Rep. Kevin A. McCarthy

Filed: 10/25/2011

 

 


 

 


 
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1
AMENDMENT TO HOUSE BILL 690

2    AMENDMENT NO. ______. Amend House Bill 690 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 shall
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 construction ramp-up and ramp-down time to the
26investment periods specified in this subsection (b). For each

 

 

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1such investment period, the ramp-up and ramp-down time shall
2not exceed a total of 6 months.
3    Within 60 days after filing a tariff under subsection (c)
4of this Section, a participating utility shall submit to the
5Commission its plan, including scope, schedule, and staffing,
6for satisfying its infrastructure investment program
7commitments pursuant to this subsection (b). The submitted plan
8shall include a schedule and staffing plan for the next
9calendar year. The plan shall also include a plan for the
10creation, operation, and administration of a Smart Grid test
11bed as described in subsection (c) of Section 16-108.8. The
12plan need not allocate the work equally over the respective
13periods, but should allocate material increments throughout
14such periods commensurate with the work to be undertaken. No
15later than April 1 of each subsequent year, the utility shall
16submit to the Commission a report that includes any updates to
17the plan, a schedule for the next calendar year, the
18expenditures made for the prior calendar year and cumulatively,
19and the number of full-time equivalent jobs created for the
20prior calendar year and cumulatively. If the utility is
21materially deficient in satisfying a schedule or staffing plan,
22then the report must also include a corrective action plan to
23address the deficiency. The fact that the plan, implementation
24of the plan, or a schedule changes shall not imply the
25imprudence or unreasonableness of the infrastructure
26investment program, plan, or schedule. Further, no later than

 

 

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

 

 

09700HB0690ham001- 24 -LRB097 03518 CEL 59067 a

1program year that the Commission finds as set forth in this
2paragraph, the participating utility shall, within 30 days
3after the entry of the Commission's order, pay $6,000 $3,000 to
4a fund for training grants administered under Section 605-800
5of The Department of Commerce and Economic Opportunity Law,
6which shall not be a recoverable expense.
7    With respect to the participating utility's investment
8amount commitments, if, after considering the utility's
9corrective action plan and compliance thereunder, the
10Commission enters an order finding, after notice and hearing,
11that a participating utility is not satisfying its investment
12amount commitments described in this subsection (b), then the
13utility shall no longer be eligible to annually update the
14performance-based formula rate tariff pursuant to subsection
15(d) of this Section. In such event, the then current rates
16shall remain in effect until such time as new rates are set
17pursuant to Article IX of this Act, subject to retroactive
18adjustment, with interest, to reconcile rates charged with
19actual costs.
20    If the Commission finds that a participating utility is no
21longer eligible to update the performance-based formula rate
22tariff pursuant to subsection (d) of this Section, or the
23performance-based formula rate is otherwise terminated, then
24the participating utility's voluntary commitments and
25obligations under this subsection (b) shall immediately
26terminate, except for the utility's obligation to pay an amount

 

 

09700HB0690ham001- 25 -LRB097 03518 CEL 59067 a

1already owed to the fund for training grants pursuant to a
2Commission order.
3    In meeting the obligations of this subsection (b), to the
4extent feasible and consistent with State and federal law, the
5investments under the infrastructure investment program should
6provide employment opportunities for all segments of the
7population and workforce, including minority-owned and
8female-owned business enterprises, and shall not, consistent
9with State and federal law, discriminate based on race or
10socioeconomic status.
11    (b-5) Nothing in this Section shall prohibit the Commission
12from investigating the prudence and reasonableness of the
13expenditures made under the infrastructure investment program
14during the annual review required by subsection (d) of this
15Section and shall, as part of such investigation, determine
16whether the utility's actual costs under the program are
17prudent and reasonable. The fact that a participating utility
18invests more than the minimum amounts specified in subsection
19(b) of this Section or its plan shall not imply imprudence or
20unreasonableness.
21    If the participating utility finds that it is implementing
22its plan for satisfying the infrastructure investment program
23commitments described in subsection (b) of this Section at a
24cost below the estimated amounts specified in subsection (b) of
25this Section, then the utility may file a petition with the
26Commission requesting that it be permitted to satisfy its

 

 

09700HB0690ham001- 26 -LRB097 03518 CEL 59067 a

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

 

 

09700HB0690ham001- 27 -LRB097 03518 CEL 59067 a

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

 

 

09700HB0690ham001- 28 -LRB097 03518 CEL 59067 a

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

 

 

09700HB0690ham001- 29 -LRB097 03518 CEL 59067 a

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

 

 

