfy its peak job commitment described in
16this subsection (b) for reasons that are reasonably within its
17control, then the Commission shall also determine, after
18consideration of the evidence, including, but not limited to,
19evidence submitted by the Department of Commerce and Economic
20Opportunity and the utility, the deficiency in the number of
21full-time equivalent jobs during the peak program year due to
22such failure. The Commission shall notify the Department of any
23proceeding that is initiated pursuant to this paragraph. For
24each full-time equivalent job deficiency during the peak
25program year that the Commission finds as set forth in this
26paragraph, the participating utility shall, within 30 days

 

 

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1after the entry of the Commission's order, pay $6,000 $3,000 to
2a fund for training grants administered under Section 605-800
3of The Department of Commerce and Economic Opportunity Law,
4which shall not be a recoverable expense.
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.

 

 

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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, and shall not, consistent
7with State and federal law, discriminate based on race or
8socioeconomic status.
9    (b-5) Nothing in this Section shall prohibit the Commission
10from investigating the prudence and reasonableness of the
11expenditures made under the infrastructure investment program
12during the annual review required by subsection (d) of this
13Section and shall, as part of such investigation, determine
14whether the utility's actual costs under the program are
15prudent and reasonable. The fact that a participating utility
16invests more than the minimum amounts specified in subsection
17(b) of this Section or its plan shall not imply imprudence or
18unreasonableness.
19    If the participating utility finds that it is implementing
20its plan for satisfying the infrastructure investment program
21commitments described in subsection (b) of this Section at a
22cost below the estimated amounts specified in subsection (b) of
23this Section, then the utility may file a petition with the
24Commission requesting that it be permitted to satisfy its
25commitments by spending less than the estimated amounts
26specified in subsection (b) of this Section. The Commission

 

 

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1shall, after notice and hearing, enter its order approving, or
2approving as modified, or denying each such petition within 150
3days after the filing of the petition.
4    In no event, absent General Assembly approval, shall the
5capital investment costs incurred by a participating utility
6other than a combination utility in satisfying its
7infrastructure investment program commitments described in
8subsection (b) of this Section exceed $3,000,000,000 or, for a
9participating utility that is a combination utility,
10$720,000,000. If the participating utility's updated cost
11estimates for satisfying its infrastructure investment program
12commitments described in subsection (b) of this Section exceed
13the limitation imposed by this subsection (b-5), then it shall
14submit a report to the Commission that identifies the increased
15costs and explains the reason or reasons for the increased
16costs no later than the year in which the utility estimates it
17will exceed the limitation. The Commission shall review the
18report and shall, within 90 days after the participating
19utility files the report, report to the General Assembly its
20findings regarding the participating utility's report. If the
21General Assembly does not amend the limitation imposed by this
22subsection (b-5), then the utility may modify its plan so as
23not to exceed the limitation imposed by this subsection (b-5)
24and may propose corresponding changes to the metrics
25established pursuant to subparagraphs (5) through (8) of
26subsection (f) of this Section, and the Commission may modify

 

 

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1the metrics and incremental savings goals established pursuant
2to subsection (f) of this Section accordingly.
3    (b-10) All participating utilities shall make
4contributions for an energy low-income and support program in
5accordance with this subsection. Beginning no later than 180
6days after a participating utility files a performance-based
7formula rate tariff pursuant to subsection (c) of this Section,
8or beginning no later than January 1, 2012 if such utility
9files such performance-based formula rate tariff within 14 days
10of the effective date of this amendatory Act of the 97th
11General Assembly, and without obtaining any approvals from the
12Commission or any other agency other than as set forth in this
13Section, regardless of whether any such approval would
14otherwise be required, a participating utility other than a
15combination utility shall pay $10,000,000 per year for 5 years
16and a participating utility that is a combination utility shall
17pay $1,000,000 per year for 10 years to the energy low-income
18and support program, which is intended to fund customer
19assistance programs with the primary purpose being avoidance of
20imminent disconnection. Such programs may include:
21        (1) a residential hardship program that may partner
22    with community-based organizations, including senior
23    citizen organizations, and provides grants to low-income
24    residential customers, including low-income senior
25    citizens, who demonstrate a hardship;
26        (2) a program that provides grants and other bill

 

 

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1    payment concessions to disabled veterans who demonstrate a
2    hardship and members of the armed services or reserve
3    forces of the United States or members of the Illinois
4    National Guard who are on active duty pursuant to an
5    executive order of the President of the United States, an
6    act of the Congress of the United States, or an order of
7    the Governor and who demonstrate a hardship;
8        (3) a budget assistance program that provides tools and
9    education to low-income senior citizens to assist them with
10    obtaining information regarding energy usage and effective
11    means of managing energy costs;
12        (4) a non-residential special hardship program that
13    provides grants to non-residential customers such as small
14    businesses and non-profit organizations that demonstrate a
15    hardship, including those providing services to senior
16    citizen and low-income customers; and
17        (5) a performance-based assistance program that
18    provides grants to encourage residential customers to make
19    on-time payments by matching a portion of the customer's
20    payments or providing credits towards arrearages.
21    The payments made by a participating utility pursuant to
22this subsection (b-10) shall not be a recoverable expense. A
23participating utility may elect to fund either new or existing
24customer assistance programs, including, but not limited to,
25those that are administered by the utility.
26    Programs that use funds that are provided by a

 

 

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1participating utility to reduce utility bills may be
2implemented through tariffs that are filed with and reviewed by
3the Commission. If a utility elects to file tariffs with the
4Commission to implement all or a portion of the programs, those
5tariffs shall, regardless of the date actually filed, be deemed
6accepted and approved, and shall become effective on the
7effective date of this amendatory Act of the 97th General
8Assembly. The participating utilities whose customers benefit
9from the funds that are disbursed as contemplated in this
10Section shall file annual reports documenting the disbursement
11of those funds with the Commission. The Commission has the
12authority to audit disbursement of the funds to ensure they
13were disbursed consistently with this Section.
14    If the Commission finds that a participating utility is no
15longer eligible to update the performance-based formula rate
16tariff pursuant to subsection (d) of this Section, or the
17performance-based formula rate is otherwise terminated, then
18the participating utility's voluntary commitments and
19obligations under this subsection (b-10) shall immediately
20terminate.
21    (c) A participating utility may elect to recover its
22delivery services costs through a performance-based formula
23rate approved by the Commission, which shall specify the cost
24components that form the basis of the rate charged to customers
25with sufficient specificity to operate in a standardized manner
26and be updated annually with transparent information that

 

 

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1reflects the utility's actual costs to be recovered during the
2applicable rate year, which is the period beginning with the
3first billing day of January and extending through the last
4billing day of the following December. In the event the utility
5recovers a portion of its costs through automatic adjustment
6clause tariffs on the effective date of this amendatory Act of
7the 97th General Assembly, the utility may elect to continue to
8recover these costs through such tariffs, but then these costs
9shall not be recovered through the performance-based formula
10rate. In the event the participating utility, prior to the
11effective date of this amendatory Act of the 97th General
12Assembly, filed electric delivery services tariffs with the
13Commission pursuant to Section 9-201 of this Act that are
14related to the recovery of its electric delivery services costs
15that are still pending on the effective date of this amendatory
16Act of the 97th General Assembly, the participating utility
17shall, at the time it files its performance-based formula rate
18tariff with the Commission, also file a notice of withdrawal
19with the Commission to withdraw the electric delivery services
20tariffs previously filed pursuant to Section 9-201 of this Act.
21Upon receipt of such notice, the Commission shall dismiss with
22prejudice any docket that had been initiated to investigate the
23electric delivery services tariffs filed pursuant to Section
249-201 of this Act, and such tariffs and the record related
25thereto shall not be the subject of any further hearing,
26investigation, or proceeding of any kind related to rates for

