101ST GENERAL ASSEMBLY
State of Illinois
2019 and 2020
SB3977

 

Introduced 2/21/2020, by Sen. Christopher Belt

 

SYNOPSIS AS INTRODUCED:
 
See Index

    Amends the Illinois Power Agency Act. For electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers in this State: defines "energy efficiency"; in provisions concerning the renewable portfolio standards, specifies the goals for procurement of renewable energy credits and cost-effective renewable energy resources that shall be included in the long-term renewable resources procurement plan and makes other changes concerning these procurements; and provides for the calculation of the cost of equity for the purposes of recovering all reasonable and prudently incurred costs of energy efficiency measures from retail customers. Provides that savings of fuels other than electricity achieved by measures that educate about, incentivize, encourage or otherwise support the use of electricity to power vehicles shall count towards the applicable annual incremental goal and shall not be included in determining certain limits. Amends the Public Utilities Act. Provides that an electric utility that serves less than 3,000,000 retail customers but more than 500,000 customers in this State may plan for, construct, install, control, own, manage, or operate photovoltaic electricity production facilities and any energy storage facilities that are planned for, constructed, installed, controlled, owned, managed or operated in connection with photovoltaic electricity production facilities without obtaining a certificate of public convenience and necessity subject to specified terms and conditions. Defines "electric vehicle", "electric vehicle charging station", and "energy storage" for the purposes of the Electric Service Customer Choice and Rate Relief Law of 1997. Provides that, beginning in 2022, without obtaining any approvals from the Illinois Commerce Commission or any other agency, regardless of whether any such approval would otherwise be required, a participating utility that is a combination utility shall pay $1,000,000 per year for 10 years to the energy low-income and support program. Adds provisions authorizing certain utilities to plan for, construct, install, control, own, manage or operate electric vehicle charging infrastructure, including, but not limited to, electric vehicle charging stations within their service territories. Effective immediately.


LRB101 20818 JLS 70537 b

 

 

A BILL FOR

 

SB3977LRB101 20818 JLS 70537 b

1    AN ACT concerning regulation.
 
2    Be it enacted by the People of the State of Illinois,
3represented in the General Assembly:
 
4    Section 1. Findings.
5    (a) Over the last decade, the General Assembly has
6empowered the State of Illinois to become a national leader in
7the implementation of a progressive energy policy. The General
8Assembly has enacted laws to increase investment in equitable
9energy efficiency, clean and renewable energy, and continued
10modernization of the electric grid. The General Assembly has
11further encouraged and enabled investment in the clean energy
12economy in Illinois to ensure that the State and its citizens,
13including low-income individuals, are equipped to enjoy the
14opportunities and benefits of a smart grid and smart metering
15infrastructure platform, adopt and deploy cost-effective
16distributed energy resource technologies and devices, and
17benefit from investments in job training and job creation. To
18ensure this progress can be sustained, the General Assembly
19finds and declares the following:
20        (1) The State of Illinois is a geographically large and
21    diverse State and communities in central and southern
22    Illinois have different strengths and needs than those in
23    the northern region of the State.
24        (2) The changing energy marketplace is having a

 

 

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1    measurable effect on employment, economic development,
2    business growth, non-profit health, school funding, local
3    government stability, and community development in central
4    and southern Illinois, and updated policies are needed to
5    address those impacts.
6        (3) The State should accelerate the development and
7    adoption of technologies and facilities in central and
8    southern Illinois so that there are greater opportunities
9    for investment in clean energy, electric vehicles, energy
10    storage facilities, management of peak load, and grid
11    stability and reliability.
12        (4) Continuing the transparent, predictable, and
13    accountable policy that allows electric utilities to
14    undertake needed system investments and earn a fair return
15    on their investments in an efficient manner is the best
16    method for building a smart, reliable grid that is equipped
17    for the clean energy future.
18    (b) The General Assembly therefore finds that it is
19necessary to develop an energy policy for central and southern
20Illinois that accelerates achievement of the State's renewable
21portfolio standard by creating new opportunities for
22investments in solar assets, building an electric vehicle
23charging infrastructure across hundreds of miles of roads,
24increasing research and deployment of new clean energy
25technology, and continuing to utilize transparent annual
26reviews to recover costs and set reasonable rates.
 

 

 

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1    Section 5. The Illinois Power Agency Act is amended by
2changing Sections 1-10 and 1-75 as follows:
 
3    (20 ILCS 3855/1-10)
4    Sec. 1-10. Definitions.
5    "Agency" means the Illinois Power Agency.
6    "Agency loan agreement" means any agreement pursuant to
7which the Illinois Finance Authority agrees to loan the
8proceeds of revenue bonds issued with respect to a project to
9the Agency upon terms providing for loan repayment installments
10at least sufficient to pay when due all principal of, interest
11and premium, if any, on those revenue bonds, and providing for
12maintenance, insurance, and other matters in respect of the
13project.
14    "Authority" means the Illinois Finance Authority.
15    "Brownfield site photovoltaic project" means photovoltaics
16that are:
17        (1) interconnected to an electric utility as defined in
18    this Section, a municipal utility as defined in this
19    Section, a public utility as defined in Section 3-105 of
20    the Public Utilities Act, or an electric cooperative, as
21    defined in Section 3-119 of the Public Utilities Act; and
22        (2) located at a site that is regulated by any of the
23    following entities under the following programs:
24            (A) the United States Environmental Protection

 

 

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1        Agency under the federal Comprehensive Environmental
2        Response, Compensation, and Liability Act of 1980, as
3        amended;
4            (B) the United States Environmental Protection
5        Agency under the Corrective Action Program of the
6        federal Resource Conservation and Recovery Act, as
7        amended;
8            (C) the Illinois Environmental Protection Agency
9        under the Illinois Site Remediation Program; or
10            (D) the Illinois Environmental Protection Agency
11        under the Illinois Solid Waste Program.
12    "Clean coal facility" means an electric generating
13facility that uses primarily coal as a feedstock and that
14captures and sequesters carbon dioxide emissions at the
15following levels: at least 50% of the total carbon dioxide
16emissions that the facility would otherwise emit if, at the
17time construction commences, the facility is scheduled to
18commence operation before 2016, at least 70% of the total
19carbon dioxide emissions that the facility would otherwise emit
20if, at the time construction commences, the facility is
21scheduled to commence operation during 2016 or 2017, and at
22least 90% of the total carbon dioxide emissions that the
23facility would otherwise emit if, at the time construction
24commences, the facility is scheduled to commence operation
25after 2017. The power block of the clean coal facility shall
26not exceed allowable emission rates for sulfur dioxide,

 

 

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1nitrogen oxides, carbon monoxide, particulates and mercury for
2a natural gas-fired combined-cycle facility the same size as
3and in the same location as the clean coal facility at the time
4the clean coal facility obtains an approved air permit. All
5coal used by a clean coal facility shall have high volatile
6bituminous rank and greater than 1.7 pounds of sulfur per
7million btu content, unless the clean coal facility does not
8use gasification technology and was operating as a conventional
9coal-fired electric generating facility on June 1, 2009 (the
10effective date of Public Act 95-1027).
11    "Clean coal SNG brownfield facility" means a facility that
12(1) has commenced construction by July 1, 2015 on an urban
13brownfield site in a municipality with at least 1,000,000
14residents; (2) uses a gasification process to produce
15substitute natural gas; (3) uses coal as at least 50% of the
16total feedstock over the term of any sourcing agreement with a
17utility and the remainder of the feedstock may be either
18petroleum coke or coal, with all such coal having a high
19bituminous rank and greater than 1.7 pounds of sulfur per
20million Btu content unless the facility reasonably determines
21that it is necessary to use additional petroleum coke to
22deliver additional consumer savings, in which case the facility
23shall use coal for at least 35% of the total feedstock over the
24term of any sourcing agreement; and (4) captures and sequesters
25at least 85% of the total carbon dioxide emissions that the
26facility would otherwise emit.

 

 

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1    "Clean coal SNG facility" means a facility that uses a
2gasification process to produce substitute natural gas, that
3sequesters at least 90% of the total carbon dioxide emissions
4that the facility would otherwise emit, that uses at least 90%
5coal as a feedstock, with all such coal having a high
6bituminous rank and greater than 1.7 pounds of sulfur per
7million btu content, and that has a valid and effective permit
8to construct emission sources and air pollution control
9equipment and approval with respect to the federal regulations
10for Prevention of Significant Deterioration of Air Quality
11(PSD) for the plant pursuant to the federal Clean Air Act;
12provided, however, a clean coal SNG brownfield facility shall
13not be a clean coal SNG facility.
14    "Commission" means the Illinois Commerce Commission.
15    "Community renewable generation project" means an electric
16generating facility that:
17        (1) is powered by wind, solar thermal energy,
18    photovoltaic cells or panels, biodiesel, crops and
19    untreated and unadulterated organic waste biomass, tree
20    waste, and hydropower that does not involve new
21    construction or significant expansion of hydropower dams;
22        (2) is interconnected at the distribution system level
23    of an electric utility as defined in this Section, a
24    municipal utility as defined in this Section that owns or
25    operates electric distribution facilities, a public
26    utility as defined in Section 3-105 of the Public Utilities

 

 

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1    Act, or an electric cooperative, as defined in Section
2    3-119 of the Public Utilities Act;
3        (3) credits the value of electricity generated by the
4    facility to the subscribers of the facility; and
5        (4) is limited in nameplate capacity to less than or
6    equal to 2,000 kilowatts.
7    "Costs incurred in connection with the development and
8construction of a facility" means:
9        (1) the cost of acquisition of all real property,
10    fixtures, and improvements in connection therewith and
11    equipment, personal property, and other property, rights,
12    and easements acquired that are deemed necessary for the
13    operation and maintenance of the facility;
14        (2) financing costs with respect to bonds, notes, and
15    other evidences of indebtedness of the Agency;
16        (3) all origination, commitment, utilization,
17    facility, placement, underwriting, syndication, credit
18    enhancement, and rating agency fees;
19        (4) engineering, design, procurement, consulting,
20    legal, accounting, title insurance, survey, appraisal,
21    escrow, trustee, collateral agency, interest rate hedging,
22    interest rate swap, capitalized interest, contingency, as
23    required by lenders, and other financing costs, and other
24    expenses for professional services; and
25        (5) the costs of plans, specifications, site study and
26    investigation, installation, surveys, other Agency costs

 

 

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1    and estimates of costs, and other expenses necessary or
2    incidental to determining the feasibility of any project,
3    together with such other expenses as may be necessary or
4    incidental to the financing, insuring, acquisition, and
5    construction of a specific project and starting up,
6    commissioning, and placing that project in operation.
7    "Delivery services" has the same definition as found in
8Section 16-102 of the Public Utilities Act.
9    "Delivery year" means the consecutive 12-month period
10beginning June 1 of a given year and ending May 31 of the
11following year.
12    "Department" means the Department of Commerce and Economic
13Opportunity.
14    "Director" means the Director of the Illinois Power Agency.
15    "Demand-response" means measures that decrease peak
16electricity demand or shift demand from peak to off-peak
17periods.
18    "Distributed renewable energy generation device" means a
19device that is:
20        (1) powered by wind, solar thermal energy,
21    photovoltaic cells or panels, biodiesel, crops and
22    untreated and unadulterated organic waste biomass, tree
23    waste, and hydropower that does not involve new
24    construction or significant expansion of hydropower dams;
25        (2) interconnected at the distribution system level of
26    either an electric utility as defined in this Section, a

 

 

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1    municipal utility as defined in this Section that owns or
2    operates electric distribution facilities, or a rural
3    electric cooperative as defined in Section 3-119 of the
4    Public Utilities Act;
5        (3) located on the customer side of the customer's
6    electric meter and is primarily used to offset that
7    customer's electricity load; and
8        (4) limited in nameplate capacity to less than or equal
9    to 2,000 kilowatts.
10    "Energy efficiency" means measures that reduce the amount
11of electricity or natural gas consumed in order to achieve a
12given end use. "Energy efficiency" includes voltage
13optimization measures that optimize the voltage at points on
14the electric distribution voltage system and thereby reduce
15electricity consumption by electric customers' end use
16devices. "Energy efficiency" also includes measures that
17reduce the total Btus of electricity, natural gas, and other
18fuels needed to meet the end use or uses. For electric
19utilities that serve less than 3,000,000 retail customers but
20more than 500,000 retail customers in this State, energy
21efficiency measures that reduce the total Btus of electricity,
22natural gas, or other fuels needed to meet the end use or uses,
23shall include, but are not limited to, measures that educate
24about, incentivize, encourage, or otherwise support the use of
25electricity to power, in whole or in part, vehicles, including,
26but not limited to, cars, trucks, buses, trains, trolleys,

 

 

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1boats, on-road or off-road vehicles, or other equipment or
2methods of transporting goods or people, and such measures
3shall include, but are not limited to, measures that educate
4about, incentivize, encourage, or otherwise support the
5adoption of electric vehicles by retail customers of all
6customer classes.
7    "Electric utility" has the same definition as found in
8Section 16-102 of the Public Utilities Act.
9    "Facility" means an electric generating unit or a
10co-generating unit that produces electricity along with
11related equipment necessary to connect the facility to an
12electric transmission or distribution system.
13    "Governmental aggregator" means one or more units of local
14government that individually or collectively procure
15electricity to serve residential retail electrical loads
16located within its or their jurisdiction.
17    "Local government" means a unit of local government as
18defined in Section 1 of Article VII of the Illinois
19Constitution.
20    "Municipality" means a city, village, or incorporated
21town.
22    "Municipal utility" means a public utility owned and
23operated by any subdivision or municipal corporation of this
24State.
25    "Nameplate capacity" means the aggregate inverter
26nameplate capacity in kilowatts AC.