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1with sufficient specificity to operate in a standardized manner
2and be updated annually with transparent information that
3reflects the utility's actual costs to be recovered during the
4applicable rate year, which is the period beginning with the
5first billing day of January and extending through the last
6billing day of the following December. In the event the utility
7recovers a portion of its costs through automatic adjustment
8clause tariffs on the effective date of this amendatory Act of
9the 97th General Assembly, the utility may elect to continue to
10recover these costs through such tariffs, but then these costs
11shall not be recovered through the performance-based formula
12rate. In the event the participating utility, prior to the
13effective date of this amendatory Act of the 97th General
14Assembly, filed electric delivery services tariffs with the
15Commission pursuant to Section 9-201 of this Act that are
16related to the recovery of its electric delivery services costs
17that are still pending on the effective date of this amendatory
18Act of the 97th General Assembly, the participating utility
19shall, at the time it files its performance-based formula rate
20tariff with the Commission, also file a notice of withdrawal
21with the Commission to withdraw the electric delivery services
22tariffs previously filed pursuant to Section 9-201 of this Act.
23Upon receipt of such notice, the Commission shall dismiss with
24prejudice any docket that had been initiated to investigate the
25electric delivery services tariffs filed pursuant to Section
269-201 of this Act, and such tariffs and the record related

 

 

09700HB0690ham001- 31 -LRB097 03518 CEL 59067 a

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

 

 

09700HB0690ham001- 32 -LRB097 03518 CEL 59067 a

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

 

 

09700HB0690ham001- 33 -LRB097 03518 CEL 59067 a

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

 

 

09700HB0690ham001- 34 -LRB097 03518 CEL 59067 a

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

 

 

09700HB0690ham001- 35 -LRB097 03518 CEL 59067 a

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

 

 

09700HB0690ham001- 36 -LRB097 03518 CEL 59067 a

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

 

 

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

 

 

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1modified, the performance-based formula rate, including the
2initial rates, as just and reasonable within 270 days after the
3date on which the tariff was filed, or, if the tariff is filed
4within 14 days after the effective date of this amendatory Act
5of the 97th General Assembly, then by May 31, 2012. Such review
6shall be based on the same evidentiary standards, including,
7but not limited to, those concerning the prudence and
8reasonableness of the costs incurred by the utility, the
9Commission applies in a hearing to review a filing for a
10general increase in rates under Article IX of this Act. The
11initial rates shall take effect within 30 days after the
12Commission's order approving the performance-based formula
13rate tariff.
14    Until such time as the Commission approves a different rate
15design and cost allocation pursuant to subsection (e) of this
16Section, rate design and cost allocation across customer
17classes shall be consistent with the Commission's most recent
18order regarding the participating utility's request for a
19general increase in its delivery services rates.
20    Subsequent changes to the performance-based formula rate
21structure or protocols shall be made as set forth in Section
229-201 of this Act, but nothing in this subsection (c) is
23intended to limit the Commission's authority under Article IX
24and other provisions of this Act to initiate an investigation
25of a participating utility's performance-based formula rate
26tariff, provided that any such changes shall be consistent with

 

 

09700HB0690ham001- 39 -LRB097 03518 CEL 59067 a

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

 

 

09700HB0690ham001- 40 -LRB097 03518 CEL 59067 a

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

 

 

09700HB0690ham001- 41 -LRB097 03518 CEL 59067 a

1    such calendar year (weighted, as applicable) with (ii) the
2    revenue requirement for that calendar year calculated
3    pursuant to the performance-based formula rate using (A)
4    actual costs for that year as reflected in the applicable
5    FERC Form 1, and (B) for the first such reconciliation
6    only, the cost of equity, which shall be calculated as the
7    sum of 590 basis points plus the average for the applicable
8    calendar year of the monthly average yields of 30-year U.S.
9    Treasury bonds published by the Board of Governors of the
10    Federal Reserve System in its weekly H.15 Statistical
11    Release or successor publication approved by the
12    Commission in such order or orders in effect during that
13    year (weighted, as applicable). The first such
14    reconciliation is not intended to provide for the recovery
15    of costs previously excluded from rates based on a prior
16    Commission order finding of imprudence or
17    unreasonableness. Each reconciliation shall be certified
18    by the participating utility in the same manner that FERC
19    Form 1 is certified. The filing shall also include the
20    charge or credit, if any, resulting from the calculation
21    required by paragraph (6) of subsection (c) of this
22    Section.
23        Notwithstanding anything that may be to the contrary,
24    the intent of the reconciliation is to ultimately reconcile
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        (2) The new charges shall take effect beginning on the
7    first billing day of the following January billing period
8    and remain in effect through the last billing day of the
9    next December billing period regardless of whether the
10    Commission enters upon a hearing pursuant to this
11    subsection (d).
12        (3) The filing shall include relevant and necessary
13    data and documentation for the applicable rate year that is
14    consistent with the Commission's rules applicable to a
15    filing for a general increase in rates or any rules adopted
16    by the Commission to implement this Section. Normalization
17    adjustments shall not be required. Notwithstanding any
18    other provision of this Section or Act or any rule or other
19    requirement adopted by the Commission, a participating
20    utility that is a combination utility with more than one
21    rate zone shall not be required to file a separate set of
22    such data and documentation for each rate zone and may
23    combine such data and documentation into a single set of
24    schedules.
25    Within 45 days after the utility files its annual update of
26cost inputs to the performance-based formula rate, the