 

 

09700HB3036sam001- 31 -LRB097 05714 CEL 59004 a

1electric delivery services.
2    The performance-based formula rate shall be implemented
3through a tariff filed with the Commission consistent with the
4provisions of this subsection (c) that shall be applicable to
5all delivery services customers. The Commission shall initiate
6and conduct an investigation of the tariff in a manner
7consistent with the provisions of this subsection (c) and the
8provisions of Article IX of this Act to the extent they do not
9conflict with this subsection (c). Except in the case where the
10Commission finds, after notice and hearing, that a
11participating utility is not satisfying its investment amount
12commitments under subsection (b) of this Section, the
13performance-based formula rate shall remain in effect at the
14discretion of the utility. The performance-based formula rate
15approved by the Commission shall do the following:
16        (1) Provide for the recovery of the utility's actual
17    costs of delivery services that are prudently incurred and
18    reasonable in amount consistent with Commission practice
19    and law. The sole fact that a cost differs from that
20    incurred in a prior calendar year or that an investment is
21    different from that made in a prior calendar year shall not
22    imply the imprudence or unreasonableness of that cost or
23    investment.
24        (2) Reflect the utility's actual capital structure for
25    the applicable calendar year, excluding goodwill, subject
26    to a determination of prudence and reasonableness

 

 

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1    consistent with Commission practice and law.
2        (3) Include a cost of equity, which shall be calculated
3    as the sum of the following:
4            (A) the average for the applicable calendar year of
5        the monthly average yields of 30-year U.S. Treasury
6        bonds published by the Board of Governors of the
7        Federal Reserve System in its weekly H.15 Statistical
8        Release or successor publication; and
9            (B) 580 600 basis points.
10        At such time as the Board of Governors of the Federal
11    Reserve System ceases to include the monthly average yields
12    of 30-year U.S. Treasury bonds in its weekly H.15
13    Statistical Release or successor publication, the monthly
14    average yields of the U.S. Treasury bonds then having the
15    longest duration published by the Board of Governors in its
16    weekly H.15 Statistical Release or successor publication
17    shall instead be used for purposes of this paragraph (3).
18        (4) Permit and set forth protocols, subject to a
19    determination of prudence and reasonableness consistent
20    with Commission practice and law, for the following:
21            (A) recovery of incentive compensation expense
22        that is based on the achievement of operational
23        metrics, including metrics related to budget controls,
24        outage duration and frequency, safety, customer
25        service, efficiency and productivity, and
26        environmental compliance. Incentive compensation

 

 

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1        expense that is based on net income or an affiliate's
2        earnings per share shall not be recoverable under the
3        performance-based formula rate;
4            (B) recovery of pension and other post-employment
5        benefits expense, provided that such costs are
6        supported by an actuarial study;
7            (C) recovery of severance costs, provided that if
8        the amount is over $3,700,000 for a participating
9        utility that is a combination utility or $10,000,000
10        for a participating utility that serves more than 3
11        million retail customers, then the full amount shall be
12        amortized consistent with subparagraph (F) of this
13        paragraph (4);
14            (D) investment return on pension assets net of
15        deferred tax benefits equal to the utility's long-term
16        debt cost of capital as of the end of the applicable
17        calendar year;
18            (E) recovery of the expenses related to the
19        Commission proceeding under this subsection (c) to
20        approve this performance-based formula rate and
21        initial rates or to subsequent proceedings related to
22        the formula, provided that the recovery shall be
23        amortized over a 3-year period; recovery of expenses
24        related to the annual Commission proceedings under
25        subsection (d) of this Section to review the inputs to
26        the performance-based formula rate shall be expensed

 

 

09700HB3036sam001- 34 -LRB097 05714 CEL 59004 a

1        and recovered through the performance-based formula
2        rate;
3            (F) amortization over a 5-year period of the full
4        amount of each charge or credit that exceeds $3,700,000
5        for a participating utility that is a combination
6        utility or $10,000,000 for a participating utility
7        that serves more than 3 million retail customers in the
8        applicable calendar year and that relates to a
9        workforce reduction program's severance costs, changes
10        in accounting rules, changes in law, compliance with
11        any Commission-initiated audit, or a single storm or
12        other similar expense, provided that any unamortized
13        balance shall be reflected in rate base. For purposes
14        of this subparagraph (F), changes in law includes any
15        enactment, repeal, or amendment in a law, ordinance,
16        rule, regulation, interpretation, permit, license,
17        consent, or order, including those relating to taxes,
18        accounting, or to environmental matters, or in the
19        interpretation or application thereof by any
20        governmental authority occurring after the effective
21        date of this amendatory Act of the 97th General
22        Assembly;
23            (G) recovery of existing regulatory assets over
24        the periods previously authorized by the Commission;
25            (H) historical weather normalized billing
26        determinants; and

 

 

09700HB3036sam001- 35 -LRB097 05714 CEL 59004 a

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

 

 

09700HB3036sam001- 36 -LRB097 05714 CEL 59004 a

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

 

 

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1    the utility files its performance-based formula rate
2    tariff pursuant to subsection (c) of this Section, with
3    what the revenue requirement would have been had the actual
4    cost information for the applicable calendar year been
5    available at the filing date.
6    The utility shall file, together with its tariff, final
7data based on its most recently filed FERC Form 1, plus
8projected plant additions and correspondingly updated
9depreciation reserve and expense for the calendar year in which
10the tariff and data are filed, that shall populate the
11performance-based formula rate and set the initial delivery
12services rates under the formula. For purposes of this Section,
13"FERC Form 1" means the Annual Report of Major Electric
14Utilities, Licensees and Others that electric utilities are
15required to file with the Federal Energy Regulatory Commission
16under the Federal Power Act, Sections 3, 4(a), 304 and 209,
17modified as necessary to be consistent with 83 Ill. Admin. Code
18Part 415 as of May 1, 2011. Nothing in this Section is intended
19to allow costs that are not otherwise recoverable to be
20recoverable by virtue of inclusion in FERC Form 1.
21    After the utility files its proposed performance-based
22formula rate structure and protocols and initial rates, the
23Commission shall initiate a docket to review the filing. The
24Commission shall enter an order approving, or approving as
25modified, the performance-based formula rate, including the
26initial rates, as just and reasonable within 270 days after the

 

 