 

 

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1    "Person" means any natural person, firm, partnership,
2corporation, either domestic or foreign, company, association,
3limited liability company, joint stock company, or association
4and includes any trustee, receiver, assignee, or personal
5representative thereof.
6    "Project" means the planning, bidding, and construction of
7a facility.
8    "Public utility" has the same definition as found in
9Section 3-105 of the Public Utilities Act.
10    "Real property" means any interest in land together with
11all structures, fixtures, and improvements thereon, including
12lands under water and riparian rights, any easements,
13covenants, licenses, leases, rights-of-way, uses, and other
14interests, together with any liens, judgments, mortgages, or
15other claims or security interests related to real property.
16    "Renewable energy credit" means a tradable credit that
17represents the environmental attributes of one megawatt hour of
18energy produced from a renewable energy resource.
19    "Renewable energy resources" includes energy and its
20associated renewable energy credit or renewable energy credits
21from wind, solar thermal energy, photovoltaic cells and panels,
22biodiesel, anaerobic digestion, crops and untreated and
23unadulterated organic waste biomass, tree waste, and
24hydropower that does not involve new construction or
25significant expansion of hydropower dams. For purposes of this
26Act, landfill gas produced in the State is considered a

 

 

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1renewable energy resource. "Renewable energy resources" does
2not include the incineration or burning of tires, garbage,
3general household, institutional, and commercial waste,
4industrial lunchroom or office waste, landscape waste other
5than tree waste, railroad crossties, utility poles, or
6construction or demolition debris, other than untreated and
7unadulterated waste wood.
8    "Retail customer" has the same definition as found in
9Section 16-102 of the Public Utilities Act.
10    "Revenue bond" means any bond, note, or other evidence of
11indebtedness issued by the Authority, the principal and
12interest of which is payable solely from revenues or income
13derived from any project or activity of the Agency.
14    "Sequester" means permanent storage of carbon dioxide by
15injecting it into a saline aquifer, a depleted gas reservoir,
16or an oil reservoir, directly or through an enhanced oil
17recovery process that may involve intermediate storage,
18regardless of whether these activities are conducted by a clean
19coal facility, a clean coal SNG facility, a clean coal SNG
20brownfield facility, or a party with which a clean coal
21facility, clean coal SNG facility, or clean coal SNG brownfield
22facility has contracted for such purposes.
23    "Service area" has the same definition as found in Section
2416-102 of the Public Utilities Act.
25    "Sourcing agreement" means (i) in the case of an electric
26utility, an agreement between the owner of a clean coal

 

 

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1facility and such electric utility, which agreement shall have
2terms and conditions meeting the requirements of paragraph (3)
3of subsection (d) of Section 1-75, (ii) in the case of an
4alternative retail electric supplier, an agreement between the
5owner of a clean coal facility and such alternative retail
6electric supplier, which agreement shall have terms and
7conditions meeting the requirements of Section 16-115(d)(5) of
8the Public Utilities Act, and (iii) in case of a gas utility,
9an agreement between the owner of a clean coal SNG brownfield
10facility and the gas utility, which agreement shall have the
11terms and conditions meeting the requirements of subsection
12(h-1) of Section 9-220 of the Public Utilities Act.
13    "Subscriber" means a person who (i) takes delivery service
14from an electric utility, and (ii) has a subscription of no
15less than 200 watts to a community renewable generation project
16that is located in the electric utility's service area. No
17subscriber's subscriptions may total more than 40% of the
18nameplate capacity of an individual community renewable
19generation project. Entities that are affiliated by virtue of a
20common parent shall not represent multiple subscriptions that
21total more than 40% of the nameplate capacity of an individual
22community renewable generation project.
23    "Subscription" means an interest in a community renewable
24generation project expressed in kilowatts, which is sized
25primarily to offset part or all of the subscriber's electricity
26usage.

 

 

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1    "Substitute natural gas" or "SNG" means a gas manufactured
2by gasification of hydrocarbon feedstock, which is
3substantially interchangeable in use and distribution with
4conventional natural gas.
5    "Total resource cost test" or "TRC test" means a standard
6that is met if, for an investment in energy efficiency or
7demand-response measures, the benefit-cost ratio is greater
8than one. The benefit-cost ratio is the ratio of the net
9present value of the total benefits of the program to the net
10present value of the total costs as calculated over the
11lifetime of the measures. A total resource cost test compares
12the sum of avoided electric utility costs, representing the
13benefits that accrue to the system and the participant in the
14delivery of those efficiency measures and including avoided
15costs associated with reduced use of natural gas or other
16fuels, avoided costs associated with reduced water
17consumption, and avoided costs associated with reduced
18operation and maintenance costs, as well as other quantifiable
19societal benefits, to the sum of all incremental costs of
20end-use measures that are implemented due to the program
21(including both utility and participant contributions), plus
22costs to administer, deliver, and evaluate each demand-side
23program, to quantify the net savings obtained by substituting
24the demand-side program for supply resources. In calculating
25avoided costs of power and energy that an electric utility
26would otherwise have had to acquire, reasonable estimates shall

 

 

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1be included of financial costs likely to be imposed by future
2regulations and legislation on emissions of greenhouse gases.
3In discounting future societal costs and benefits for the
4purpose of calculating net present values, a societal discount
5rate based on actual, long-term Treasury bond yields should be
6used. Notwithstanding anything to the contrary, the TRC test
7shall not include or take into account a calculation of market
8price suppression effects or demand reduction induced price
9effects.
10    "Utility-scale solar project" means an electric generating
11facility that:
12        (1) generates electricity using photovoltaic cells;
13    and
14        (2) has a nameplate capacity that is greater than 2,000
15    kilowatts.
16    "Utility-scale wind project" means an electric generating
17facility that:
18        (1) generates electricity using wind; and
19        (2) has a nameplate capacity that is greater than 2,000
20    kilowatts.
21    "Zero emission credit" means a tradable credit that
22represents the environmental attributes of one megawatt hour of
23energy produced from a zero emission facility.
24    "Zero emission facility" means a facility that: (1) is
25fueled by nuclear power; and (2) is interconnected with PJM
26Interconnection, LLC or the Midcontinent Independent System

 

 

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1Operator, Inc., or their successors.
2(Source: P.A. 98-90, eff. 7-15-13; 99-906, eff. 6-1-17.)
 
3    (20 ILCS 3855/1-75)
4    Sec. 1-75. Planning and Procurement Bureau. The Planning
5and Procurement Bureau has the following duties and
6responsibilities:
7    (a) The Planning and Procurement Bureau shall each year,
8beginning in 2008, develop procurement plans and conduct
9competitive procurement processes in accordance with the
10requirements of Section 16-111.5 of the Public Utilities Act
11for the eligible retail customers of electric utilities that on
12December 31, 2005 provided electric service to at least 100,000
13customers in Illinois. Beginning with the delivery year
14commencing on June 1, 2017, the Planning and Procurement Bureau
15shall develop plans and processes for the procurement of zero
16emission credits from zero emission facilities in accordance
17with the requirements of subsection (d-5) of this Section. The
18Planning and Procurement Bureau shall also develop procurement
19plans and conduct competitive procurement processes in
20accordance with the requirements of Section 16-111.5 of the
21Public Utilities Act for the eligible retail customers of small
22multi-jurisdictional electric utilities that (i) on December
2331, 2005 served less than 100,000 customers in Illinois and
24(ii) request a procurement plan for their Illinois
25jurisdictional load. This Section shall not apply to a small

 

 

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1multi-jurisdictional utility until such time as a small
2multi-jurisdictional utility requests the Agency to prepare a
3procurement plan for their Illinois jurisdictional load. For
4the purposes of this Section, the term "eligible retail
5customers" has the same definition as found in Section
616-111.5(a) of the Public Utilities Act.
7    Beginning with the plan or plans to be implemented in the
82017 delivery year, the Agency shall no longer include the
9procurement of renewable energy resources in the annual
10procurement plans required by this subsection (a), except as
11provided in subsection (q) of Section 16-111.5 of the Public
12Utilities Act, and shall instead develop a long-term renewable
13resources procurement plan in accordance with subsection (c) of
14this Section and Section 16-111.5 of the Public Utilities Act.
15        (1) The Agency shall each year, beginning in 2008, as
16    needed, issue a request for qualifications for experts or
17    expert consulting firms to develop the procurement plans in
18    accordance with Section 16-111.5 of the Public Utilities
19    Act. In order to qualify an expert or expert consulting
20    firm must have:
21            (A) direct previous experience assembling
22        large-scale power supply plans or portfolios for
23        end-use customers;
24            (B) an advanced degree in economics, mathematics,
25        engineering, risk management, or a related area of
26        study;

 

 

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1            (C) 10 years of experience in the electricity
2        sector, including managing supply risk;
3            (D) expertise in wholesale electricity market
4        rules, including those established by the Federal
5        Energy Regulatory Commission and regional transmission
6        organizations;
7            (E) expertise in credit protocols and familiarity
8        with contract protocols;
9            (F) adequate resources to perform and fulfill the
10        required functions and responsibilities; and
11            (G) the absence of a conflict of interest and
12        inappropriate bias for or against potential bidders or
13        the affected electric utilities.
14        (2) The Agency shall each year, as needed, issue a
15    request for qualifications for a procurement administrator
16    to conduct the competitive procurement processes in
17    accordance with Section 16-111.5 of the Public Utilities
18    Act. In order to qualify an expert or expert consulting
19    firm must have:
20            (A) direct previous experience administering a
21        large-scale competitive procurement process;
22            (B) an advanced degree in economics, mathematics,
23        engineering, or a related area of study;
24            (C) 10 years of experience in the electricity
25        sector, including risk management experience;
26            (D) expertise in wholesale electricity market

 

 

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1        rules, including those established by the Federal
2        Energy Regulatory Commission and regional transmission
3        organizations;
4            (E) expertise in credit and contract protocols;
5            (F) adequate resources to perform and fulfill the
6        required functions and responsibilities; and
7            (G) the absence of a conflict of interest and
8        inappropriate bias for or against potential bidders or
9        the affected electric utilities.
10        (3) The Agency shall provide affected utilities and
11    other interested parties with the lists of qualified
12    experts or expert consulting firms identified through the
13    request for qualifications processes that are under
14    consideration to develop the procurement plans and to serve
15    as the procurement administrator. The Agency shall also
16    provide each qualified expert's or expert consulting
17    firm's response to the request for qualifications. All
18    information provided under this subparagraph shall also be
19    provided to the Commission. The Agency may provide by rule
20    for fees associated with supplying the information to
21    utilities and other interested parties. These parties
22    shall, within 5 business days, notify the Agency in writing
23    if they object to any experts or expert consulting firms on
24    the lists. Objections shall be based on:
25            (A) failure to satisfy qualification criteria;
26            (B) identification of a conflict of interest; or

 

 

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1            (C) evidence of inappropriate bias for or against
2        potential bidders or the affected utilities.
3        The Agency shall remove experts or expert consulting
4    firms from the lists within 10 days if there is a
5    reasonable basis for an objection and provide the updated
6    lists to the affected utilities and other interested
7    parties. If the Agency fails to remove an expert or expert
8    consulting firm from a list, an objecting party may seek
9    review by the Commission within 5 days thereafter by filing
10    a petition, and the Commission shall render a ruling on the
11    petition within 10 days. There is no right of appeal of the
12    Commission's ruling.
13        (4) The Agency shall issue requests for proposals to
14    the qualified experts or expert consulting firms to develop
15    a procurement plan for the affected utilities and to serve
16    as procurement administrator.
17        (5) The Agency shall select an expert or expert
18    consulting firm to develop procurement plans based on the
19    proposals submitted and shall award contracts of up to 5
20    years to those selected.
21        (6) The Agency shall select an expert or expert
22    consulting firm, with approval of the Commission, to serve
23    as procurement administrator based on the proposals
24    submitted. If the Commission rejects, within 5 days, the
25    Agency's selection, the Agency shall submit another
26    recommendation within 3 days based on the proposals