 

 

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1Commission shall have the authority, either upon complaint or
2its own initiative, but with reasonable notice, to enter upon a
3hearing concerning the prudence and reasonableness of the costs
4incurred by the utility to be recovered during the applicable
5rate year that are reflected in the inputs to the
6performance-based formula rate derived from the utility's FERC
7Form 1. During the course of the hearing, each objection shall
8be stated with particularity and evidence provided in support
9thereof, after which the utility shall have the opportunity to
10rebut the evidence. Discovery shall be allowed consistent with
11the Commission's Rules of Practice, which Rules shall be
12enforced by the Commission or the assigned hearing examiner.
13The Commission shall apply the same evidentiary standards,
14including, but not limited to, those concerning the prudence
15and reasonableness of the costs incurred by the utility, in the
16hearing as it would apply in a hearing to review a filing for a
17general increase in rates under Article IX of this Act. The
18Commission shall not, however, have the authority in a
19proceeding under this subsection (d) to consider or order any
20changes to the structure or protocols of the performance-based
21formula rate approved pursuant to subsection (c) of this
22Section. In a proceeding under this subsection (d), the
23Commission shall enter its order no later than the earlier of
24240 days after the utility's filing of its annual update of
25cost inputs to the performance-based formula rate or December
2631. The Commission's determinations of the prudence and

 

 

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

 

 

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1placed into effect for the utility. Following approval of a
2participating utility's performance-based formula rate tariff
3pursuant to subsection (c) of this Section, the utility shall
4make a filing with the Commission within one year after the
5effective date of the performance-based formula rate tariff
6that proposes changes to the tariff to incorporate the findings
7of any final rate design orders of the Commission applicable to
8the participating utility and entered subsequent to the
9Commission's approval of the tariff. The Commission shall,
10after notice and hearing, enter its order approving, or
11approving with modification, the proposed changes to the
12performance-based formula rate tariff within 240 days after the
13utility's filing. Following such approval, the utility shall
14make a filing with the Commission during each subsequent 3-year
15period that either proposes revenue-neutral tariff changes or
16re-files the existing tariffs without change, which shall
17present the Commission with an opportunity to suspend the
18tariffs and consider revenue-neutral tariff changes related to
19rate design.
20    (f) Within 30 days after the filing of a tariff pursuant to
21subsection (c) of this Section, each participating utility
22shall develop and file with the Commission multi-year metrics
23designed to achieve, ratably (i.e., in equal segments) over a
2410-year period, improvement over baseline performance values
25as follows:
26        (1) Twenty percent improvement in the System Average

 

 

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

 

 

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

 

 

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1    percentage of the participating utility's capital
2    expenditures that were paid to minority-owned and
3    female-owned business enterprises in 2010.
4    The definitions set forth in 83 Ill. Admin. Code Part
5411.20 as of May 1, 2011 shall be used for purposes of
6calculating performance under paragraphs (1) through (3.5) (3)
7of this subsection (f), provided, however, that the
8participating utility may exclude up to 9 extreme weather event
9days from such calculation for each year, and provided further
10that the participating utility shall exclude 9 extreme weather
11event days when calculating each year of the baseline period to
12the extent that there are 9 such days in a given year of the
13baseline period. For purposes of this Section, an extreme
14weather event day is a 24-hour calendar day (beginning at 12:00
15a.m. and ending at 11:59 p.m.) during which any weather event
16(e.g., storm, tornado) caused interruptions for 10,000 or more
17of the participating utility's customers for 3 hours or more.
18If there are more than 9 extreme weather event days in a year,
19then the utility may choose no more than 9 extreme weather
20event days to exclude, provided that the same extreme weather
21event days are excluded from each of the calculations performed
22under paragraphs (1) through (3.5) (3) of this subsection (f).
23    The metrics shall include incremental performance goals
24for each year of the 10-year period, which shall be designed to
25demonstrate that the utility is on track to achieve the
26performance goal in each category at the end of the 10-year

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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1the imposition of financial penalties for failing to achieve
2one or more of the metrics established pursuant to subparagraph
3(1) through (4) of subsection (f) of this Section.
4    (g) On or before July 31, 2014, each participating utility
5shall file a report with the Commission that sets forth the
6average annual increase in the average amount paid per
7kilowatthour for residential eligible retail customers,
8exclusive of the effects of energy efficiency programs,
9comparing the 12-month period ending May 31, 2012; the 12-month
10period ending May 31, 2013; and the 12-month period ending May
1131, 2014. For a participating utility that is a combination
12utility with more than one rate zone, the weighted average
13aggregate increase shall be provided. The report shall be filed
14together with a statement from an independent auditor attesting
15to the accuracy of the report. The cost of the independent
16auditor shall be borne by the participating utility and shall
17not be a recoverable expense.
18    In the event that the average annual increase exceeds 2.5%
19as calculated pursuant to this subsection (g), then Sections
2016-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act, other
21than this subsection, shall be inoperative as they relate to
22the utility and its service area as of the date of the report
23due to be submitted pursuant to this subsection and the utility
24shall no longer be eligible to annually update the
25performance-based formula rate tariff pursuant to subsection
26(d) of this Section. In such event, the then current rates