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1date on which the tariff was filed, or, if the tariff is filed
2within 14 days after the effective date of this amendatory Act
3of the 97th General Assembly, then by May 31, 2012. Such review
4shall be based on the same evidentiary standards, including,
5but not limited to, those concerning the prudence and
6reasonableness of the costs incurred by the utility, the
7Commission applies in a hearing to review a filing for a
8general increase in rates under Article IX of this Act. The
9initial rates shall take effect within 30 days after the
10Commission's order approving the performance-based formula
11rate tariff.
12    Until such time as the Commission approves a different rate
13design and cost allocation pursuant to subsection (e) of this
14Section, rate design and cost allocation across customer
15classes shall be consistent with the Commission's most recent
16order regarding the participating utility's request for a
17general increase in its delivery services rates.
18    Subsequent changes to the performance-based formula rate
19structure or protocols shall be made as set forth in Section
209-201 of this Act, but nothing in this subsection (c) is
21intended to limit the Commission's authority under Article IX
22and other provisions of this Act to initiate an investigation
23of a participating utility's performance-based formula rate
24tariff, provided that any such changes shall be consistent with
25paragraphs (1) through (6) of this subsection (c). Any change
26ordered by the Commission shall be made at the same time new

 

 

09700HB3036sam001- 39 -LRB097 05714 CEL 59004 a

1rates take effect following the Commission's next order
2pursuant to subsection (d) of this Section, provided that the
3new rates take effect no less than 30 days after the date on
4which the Commission issues an order adopting the change.
5    A participating utility that files a tariff pursuant to
6this subsection (c) must submit a one-time $200,000 filing fee
7at the time the Chief Clerk of the Commission accepts the
8filing, which shall be a recoverable expense.
9    In the event the performance-based formula rate is
10terminated, the then current rates shall remain in effect until
11such time as new rates are set pursuant to Article IX of this
12Act, subject to retroactive rate adjustment, with interest, to
13reconcile rates charged with actual costs. At such time that
14the performance-based formula rate is terminated, the
15participating utility's voluntary commitments and obligations
16under subsection (b) of this Section shall immediately
17terminate, except for the utility's obligation to pay an amount
18already owed to the fund for training grants pursuant to a
19Commission order issued under subsection (b) of this Section.
20    (d) Subsequent to the Commission's issuance of an order
21approving the utility's performance-based formula rate
22structure and protocols, and initial rates under subsection (c)
23of this Section, the utility shall file, on or before May 1 of
24each year, with the Chief Clerk of the Commission its updated
25cost inputs to the performance-based formula rate for the
26applicable rate year and the corresponding new charges. Each

 

 

09700HB3036sam001- 40 -LRB097 05714 CEL 59004 a

1such filing shall conform to the following requirements and
2include the following information:
3        (1) The inputs to the performance-based formula rate
4    for the applicable rate year shall be based on final
5    historical data reflected in the utility's most recently
6    filed annual FERC Form 1 plus projected plant additions and
7    correspondingly updated depreciation reserve and expense
8    for the calendar year in which the inputs are filed. The
9    filing shall also include a reconciliation of the revenue
10    requirement that was in effect for the prior rate year (as
11    set by the cost inputs for the prior rate year) with the
12    actual revenue requirement for the prior rate year (as
13    reflected in the applicable FERC Form 1 that reports the
14    actual costs for the prior rate year). Any over-collection
15    or under-collection indicated by such reconciliation shall
16    be reflected as a credit against, or recovered as an
17    additional charge to, respectively, with interest, the
18    charges for the applicable rate year. Provided, however,
19    that the first such reconciliation shall be for the
20    calendar year in which the utility files its
21    performance-based formula rate tariff pursuant to
22    subsection (c) of this Section and shall reconcile (i) the
23    revenue requirement or requirements established by the
24    rate order or orders in effect from time to time during
25    such calendar year (weighted, as applicable) with (ii) the
26    revenue requirement for that calendar year calculated

 

 

09700HB3036sam001- 41 -LRB097 05714 CEL 59004 a

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

 

 

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1    what the revenue requirement would have been had the actual
2    cost information for the applicable calendar year been
3    available at the filing date.
4        (2) The new charges shall take effect beginning on the
5    first billing day of the following January billing period
6    and remain in effect through the last billing day of the
7    next December billing period regardless of whether the
8    Commission enters upon a hearing pursuant to this
9    subsection (d).
10        (3) The filing shall include relevant and necessary
11    data and documentation for the applicable rate year that is
12    consistent with the Commission's rules applicable to a
13    filing for a general increase in rates or any rules adopted
14    by the Commission to implement this Section. Normalization
15    adjustments shall not be required. Notwithstanding any
16    other provision of this Section or Act or any rule or other
17    requirement adopted by the Commission, a participating
18    utility that is a combination utility with more than one
19    rate zone shall not be required to file a separate set of
20    such data and documentation for each rate zone and may
21    combine such data and documentation into a single set of
22    schedules.
23    Within 45 days after the utility files its annual update of
24cost inputs to the performance-based formula rate, the
25Commission shall have the authority, either upon complaint or
26its own initiative, but with reasonable notice, to enter upon a

 

 

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1hearing concerning the prudence and reasonableness of the costs
2incurred by the utility to be recovered during the applicable
3rate year that are reflected in the inputs to the
4performance-based formula rate derived from the utility's FERC
5Form 1. During the course of the hearing, each objection shall
6be stated with particularity and evidence provided in support
7thereof, after which the utility shall have the opportunity to
8rebut the evidence. Discovery shall be allowed consistent with
9the Commission's Rules of Practice, which Rules shall be
10enforced by the Commission or the assigned hearing examiner.
11The Commission shall apply the same evidentiary standards,
12including, but not limited to, those concerning the prudence
13and reasonableness of the costs incurred by the utility, in the
14hearing as it would apply in a hearing to review a filing for a
15general increase in rates under Article IX of this Act. The
16Commission shall not, however, have the authority in a
17proceeding under this subsection (d) to consider or order any
18changes to the structure or protocols of the performance-based
19formula rate approved pursuant to subsection (c) of this
20Section. In a proceeding under this subsection (d), the
21Commission shall enter its order no later than the earlier of
22240 days after the utility's filing of its annual update of
23cost inputs to the performance-based formula rate or December
2431. The Commission's determinations of the prudence and
25reasonableness of the costs incurred for the applicable
26calendar year shall be final upon entry of the Commission's

 

 

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1order and shall not be subject to reopening, reexamination, or
2collateral attack in any other Commission proceeding, case,
3docket, order, rule or regulation, provided, however, that
4nothing in this subsection (d) shall prohibit a party from
5petitioning the Commission to rehear or appeal to the courts
6the order pursuant to the provisions of this Act.
7    In the event the Commission does not, either upon complaint
8or its own initiative, enter upon a hearing within 45 days
9after the utility files the annual update of cost inputs to its
10performance-based formula rate, then the costs incurred for the
11applicable calendar year shall be deemed prudent and
12reasonable, and the filed charges shall not be subject to
13reopening, reexamination, or collateral attack in any other
14proceeding, case, docket, order, rule, or regulation.
15    A participating utility's first filing of the updated cost
16inputs, and any Commission investigation of such inputs
17pursuant to this subsection (d) shall proceed notwithstanding
18the fact that the Commission's investigation under subsection
19(c) of this Section is still pending and notwithstanding any
20other law, order, rule, or Commission practice to the contrary.
21    (e) Nothing in subsections (c) or (d) of this Section shall
22prohibit the Commission from investigating, or a participating
23utility from filing, revenue-neutral tariff changes related to
24rate design of a performance-based formula rate that has been
25placed into effect for the utility. Following approval of a
26participating utility's performance-based formula rate tariff