 

 

SB3977- 21 -LRB101 20818 JLS 70537 b

1    submitted. The Agency shall award a 5-year contract to the
2    expert or expert consulting firm so selected with
3    Commission approval.
4    (b) The experts or expert consulting firms retained by the
5Agency shall, as appropriate, prepare procurement plans, and
6conduct a competitive procurement process as prescribed in
7Section 16-111.5 of the Public Utilities Act, to ensure
8adequate, reliable, affordable, efficient, and environmentally
9sustainable electric service at the lowest total cost over
10time, taking into account any benefits of price stability, for
11eligible retail customers of electric utilities that on
12December 31, 2005 provided electric service to at least 100,000
13customers in the State of Illinois, and for eligible Illinois
14retail customers of small multi-jurisdictional electric
15utilities that (i) on December 31, 2005 served less than
16100,000 customers in Illinois and (ii) request a procurement
17plan for their Illinois jurisdictional load.
18    (c) Renewable portfolio standard.
19        (1)(A) The Agency shall develop a long-term renewable
20    resources procurement plan that shall include procurement
21    programs and competitive procurement events necessary to
22    meet the goals set forth in this subsection (c). The
23    initial long-term renewable resources procurement plan
24    shall be released for comment no later than 160 days after
25    June 1, 2017 (the effective date of Public Act 99-906). The
26    Agency shall review, and may revise on an expedited basis,

 

 

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1    the long-term renewable resources procurement plan at
2    least every 2 years, which shall be conducted in
3    conjunction with the procurement plan under Section
4    16-111.5 of the Public Utilities Act to the extent
5    practicable to minimize administrative expense. The
6    long-term renewable resources procurement plans shall be
7    subject to review and approval by the Commission under
8    Section 16-111.5 of the Public Utilities Act.
9        (B) Subject to subparagraph (F) of this paragraph (1),
10    for electric utilities that serve more than 3,000,000
11    retail customers in this State or less than 500,000 retail
12    customers in this State, the long-term renewable resources
13    procurement plan shall include the goals for procurement of
14    renewable energy credits to meet at least the following
15    overall percentages: 13% by the 2017 delivery year;
16    increasing by at least 1.5% each delivery year thereafter
17    to at least 25% by the 2025 delivery year; and continuing
18    at no less than 25% for each delivery year thereafter and
19    for electric utilities that serve less than 3,000,000
20    retail customers but more than 500,000 retail customers in
21    this State, the long-term renewable resources procurement
22    plan shall include the goals for procurement of renewable
23    energy credits to meet at least the following overall
24    percentages: 13% by the 2017 delivery year; increasing by
25    at least 1.5% each delivery year thereafter to at least 25%
26    by the 2025 delivery year, and by at least 1.5% every year

 

 

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1    thereafter to at least 32.5% by the 2030 delivery year; and
2    continuing at no less than 32.5% for each delivery year
3    thereafter. In the event of a conflict between these goals
4    and the new wind and new photovoltaic procurement
5    requirements described in items (i) through (iii) of
6    subparagraph (C) of this paragraph (1), the long-term plan
7    shall prioritize compliance with the new wind and new
8    photovoltaic procurement requirements described in items
9    (i) through (iii) of subparagraph (C) of this paragraph (1)
10    over the annual percentage targets described in this
11    subparagraph (B).
12        For the delivery year beginning June 1, 2017, the
13    procurement plan shall include cost-effective renewable
14    energy resources equal to at least 13% of each utility's
15    load for eligible retail customers and 13% of the
16    applicable portion of each utility's load for retail
17    customers who are not eligible retail customers, which
18    applicable portion shall equal 50% of the utility's load
19    for retail customers who are not eligible retail customers
20    on February 28, 2017.
21        For the delivery year beginning June 1, 2018, the
22    procurement plan shall include cost-effective renewable
23    energy resources equal to at least 14.5% of each utility's
24    load for eligible retail customers and 14.5% of the
25    applicable portion of each utility's load for retail
26    customers who are not eligible retail customers, which

 

 

SB3977- 24 -LRB101 20818 JLS 70537 b

1    applicable portion shall equal 75% of the utility's load
2    for retail customers who are not eligible retail customers
3    on February 28, 2017.
4        For the delivery year beginning June 1, 2019, and for
5    each year thereafter, the procurement plans shall include
6    cost-effective renewable energy resources equal to a
7    minimum percentage of each utility's load for all retail
8    customers as follows: for electric utilities that serve
9    more than 3,000,000 retail customers in this State or less
10    than 500,000 retail customers in this State, 16% by June 1,
11    2019; increasing by 1.5% each year thereafter to 25% by
12    June 1, 2025; and 25% by June 1, 2026 and each year
13    thereafter and for electric utilities that serve less than
14    3,000,000 retail customers but more than 500,000 retail
15    customers in this State, 16% by June 1, 2019; increasing by
16    1.5% each year thereafter to 32.5% by June 1, 2030; and
17    32.5% by June 1, 2031 and each year thereafter.
18        For each delivery year, the Agency shall first
19    recognize each utility's obligations for that delivery
20    year under existing contracts. Any renewable energy
21    credits under existing contracts, including renewable
22    energy credits as part of renewable energy resources, shall
23    be used to meet the goals set forth in this subsection (c)
24    for the delivery year.
25        (C) Of the renewable energy credits procured under this
26    subsection (c), at least 75% shall come from wind and

 

 

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1    photovoltaic projects. The long-term renewable resources
2    procurement plan described in subparagraph (A) of this
3    paragraph (1) shall include the procurement of renewable
4    energy credits in amounts equal to at least the following:
5            (i) By the end of the 2020 delivery year:
6                At least 2,000,000 renewable energy credits
7            for each delivery year shall come from new wind
8            projects; and
9                At least 2,000,000 renewable energy credits
10            for each delivery year shall come from new
11            photovoltaic projects; of that amount, to the
12            extent possible, the Agency shall procure: at
13            least 50% from solar photovoltaic projects using
14            the program outlined in subparagraph (K) of this
15            paragraph (1) from distributed renewable energy
16            generation devices or community renewable
17            generation projects; at least 40% from
18            utility-scale solar projects; at least 2% from
19            brownfield site photovoltaic projects that are not
20            community renewable generation projects; and the
21            remainder shall be determined through the
22            long-term planning process described in
23            subparagraph (A) of this paragraph (1); however,
24            if the long-term renewable resources procurement
25            plan includes the procurement of more than
26            2,000,000 renewable energy credits from new

 

 

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1            photovoltaic projects, then the foregoing
2            allocations of renewable energy credits from the
3            program outlined in subparagraph (K) of this
4            paragraph (1), utility-scale solar projects, and
5            brownfield site photovoltaic projects that are not
6            community renewable generation projects shall not
7            apply to the portion of the renewable energy
8            credits procured in excess of the 2,000,000
9            renewable energy credits procured on behalf of
10            electric utilities that serve less than 3,000,000
11            retail customers but more than 500,000 retail
12            customers in this State and the allocation of such
13            procurement on behalf of electric utilities that
14            serve less than 3,000,000 retail customers but
15            more than 500,000 retail customers in this State
16            shall instead be based on the mix that produces the
17            lowest cost for the renewable energy credits
18            procured.
19            (ii) By the end of the 2025 delivery year:
20                At least 3,000,000 renewable energy credits
21            for each delivery year shall come from new wind
22            projects; and
23                At least 3,000,000 renewable energy credits
24            for each delivery year shall come from new
25            photovoltaic projects; of that amount, to the
26            extent possible, the Agency shall procure: at

 

 

SB3977- 27 -LRB101 20818 JLS 70537 b

1            least 50% from solar photovoltaic projects using
2            the program outlined in subparagraph (K) of this
3            paragraph (1) from distributed renewable energy
4            devices or community renewable generation
5            projects; at least 40% from utility-scale solar
6            projects; at least 2% from brownfield site
7            photovoltaic projects that are not community
8            renewable generation projects; and the remainder
9            shall be determined through the long-term planning
10            process described in subparagraph (A) of this
11            paragraph (1); however, if the long-term renewable
12            resources procurement plan includes the
13            procurement of more than 3,000,000 renewable
14            energy credits from new photovoltaic projects,
15            then the foregoing allocations of renewable energy
16            credits from the program outlined in subparagraph
17            (K) of this paragraph (1), utility-scale solar
18            projects, and brownfield site photovoltaic
19            projects that are not community renewable
20            generation projects shall not apply to the portion
21            of the renewable energy credits procured in excess
22            of the 3,000,000 renewable energy credits procured
23            on behalf of electric utilities that serve less
24            than 3,000,000 retail customers but more than
25            500,000 retail customers in this State and the
26            allocation of such procurement on behalf of

 

 

SB3977- 28 -LRB101 20818 JLS 70537 b

1            electric utilities that serve less than 3,000,000
2            retail customers but more than 500,000 retail
3            customers in this State shall instead be based on
4            the mix that produced the lowest cost for the
5            renewable energy credits procured.
6            (iii) By the end of the 2030 delivery year:
7                At least 4,000,000 renewable energy credits
8            for each delivery year shall come from new wind
9            projects; and
10                At least 4,000,000 renewable energy credits
11            for each delivery year shall come from new
12            photovoltaic projects; of that amount, to the
13            extent possible, the Agency shall procure: at
14            least 50% from solar photovoltaic projects using
15            the program outlined in subparagraph (K) of this
16            paragraph (1) from distributed renewable energy
17            devices or community renewable generation
18            projects; at least 40% from utility-scale solar
19            projects; at least 2% from brownfield site
20            photovoltaic projects that are not community
21            renewable generation projects; and the remainder
22            shall be determined through the long-term planning
23            process described in subparagraph (A) of this
24            paragraph (1); however, if the long-term renewable
25            resources procurement plan includes the
26            procurement of more than 4,000,000 renewable

 

 

SB3977- 29 -LRB101 20818 JLS 70537 b

1            energy credits from new photovoltaic projects,
2            then the foregoing allocations of renewable energy
3            credits from the program outlined in subparagraph
4            (K) of this paragraph (1), utility-scale solar
5            projects, and brownfield site photovoltaic
6            projects that are not community renewable
7            generation projects shall not apply to the portion
8            of the renewable energy credits procured in excess
9            of the 4,000,000 renewable energy credits procured
10            on behalf of electric utilities that serve less
11            than 3,000,000 retail customers but more than
12            500,000 retail customers in this State and the
13            allocation of such procurement on behalf of
14            electric utilities that serve less than 3,000,000
15            retail customers but more than 500,000 retail
16            customers in this State shall instead be based on
17            the mix that produced the lowest cost for the
18            renewable energy credits procured.
19            For purposes of this Section:
20                "New wind projects" means wind renewable
21            energy facilities that are energized after June 1,
22            2017 for the delivery year commencing June 1, 2017
23            or within 3 years after the date the Commission
24            approves contracts for subsequent delivery years.
25                "New photovoltaic projects" means photovoltaic
26            renewable energy facilities that are energized

 

 

SB3977- 30 -LRB101 20818 JLS 70537 b

1            after June 1, 2017. Photovoltaic projects
2            developed under Section 1-56 of this Act shall not
3            apply towards the new photovoltaic project
4            requirements in this subparagraph (C).
5        (D) Renewable energy credits shall be cost effective.
6    For purposes of this subsection (c), "cost effective" means
7    that the costs of procuring renewable energy resources do
8    not cause the limit stated in subparagraph (E) of this
9    paragraph (1) to be exceeded and, for renewable energy
10    credits procured through a competitive procurement event,
11    do not exceed benchmarks based on market prices for like
12    products in the region. For purposes of this subsection
13    (c), "like products" means contracts for renewable energy
14    credits from the same or substantially similar technology,
15    same or substantially similar vintage (new or existing),
16    the same or substantially similar quantity, and the same or
17    substantially similar contract length and structure.
18    Benchmarks shall be developed by the procurement
19    administrator, in consultation with the Commission staff,
20    Agency staff, and the procurement monitor and shall be
21    subject to Commission review and approval. If price
22    benchmarks for like products in the region are not
23    available, the procurement administrator shall establish
24    price benchmarks based on publicly available data on
25    regional technology costs and expected current and future
26    regional energy prices. The benchmarks in this Section

 

 