 

 

09700HB0690ham001- 55 -LRB097 03518 CEL 59067 a

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

 

 

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1reasonableness determinations already made.
2    (h) Sections 16-108.5, 16-108.6, 16-108.7, and 16-108.8 of
3this Act, other than this subsection, are inoperative after
4December 31, 2017 for every participating utility, after which
5time a participating utility shall no longer be eligible to
6annually update the performance-based formula rate tariff
7pursuant to subsection (d) of this Section. At such time, the
8then current rates shall remain in effect until such time as
9new rates are set pursuant to Article IX of this Act, subject
10to retroactive adjustment, with interest, to reconcile rates
11charged with actual costs.
12    By December 31, 2017, the Commission shall prepare and file
13with the General Assembly a report on the infrastructure
14program and the performance-based formula rate. The report
15shall include the change in the average amount per kilowatthour
16paid by residential customers between June 1, 2011 and May 31,
172017. If the change in the total average rate paid exceeds 2.5%
18compounded annually, the Commission shall include in the report
19an analysis that shows the portion of the change due to the
20delivery services component and the portion of the change due
21to the supply component of the rate. The report shall include
22separate sections for each participating utility.
23    In the event Sections 16-108.5, 16-108.6, 16-108.7, and
2416-108.8 of this Act do not become inoperative after December
2531, 2017, then these Sections are inoperative after December
2631, 2022 for every participating utility, after which time a

 

 

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1participating utility shall no longer be eligible to annually
2update the performance-based formula rate tariff pursuant to
3subsection (d) of this Section. At such time, the then current
4rates shall remain in effect until such time as new rates are
5set pursuant to Article IX of this Act, subject to retroactive
6adjustment, with interest, to reconcile rates charged with
7actual costs.
8    The fact that this Section becomes inoperative as set forth
9in this subsection shall not be construed to mean that the
10Commission may reexamine or otherwise reopen prudence or
11reasonableness determinations already made.
12    (i) While a participating utility may use, develop, and
13maintain broadband systems and the delivery of broadband
14services, voice-over-internet-protocol services,
15telecommunications services, and cable and video programming
16services for use in providing delivery services and Smart Grid
17functionality or application to its retail customers,
18including, but not limited to, the installation,
19implementation and maintenance of Smart Grid electric system
20upgrades as defined in Section 16-108.6 of this Act, a
21participating utility is prohibited from offering to its retail
22customers broadband services or the delivery of broadband
23services, voice-over-internet-protocol services,
24telecommunications services, or cable or video programming
25services, unless they are part of a service directly related to
26delivery services or Smart Grid functionality or applications

 

 

09700HB0690ham001- 58 -LRB097 03518 CEL 59067 a

1as defined in Section 16-108.6 of this Act, and from recovering
2the costs of such offerings from retail customers.
3    (j) Nothing in this Section is intended to legislatively
4overturn the opinion issued in Commonwealth Edison Co. v. Ill.
5Commerce Comm'n, Nos. 2-08-0959, 2-08-1037, 2-08-1137,
61-08-3008, 1-08-3030, 1-08-3054, 1-08-3313 cons. (Ill. App.
7Ct. 2d Dist. Sept. 30, 2010). This amendatory Act of the 97th
8General Assembly shall not be construed as creating a contract
9between the General Assembly and the participating utility, and
10shall not establish a property right in the participating
11utility.
12(Source: 09700SB1652enr.)
 
13    (220 ILCS 5/16-108.6)
14    Sec. 16-108.6. Provisions relating to Smart Grid Advanced
15Metering Infrastructure Deployment Plan.
16    (a) For purposes of this Section and Sections 16-108.7 and
1716-108.8 of this Act:
18    "Advanced Metering Infrastructure" or "AMI" means the
19communications hardware and software and associated system
20software that enables Smart Grid functions by creating a
21network between advanced meters and utility business systems
22and allowing collection and distribution of information to
23customers and other parties in addition to providing
24information to the utility itself.
25    "Cost-beneficial" means a determination that the benefits

 

 

09700HB0690ham001- 59 -LRB097 03518 CEL 59067 a

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

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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1Advisory Council shall be established, which shall consist of 9
27 total voting members with each member possessing either
3technical, business or consumer expertise in Smart Grid issues,
45 of whom shall be appointed by and each having been the single
5appointment of one of the following: the Governor, one of whom
6shall be appointed by the Speaker of the House, one of whom
7shall be appointed by the Minority Leader of the House, one of
8whom shall be appointed by the President of the Senate, and one
9of whom shall be appointed by the Minority Leader of the
10Senate. Of the Governor's 5 appointments: (i) at least one must
11represent a non-profit membership organization whose mission
12is to cultivate innovation and technology-based economic
13development in Illinois by fostering public-private
14partnerships to develop and execute research and development
15projects, advocating for funding for research and development
16initiatives, and collaborating with public and private
17partners to attract and retain research and development
18resources and talent in Illinois; (ii) at least one must
19represent a non-profit public body corporate and politic
20created by law that has a duty to represent and protect
21residential utility consumers in Illinois; (iii) at least one
22must represent a membership organization that represents the
23interests of individuals and companies that own, operate,
24manage, and service commercial buildings in a municipality with
25a population of 1,000,000 or more inhabitants; (iv) at least
26one must represent an alternative retail electric supplier that