 

 

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1pursuant to subsection (c) of this Section, the utility shall
2make a filing with the Commission within one year after the
3effective date of the performance-based formula rate tariff
4that proposes changes to the tariff to incorporate the findings
5of any final rate design orders of the Commission applicable to
6the participating utility and entered subsequent to the
7Commission's approval of the tariff. The Commission shall,
8after notice and hearing, enter its order approving, or
9approving with modification, the proposed changes to the
10performance-based formula rate tariff within 240 days after the
11utility's filing. Following such approval, the utility shall
12make a filing with the Commission during each subsequent 3-year
13period that either proposes revenue-neutral tariff changes or
14re-files the existing tariffs without change, which shall
15present the Commission with an opportunity to suspend the
16tariffs and consider revenue-neutral tariff changes related to
17rate design.
18    (f) Within 30 days after the filing of a tariff pursuant to
19subsection (c) of this Section, each participating utility
20shall develop and file with the Commission multi-year metrics
21designed to achieve, ratably (i.e., in equal segments) over a
2210-year period, improvement over baseline performance values
23as follows:
24        (1) Twenty percent improvement in the System Average
25    Interruption Frequency Index, using a baseline of the
26    average of the data from 2001 through 2010.

 

 

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1        (2) Fifteen percent improvement in the system Customer
2    Average Interruption Duration Index, using a baseline of
3    the average of the data from 2001 through 2010.
4        (3) For a participating utility other than a
5    combination utility, 20% improvement in the System Average
6    Interruption Frequency Index for its Southern Region,
7    using a baseline of the average of the data from 2001
8    through 2010. For purposes of this paragraph (3) paragraph
9    (C), Southern Region shall have the meaning set forth in
10    the participating utility's most recent report filed
11    pursuant to Section 16-125 of this Act.
12        (3.5) For a participating utility other than a
13    combination utility, 20% improvement in the System Average
14    Interruption Frequency Index for its Northeastern Region,
15    using a baseline of the average of the data from 2001
16    through 2010. For purposes of this paragraph (3.5),
17    Northeastern Region shall have the meaning set forth in the
18    participating utility's most recent report filed pursuant
19    to Section 16-125 of this Act.
20        (4) Seventy-five percent improvement in the total
21    number of customers who exceed the service reliability
22    targets as set forth in subparagraphs (A) through (C) of
23    paragraph (4) of subsection (b) of 83 Ill. Admin. Code Part
24    411.140 as of May 1, 2011, using 2010 as the baseline year.
25        (5) Reduction in issuance of estimated electric bills:
26    90% improvement for a participating utility other than a

 

 

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1    combination utility, and 56% improvement for a
2    participating utility that is a combination utility, using
3    a baseline of the average number of estimated bills for the
4    years 2008 through 2010.
5        (6) Consumption on inactive meters: 90% improvement
6    for a participating utility other than a combination
7    utility, and 56% improvement for a participating utility
8    that is a combination utility, using a baseline of the
9    average unbilled kilowatthours for the years 2009 and 2010.
10        (7) Unaccounted for energy: 50% improvement for a
11    participating utility other than a combination utility
12    using a baseline of the non-technical line loss unaccounted
13    for energy kilowatthours for the year 2009.
14        (8) Uncollectible expense: reduce uncollectible
15    expense by at least $30,000,000 for a participating utility
16    other than a combination utility and by at least $3,500,000
17    for a participating utility that is a combination utility,
18    using a baseline of the average uncollectible expense for
19    the years 2008 through 2010.
20        (9) Opportunities for minority-owned and female-owned
21    business enterprises: design a performance metric
22    regarding the creation of opportunities for minority-owned
23    and female-owned business enterprises consistent with
24    State and federal law using a base performance value of the
25    percentage of the participating utility's capital
26    expenditures that were paid to minority-owned and

 

 

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1    female-owned business enterprises in 2010.
2    The definitions set forth in 83 Ill. Admin. Code Part
3411.20 as of May 1, 2011 shall be used for purposes of
4calculating performance under paragraphs (1) through (3.5) (3)
5of this subsection (f), provided, however, that the
6participating utility may exclude up to 9 extreme weather event
7days from such calculation for each year, and provided further
8that the participating utility shall exclude 9 extreme weather
9event days when calculating each year of the baseline period to
10the extent that there are 9 such days in a given year of the
11baseline period. For purposes of this Section, an extreme
12weather event day is a 24-hour calendar day (beginning at 12:00
13a.m. and ending at 11:59 p.m.) during which any weather event
14(e.g., storm, tornado) caused interruptions for 10,000 or more
15of the participating utility's customers for 3 hours or more.
16If there are more than 9 extreme weather event days in a year,
17then the utility may choose no more than 9 extreme weather
18event days to exclude, provided that the same extreme weather
19event days are excluded from each of the calculations performed
20under paragraphs (1) through (3) of this subsection (f).
21    The metrics shall include incremental performance goals
22for each year of the 10-year period, which shall be designed to
23demonstrate that the utility is on track to achieve the
24performance goal in each category at the end of the 10-year
25period. The utility shall elect when the 10-year period shall
26commence for the metrics set forth in subparagraphs (1) through

 

 

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1(4) and (9) of this subsection (f), provided that it begins no
2later than 14 months following the date on which the utility
3begins investing pursuant to subsection (b) of this Section,
4and when the 10-year period shall commence for the metrics set
5forth in subparagraphs (5) through (8) of this subsection (f),
6provided that it begins no later than 14 months following the
7date on which the Commission enters its order approving the
8utility's Advanced Metering Infrastructure Deployment Plan
9pursuant to subsection (c) of Section 16-108.6 of this Act.
10    The metrics and performance goals set forth in
11subparagraphs (5) through (8) of this subsection (f) are based
12on the assumptions that the participating utility may fully
13implement the technology described in subsection (b) of this
14Section, including utilizing the full functionality of such
15technology and that there is no requirement for personal
16on-site notification. If the utility is unable to meet the
17metrics and performance goals set forth in subparagraphs (5)
18through (8) of this subsection (f) for such reasons, and the
19Commission so finds after notice and hearing, then the utility
20shall be excused from compliance, but only to the limited
21extent achievement of the affected metrics and performance
22goals was hindered by the less than full implementation.
23    (f-5) The financial penalties applicable to the metrics
24described in subparagraphs (1) through (9) (8) of subsection
25(f) of this Section, as applicable, shall be applied through an
26adjustment to the participating utility's return on equity of

 

 