SB3977- 31 -LRB101 20818 JLS 70537 b

1    shall not be used to curtail or otherwise reduce
2    contractual obligations entered into by or through the
3    Agency prior to June 1, 2017 (the effective date of Public
4    Act 99-906).
5        (E) For purposes of this subsection (c), the required
6    procurement of cost-effective renewable energy resources
7    for a particular year commencing prior to June 1, 2017
8    shall be measured as a percentage of the actual amount of
9    electricity (megawatt-hours) supplied by the electric
10    utility to eligible retail customers in the delivery year
11    ending immediately prior to the procurement, and, for
12    delivery years commencing on and after June 1, 2017, the
13    required procurement of cost-effective renewable energy
14    resources for a particular year shall be measured as a
15    percentage of the actual amount of electricity
16    (megawatt-hours) delivered by the electric utility in the
17    delivery year ending immediately prior to the procurement,
18    to all retail customers in its service territory. For
19    purposes of this subsection (c), the amount paid per
20    kilowatthour means the total amount paid for electric
21    service expressed on a per kilowatthour basis. For purposes
22    of this subsection (c), the total amount paid for electric
23    service includes without limitation amounts paid for
24    supply, transmission, distribution, surcharges, and add-on
25    taxes.
26        Notwithstanding the requirements of this subsection

 

 

SB3977- 32 -LRB101 20818 JLS 70537 b

1    (c), the total of renewable energy resources procured under
2    the procurement plan for any single year shall be subject
3    to the limitations of this subparagraph (E). Such
4    procurement shall be reduced for all retail customers based
5    on the amount necessary to limit the annual estimated
6    average net increase due to the costs of these resources
7    included in the amounts paid by eligible retail customers
8    in connection with electric service to no more than the
9    greater of 2.015% of the amount paid per kilowatthour by
10    those customers during the year ending May 31, 2007 or the
11    incremental amount per kilowatthour paid for these
12    resources in 2011; however, procurements that occur for
13    procurement periods that begin on or after June 1, 2026
14    shall be reduced for all retail customers of electric
15    utilities that serve less than 3,000,000 retail customers
16    but more than 500,000 retail customers in this State only
17    by an amount necessary to limit the annual estimated
18    average net increase due to the costs of these resources
19    included in the amounts paid by eligible retail customers
20    in connection with electric service to no more than the
21    greater of 2.515% of the amount paid per kilowatthour by
22    those customers during the year ending May 31, 2007 or the
23    incremental amount per kilowatthour paid for these
24    resources in 2011. To arrive at a maximum dollar amount of
25    renewable energy resources to be procured for the
26    particular delivery year, the resulting per kilowatthour

 

 

SB3977- 33 -LRB101 20818 JLS 70537 b

1    amount shall be applied to the actual amount of
2    kilowatthours of electricity delivered, or applicable
3    portion of such amount as specified in paragraph (1) of
4    this subsection (c), as applicable, by the electric utility
5    in the delivery year immediately prior to the procurement
6    to all retail customers in its service territory. The
7    calculations required by this subparagraph (E) shall be
8    made only once for each delivery year at the time that the
9    renewable energy resources are procured. Once the
10    determination as to the amount of renewable energy
11    resources to procure is made based on the calculations set
12    forth in this subparagraph (E) and the contracts procuring
13    those amounts are executed, no subsequent rate impact
14    determinations shall be made and no adjustments to those
15    contract amounts shall be allowed. All costs incurred under
16    such contracts shall be fully recoverable by the electric
17    utility as provided in this Section.
18        (F) If the limitation on the amount of renewable energy
19    resources procured in subparagraph (E) of this paragraph
20    (1) prevents the Agency from meeting all of the goals in
21    this subsection (c), the Agency's long-term plan shall
22    prioritize compliance with the requirements of this
23    subsection (c) regarding renewable energy credits in the
24    following order:
25            (i) renewable energy credits under existing
26        contractual obligations;

 

 

SB3977- 34 -LRB101 20818 JLS 70537 b

1            (i-5) funding for the Illinois Solar for All
2        Program, as described in subparagraph (O) of this
3        paragraph (1);
4            (ii) renewable energy credits necessary to comply
5        with the new wind and new photovoltaic procurement
6        requirements described in items (i) through (iii) of
7        subparagraph (C) of this paragraph (1); and
8            (iii) renewable energy credits necessary to meet
9        the remaining requirements of this subsection (c).
10        (G) The following provisions shall apply to the
11    Agency's procurement of renewable energy credits under
12    this subsection (c):
13            (i) Notwithstanding whether a long-term renewable
14        resources procurement plan has been approved, the
15        Agency shall conduct an initial forward procurement
16        for renewable energy credits from new utility-scale
17        wind projects within 160 days after June 1, 2017 (the
18        effective date of Public Act 99-906). For the purposes
19        of this initial forward procurement, the Agency shall
20        solicit 15-year contracts for delivery of 1,000,000
21        renewable energy credits delivered annually from new
22        utility-scale wind projects to begin delivery on June
23        1, 2019, if available, but not later than June 1, 2021,
24        unless the project has delays in the establishment of
25        an operating interconnection with the applicable
26        transmission or distribution system as a result of the

 

 

SB3977- 35 -LRB101 20818 JLS 70537 b

1        actions or inactions of the transmission or
2        distribution provider, or other causes for force
3        majeure as outlined in the procurement contract, in
4        which case, not later than June 1, 2022. Payments to
5        suppliers of renewable energy credits shall commence
6        upon delivery. Renewable energy credits procured under
7        this initial procurement shall be included in the
8        Agency's long-term plan and shall apply to all
9        renewable energy goals in this subsection (c).
10            (ii) Notwithstanding whether a long-term renewable
11        resources procurement plan has been approved, the
12        Agency shall conduct an initial forward procurement
13        for renewable energy credits from new utility-scale
14        solar projects and brownfield site photovoltaic
15        projects within one year after June 1, 2017 (the
16        effective date of Public Act 99-906). For the purposes
17        of this initial forward procurement, the Agency shall
18        solicit 15-year contracts for delivery of 1,000,000
19        renewable energy credits delivered annually from new
20        utility-scale solar projects and brownfield site
21        photovoltaic projects to begin delivery on June 1,
22        2019, if available, but not later than June 1, 2021,
23        unless the project has delays in the establishment of
24        an operating interconnection with the applicable
25        transmission or distribution system as a result of the
26        actions or inactions of the transmission or

 

 

SB3977- 36 -LRB101 20818 JLS 70537 b

1        distribution provider, or other causes for force
2        majeure as outlined in the procurement contract, in
3        which case, not later than June 1, 2022. The Agency may
4        structure this initial procurement in one or more
5        discrete procurement events. Payments to suppliers of
6        renewable energy credits shall commence upon delivery.
7        Renewable energy credits procured under this initial
8        procurement shall be included in the Agency's
9        long-term plan and shall apply to all renewable energy
10        goals in this subsection (c).
11            (iii) Subsequent forward procurements for
12        utility-scale wind projects shall solicit at least
13        1,000,000 renewable energy credits delivered annually
14        per procurement event and shall be planned, scheduled,
15        and designed such that the cumulative amount of
16        renewable energy credits delivered from all new wind
17        projects in each delivery year shall not exceed the
18        Agency's projection of the cumulative amount of
19        renewable energy credits that will be delivered from
20        all new photovoltaic projects, including utility-scale
21        and distributed photovoltaic devices, in the same
22        delivery year at the time scheduled for wind contract
23        delivery.
24            (iv) If, at any time after the time set for
25        delivery of renewable energy credits pursuant to the
26        initial procurements in items (i) and (ii) of this

 

 

SB3977- 37 -LRB101 20818 JLS 70537 b

1        subparagraph (G), the cumulative amount of renewable
2        energy credits projected to be delivered from all new
3        wind projects in a given delivery year exceeds the
4        cumulative amount of renewable energy credits
5        projected to be delivered from all new photovoltaic
6        projects in that delivery year by 200,000 or more
7        renewable energy credits, then the Agency shall within
8        60 days adjust the procurement programs in the
9        long-term renewable resources procurement plan to
10        ensure that the projected cumulative amount of
11        renewable energy credits to be delivered from all new
12        wind projects does not exceed the projected cumulative
13        amount of renewable energy credits to be delivered from
14        all new photovoltaic projects by 200,000 or more
15        renewable energy credits, provided that nothing in
16        this Section shall preclude the projected cumulative
17        amount of renewable energy credits to be delivered from
18        all new photovoltaic projects from exceeding the
19        projected cumulative amount of renewable energy
20        credits to be delivered from all new wind projects in
21        each delivery year and provided further that nothing in
22        this item (iv) shall require the curtailment of an
23        executed contract. The Agency shall update, on a
24        quarterly basis, its projection of the renewable
25        energy credits to be delivered from all projects in
26        each delivery year. Notwithstanding anything to the

 

 

SB3977- 38 -LRB101 20818 JLS 70537 b

1        contrary, the Agency may adjust the timing of
2        procurement events conducted under this subparagraph
3        (G). The long-term renewable resources procurement
4        plan shall set forth the process by which the
5        adjustments may be made.
6            (v) All procurements under this subparagraph (G)
7        shall comply with the geographic requirements in
8        subparagraph (I) of this paragraph (1) and shall follow
9        the procurement processes and procedures described in
10        this Section and Section 16-111.5 of the Public
11        Utilities Act to the extent practicable, and these
12        processes and procedures may be expedited to
13        accommodate the schedule established by this
14        subparagraph (G).
15        (H) The procurement of renewable energy resources for a
16    given delivery year shall be reduced as described in this
17    subparagraph (H) if an alternative retail electric
18    supplier meets the requirements described in this
19    subparagraph (H).
20            (i) Within 45 days after June 1, 2017 (the
21        effective date of Public Act 99-906), an alternative
22        retail electric supplier or its successor shall submit
23        an informational filing to the Illinois Commerce
24        Commission certifying that, as of December 31, 2015,
25        the alternative retail electric supplier owned one or
26        more electric generating facilities that generates

 

 

SB3977- 39 -LRB101 20818 JLS 70537 b

1        renewable energy resources as defined in Section 1-10
2        of this Act, provided that such facilities are not
3        powered by wind or photovoltaics, and the facilities
4        generate one renewable energy credit for each
5        megawatthour of energy produced from the facility.
6            The informational filing shall identify each
7        facility that was eligible to satisfy the alternative
8        retail electric supplier's obligations under Section
9        16-115D of the Public Utilities Act as described in
10        this item (i).
11            (ii) For a given delivery year, the alternative
12        retail electric supplier may elect to supply its retail
13        customers with renewable energy credits from the
14        facility or facilities described in item (i) of this
15        subparagraph (H) that continue to be owned by the
16        alternative retail electric supplier.
17            (iii) The alternative retail electric supplier
18        shall notify the Agency and the applicable utility, no
19        later than February 28 of the year preceding the
20        applicable delivery year or 15 days after June 1, 2017
21        (the effective date of Public Act 99-906), whichever is
22        later, of its election under item (ii) of this
23        subparagraph (H) to supply renewable energy credits to
24        retail customers of the utility. Such election shall
25        identify the amount of renewable energy credits to be
26        supplied by the alternative retail electric supplier

 

 

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1        to the utility's retail customers and the source of the
2        renewable energy credits identified in the
3        informational filing as described in item (i) of this
4        subparagraph (H), subject to the following
5        limitations:
6                For the delivery year beginning June 1, 2018,
7            the maximum amount of renewable energy credits to
8            be supplied by an alternative retail electric
9            supplier under this subparagraph (H) shall be 68%
10            multiplied by 25% multiplied by 14.5% multiplied
11            by the amount of metered electricity
12            (megawatt-hours) delivered by the alternative
13            retail electric supplier to Illinois retail
14            customers during the delivery year ending May 31,
15            2016.
16                For delivery years beginning June 1, 2019 and
17            each year thereafter, the maximum amount of
18            renewable energy credits to be supplied by an
19            alternative retail electric supplier under this
20            subparagraph (H) shall be 68% multiplied by 50%
21            multiplied by 16% multiplied by the amount of
22            metered electricity (megawatt-hours) delivered by
23            the alternative retail electric supplier to
24            Illinois retail customers during the delivery year
25            ending May 31, 2016, provided that the 16% value
26            shall increase by 1.5% each delivery year

 

 

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1            thereafter to 25% by the delivery year beginning
2            June 1, 2025, and thereafter the 25% value shall
3            apply to each delivery year.
4            For each delivery year, the total amount of
5        renewable energy credits supplied by all alternative
6        retail electric suppliers under this subparagraph (H)
7        shall not exceed 9% of the Illinois target renewable
8        energy credit quantity. The Illinois target renewable
9        energy credit quantity for the delivery year beginning
10        June 1, 2018 is 14.5% multiplied by the total amount of
11        metered electricity (megawatt-hours) delivered in the
12        delivery year immediately preceding that delivery
13        year, provided that the 14.5% shall increase by 1.5%
14        each delivery year thereafter to 25% by the delivery
15        year beginning June 1, 2025, and thereafter the 25%
16        value shall apply to each delivery year.
17            If the requirements set forth in items (i) through
18        (iii) of this subparagraph (H) are met, the charges
19        that would otherwise be applicable to the retail
20        customers of the alternative retail electric supplier
21        under paragraph (6) of this subsection (c) for the
22        applicable delivery year shall be reduced by the ratio
23        of the quantity of renewable energy credits supplied by
24        the alternative retail electric supplier compared to
25        that supplier's target renewable energy credit
26        quantity. The supplier's target renewable energy