 

 

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1has obtained a certificate of service authority pursuant to
2Section 16-115 of this Act and that is not an affiliate of a
3participating utility prior to one year after the effective
4date of this amendatory Act of the 97th General Assembly , the
5Illinois Science and Technology Coalition, and the Citizens
6Utility Board.
7    The Governor shall designate one of the members of the
8Council to serve as chairman, and that person shall serve as
9the chairman at the pleasure of the Governor. The members shall
10not be compensated for serving on the Smart Grid Advisory
11Council. The Smart Grid Advisory Council shall have the
12following duties:
13        (1) Serve as an advisor to participating utilities
14    subject to this Section and in the manner described in this
15    Section, and the recommendations provided by the Council,
16    although non-binding, shall be considered by the
17    utilities.
18        (2) Serve as trustees of the trust or foundation
19    established pursuant to Section 16-108.7 of this Act with
20    the duties enumerated thereunder.
21    (c) After consultation with the Smart Grid Advisory
22Council, each participating utility shall file a Smart Grid
23Advanced Metering Infrastructure Deployment Plan ("AMI Plan")
24with the Commission within 180 days after the effective date of
25this amendatory Act of the 97th General Assembly or by November
261, 2011, whichever is later, or in the case of a combination

 

 

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1utility as defined in Section 16-108.5, by April 1, 2012,
2provided that a participating utility shall not file its plan
3until the evaluation report on the Pilot Program described in
4this subsection (c) is issued. The AMI Plan shall provide for
5investment over a 10-year period that is sufficient to
6implement the AMI Plan across its entire service territory in a
7manner that is consistent with subsection (b) of Section
816-108.5 of this Act. The AMI Plan shall contain:
9        (1) the participating utility's Smart Grid AMI vision
10    statement that is consistent with the goal of developing a
11    cost-beneficial Smart Grid;
12        (2) a statement of Smart Grid AMI strategy that
13    includes a description of how the utility evaluates and
14    prioritizes technology choices to create customer value,
15    including a plan to enhance and enable customers' ability
16    to take advantage of Smart Grid functions beginning at the
17    time an account has billed successfully on the AMI network;
18        (3) a deployment schedule and plan that includes
19    deployment of AMI to all customers for a participating
20    utility other than a combination utility, and to 62% of all
21    customers for a participating utility that is a combination
22    utility;
23        (4) annual milestones and metrics for the purposes of
24    measuring the success of the AMI Plan in enabling Smart
25    Grid functions; and enhancing consumer benefits from Smart
26    Grid AMI; and

 

 

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1        (5) a plan for the consumer education to be implemented
2    by the participating utility.
3    The AMI Plan shall be fully consistent with the standards
4of the National Institute of Standard and Technology (NIST) for
5Smart Grid interoperability that are in effect at the time the
6participating utility files its AMI Plan, shall include open
7standards and internet protocol to the maximum extent possible
8consistent with cyber security, and shall maximize, to the
9extent possible, a flexible smart meter platform that can
10accept remote device upgrades and contain sufficient internal
11memory capacity for additional storage capabilities, functions
12and services without the need for physical access to the meter.
13    The AMI Plan shall secure the privacy of personal
14information and establish the right of consumers to consent to
15the disclosure of personal energy information to third parties
16through electronic, web-based, and other means in accordance
17with State and federal law and regulations regarding consumer
18privacy and protection of consumer data.
19    After notice and hearing, the Commission shall, within 60
20days of the filing of an AMI Plan, issue its order approving,
21or approving with modification, the AMI Plan if the Commission
22finds that the AMI Plan contains the information required in
23paragraphs (1) through (5) of this subsection (c) and further
24finds that the implementation of the AMI Plan will be
25cost-beneficial consistent with the principles established
26through the Illinois Smart Grid Collaborative, giving weight to

 

 

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

 

 