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1no more than a total of 30 basis points in each of the first 3
2years, of no more than a total of 34 basis points in each of the
33 years thereafter, and of no more than a total of 38 basis
4points in each of the 4 years thereafter, as follows:
5        (1) With respect to each of the incremental annual
6    performance goals established pursuant to paragraph (1) of
7    subsection (f) of this Section,
8            (A) for each year that a participating utility
9        other than a combination utility does not achieve the
10        annual goal, the participating utility's return on
11        equity shall be reduced as follows: during years 1
12        through 3, by 5 basis points; during years 4 through 6,
13        by 6 basis points; and during years 7 through 10, by 7
14        basis points; for such unachieved goal for the
15        following 12-month period, and
16            (B) for each year that a participating utility that
17        is a combination utility does not achieve the annual
18        goal, the participating utility's return on equity
19        shall be reduced as follows: during years 1 through 3,
20        by 10 basis points; during years 4 through 6, by 12
21        basis points; and during years 7 through 10, by 14
22        basis points for each such unachieved goal for the
23        following 12-month period.
24        (2) With respect to each of the incremental annual
25    performance goals established pursuant to subparagraphs
26    (2), (3), and (4) of subsection (f) of this Section, as

 

 

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1    applicable, for each year that the participating utility
2    does not achieve each such goal, the participating
3    utility's return on equity shall be reduced as follows:
4    during years 1 through 3, by 5 basis points; during years 4
5    through 6, by 6 basis points; and during years 7 through
6    10, by 7 basis points for each such unachieved goal for the
7    following 12-month period.
8        (3) With respect to each of the incremental annual
9    performance goals established pursuant to paragraphs (3)
10    and (3.5) of subsection (f) of this Section, for each year
11    that a participating utility other than a combination
12    utility does not achieve both such goals, the participating
13    utility's return on equity shall be reduced as follows:
14    during years 1 through 3, by 5 basis points; during years 4
15    through 6, by 6 basis points; and during years 7 through
16    10, by 7 basis points.
17        (4) With respect to each of the incremental annual
18    performance goals established pursuant to paragraph (4) of
19    subsection (f) of this Section, for each year that the
20    participating utility does not achieve each such goal, the
21    participating utility's return on equity shall be reduced
22    as follows: during years 1 through 3, by 5 basis points;
23    during years 4 through 6, by 6 basis points; and during
24    years 7 through 10, by 7 basis points.
25        (5) With respect to each of the incremental annual
26    performance goals established pursuant to subparagraph (5)

 

 

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1    of subsection (f) of this Section, for each year that the
2    participating utility does not achieve at least 95% of each
3    such goal, the participating utility's return on equity
4    shall be reduced by 5 basis points for each such unachieved
5    goal for the following 12-month period.
6        (6) (3) With respect to each of the incremental annual
7    performance goals established pursuant to paragraphs (6),
8    (7), and (8) of subsection (f) of this Section, as
9    applicable, which together measure non-operational
10    customer savings and benefits relating to the
11    implementation of the Advanced Metering Infrastructure
12    Deployment Plan, as defined in Section 16-108.6 of this
13    Act, the performance under each such goal shall be
14    calculated in terms of the percentage of the goal achieved.
15    The percentage of goal achieved for each of the goals shall
16    be aggregated, and an average percentage value calculated,
17    for each year of the 10-year period. If the utility does
18    not achieve an average percentage value in a given year of
19    at least 95%, the participating utility's return on equity
20    shall be reduced by 5 basis points for the following
21    12-month period.
22    The financial penalties shall be applied as described in
23this subsection (f-5) through a separate tariff mechanism,
24which shall be filed by the utility together with its metrics.
25In the event the formula rate tariff established pursuant to
26subsection (c) of this Section terminates, the utility's

 

 

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

 

 

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1    (g) On or before July 31, 2014, each participating utility
2shall file a report with the Commission that sets forth the
3average annual increase in the average amount paid per
4kilowatthour for residential eligible retail customers,
5exclusive of the effects of energy efficiency programs,
6comparing the 12-month period ending May 31, 2012; the 12-month
7period ending May 31, 2013; and the 12-month period ending May
831, 2014. For a participating utility that is a combination
9utility with more than one rate zone, the weighted average
10aggregate increase shall be provided. The report shall be filed
11together with a statement from an independent auditor attesting
12to the accuracy of the report. The cost of the independent
13auditor shall be borne by the participating utility and shall
14not be a recoverable expense.
15    In the event that the average annual increase exceeds 2.5%
16as calculated pursuant to this subsection (g), then Sections
1716-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act, other
18than this subsection, shall be inoperative as they relate to
19the utility and its service area as of the date of the report
20due to be submitted pursuant to this subsection and the utility
21shall no longer be eligible to annually update the
22performance-based formula rate tariff pursuant to subsection
23(d) of this Section. In such event, the then current rates
24shall remain in effect until such time as new rates are set
25pursuant to Article IX of this Act, subject to retroactive
26adjustment, with interest, to reconcile rates charged with

 

 

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1actual costs, and the participating utility's voluntary
2commitments and obligations under subsection (b) of this
3Section shall immediately terminate, except for the utility's
4obligation to pay an amount already owed to the fund for
5training grants pursuant to a Commission order issued under
6subsection (b) of this Section.
7    In the event that the average annual increase is 2.5% or
8less as calculated pursuant to this subsection (g), then the
9performance-based formula rate shall remain in effect as set
10forth in this Section.
11    For purposes of this Section, the amount per kilowatthour
12means the total amount paid for electric service expressed on a
13per kilowatthour basis, and the total amount paid for electric
14service includes without limitation amounts paid for supply,
15transmission, distribution, surcharges, and add-on taxes
16exclusive of any increases in taxes or new taxes imposed after
17the effective date of this amendatory Act of the 97th General
18Assembly. For purposes of this Section, "eligible retail
19customers" shall have the meaning set forth in Section 16-111.5
20of this Act.
21    The fact that this Section becomes inoperative as set forth
22in this subsection shall not be construed to mean that the
23Commission may reexamine or otherwise reopen prudence or
24reasonableness determinations already made.
25    (h) Sections 16-108.5, 16-108.6, 16-108.7, and 16-108.8 of
26this Act, other than this subsection, are inoperative after

 

 

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1December 31, 2017 for every participating utility, after which
2time a participating utility shall no longer be eligible to
3annually update the performance-based formula rate tariff
4pursuant to subsection (d) of this Section. At such time, the
5then current rates shall remain in effect until such time as
6new rates are set pursuant to Article IX of this Act, subject
7to retroactive adjustment, with interest, to reconcile rates
8charged with actual costs.
9    By December 31, 2017, the Commission shall prepare and file
10with the General Assembly a report on the infrastructure
11program and the performance-based formula rate. The report
12shall include the change in the average amount per kilowatthour
13paid by residential customers between June 1, 2011 and May 31,
142017. If the change in the total average rate paid exceeds 2.5%
15compounded annually, the Commission shall include in the report
16an analysis that shows the portion of the change due to the
17delivery services component and the portion of the change due
18to the supply component of the rate. The report shall include
19separate sections for each participating utility.
20    In the event Sections 16-108.5, 16-108.6, 16-108.7, and
2116-108.8 of this Act do not become inoperative after December
2231, 2017, then these Sections are inoperative after December
2331, 2022 for every participating utility, after which time a
24participating utility shall no longer be eligible to annually
25update the performance-based formula rate tariff pursuant to
26subsection (d) of this Section. At such time, the then current

 

 