 

 

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1        credit quantity for the delivery year beginning June 1,
2        2018 is 14.5% multiplied by the total amount of metered
3        electricity (megawatt-hours) delivered by the
4        alternative retail supplier in that delivery year,
5        provided that the 14.5% shall increase by 1.5% each
6        delivery year thereafter to 25% by the delivery year
7        beginning June 1, 2025, and thereafter the 25% value
8        shall apply to each delivery year.
9            On or before April 1 of each year, the Agency shall
10        annually publish a report on its website that
11        identifies the aggregate amount of renewable energy
12        credits supplied by alternative retail electric
13        suppliers under this subparagraph (H).
14        (I) The Agency shall design its long-term renewable
15    energy procurement plan to maximize the State's interest in
16    the health, safety, and welfare of its residents, including
17    but not limited to minimizing sulfur dioxide, nitrogen
18    oxide, particulate matter and other pollution that
19    adversely affects public health in this State, increasing
20    fuel and resource diversity in this State, enhancing the
21    reliability and resiliency of the electricity distribution
22    system in this State, meeting goals to limit carbon dioxide
23    emissions under federal or State law, and contributing to a
24    cleaner and healthier environment for the citizens of this
25    State, while balancing these goals with the requirement to
26    minimize the cost to customers attributable to the

 

 

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1    procurement of renewable energy credits set forth in
2    subparagraph (C) of paragraph (1) of this subsection (c).
3    In order to further these legislative purposes, renewable
4    energy credits shall be eligible to be counted toward the
5    renewable energy requirements of this subsection (c) if
6    they are generated from facilities located in this State.
7    The Agency may qualify renewable energy credits from
8    facilities located in states adjacent to Illinois if the
9    generator demonstrates and the Agency determines that the
10    operation of such facility or facilities will help promote
11    the State's interest in the health, safety, and welfare of
12    its residents based on the public interest criteria
13    described above. To ensure that the public interest
14    criteria are applied to the procurement and given full
15    effect, the Agency's long-term procurement plan shall
16    describe in detail how each public interest factor shall be
17    considered and weighted for facilities located in states
18    adjacent to Illinois.
19        (J) In order to promote the competitive development of
20    renewable energy resources in furtherance of the State's
21    interest in the health, safety, and welfare of its
22    residents, renewable energy credits shall not be eligible
23    to be counted toward the renewable energy requirements of
24    this subsection (c) if they are sourced from a generating
25    unit whose costs were being recovered through rates
26    regulated by this State or any other state or states on or

 

 

SB3977- 44 -LRB101 20818 JLS 70537 b

1    after January 1, 2017. Each contract executed to purchase
2    renewable energy credits under this subsection (c) shall
3    provide for the contract's termination if the costs of the
4    generating unit supplying the renewable energy credits
5    subsequently begin to be recovered through rates regulated
6    by this State or any other state or states; and each
7    contract shall further provide that, in that event, the
8    supplier of the credits must return 110% of all payments
9    received under the contract. Amounts returned under the
10    requirements of this subparagraph (J) shall be retained by
11    the utility and all of these amounts shall be used for the
12    procurement of additional renewable energy credits from
13    new wind or new photovoltaic resources as defined in this
14    subsection (c). The long-term plan shall provide that these
15    renewable energy credits shall be procured in the next
16    procurement event.
17        Notwithstanding the limitations of this subparagraph
18    (J), renewable energy credits sourced from generating
19    units that are constructed, purchased, owned, or leased by
20    an electric utility as part of an approved project,
21    program, or pilot under Section 1-56 of this Act shall be
22    eligible to be counted toward the renewable energy
23    requirements of this subsection (c), regardless of how the
24    costs of these units are recovered.
25        (K) The long-term renewable resources procurement plan
26    developed by the Agency in accordance with subparagraph (A)

 

 

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1    of this paragraph (1) shall include an Adjustable Block
2    program for the procurement of renewable energy credits
3    from new photovoltaic projects that are distributed
4    renewable energy generation devices or new photovoltaic
5    community renewable generation projects on behalf of
6    electric utilities that serve more than 3,000,000 retail
7    customers or less than 500,000 retail customers in this
8    State and a competitive procurement process for the
9    procurement of new photovoltaic community renewable
10    generation projects on behalf of electric utilities that
11    serve less than 3,000,000 retail customers but more than
12    500,000 retail customers in this State. The Adjustable
13    Block program shall be designed to provide a transparent
14    schedule of prices and quantities to enable the
15    photovoltaic market to scale up and for renewable energy
16    credit prices to adjust at a predictable rate over time.
17    The prices set by the Adjustable Block program can be
18    reflected as a set value or as the product of a formula.
19        The Adjustable Block program shall include for each
20    category of eligible projects: a schedule of standard block
21    purchase prices to be offered; a series of steps, with
22    associated nameplate capacity and purchase prices that
23    adjust from step to step; and automatic opening of the next
24    step as soon as the nameplate capacity and available
25    purchase prices for an open step are fully committed or
26    reserved. Only projects energized on or after June 1, 2017

 

 

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1    shall be eligible for the Adjustable Block program. For
2    each block group the Agency shall determine the number of
3    blocks, the amount of generation capacity in each block,
4    and the purchase price for each block, provided that the
5    purchase price provided and the total amount of generation
6    in all blocks for all block groups shall be sufficient to
7    meet the goals in this subsection (c). The Agency may
8    periodically review its prior decisions establishing the
9    number of blocks, the amount of generation capacity in each
10    block, and the purchase price for each block, and may
11    propose, on an expedited basis, changes to these previously
12    set values, including but not limited to redistributing
13    these amounts and the available funds as necessary and
14    appropriate, subject to Commission approval as part of the
15    periodic plan revision process described in Section
16    16-111.5 of the Public Utilities Act. The Agency may define
17    different block sizes, purchase prices, or other distinct
18    terms and conditions for projects located in different
19    utility service territories if the Agency deems it
20    necessary to meet the goals in this subsection (c);
21    however, if, for any block to be procured on behalf of
22    electric utilities that serve less than 3,000,000 retail
23    customers but more than 500,000 retail customers in this
24    State, the quantity of renewable energy credits sought by
25    eligible projects exceeds the quantity of renewable energy
26    credits defined by the Agency for the block, the Agency

 

 

SB3977- 47 -LRB101 20818 JLS 70537 b

1    shall lower the price applicable to the block and require
2    eligible projects to affirm the commitment to the quantity
3    of renewable energy credits sought. The Agency shall employ
4    a stepped process of lowering the price applicable to the
5    block so as to identify a price at which the quantity of
6    renewable energy credits sought by eligible projects
7    balances with the renewable energy credits sought by the
8    Agency for the block.
9        The competitive procurement process used for the
10    procurement of new photovoltaic community renewable
11    generation projects on behalf of electric utilities that
12    serve less than 3,000,000 retail customers but more than
13    500,000 retail customers in this State shall define the
14    quantity of renewable energy credits to be procured and
15    allow bidders to submit price offers to the Agency. The
16    Agency shall conduct the competitive procurement process
17    in a manner that results in the lowest cost for the
18    renewable energy credits procured.
19        The Adjustable Block program and competitive
20    procurement process shall include at least the following
21    block groups in at least the following amounts, which may
22    be adjusted upon review by the Agency and approval by the
23    Commission as described in this subparagraph (K):
24            (i) At least 25% from distributed renewable energy
25        generation devices with a nameplate capacity of no more
26        than 10 kilowatts.

 

 

SB3977- 48 -LRB101 20818 JLS 70537 b

1            (ii) At least 25% from distributed renewable
2        energy generation devices with a nameplate capacity of
3        more than 10 kilowatts and no more than 2,000
4        kilowatts. The Agency may create sub-categories within
5        this category to account for the differences between
6        projects for small commercial customers, large
7        commercial customers, and public or non-profit
8        customers.
9            (iii) At least 25% from photovoltaic community
10        renewable generation projects.
11            (iv) The remaining 25% shall be allocated as
12        specified by the Agency in the long-term renewable
13        resources procurement plan.
14        The Adjustable Block program shall be designed to
15    ensure that renewable energy credits are procured from
16    photovoltaic distributed renewable energy generation
17    devices and new photovoltaic community renewable energy
18    generation projects in diverse locations and are not
19    concentrated in a few geographic areas.
20        (L) The procurement of photovoltaic renewable energy
21    credits under items (i) through (iv) of subparagraph (K) of
22    this paragraph (1) shall be subject to the following
23    contract and payment terms:
24            (i) The Agency shall procure contracts of at least
25        15 years in length.
26            (ii) For those renewable energy credits that

 

 

SB3977- 49 -LRB101 20818 JLS 70537 b

1        qualify and are procured under item (i) of subparagraph
2        (K) of this paragraph (1), the renewable energy credit
3        purchase price shall be paid in full by the contracting
4        utilities at the time that the facility producing the
5        renewable energy credits is interconnected at the
6        distribution system level of the utility and
7        energized. The electric utility shall receive and
8        retire all renewable energy credits generated by the
9        project for the first 15 years of operation.
10            (iii) For those renewable energy credits that
11        qualify and are procured under item (ii) and (iii) of
12        subparagraph (K) of this paragraph (1) and any
13        additional categories of distributed generation
14        included in the long-term renewable resources
15        procurement plan and approved by the Commission, 20
16        percent of the renewable energy credit purchase price
17        shall be paid by the contracting utilities at the time
18        that the facility producing the renewable energy
19        credits is interconnected at the distribution system
20        level of the utility and energized. The remaining
21        portion shall be paid ratably over the subsequent
22        4-year period. The electric utility shall receive and
23        retire all renewable energy credits generated by the
24        project for the first 15 years of operation.
25            (iv) Each contract shall include provisions to
26        ensure the delivery of the renewable energy credits for

 

 

SB3977- 50 -LRB101 20818 JLS 70537 b

1        the full term of the contract.
2            (v) The utility shall be the counterparty to the
3        contracts executed under this subparagraph (L) that
4        are approved by the Commission under the process
5        described in Section 16-111.5 of the Public Utilities
6        Act. No contract shall be executed for an amount that
7        is less than one renewable energy credit per year.
8            (vi) If, at any time, approved applications for the
9        Adjustable Block program exceed funds collected by the
10        electric utility or would cause the Agency to exceed
11        the limitation described in subparagraph (E) of this
12        paragraph (1) on the amount of renewable energy
13        resources that may be procured, then the Agency shall
14        consider future uncommitted funds to be reserved for
15        these contracts on a first-come, first-served basis,
16        with the delivery of renewable energy credits required
17        beginning at the time that the reserved funds become
18        available.
19            (vii) Nothing in this Section shall require the
20        utility to advance any payment or pay any amounts that
21        exceed the actual amount of revenues collected by the
22        utility under paragraph (6) of this subsection (c) and
23        subsection (k) of Section 16-108 of the Public
24        Utilities Act, and contracts executed under this
25        Section shall expressly incorporate this limitation.
26        (M) The Agency shall be authorized to retain one or

 

 

SB3977- 51 -LRB101 20818 JLS 70537 b

1    more experts or expert consulting firms to develop,
2    administer, implement, operate, and evaluate the
3    Adjustable Block program described in subparagraph (K) of
4    this paragraph (1), and the Agency shall retain the
5    consultant or consultants in the same manner, to the extent
6    practicable, as the Agency retains others to administer
7    provisions of this Act, including, but not limited to, the
8    procurement administrator. The selection of experts and
9    expert consulting firms and the procurement process
10    described in this subparagraph (M) are exempt from the
11    requirements of Section 20-10 of the Illinois Procurement
12    Code, under Section 20-10 of that Code. The Agency shall
13    strive to minimize administrative expenses in the
14    implementation of the Adjustable Block program.
15        The Agency and its consultant or consultants shall
16    monitor block activity, share program activity with
17    stakeholders and conduct regularly scheduled meetings to
18    discuss program activity and market conditions. If
19    necessary, the Agency may make prospective administrative
20    adjustments to the Adjustable Block program design, such as
21    redistributing available funds or making adjustments to
22    purchase prices as necessary to achieve the goals of this
23    subsection (c). Program modifications to any price,
24    capacity block, or other program element that do not
25    deviate from the Commission's approved value by more than
26    25% shall take effect immediately and are not subject to

 

 