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1utility receives revenues from the sale of information obtained
2through Smart Grid technology that is not personal information,
3the participating utility shall use such revenues to offset the
4revenue requirement.
5    (e) On April 1 of each year beginning in 2013 and after
6consultation with the Smart Grid Advisory Council, each
7participating utility shall submit a report regarding the
8progress it has made toward completing implementation of its
9AMI Plan. This report shall:
10        (1) describe the AMI investments made during the prior
11    12 months and the AMI investments planned to be made in the
12    following 12 months;
13        (2) provide sufficient detail to determine the
14    utility's progress in meeting the metrics and milestones
15    identified by the utility in its AMI Plan; and
16        (3) identify any updates to the AMI Plan.
17    Within 21 days after the utility files its annual report,
18the Commission shall have authority, either upon complaint or
19its own initiative, but with reasonable notice, to enter upon
20an investigation regarding the utility's progress in
21implementing the AMI Plan as described in paragraph (1) of this
22subsection (e). If the Commission finds, after notice and
23hearing, that the participating utility's progress in
24implementing the AMI Plan is materially deficient for the given
25plan year, then the Commission shall issue an order requiring
26the participating utility to devise a corrective action plan,

 

 

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1subject to Commission approval and oversight, to bring
2implementation back on schedule consistent with the AMI Plan.
3The Commission's order must be entered within 90 days after the
4utility files its annual report. If the Commission does not
5initiate an investigation within 21 days after the utility
6files its annual report, then the filing shall be deemed
7accepted by the Commission. The utility shall not be required
8to suspend implementation of its AMI Plan during any Commission
9investigation.
10    The participating utility's annual report regarding AMI
11Plan year 10 shall contain a statement verifying that the
12implementation of its AMI Plan is complete, provided, however,
13that if the utility is subject to a corrective action plan that
14extends the implementation period beyond 10 years, the utility
15shall include the verification statement in its final annual
16report. Following the date of a Commission order approving the
17final annual report or the date on which the final report is
18deemed accepted by the Commission, the utility's annual
19reporting obligations under this subsection (d) shall
20terminate, provided, however, that the utility shall have a
21continuing obligation to provide information, upon request, to
22the Commission and Smart Grid Advisory Council regarding the
23AMI Plan.
24    (f) Each participating utility shall pay a pro rata share,
25based on number of customers, of $5,000,000 per year to the
26trust or foundation established pursuant to Section 16-108.7 of

 

 

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1this Act for each plan year of the AMI Plan, which shall be
2used for purposes of providing customer education regarding
3smart meters and related consumer-facing technologies and
4services and 70% of which shall be a recoverable expense;
5provided that other reasonable amounts expended by the utility
6for such consumer education shall not be subject to the 70%
7limitation of this subsection.
8    (g) Within 60 days after the Commission approves a
9participating utility's AMI Plan pursuant to subsection (c) of
10this Section, the participating utility, after consultation
11with the Smart Grid Advisory Council, shall file a proposed
12tariff with the Commission that offers an opt-in market-based
13peak time rebate program to all residential retail customers
14with smart meters that is designed to provide, in a
15competitively neutral manner, rebates to those residential
16retail customers that curtail their use of electricity during
17specific periods that are identified as peak usage periods. The
18total amount of rebates shall be the amount of compensation the
19utility obtains through markets or programs at the applicable
20regional transmission organization. The utility shall make all
21reasonable attempts to secure funding for the peak time rebate
22program through markets or programs at the applicable regional
23transmission organization. The rules and procedures for
24consumers to opt-in to the peak time rebate program shall
25include electronic sign-up, be designed to maximize
26participation, and be included on the utility's website. The

 

 

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1Commission shall monitor the performance of programs
2established pursuant to this subsection (g) and shall order the
3termination or modification of a program if it determines that
4the program is not, after a reasonable period of time for
5development of at least 4 years, resulting in net benefits to
6the residential customers of the participating utility.
7    (h) 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 5/16-108.7)
15    Sec. 16-108.7. Illinois Science and Energy Innovation
16Trust.
17    (a) Within 90 days of the effective date of this amendatory
18Act of the 97th General Assembly, the members of the Smart Grid
19Advisory Council established pursuant to Section 16-108.6 of
20this Act, or a majority of the members thereof, shall cause to
21be established an Illinois science and energy innovation trust
22or foundation for the purposes of providing financial and
23technical support and assistance to entities, public or
24private, within the State of Illinois including, but not
25limited to, units of State and local government, educational

 

 

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1and research institutions, corporations, and charitable,
2educational, environmental and community organizations, for
3programs and projects that support, encourage or utilize
4innovative technologies or other methods of modernizing the
5State's electric grid that will benefit the public by promoting
6economic development in Illinois. Such activities shall be
7supported through grants, loans, contracts, or other programs
8designed to assist and further benefit technological advances
9in the area of electric grid modernization and operation. The
10trust or foundation shall also be eligible for receipt of other
11energy and environmental grant opportunities, from public or
12private sources. The trust or foundation shall not be a
13governmental entity.
14    (b) Funds received by the trust or foundation pursuant to
15subsection (f) of Section 16-108.6 of this Act shall be used
16solely for the purpose of providing consumer education
17regarding smart meters and related consumer-facing
18technologies and services and the peak time rebate program
19described in subsection (g) of Section 16-108.6 of this Act.
20Thirty percent of such funds received from each participating
21utility shall be used by the trust or foundation for purposes
22of providing such education to each participating utility's
23low-income retail customers, including low-income senior
24citizens.
25    The trust or foundation shall use all funds received
26pursuant to subsection (f) of Section 16-108.6 of this Act in a