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1rates shall remain in effect until such time as new rates are
2set pursuant to Article IX of this Act, subject to retroactive
3adjustment, with interest, to reconcile rates charged with
4actual costs.
5    The fact that this Section becomes inoperative as set forth
6in this subsection shall not be construed to mean that the
7Commission may reexamine or otherwise reopen prudence or
8reasonableness determinations already made.
9    (i) While a participating utility may use, develop, and
10maintain broadband systems and the delivery of broadband
11services, voice-over-internet-protocol services,
12telecommunications services, and cable and video programming
13services for use in providing delivery services and Smart Grid
14functionality or application to its retail customers,
15including, but not limited to, the installation,
16implementation and maintenance of Smart Grid electric system
17upgrades as defined in Section 16-108.6 of this Act, a
18participating utility is prohibited from offering to its retail
19customers broadband services or the delivery of broadband
20services, voice-over-internet-protocol services,
21telecommunications services, or cable or video programming
22services, unless they are part of a service directly related to
23delivery services or Smart Grid functionality or applications
24as defined in Section 16-108.6 of this Act, and from recovering
25the costs of such offerings from retail customers.
26    (j) Nothing in this Section is intended to legislatively

 

 

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1overturn the opinion issued in Commonwealth Edison Co. v. Ill.
2Commerce Comm'n, Nos. 2-08-0959, 2-08-1037, 2-08-1137,
31-08-3008, 1-08-3030, 1-08-3054, 1-08-3313 cons. (Ill. App.
4Ct. 2d Dist. Sept. 30, 2010). This amendatory Act of the 97th
5General Assembly shall not be construed as creating a contract
6between the General Assembly and the participating utility, and
7shall not establish a property right in the participating
8utility.
9(Source: 09700SB1652enr.)
 
10    (220 ILCS 5/16-108.6)
11    Sec. 16-108.6. Provisions relating to Smart Grid Advanced
12Metering Infrastructure Deployment Plan.
13    (a) For purposes of this Section and Sections 16-108.7 and
1416-108.8 of this Act:
15    "Advanced Metering Infrastructure" or "AMI" means the
16communications hardware and software and associated system
17software that enables Smart Grid functions by creating a
18network between advanced meters and utility business systems
19and allowing collection and distribution of information to
20customers and other parties in addition to providing
21information to the utility itself.
22    "Cost-beneficial" means a determination that the benefits
23of a participating utility's Smart Grid AMI Deployment Plan
24exceed the costs of the Smart Grid AMI Deployment Plan as
25initially filed with the Commission or as subsequently modified

 

 

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

 

 

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

 

 

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

 

 

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1directly relate to or support installing, implementing or
2enabling Smart Grid functions; (2) physical interconnection of
3generators or other devices to the grid except those that are
4directly related to enabling Smart Grid functions; or (3)
5ongoing or routine operation, billing, customer relations,
6security, and maintenance.
7    "Smart Grid functions" means:
8        (1) the ability to develop, store, send, and receive
9    digital information concerning or enabling grid
10    operations, electricity use, costs, prices, time of use,
11    nature of use, storage, or other information relevant to
12    device, grid, or utility operations, to or from or by means
13    of the electric utility system through one or a combination
14    of devices and technologies;
15        (2) the ability to develop, store, send, and receive
16    digital information concerning electricity use, costs,
17    prices, time of use, nature of use, storage, or other
18    information relevant to device, grid, or utility
19    operations to or from a computer or other control device;
20        (3) the ability to measure or monitor electricity use
21    as a function of time of day, power quality characteristics
22    such as voltage level, current, cycles per second, or
23    source or type of generation and to store, synthesize, or
24    report that information by digital means;
25        (4) the ability to sense and localize disruptions or
26    changes in power flows on the grid and communicate such

 

 

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

 

 

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15 of whom shall be appointed by and each having been the single
2appointment of one of the following: the Governor, one of whom
3shall be appointed by the Speaker of the House, one of whom
4shall be appointed by the Minority Leader of the House, one of
5whom shall be appointed by the President of the Senate, and one
6of whom shall be appointed by the Minority Leader of the
7Senate. Of the Governor's 4 appointments: (i) at least one must
8represent the Illinois Science & Technology Coalition, (ii) at
9least one must represent the Citizens Utility Board, (iii) at
10least one must represent the Building Owners and Managers
11Association of Chicago, and (iv) at least one must represent an
12alternative retail electric supplier that has obtained a
13certificate of service authority pursuant to Section 16-115 of
14this Act and that is not an affiliate of a participating
15utility prior to one year after the effective date of this
16amendatory Act of the 97th General Assembly , the Illinois
17Science and Technology Coalition, and the Citizens Utility
18Board.
19    The Governor shall designate one of the members of the
20Council to serve as chairman, and that person shall serve as
21the chairman at the pleasure of the Governor. The members shall
22not be compensated for serving on the Smart Grid Advisory
23Council. The Smart Grid Advisory Council shall have the
24following duties:
25        (1) Serve as an advisor to participating utilities
26    subject to this Section and in the manner described in this

 

 

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1    Section, and the recommendations provided by the Council,
2    although non-binding, shall be considered by the
3    utilities.
4        (2) Serve as trustees of the trust or foundation
5    established pursuant to Section 16-108.7 of this Act with
6    the duties enumerated thereunder.
7    (c) After consultation with the Smart Grid Advisory
8Council, each participating utility shall file a Smart Grid
9Advanced Metering Infrastructure Deployment Plan ("AMI Plan")
10with the Commission within 180 days after the effective date of
11this amendatory Act of the 97th General Assembly or by November
121, 2011, whichever is later, or in the case of a combination
13utility as defined in Section 16-108.5, by April 1, 2012,
14provided that a participating utility shall not file its plan
15until the evaluation report on the Pilot Program described in
16this subsection (c) is issued. The AMI Plan shall provide for
17investment over a 10-year period that is sufficient to
18implement the AMI Plan across its entire service territory in a
19manner that is consistent with subsection (b) of Section
2016-108.5 of this Act. The AMI Plan shall contain:
21        (1) the participating utility's Smart Grid AMI vision
22    statement that is consistent with the goal of developing a
23    cost-beneficial Smart Grid;
24        (2) a statement of Smart Grid AMI strategy that
25    includes a description of how the utility evaluates and
26    prioritizes technology choices to create customer value,

 

 

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1    including a plan to enhance and enable customers' ability
2    to take advantage of Smart Grid functions beginning at the
3    time an account has billed successfully on the AMI network;
4        (3) a deployment schedule and plan that includes
5    deployment of AMI to all customers for a participating
6    utility other than a combination utility, and to 62% of all
7    customers for a participating utility that is a combination
8    utility;
9        (4) annual milestones and metrics for the purposes of
10    measuring the success of the AMI Plan in enabling Smart
11    Grid functions; and enhancing consumer benefits from Smart
12    Grid AMI; and
13        (5) a plan for the consumer education to be implemented
14    by the participating utility.
15    The AMI Plan shall be fully consistent with the standards
16of the National Institute of Standard and Technology (NIST) for
17Smart Grid interoperability that are in effect at the time the
18participating utility files its AMI Plan, shall include open
19standards and internet protocol to the maximum extent possible
20consistent with cyber security, and shall maximize, to the
21extent possible, a flexible smart meter platform that can
22accept remote device upgrades and contain sufficient internal
23memory capacity for additional storage capabilities, functions
24and services without the need for physical access to the meter.
25    The AMI Plan shall secure the privacy of personal
26information and establish the right of consumers to consent to