SB3977- 52 -LRB101 20818 JLS 70537 b

1    Commission review and approval. Program modifications to
2    any price, capacity block, or other program element that
3    deviate more than 25% from the Commission's approved value
4    must be approved by the Commission as a long-term plan
5    amendment under Section 16-111.5 of the Public Utilities
6    Act. The Agency shall consider stakeholder feedback when
7    making adjustments to the Adjustable Block design and shall
8    notify stakeholders in advance of any planned changes.
9        (N) The long-term renewable resources procurement plan
10    required by this subsection (c) shall include a community
11    renewable generation program. The Agency shall establish
12    the terms, conditions, and program requirements for
13    community renewable generation projects with a goal to
14    expand renewable energy generating facility access to a
15    broader group of energy consumers, to ensure robust
16    participation opportunities for residential and small
17    commercial customers and those who cannot install
18    renewable energy on their own properties. Any plan approved
19    by the Commission shall allow subscriptions to community
20    renewable generation projects to be portable and
21    transferable. For purposes of this subparagraph (N),
22    "portable" means that subscriptions may be retained by the
23    subscriber even if the subscriber relocates or changes its
24    address within the same utility service territory; and
25    "transferable" means that a subscriber may assign or sell
26    subscriptions to another person within the same utility

 

 

SB3977- 53 -LRB101 20818 JLS 70537 b

1    service territory.
2        Electric utilities shall provide a monetary credit to a
3    subscriber's subsequent bill for service for the
4    proportional output of a community renewable generation
5    project attributable to that subscriber as specified in
6    Section 16-107.5 of the Public Utilities Act.
7        The Agency shall purchase renewable energy credits
8    from subscribed shares of photovoltaic community renewable
9    generation projects through the Adjustable Block program
10    and the competitive procurement process described in
11    subparagraph (K) of this paragraph (1) or through the
12    Illinois Solar for All Program described in Section 1-56 of
13    this Act. The electric utility shall purchase any
14    unsubscribed energy from community renewable generation
15    projects that are Qualifying Facilities ("QF") under the
16    electric utility's tariff for purchasing the output from
17    QFs under Public Utilities Regulatory Policies Act of 1978.
18        The owners of and any subscribers to a community
19    renewable generation project shall not be considered
20    public utilities or alternative retail electricity
21    suppliers under the Public Utilities Act solely as a result
22    of their interest in or subscription to a community
23    renewable generation project and shall not be required to
24    become an alternative retail electric supplier by
25    participating in a community renewable generation project
26    with a public utility.

 

 

SB3977- 54 -LRB101 20818 JLS 70537 b

1        (O) For the delivery year beginning June 1, 2018, the
2    long-term renewable resources procurement plan required by
3    this subsection (c) shall provide for the Agency to procure
4    contracts to continue offering the Illinois Solar for All
5    Program described in subsection (b) of Section 1-56 of this
6    Act, and the contracts approved by the Commission shall be
7    executed by the utilities that are subject to this
8    subsection (c). The long-term renewable resources
9    procurement plan shall allocate 5% of the funds available
10    under the plan for the applicable delivery year, or
11    $10,000,000 per delivery year, whichever is greater, to
12    fund the programs, and the plan shall determine the amount
13    of funding to be apportioned to the programs identified in
14    subsection (b) of Section 1-56 of this Act; provided that
15    for the delivery years beginning June 1, 2017, June 1,
16    2021, and June 1, 2025, the long-term renewable resources
17    procurement plan shall allocate 10% of the funds available
18    under the plan for the applicable delivery year, or
19    $20,000,000 per delivery year, whichever is greater, and
20    $10,000,000 of such funds in such year shall be used by an
21    electric utility that serves more than 3,000,000 retail
22    customers in the State to implement a Commission-approved
23    plan under Section 16-108.12 of the Public Utilities Act.
24    In making the determinations required under this
25    subparagraph (O), the Commission shall consider the
26    experience and performance under the programs and any

 

 

SB3977- 55 -LRB101 20818 JLS 70537 b

1    evaluation reports. The Commission shall also provide for
2    an independent evaluation of those programs on a periodic
3    basis that are funded under this subparagraph (O).
4        (2) (Blank).
5        (3) (Blank).
6        (4) The electric utility shall retire all renewable
7    energy credits used to comply with the standard.
8        (5) Beginning with the 2010 delivery year and ending
9    June 1, 2017, an electric utility subject to this
10    subsection (c) shall apply the lesser of the maximum
11    alternative compliance payment rate or the most recent
12    estimated alternative compliance payment rate for its
13    service territory for the corresponding compliance period,
14    established pursuant to subsection (d) of Section 16-115D
15    of the Public Utilities Act to its retail customers that
16    take service pursuant to the electric utility's hourly
17    pricing tariff or tariffs. The electric utility shall
18    retain all amounts collected as a result of the application
19    of the alternative compliance payment rate or rates to such
20    customers, and, beginning in 2011, the utility shall
21    include in the information provided under item (1) of
22    subsection (d) of Section 16-111.5 of the Public Utilities
23    Act the amounts collected under the alternative compliance
24    payment rate or rates for the prior year ending May 31.
25    Notwithstanding any limitation on the procurement of
26    renewable energy resources imposed by item (2) of this

 

 

SB3977- 56 -LRB101 20818 JLS 70537 b

1    subsection (c), the Agency shall increase its spending on
2    the purchase of renewable energy resources to be procured
3    by the electric utility for the next plan year by an amount
4    equal to the amounts collected by the utility under the
5    alternative compliance payment rate or rates in the prior
6    year ending May 31.
7        (6) The electric utility shall be entitled to recover
8    all of its costs associated with the procurement of
9    renewable energy credits under plans approved under this
10    Section and Section 16-111.5 of the Public Utilities Act.
11    These costs shall include associated reasonable expenses
12    for implementing the procurement programs, including, but
13    not limited to, the costs of administering and evaluating
14    the Adjustable Block program, through an automatic
15    adjustment clause tariff in accordance with subsection (k)
16    of Section 16-108 of the Public Utilities Act.
17        (7) Renewable energy credits procured from new
18    photovoltaic projects or new distributed renewable energy
19    generation devices under this Section after June 1, 2017
20    (the effective date of Public Act 99-906) must be procured
21    from devices installed by a qualified person in compliance
22    with the requirements of Section 16-128A of the Public
23    Utilities Act and any rules or regulations adopted
24    thereunder.
25        In meeting the renewable energy requirements of this
26    subsection (c), to the extent feasible and consistent with

 

 

SB3977- 57 -LRB101 20818 JLS 70537 b

1    State and federal law, the renewable energy credit
2    procurements, Adjustable Block solar program, and
3    community renewable generation program shall provide
4    employment opportunities for all segments of the
5    population and workforce, including minority-owned and
6    female-owned business enterprises, and shall not,
7    consistent with State and federal law, discriminate based
8    on race or socioeconomic status.
9    (d) Clean coal portfolio standard.
10        (1) The procurement plans shall include electricity
11    generated using clean coal. Each utility shall enter into
12    one or more sourcing agreements with the initial clean coal
13    facility, as provided in paragraph (3) of this subsection
14    (d), covering electricity generated by the initial clean
15    coal facility representing at least 5% of each utility's
16    total supply to serve the load of eligible retail customers
17    in 2015 and each year thereafter, as described in paragraph
18    (3) of this subsection (d), subject to the limits specified
19    in paragraph (2) of this subsection (d). It is the goal of
20    the State that by January 1, 2025, 25% of the electricity
21    used in the State shall be generated by cost-effective
22    clean coal facilities. For purposes of this subsection (d),
23    "cost-effective" means that the expenditures pursuant to
24    such sourcing agreements do not cause the limit stated in
25    paragraph (2) of this subsection (d) to be exceeded and do
26    not exceed cost-based benchmarks, which shall be developed

 

 

SB3977- 58 -LRB101 20818 JLS 70537 b

1    to assess all expenditures pursuant to such sourcing
2    agreements covering electricity generated by clean coal
3    facilities, other than the initial clean coal facility, by
4    the procurement administrator, in consultation with the
5    Commission staff, Agency staff, and the procurement
6    monitor and shall be subject to Commission review and
7    approval.
8        A utility party to a sourcing agreement shall
9    immediately retire any emission credits that it receives in
10    connection with the electricity covered by such agreement.
11        Utilities shall maintain adequate records documenting
12    the purchases under the sourcing agreement to comply with
13    this subsection (d) and shall file an accounting with the
14    load forecast that must be filed with the Agency by July 15
15    of each year, in accordance with subsection (d) of Section
16    16-111.5 of the Public Utilities Act.
17        A utility shall be deemed to have complied with the
18    clean coal portfolio standard specified in this subsection
19    (d) if the utility enters into a sourcing agreement as
20    required by this subsection (d).
21        (2) For purposes of this subsection (d), the required
22    execution of sourcing agreements with the initial clean
23    coal facility for a particular year shall be measured as a
24    percentage of the actual amount of electricity
25    (megawatt-hours) supplied by the electric utility to
26    eligible retail customers in the planning year ending

 

 

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1    immediately prior to the agreement's execution. For
2    purposes of this subsection (d), the amount paid per
3    kilowatthour means the total amount paid for electric
4    service expressed on a per kilowatthour basis. For purposes
5    of this subsection (d), the total amount paid for electric
6    service includes without limitation amounts paid for
7    supply, transmission, distribution, surcharges and add-on
8    taxes.
9        Notwithstanding the requirements of this subsection
10    (d), the total amount paid under sourcing agreements with
11    clean coal facilities pursuant to the procurement plan for
12    any given year shall be reduced by an amount necessary to
13    limit the annual estimated average net increase due to the
14    costs of these resources included in the amounts paid by
15    eligible retail customers in connection with electric
16    service to:
17            (A) in 2010, no more than 0.5% of the amount paid
18        per kilowatthour by those customers during the year
19        ending May 31, 2009;
20            (B) in 2011, the greater of an additional 0.5% of
21        the amount paid per kilowatthour by those customers
22        during the year ending May 31, 2010 or 1% of the amount
23        paid per kilowatthour by those customers during the
24        year ending May 31, 2009;
25            (C) in 2012, the greater of an additional 0.5% of
26        the amount paid per kilowatthour by those customers

 

 

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1        during the year ending May 31, 2011 or 1.5% of the
2        amount paid per kilowatthour by those customers during
3        the year ending May 31, 2009;
4            (D) in 2013, the greater of an additional 0.5% of
5        the amount paid per kilowatthour by those customers
6        during the year ending May 31, 2012 or 2% of the amount
7        paid per kilowatthour by those customers during the
8        year ending May 31, 2009; and
9            (E) thereafter, the total amount paid under
10        sourcing agreements with clean coal facilities
11        pursuant to the procurement plan for any single year
12        shall be reduced by an amount necessary to limit the
13        estimated average net increase due to the cost of these
14        resources included in the amounts paid by eligible
15        retail customers in connection with electric service
16        to no more than the greater of (i) 2.015% of the amount
17        paid per kilowatthour by those customers during the
18        year ending May 31, 2009 or (ii) the incremental amount
19        per kilowatthour paid for these resources in 2013.
20        These requirements may be altered only as provided by
21        statute.
22        No later than June 30, 2015, the Commission shall
23    review the limitation on the total amount paid under
24    sourcing agreements, if any, with clean coal facilities
25    pursuant to this subsection (d) and report to the General
26    Assembly its findings as to whether that limitation unduly

 

 

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1    constrains the amount of electricity generated by
2    cost-effective clean coal facilities that is covered by
3    sourcing agreements.
4        (3) Initial clean coal facility. In order to promote
5    development of clean coal facilities in Illinois, each
6    electric utility subject to this Section shall execute a
7    sourcing agreement to source electricity from a proposed
8    clean coal facility in Illinois (the "initial clean coal
9    facility") that will have a nameplate capacity of at least
10    500 MW when commercial operation commences, that has a
11    final Clean Air Act permit on June 1, 2009 (the effective
12    date of Public Act 95-1027), and that will meet the
13    definition of clean coal facility in Section 1-10 of this
14    Act when commercial operation commences. The sourcing
15    agreements with this initial clean coal facility shall be
16    subject to both approval of the initial clean coal facility
17    by the General Assembly and satisfaction of the
18    requirements of paragraph (4) of this subsection (d) and
19    shall be executed within 90 days after any such approval by
20    the General Assembly. The Agency and the Commission shall
21    have authority to inspect all books and records associated
22    with the initial clean coal facility during the term of
23    such a sourcing agreement. A utility's sourcing agreement
24    for electricity produced by the initial clean coal facility
25    shall include:
26            (A) a formula contractual price (the "contract

 

 

SB3977- 62 -LRB101 20818 JLS 70537 b

1        price") approved pursuant to paragraph (4) of this
2        subsection (d), which shall:
3                (i) be determined using a cost of service
4            methodology employing either a level or deferred
5            capital recovery component, based on a capital
6            structure consisting of 45% equity and 55% debt,
7            and a return on equity as may be approved by the
8            Federal Energy Regulatory Commission, which in any
9            case may not exceed the lower of 11.5% or the rate
10            of return approved by the General Assembly
11            pursuant to paragraph (4) of this subsection (d);
12            and
13                (ii) provide that all miscellaneous net
14            revenue, including but not limited to net revenue
15            from the sale of emission allowances, if any,
16            substitute natural gas, if any, grants or other
17            support provided by the State of Illinois or the
18            United States Government, firm transmission
19            rights, if any, by-products produced by the
20            facility, energy or capacity derived from the
21            facility and not covered by a sourcing agreement
22            pursuant to paragraph (3) of this subsection (d) or
23            item (5) of subsection (d) of Section 16-115 of the
24            Public Utilities Act, whether generated from the
25            synthesis gas derived from coal, from SNG, or from
26            natural gas, shall be credited against the revenue