 

 

09700HB0690ham001- 74 -LRB097 03518 CEL 59067 a

1manner that reflects the unique needs and characteristics of
2each participating utility's service territory and in
3proportion to each participating utility's payment.
4    (c) Such trust or foundation shall be governed by a
5declaration of trust or articles of incorporation and bylaws
6which shall, at a minimum, provide the following:
7        (1) There shall initially be 9 7 trustees of the trust
8    or foundation, which shall consist of the members of the
9    Smart Grid Advisory Council established pursuant to
10    Section 16-108.6 of this Act. Subsequently, the
11    participating utilities shall appoint one trustee and the
12    Clean Energy Trust shall appoint one non-voting trustee who
13    shall provide expertise regarding early stage investment
14    in Smart Grid projects.
15        (2) All trustees shall be entitled to reimbursement for
16    reasonable expenses incurred on behalf of the trust in the
17    performance of their duties as trustees. All such
18    reimbursements shall be paid out of the trust.
19        (3) Trustees shall be appointed within 60 days after
20    the creation of the trust or foundation and shall serve for
21    a term of 5 years commencing upon the date of their
22    respective appointments, until their respective successors
23    are appointed and qualified.
24        (4) A vacancy in the office of trustee shall be filled
25    by the person holding the office responsible for appointing
26    the trustee whose death or resignation creates the vacancy,

 

 

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

 

 

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

 

 

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1    is to remain self-funding. In order to meet this objective,
2    the trustees may sign agreements with those entities
3    receiving funding that provide for license fees,
4    royalties, or other payments to the trust or foundation
5    from such entities that receive support for their product
6    development from the trust or foundation. Such payments,
7    however, shall be contingent on the commercialization of
8    such products, services, or technologies enabled by the
9    funding provided by the trust or foundation.
10    (d) The trustees shall notify each participating utility as
11defined in Section 16-108.5 of this Act of the formation of the
12trust or foundation. Within 90 days after receipt of the
13notification, each participating utility that is not a
14combination utility as defined in Section 16-108.5 of this Act
15shall contribute $15,000,000 to the trust or foundation, and
16each participating utility that is a combination utility, as
17defined in Section 16-108.5 of this Act, shall contribute
18$7,500,000 to the trust or foundation established pursuant to
19this Section. Such contributions shall not be a recoverable
20expense.
21    (e) If Section 16-108.5 of this Act becomes inoperative
22with respect to one or more participating utilities as set
23forth in subsection (g) or (h) of that Section, then Sections
2416-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act shall
25become inoperative as to each affected utility and its service
26area on the same date as Section 16-108.5 becomes inoperative.

 

 

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1(Source: 09700SB1652enr.)
 
2    (220 ILCS 5/16-128)
3    Sec. 16-128. Provisions related to utility employees
4during the mandatory transition period.
5    (a) The General Assembly finds:
6        (1) The reliability and safety of the electric system
7    has depended and depends on a workforce of skilled and
8    dedicated employees, equipped with technical training and
9    experience.
10        (2) The integrity and reliability of the system also
11    requires the industry's commitment to invest in regular
12    inspection and maintenance, to assure that it can withstand
13    the demands of heavy service requirements and emergency
14    situations.
15        (3) It is in the State's interest to protect the
16    interests of utility employees who have and continue to
17    dedicate themselves to assuring reliable service to the
18    citizens of this State, and who might otherwise be
19    economically displaced in a restructured industry.
20    The General Assembly further finds that it is necessary to
21assure that employees of electric utilities and employees of
22contractors or subcontractors performing work on behalf of an
23electric utility operating in the deregulated industry have the
24requisite skills, knowledge, training, experience, and
25competence to provide reliable and safe electrical service

 

 

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1under this Act .
2    The General Assembly also finds that it is necessary to
3assure that employees of alternative retail electric suppliers
4and employees of contractors or subcontractors performing work
5on behalf of an alternative retail electric supplier operating
6in the deregulated industry have the requisite skills,
7knowledge, training, experience, and competence to provide
8reliable and safe electrical service under this Act.
9    To ensure that these findings and prerequisites for
10reliable and safe electrical service continue to prevail, each
11alternative retail electric supplier, electric utility, and
12contractors and subcontractors performing work on behalf of an
13electric utility or alternative retail electric supplier must
14demonstrate the competence of their respective employees to
15work on the distribution system.
16    The knowledge, skill, training, experience, and competence
17levels to be demonstrated shall be consistent with those
18required of or by the electric utilities in this State as of
19January 1, 2007, with respect to their employees and employees
20of contractors or subcontractors performing work on their
21behalf. Nothing in this Section shall prohibit an electric
22utility from establishing knowledge, skill, training,
23experience, and competence levels greater than those required
24as of January 1, 2007.
25    An adequate demonstration of requisite knowledge, skill,
26training, experience, and competence shall include, at a

 