 

 

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1the disclosure of personal energy information to third parties
2through electronic, web-based, and other means in accordance
3with State and federal law and regulations regarding consumer
4privacy and protection of consumer data.
5    After notice and hearing, the Commission shall, within 60
6days of the filing of an AMI Plan, issue its order approving,
7or approving with modification, the AMI Plan if the Commission
8finds that the AMI Plan contains the information required in
9paragraphs (1) through (5) of this subsection (c) and further
10finds that the implementation of the AMI Plan will be
11cost-beneficial consistent with the principles established
12through the Illinois Smart Grid Collaborative, giving weight to
13the results of any Commission-approved pilot designed to
14examine the benefits and costs of AMI deployment. A
15participating utility's decision to invest pursuant to an AMI
16Plan approved by the Commission shall not be subject to
17prudence reviews in subsequent Commission proceedings. Nothing
18in this subsection (c) is intended to limit the Commission's
19ability to review the reasonableness of the costs incurred
20under the AMI Plan. A participating utility shall be allowed to
21recover the reasonable costs it incurs in implementing a
22Commission-approved AMI Plan, including the costs of retired
23meters, and may recover such costs through its tariffs,
24including the performance-based formula rate tariff approved
25pursuant to subsection (c) of Section 16-108.5 of this Act.
26    (d) The AMI Plan shall secure the privacy of the customer's

 

 

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1personal information. "Personal information" for this purpose
2consists of the customer's name, address, telephone number, and
3other personally identifying information, as well as
4information about the customer's electric usage. Electric
5utilities, their contractors or agents, and any third party who
6comes into possession of such personal information by virtue of
7working on Smart Grid technology shall not disclose such
8personal information to be used in mailing lists or to be used
9for other commercial purposes not reasonably related to the
10conduct of the utility's business. Electric utilities shall
11comply with the consumer privacy requirements of the Personal
12Information Protection Act. In the event a participating
13utility receives revenues from the sale of information obtained
14through Smart Grid technology that is not personal information,
15the participating utility shall use such revenues to offset the
16revenue requirement.
17    (e) On April 1 of each year beginning in 2013 and after
18consultation with the Smart Grid Advisory Council, each
19participating utility shall submit a report regarding the
20progress it has made toward completing implementation of its
21AMI Plan. This report shall:
22        (1) describe the AMI investments made during the prior
23    12 months and the AMI investments planned to be made in the
24    following 12 months;
25        (2) provide sufficient detail to determine the
26    utility's progress in meeting the metrics and milestones

 

 

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

 

 

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1shall include the verification statement in its final annual
2report. Following the date of a Commission order approving the
3final annual report or the date on which the final report is
4deemed accepted by the Commission, the utility's annual
5reporting obligations under this subsection (d) shall
6terminate, provided, however, that the utility shall have a
7continuing obligation to provide information, upon request, to
8the Commission and Smart Grid Advisory Council regarding the
9AMI Plan.
10    (f) Each participating utility shall pay a pro rata share,
11based on number of customers, of $5,000,000 per year to the
12trust or foundation established pursuant to Section 16-108.7 of
13this Act for each plan year of the AMI Plan, which shall be
14used for purposes of providing customer education regarding
15smart meters and related consumer-facing technologies and
16services and 70% of which shall be a recoverable expense;
17provided that other reasonable amounts expended by the utility
18for such consumer education shall not be subject to the 70%
19limitation of this subsection.
20    (g) Within 60 days after the Commission approves a
21participating utility's AMI Plan pursuant to subsection (c) of
22this Section, the participating utility, after consultation
23with the Smart Grid Advisory Council, shall file a proposed
24tariff with the Commission that offers an opt-in market-based
25peak time rebate program to all residential retail customers
26with smart meters that is designed to provide, in a

 

 

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1competitively neutral manner, rebates to those residential
2retail customers that curtail their use of electricity during
3specific periods that are identified as peak usage periods. The
4total amount of rebates shall be the amount of compensation the
5utility obtains through markets or programs at the applicable
6regional transmission organization. The utility shall make all
7reasonable attempts to secure funding for the peak time rebate
8program through markets or programs at the applicable regional
9transmission organization. The rules and procedures for
10consumers to opt-in to the peak time rebate program shall
11include electronic sign-up, be designed to maximize
12participation, and be included on the utility's website. The
13Commission shall monitor the performance of programs
14established pursuant to this subsection (g) and shall order the
15termination or modification of a program if it determines that
16the program is not, after a reasonable period of time for
17development of at least 4 years, resulting in net benefits to
18the residential customers of the participating utility.
19    (h) If Section 16-108.5 of this Act becomes inoperative
20with respect to one or more participating utilities as set
21forth in subsection (g) or (h) of that Section, then Sections
2216-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act shall
23become inoperative as to each affected utility and its service
24area on the same date as Section 16-108.5 becomes inoperative.
25(Source: 09700SB1652enr.)
 

 

 

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1    (220 ILCS 5/16-108.7)
2    Sec. 16-108.7. Illinois Science and Energy Innovation
3Trust.
4    (a) Within 90 days of the effective date of this amendatory
5Act of the 97th General Assembly, the members of the Smart Grid
6Advisory Council established pursuant to Section 16-108.6 of
7this Act, or a majority of the members thereof, shall cause to
8be established an Illinois science and energy innovation trust
9or foundation for the purposes of providing financial and
10technical support and assistance to entities, public or
11private, within the State of Illinois including, but not
12limited to, units of State and local government, educational
13and research institutions, corporations, and charitable,
14educational, environmental and community organizations, for
15programs and projects that support, encourage or utilize
16innovative technologies or other methods of modernizing the
17State's electric grid that will benefit the public by promoting
18economic development in Illinois. Such activities shall be
19supported through grants, loans, contracts, or other programs
20designed to assist and further benefit technological advances
21in the area of electric grid modernization and operation. The
22trust or foundation shall also be eligible for receipt of other
23energy and environmental grant opportunities, from public or
24private sources. The trust or foundation shall not be a
25governmental entity.
26    (b) Funds received by the trust or foundation pursuant to

 

 

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1subsection (f) of Section 16-108.6 of this Act shall be used
2solely for the purpose of providing consumer education
3regarding smart meters and related consumer-facing
4technologies and services and the peak time rebate program
5described in subsection (g) of Section 16-108.6 of this Act.
6Thirty percent of such funds received from each participating
7utility shall be used by the trust or foundation for purposes
8of providing such education to each participating utility's
9low-income retail customers, including low-income senior
10citizens.
11    The trust or foundation shall use all funds received
12pursuant to subsection (f) of Section 16-108.6 of this Act in a
13manner that reflects the unique needs and characteristics of
14each participating utility's service territory and in
15proportion to each participating utility's payment.
16    (c) Such trust or foundation shall be governed by a
17declaration of trust or articles of incorporation and bylaws
18which shall, at a minimum, provide the following:
19        (1) There shall initially be 9 7 trustees of the trust
20    or foundation, which shall consist of the members of the
21    Smart Grid Advisory Council established pursuant to
22    Section 16-108.6 of this Act. Subsequently, the
23    participating utilities shall appoint one trustee and the
24    Clean Energy Trust shall appoint one non-voting trustee who
25    shall provide expertise regarding early stage investment
26    in Smart Grid projects.