 

 

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1            requirement for this initial clean coal facility;
2            (B) power purchase provisions, which shall:
3                (i) provide that the utility party to such
4            sourcing agreement shall pay the contract price
5            for electricity delivered under such sourcing
6            agreement;
7                (ii) require delivery of electricity to the
8            regional transmission organization market of the
9            utility that is party to such sourcing agreement;
10                (iii) require the utility party to such
11            sourcing agreement to buy from the initial clean
12            coal facility in each hour an amount of energy
13            equal to all clean coal energy made available from
14            the initial clean coal facility during such hour
15            times a fraction, the numerator of which is such
16            utility's retail market sales of electricity
17            (expressed in kilowatthours sold) in the State
18            during the prior calendar month and the
19            denominator of which is the total retail market
20            sales of electricity (expressed in kilowatthours
21            sold) in the State by utilities during such prior
22            month and the sales of electricity (expressed in
23            kilowatthours sold) in the State by alternative
24            retail electric suppliers during such prior month
25            that are subject to the requirements of this
26            subsection (d) and paragraph (5) of subsection (d)

 

 

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1            of Section 16-115 of the Public Utilities Act,
2            provided that the amount purchased by the utility
3            in any year will be limited by paragraph (2) of
4            this subsection (d); and
5                (iv) be considered pre-existing contracts in
6            such utility's procurement plans for eligible
7            retail customers;
8            (C) contract for differences provisions, which
9        shall:
10                (i) require the utility party to such sourcing
11            agreement to contract with the initial clean coal
12            facility in each hour with respect to an amount of
13            energy equal to all clean coal energy made
14            available from the initial clean coal facility
15            during such hour times a fraction, the numerator of
16            which is such utility's retail market sales of
17            electricity (expressed in kilowatthours sold) in
18            the utility's service territory in the State
19            during the prior calendar month and the
20            denominator of which is the total retail market
21            sales of electricity (expressed in kilowatthours
22            sold) in the State by utilities during such prior
23            month and the sales of electricity (expressed in
24            kilowatthours sold) in the State by alternative
25            retail electric suppliers during such prior month
26            that are subject to the requirements of this

 

 

SB3977- 65 -LRB101 20818 JLS 70537 b

1            subsection (d) and paragraph (5) of subsection (d)
2            of Section 16-115 of the Public Utilities Act,
3            provided that the amount paid by the utility in any
4            year will be limited by paragraph (2) of this
5            subsection (d);
6                (ii) provide that the utility's payment
7            obligation in respect of the quantity of
8            electricity determined pursuant to the preceding
9            clause (i) shall be limited to an amount equal to
10            (1) the difference between the contract price
11            determined pursuant to subparagraph (A) of
12            paragraph (3) of this subsection (d) and the
13            day-ahead price for electricity delivered to the
14            regional transmission organization market of the
15            utility that is party to such sourcing agreement
16            (or any successor delivery point at which such
17            utility's supply obligations are financially
18            settled on an hourly basis) (the "reference
19            price") on the day preceding the day on which the
20            electricity is delivered to the initial clean coal
21            facility busbar, multiplied by (2) the quantity of
22            electricity determined pursuant to the preceding
23            clause (i); and
24                (iii) not require the utility to take physical
25            delivery of the electricity produced by the
26            facility;

 

 

SB3977- 66 -LRB101 20818 JLS 70537 b

1            (D) general provisions, which shall:
2                (i) specify a term of no more than 30 years,
3            commencing on the commercial operation date of the
4            facility;
5                (ii) provide that utilities shall maintain
6            adequate records documenting purchases under the
7            sourcing agreements entered into to comply with
8            this subsection (d) and shall file an accounting
9            with the load forecast that must be filed with the
10            Agency by July 15 of each year, in accordance with
11            subsection (d) of Section 16-111.5 of the Public
12            Utilities Act;
13                (iii) provide that all costs associated with
14            the initial clean coal facility will be
15            periodically reported to the Federal Energy
16            Regulatory Commission and to purchasers in
17            accordance with applicable laws governing
18            cost-based wholesale power contracts;
19                (iv) permit the Illinois Power Agency to
20            assume ownership of the initial clean coal
21            facility, without monetary consideration and
22            otherwise on reasonable terms acceptable to the
23            Agency, if the Agency so requests no less than 3
24            years prior to the end of the stated contract term;
25                (v) require the owner of the initial clean coal
26            facility to provide documentation to the

 

 

SB3977- 67 -LRB101 20818 JLS 70537 b

1            Commission each year, starting in the facility's
2            first year of commercial operation, accurately
3            reporting the quantity of carbon emissions from
4            the facility that have been captured and
5            sequestered and report any quantities of carbon
6            released from the site or sites at which carbon
7            emissions were sequestered in prior years, based
8            on continuous monitoring of such sites. If, in any
9            year after the first year of commercial operation,
10            the owner of the facility fails to demonstrate that
11            the initial clean coal facility captured and
12            sequestered at least 50% of the total carbon
13            emissions that the facility would otherwise emit
14            or that sequestration of emissions from prior
15            years has failed, resulting in the release of
16            carbon dioxide into the atmosphere, the owner of
17            the facility must offset excess emissions. Any
18            such carbon offsets must be permanent, additional,
19            verifiable, real, located within the State of
20            Illinois, and legally and practicably enforceable.
21            The cost of such offsets for the facility that are
22            not recoverable shall not exceed $15 million in any
23            given year. No costs of any such purchases of
24            carbon offsets may be recovered from a utility or
25            its customers. All carbon offsets purchased for
26            this purpose and any carbon emission credits

 

 

SB3977- 68 -LRB101 20818 JLS 70537 b

1            associated with sequestration of carbon from the
2            facility must be permanently retired. The initial
3            clean coal facility shall not forfeit its
4            designation as a clean coal facility if the
5            facility fails to fully comply with the applicable
6            carbon sequestration requirements in any given
7            year, provided the requisite offsets are
8            purchased. However, the Attorney General, on
9            behalf of the People of the State of Illinois, may
10            specifically enforce the facility's sequestration
11            requirement and the other terms of this contract
12            provision. Compliance with the sequestration
13            requirements and offset purchase requirements
14            specified in paragraph (3) of this subsection (d)
15            shall be reviewed annually by an independent
16            expert retained by the owner of the initial clean
17            coal facility, with the advance written approval
18            of the Attorney General. The Commission may, in the
19            course of the review specified in item (vii),
20            reduce the allowable return on equity for the
21            facility if the facility willfully fails to comply
22            with the carbon capture and sequestration
23            requirements set forth in this item (v);
24                (vi) include limits on, and accordingly
25            provide for modification of, the amount the
26            utility is required to source under the sourcing

 

 

SB3977- 69 -LRB101 20818 JLS 70537 b

1            agreement consistent with paragraph (2) of this
2            subsection (d);
3                (vii) require Commission review: (1) to
4            determine the justness, reasonableness, and
5            prudence of the inputs to the formula referenced in
6            subparagraphs (A)(i) through (A)(iii) of paragraph
7            (3) of this subsection (d), prior to an adjustment
8            in those inputs including, without limitation, the
9            capital structure and return on equity, fuel
10            costs, and other operations and maintenance costs
11            and (2) to approve the costs to be passed through
12            to customers under the sourcing agreement by which
13            the utility satisfies its statutory obligations.
14            Commission review shall occur no less than every 3
15            years, regardless of whether any adjustments have
16            been proposed, and shall be completed within 9
17            months;
18                (viii) limit the utility's obligation to such
19            amount as the utility is allowed to recover through
20            tariffs filed with the Commission, provided that
21            neither the clean coal facility nor the utility
22            waives any right to assert federal pre-emption or
23            any other argument in response to a purported
24            disallowance of recovery costs;
25                (ix) limit the utility's or alternative retail
26            electric supplier's obligation to incur any

 

 

SB3977- 70 -LRB101 20818 JLS 70537 b

1            liability until such time as the facility is in
2            commercial operation and generating power and
3            energy and such power and energy is being delivered
4            to the facility busbar;
5                (x) provide that the owner or owners of the
6            initial clean coal facility, which is the
7            counterparty to such sourcing agreement, shall
8            have the right from time to time to elect whether
9            the obligations of the utility party thereto shall
10            be governed by the power purchase provisions or the
11            contract for differences provisions;
12                (xi) append documentation showing that the
13            formula rate and contract, insofar as they relate
14            to the power purchase provisions, have been
15            approved by the Federal Energy Regulatory
16            Commission pursuant to Section 205 of the Federal
17            Power Act;
18                (xii) provide that any changes to the terms of
19            the contract, insofar as such changes relate to the
20            power purchase provisions, are subject to review
21            under the public interest standard applied by the
22            Federal Energy Regulatory Commission pursuant to
23            Sections 205 and 206 of the Federal Power Act; and
24                (xiii) conform with customary lender
25            requirements in power purchase agreements used as
26            the basis for financing non-utility generators.

 

 

SB3977- 71 -LRB101 20818 JLS 70537 b

1        (4) Effective date of sourcing agreements with the
2    initial clean coal facility. Any proposed sourcing
3    agreement with the initial clean coal facility shall not
4    become effective unless the following reports are prepared
5    and submitted and authorizations and approvals obtained:
6            (i) Facility cost report. The owner of the initial
7        clean coal facility shall submit to the Commission, the
8        Agency, and the General Assembly a front-end
9        engineering and design study, a facility cost report,
10        method of financing (including but not limited to
11        structure and associated costs), and an operating and
12        maintenance cost quote for the facility (collectively
13        "facility cost report"), which shall be prepared in
14        accordance with the requirements of this paragraph (4)
15        of subsection (d) of this Section, and shall provide
16        the Commission and the Agency access to the work
17        papers, relied upon documents, and any other backup
18        documentation related to the facility cost report.
19            (ii) Commission report. Within 6 months following
20        receipt of the facility cost report, the Commission, in
21        consultation with the Agency, shall submit a report to
22        the General Assembly setting forth its analysis of the
23        facility cost report. Such report shall include, but
24        not be limited to, a comparison of the costs associated
25        with electricity generated by the initial clean coal
26        facility to the costs associated with electricity

 

 

SB3977- 72 -LRB101 20818 JLS 70537 b

1        generated by other types of generation facilities, an
2        analysis of the rate impacts on residential and small
3        business customers over the life of the sourcing
4        agreements, and an analysis of the likelihood that the
5        initial clean coal facility will commence commercial
6        operation by and be delivering power to the facility's
7        busbar by 2016. To assist in the preparation of its
8        report, the Commission, in consultation with the
9        Agency, may hire one or more experts or consultants,
10        the costs of which shall be paid for by the owner of
11        the initial clean coal facility. The Commission and
12        Agency may begin the process of selecting such experts
13        or consultants prior to receipt of the facility cost
14        report.
15            (iii) General Assembly approval. The proposed
16        sourcing agreements shall not take effect unless,
17        based on the facility cost report and the Commission's
18        report, the General Assembly enacts authorizing
19        legislation approving (A) the projected price, stated
20        in cents per kilowatthour, to be charged for
21        electricity generated by the initial clean coal
22        facility, (B) the projected impact on residential and
23        small business customers' bills over the life of the
24        sourcing agreements, and (C) the maximum allowable
25        return on equity for the project; and
26            (iv) Commission review. If the General Assembly

 

 

SB3977- 73 -LRB101 20818 JLS 70537 b

1        enacts authorizing legislation pursuant to
2        subparagraph (iii) approving a sourcing agreement, the
3        Commission shall, within 90 days of such enactment,
4        complete a review of such sourcing agreement. During
5        such time period, the Commission shall implement any
6        directive of the General Assembly, resolve any
7        disputes between the parties to the sourcing agreement
8        concerning the terms of such agreement, approve the
9        form of such agreement, and issue an order finding that
10        the sourcing agreement is prudent and reasonable.
11        The facility cost report shall be prepared as follows:
12            (A) The facility cost report shall be prepared by
13        duly licensed engineering and construction firms
14        detailing the estimated capital costs payable to one or
15        more contractors or suppliers for the engineering,
16        procurement and construction of the components
17        comprising the initial clean coal facility and the
18        estimated costs of operation and maintenance of the
19        facility. The facility cost report shall include:
20                (i) an estimate of the capital cost of the core
21            plant based on one or more front end engineering
22            and design studies for the gasification island and
23            related facilities. The core plant shall include
24            all civil, structural, mechanical, electrical,
25            control, and safety systems.
26                (ii) an estimate of the capital cost of the