 

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1minimum, completion or current participation and ultimate
2completion by the employee of an accredited or otherwise
3recognized apprenticeship program for the particular craft,
4trade or skill, or specified and several years of employment
5performing a particular work function that is utilized by an
6electric utility.
7    Notwithstanding any law, tariff, Commission rule, order,
8or decision to the contrary, the Commission shall have an
9affirmative statutory obligation to ensure that an electric
10utility is employing employees, contractors, and
11subcontractors with employees who meet the requirements of
12subsection (a) of this Section when installing, constructing,
13operating, and maintaining generation, transmission, or
14distribution facilities and equipment within this State
15pursuant to any provision in this Act or any Commission order,
16rule, or decision.
17    For purposes of this Section, "distribution facilities and
18equipment" means any and all of the facilities and equipment,
19including, but not limited to, substations, distribution
20feeder circuits, switches, meters, protective equipment,
21primary circuits, distribution transformers, line extensions
22and service extensions both above or below ground, conduit,
23risers, elbows, transformer pads, junction boxes, manholes,
24pedestals, conductors, and all associated fittings that
25connect the transmission or distribution system to either the
26weatherhead on the retail customer's building or other

 

 

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1structure for above ground service or to the terminals on the
2meter base of the retail customer's building or other structure
3for below ground service.
4    To implement this requirement for alternative retail
5electric suppliers, the Commission, in determining that an
6applicant meets the standards for certification as an
7alternative retail electric supplier, shall require the
8applicant to demonstrate (i) that the applicant is licensed to
9do business, and bonded, in the State of Illinois; and (ii)
10that the employees of the applicant that will be installing,
11operating, and maintaining generation, transmission, or
12distribution facilities within this State, or any entity with
13which the applicant has contracted to perform those functions
14within this State, have the requisite knowledge, skills,
15training, experience, and competence to perform those
16functions in a safe and responsible manner in order to provide
17safe and reliable service, in accordance with the criteria
18stated above.
19    (b) The General Assembly finds, based on experience in
20other industries that have undergone similar transitions, that
21the introduction of competition into the State's electric
22utility industry may result in workforce reductions by electric
23utilities which may adversely affect persons who have been
24employed by this State's electric utilities in functions
25important to the public convenience and welfare. The General
26Assembly further finds that the impacts on employees and their

 

 

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1communities of any necessary reductions in the utility
2workforce directly caused by this restructuring of the electric
3industry shall be mitigated to the extent practicable through
4such means as offers of voluntary severance, retraining, early
5retirement, outplacement and related benefits. Therefore,
6before any such reduction in the workforce during the
7transition period, an electric utility shall present to its
8employees or their representatives a workforce reduction plan
9outlining the means by which the electric utility intends to
10mitigate the impact of such workforce reduction on its
11employees.
12    (c) In the event of a sale, purchase, or any other transfer
13of ownership during the mandatory transition period of one or
14more Illinois divisions or business units, and/or generating
15stations or generating units, of an electric utility, the
16electric utility's contract and/or agreements with the
17acquiring entity or persons shall require that the entity or
18persons hire a sufficient number of non-supervisory employees
19to operate and maintain the station, division or unit by
20initially making offers of employment to the non-supervisory
21workforce of the electric utility's division, business unit,
22generating station and/or generating unit at no less than the
23wage rates, and substantially equivalent fringe benefits and
24terms and conditions of employment that are in effect at the
25time of transfer of ownership of said division, business unit,
26generating station, and/or generating units; and said wage

 

 

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1rates and substantially equivalent fringe benefits and terms
2and conditions of employment shall continue for at least 30
3months from the time of said transfer of ownership unless the
4parties mutually agree to different terms and conditions of
5employment within that 30-month period. The utility shall offer
6a transition plan to those employees who are not offered jobs
7by the acquiring entity because that entity has a need for
8fewer workers. If there is litigation concerning the sale, or
9other transfer of ownership of the electric utility's
10divisions, business units, generating station, or generating
11units, the 30-month period will begin on the date the acquiring
12entity or persons take control or management of the divisions,
13business units, generating station or generating units of the
14electric utility.
15    (d) If a utility transfers ownership during the mandatory
16transition period of one or more Illinois divisions, business
17units, generating stations or generating units of an electric
18utility to a majority-owned subsidiary, that subsidiary shall
19continue to employ the utility's employees who were employed by
20the utility at such division, business unit or generating
21station at the time of the transfer under the same terms and
22conditions of employment as those employees enjoyed at the time
23of the transfer. If ownership of the subsidiary is subsequently
24sold or transferred to a third party during the transition
25period, the transition provisions outlined in subsection (c)
26shall apply.

 

 

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1    (e) The plant transfer provisions set forth above shall not
2apply to any generating station which was the subject of a
3sales agreement entered into before January 1, 1997.
4(Source: P.A. 90-561, eff. 12-16-97; 09700SB1652enr.)
 
5    Section 99. Effective date. This Act takes effect upon
6becoming law.".