 

 

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1        (2) All trustees shall be entitled to reimbursement for
2    reasonable expenses incurred on behalf of the trust in the
3    performance of their duties as trustees. All such
4    reimbursements shall be paid out of the trust.
5        (3) Trustees shall be appointed within 60 days after
6    the creation of the trust or foundation and shall serve for
7    a term of 5 years commencing upon the date of their
8    respective appointments, until their respective successors
9    are appointed and qualified.
10        (4) A vacancy in the office of trustee shall be filled
11    by the person holding the office responsible for appointing
12    the trustee whose death or resignation creates the vacancy,
13    and a trustee appointed to fill a vacancy shall serve the
14    remainder of the term of the trustee whose resignation or
15    death created the vacancy.
16        (5) The trust or foundation shall have an indefinite
17    term and shall terminate at such time as no trust assets
18    remain.
19        (6) The allocation and disbursement of funds for the
20    various purposes for which the trust or foundation is
21    established shall be determined by the trustees in
22    accordance with the declaration of trust or the articles of
23    incorporation and bylaws.
24        (7) The trust or foundation shall be authorized to
25    employ an executive director and other employees, or
26    contract management of the trust or foundation in its

 

 

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1    entirety to an outside organization found suitable by the
2    trustees, to enter into leases, contracts and other
3    obligations on behalf of the trust or foundation, and to
4    incur expenses that the trustees deem necessary or
5    appropriate for the fulfillment of the purposes for which
6    the trust or foundation is established, provided, however,
7    that salaries and administrative expenses incurred on
8    behalf of the trust or foundation shall not exceed 3% of
9    the trust's principal value, or $750,000, whichever is
10    greater, in any given year. The trustees shall not be
11    compensated by the trust or foundation.
12        (8) The trustees may create and appoint advisory boards
13    or committees to assist them with the administration of the
14    trust or foundation, and to advise and make recommendations
15    to them regarding the contribution and disbursement of the
16    trust or foundation funds.
17        (9) All funds dispersed by the trust or foundation for
18    programs and projects to meet the objectives of the trust
19    or foundation as enumerated in this Section shall be
20    subject to a peer-review process as determined by the
21    trustees. This process shall be designed to determine, in
22    an objective and unbiased manner, those programs and
23    projects that best fit the objectives of the trust or
24    foundation. In each fiscal year the trustees shall
25    determine, based solely on the information provided
26    through the peer-review process, a budget for programs and

 

 

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1    projects for that fiscal year.
2        (10) The trustees shall administer a Smart Grid
3    education fund from which it shall make grants to qualified
4    not-for-profit organizations for the purpose of educating
5    customers with regard to smart meters and related
6    consumer-facing technologies and services. In making such
7    grants the trust or foundation shall strongly encourage
8    grantees to coordinate to the extent practicable and
9    consider recommendations from the participating utilities
10    regarding the development and implementation of customer
11    education plans.
12        (11) One of the objectives of the trust or foundation
13    is to remain self-funding. In order to meet this objective,
14    the trustees may sign agreements with those entities
15    receiving funding that provide for license fees,
16    royalties, or other payments to the trust or foundation
17    from such entities that receive support for their product
18    development from the trust or foundation. Such payments,
19    however, shall be contingent on the commercialization of
20    such products, services, or technologies enabled by the
21    funding provided by the trust or foundation.
22    (d) The trustees shall notify each participating utility as
23defined in Section 16-108.5 of this Act of the formation of the
24trust or foundation. Within 90 days after receipt of the
25notification, each participating utility that is not a
26combination utility as defined in Section 16-108.5 of this Act

 

 

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1shall contribute $15,000,000 to the trust or foundation, and
2each participating utility that is a combination utility, as
3defined in Section 16-108.5 of this Act, shall contribute
4$7,500,000 to the trust or foundation established pursuant to
5this Section. Such contributions shall not be a recoverable
6expense.
7    (e) If Section 16-108.5 of this Act becomes inoperative
8with respect to one or more participating utilities as set
9forth in subsection (g) or (h) of that Section, then Sections
1016-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act shall
11become inoperative as to each affected utility and its service
12area on the same date as Section 16-108.5 becomes inoperative.
13(Source: 09700SB1652enr.)
 
14    (220 ILCS 5/16-128)
15    Sec. 16-128. Provisions related to utility employees
16during the mandatory transition period.
17    (a) The General Assembly finds:
18        (1) The reliability and safety of the electric system
19    has depended and depends on a workforce of skilled and
20    dedicated employees, equipped with technical training and
21    experience.
22        (2) The integrity and reliability of the system also
23    requires the industry's commitment to invest in regular
24    inspection and maintenance, to assure that it can withstand
25    the demands of heavy service requirements and emergency

 

 

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1    situations.
2        (3) It is in the State's interest to protect the
3    interests of utility employees who have and continue to
4    dedicate themselves to assuring reliable service to the
5    citizens of this State, and who might otherwise be
6    economically displaced in a restructured industry.
7    The General Assembly further finds that it is necessary to
8assure that employees of electric utilities and employees of
9contractors or subcontractors performing work on behalf of an
10electric utility operating in the deregulated industry have the
11requisite skills, knowledge, training, experience, and
12competence to provide reliable and safe electrical service
13under this Act .
14    The General Assembly also finds that it is necessary to
15assure that employees of alternative retail electric suppliers
16and employees of contractors or subcontractors performing work
17on behalf of an alternative retail electric supplier operating
18in the deregulated industry have the requisite skills,
19knowledge, training, experience, and competence to provide
20reliable and safe electrical service under this Act.
21    To ensure that these findings and prerequisites for
22reliable and safe electrical service continue to prevail, each
23alternative retail electric supplier, electric utility, and
24contractors and subcontractors performing work on behalf of an
25electric utility or alternative retail electric supplier must
26demonstrate the competence of their respective employees to

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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1    (d) If a utility transfers ownership during the mandatory
2transition period of one or more Illinois divisions, business
3units, generating stations or generating units of an electric
4utility to a majority-owned subsidiary, that subsidiary shall
5continue to employ the utility's employees who were employed by
6the utility at such division, business unit or generating
7station at the time of the transfer under the same terms and
8conditions of employment as those employees enjoyed at the time
9of the transfer. If ownership of the subsidiary is subsequently
10sold or transferred to a third party during the transition
11period, the transition provisions outlined in subsection (c)
12shall apply.
13    (e) The plant transfer provisions set forth above shall not
14apply to any generating station which was the subject of a
15sales agreement entered into before January 1, 1997.
16(Source: P.A. 90-561, eff. 12-16-97; 09700SB1652enr.)
 
17    Section 99. Effective date. This Act takes effect upon
18becoming law.".