 

 

SB3977- 74 -LRB101 20818 JLS 70537 b

1            balance of the plant, including any capital costs
2            associated with sequestration of carbon dioxide
3            emissions and all interconnects and interfaces
4            required to operate the facility, such as
5            transmission of electricity, construction or
6            backfeed power supply, pipelines to transport
7            substitute natural gas or carbon dioxide, potable
8            water supply, natural gas supply, water supply,
9            water discharge, landfill, access roads, and coal
10            delivery.
11            The quoted construction costs shall be expressed
12        in nominal dollars as of the date that the quote is
13        prepared and shall include capitalized financing costs
14        during construction, taxes, insurance, and other
15        owner's costs, and an assumed escalation in materials
16        and labor beyond the date as of which the construction
17        cost quote is expressed.
18            (B) The front end engineering and design study for
19        the gasification island and the cost study for the
20        balance of plant shall include sufficient design work
21        to permit quantification of major categories of
22        materials, commodities and labor hours, and receipt of
23        quotes from vendors of major equipment required to
24        construct and operate the clean coal facility.
25            (C) The facility cost report shall also include an
26        operating and maintenance cost quote that will provide

 

 

SB3977- 75 -LRB101 20818 JLS 70537 b

1        the estimated cost of delivered fuel, personnel,
2        maintenance contracts, chemicals, catalysts,
3        consumables, spares, and other fixed and variable
4        operations and maintenance costs. The delivered fuel
5        cost estimate will be provided by a recognized third
6        party expert or experts in the fuel and transportation
7        industries. The balance of the operating and
8        maintenance cost quote, excluding delivered fuel
9        costs, will be developed based on the inputs provided
10        by duly licensed engineering and construction firms
11        performing the construction cost quote, potential
12        vendors under long-term service agreements and plant
13        operating agreements, or recognized third party plant
14        operator or operators.
15            The operating and maintenance cost quote
16        (including the cost of the front end engineering and
17        design study) shall be expressed in nominal dollars as
18        of the date that the quote is prepared and shall
19        include taxes, insurance, and other owner's costs, and
20        an assumed escalation in materials and labor beyond the
21        date as of which the operating and maintenance cost
22        quote is expressed.
23            (D) The facility cost report shall also include an
24        analysis of the initial clean coal facility's ability
25        to deliver power and energy into the applicable
26        regional transmission organization markets and an

 

 

SB3977- 76 -LRB101 20818 JLS 70537 b

1        analysis of the expected capacity factor for the
2        initial clean coal facility.
3            (E) Amounts paid to third parties unrelated to the
4        owner or owners of the initial clean coal facility to
5        prepare the core plant construction cost quote,
6        including the front end engineering and design study,
7        and the operating and maintenance cost quote will be
8        reimbursed through Coal Development Bonds.
9        (5) Re-powering and retrofitting coal-fired power
10    plants previously owned by Illinois utilities to qualify as
11    clean coal facilities. During the 2009 procurement
12    planning process and thereafter, the Agency and the
13    Commission shall consider sourcing agreements covering
14    electricity generated by power plants that were previously
15    owned by Illinois utilities and that have been or will be
16    converted into clean coal facilities, as defined by Section
17    1-10 of this Act. Pursuant to such procurement planning
18    process, the owners of such facilities may propose to the
19    Agency sourcing agreements with utilities and alternative
20    retail electric suppliers required to comply with
21    subsection (d) of this Section and item (5) of subsection
22    (d) of Section 16-115 of the Public Utilities Act, covering
23    electricity generated by such facilities. In the case of
24    sourcing agreements that are power purchase agreements,
25    the contract price for electricity sales shall be
26    established on a cost of service basis. In the case of

 

 

SB3977- 77 -LRB101 20818 JLS 70537 b

1    sourcing agreements that are contracts for differences,
2    the contract price from which the reference price is
3    subtracted shall be established on a cost of service basis.
4    The Agency and the Commission may approve any such utility
5    sourcing agreements that do not exceed cost-based
6    benchmarks developed by the procurement administrator, in
7    consultation with the Commission staff, Agency staff and
8    the procurement monitor, subject to Commission review and
9    approval. The Commission shall have authority to inspect
10    all books and records associated with these clean coal
11    facilities during the term of any such contract.
12        (6) Costs incurred under this subsection (d) or
13    pursuant to a contract entered into under this subsection
14    (d) shall be deemed prudently incurred and reasonable in
15    amount and the electric utility shall be entitled to full
16    cost recovery pursuant to the tariffs filed with the
17    Commission.
18    (d-5) Zero emission standard.
19        (1) Beginning with the delivery year commencing on June
20    1, 2017, the Agency shall, for electric utilities that
21    serve at least 100,000 retail customers in this State,
22    procure contracts with zero emission facilities that are
23    reasonably capable of generating cost-effective zero
24    emission credits in an amount approximately equal to 16% of
25    the actual amount of electricity delivered by each electric
26    utility to retail customers in the State during calendar

 

 

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1    year 2014. For an electric utility serving fewer than
2    100,000 retail customers in this State that requested,
3    under Section 16-111.5 of the Public Utilities Act, that
4    the Agency procure power and energy for all or a portion of
5    the utility's Illinois load for the delivery year
6    commencing June 1, 2016, the Agency shall procure contracts
7    with zero emission facilities that are reasonably capable
8    of generating cost-effective zero emission credits in an
9    amount approximately equal to 16% of the portion of power
10    and energy to be procured by the Agency for the utility.
11    The duration of the contracts procured under this
12    subsection (d-5) shall be for a term of 10 years ending May
13    31, 2027. The quantity of zero emission credits to be
14    procured under the contracts shall be all of the zero
15    emission credits generated by the zero emission facility in
16    each delivery year; however, if the zero emission facility
17    is owned by more than one entity, then the quantity of zero
18    emission credits to be procured under the contracts shall
19    be the amount of zero emission credits that are generated
20    from the portion of the zero emission facility that is
21    owned by the winning supplier.
22        The 16% value identified in this paragraph (1) is the
23    average of the percentage targets in subparagraph (B) of
24    paragraph (1) of subsection (c) of this Section for the 5
25    delivery years beginning June 1, 2017.
26        The procurement process shall be subject to the

 

 

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1    following provisions:
2            (A) Those zero emission facilities that intend to
3        participate in the procurement shall submit to the
4        Agency the following eligibility information for each
5        zero emission facility on or before the date
6        established by the Agency:
7                (i) the in-service date and remaining useful
8            life of the zero emission facility;
9                (ii) the amount of power generated annually
10            for each of the years 2005 through 2015, and the
11            projected zero emission credits to be generated
12            over the remaining useful life of the zero emission
13            facility, which shall be used to determine the
14            capability of each facility;
15                (iii) the annual zero emission facility cost
16            projections, expressed on a per megawatthour
17            basis, over the next 6 delivery years, which shall
18            include the following: operation and maintenance
19            expenses; fully allocated overhead costs, which
20            shall be allocated using the methodology developed
21            by the Institute for Nuclear Power Operations;
22            fuel expenditures; non-fuel capital expenditures;
23            spent fuel expenditures; a return on working
24            capital; the cost of operational and market risks
25            that could be avoided by ceasing operation; and any
26            other costs necessary for continued operations,

 

 

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1            provided that "necessary" means, for purposes of
2            this item (iii), that the costs could reasonably be
3            avoided only by ceasing operations of the zero
4            emission facility; and
5                (iv) a commitment to continue operating, for
6            the duration of the contract or contracts executed
7            under the procurement held under this subsection
8            (d-5), the zero emission facility that produces
9            the zero emission credits to be procured in the
10            procurement.
11            The information described in item (iii) of this
12        subparagraph (A) may be submitted on a confidential
13        basis and shall be treated and maintained by the
14        Agency, the procurement administrator, and the
15        Commission as confidential and proprietary and exempt
16        from disclosure under subparagraphs (a) and (g) of
17        paragraph (1) of Section 7 of the Freedom of
18        Information Act. The Office of Attorney General shall
19        have access to, and maintain the confidentiality of,
20        such information pursuant to Section 6.5 of the
21        Attorney General Act.
22            (B) The price for each zero emission credit
23        procured under this subsection (d-5) for each delivery
24        year shall be in an amount that equals the Social Cost
25        of Carbon, expressed on a price per megawatthour basis.
26        However, to ensure that the procurement remains

 

 

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1        affordable to retail customers in this State if
2        electricity prices increase, the price in an
3        applicable delivery year shall be reduced below the
4        Social Cost of Carbon by the amount ("Price
5        Adjustment") by which the market price index for the
6        applicable delivery year exceeds the baseline market
7        price index for the consecutive 12-month period ending
8        May 31, 2016. If the Price Adjustment is greater than
9        or equal to the Social Cost of Carbon in an applicable
10        delivery year, then no payments shall be due in that
11        delivery year. The components of this calculation are
12        defined as follows:
13                (i) Social Cost of Carbon: The Social Cost of
14            Carbon is $16.50 per megawatthour, which is based
15            on the U.S. Interagency Working Group on Social
16            Cost of Carbon's price in the August 2016 Technical
17            Update using a 3% discount rate, adjusted for
18            inflation for each year of the program. Beginning
19            with the delivery year commencing June 1, 2023, the
20            price per megawatthour shall increase by $1 per
21            megawatthour, and continue to increase by an
22            additional $1 per megawatthour each delivery year
23            thereafter.
24                (ii) Baseline market price index: The baseline
25            market price index for the consecutive 12-month
26            period ending May 31, 2016 is $31.40 per

 

 

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1            megawatthour, which is based on the sum of (aa) the
2            average day-ahead energy price across all hours of
3            such 12-month period at the PJM Interconnection
4            LLC Northern Illinois Hub, (bb) 50% multiplied by
5            the Base Residual Auction, or its successor,
6            capacity price for the rest of the RTO zone group
7            determined by PJM Interconnection LLC, divided by
8            24 hours per day, and (cc) 50% multiplied by the
9            Planning Resource Auction, or its successor,
10            capacity price for Zone 4 determined by the
11            Midcontinent Independent System Operator, Inc.,
12            divided by 24 hours per day.
13                (iii) Market price index: The market price
14            index for a delivery year shall be the sum of
15            projected energy prices and projected capacity
16            prices determined as follows:
17                    (aa) Projected energy prices: the
18                projected energy prices for the applicable
19                delivery year shall be calculated once for the
20                year using the forward market price for the PJM
21                Interconnection, LLC Northern Illinois Hub.
22                The forward market price shall be calculated as
23                follows: the energy forward prices for each
24                month of the applicable delivery year averaged
25                for each trade date during the calendar year
26                immediately preceding that delivery year to

 

 

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1                produce a single energy forward price for the
2                delivery year. The forward market price
3                calculation shall use data published by the
4                Intercontinental Exchange, or its successor.
5                    (bb) Projected capacity prices:
6                        (I) For the delivery years commencing
7                    June 1, 2017, June 1, 2018, and June 1,
8                    2019, the projected capacity price shall
9                    be equal to the sum of (1) 50% multiplied
10                    by the Base Residual Auction, or its
11                    successor, price for the rest of the RTO
12                    zone group as determined by PJM
13                    Interconnection LLC, divided by 24 hours
14                    per day and, (2) 50% multiplied by the
15                    resource auction price determined in the
16                    resource auction administered by the
17                    Midcontinent Independent System Operator,
18                    Inc., in which the largest percentage of
19                    load cleared for Local Resource Zone 4,
20                    divided by 24 hours per day, and where such
21                    price is determined by the Midcontinent
22                    Independent System Operator, Inc.
23                        (II) For the delivery year commencing
24                    June 1, 2020, and each year thereafter, the
25                    projected capacity price shall be equal to
26                    the sum of (1) 50% multiplied by the Base

 

 

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1                    Residual Auction, or its successor, price
2                    for the ComEd zone as determined by PJM
3                    Interconnection LLC, divided by 24 hours
4                    per day, and (2) 50% multiplied by the
5                    resource auction price determined in the
6                    resource auction administered by the
7                    Midcontinent Independent System Operator,
8                    Inc., in which the largest percentage of
9                    load cleared for Local Resource Zone 4,
10                    divided by 24 hours per day, and where such
11                    price is determined by the Midcontinent
12                    Independent System Operator, Inc.
13            For purposes of this subsection (d-5):
14                "Rest of the RTO" and "ComEd Zone" shall have
15            the meaning ascribed to them by PJM
16            Interconnection, LLC.
17                "RTO" means regional transmission
18            organization.
19            (C) No later than 45 days after June 1, 2017 (the
20        effective date of Public Act 99-906), the Agency shall
21        publish its proposed zero emission standard
22        procurement plan. The plan shall be consistent with the
23        provisions of this paragraph (1) and shall provide that
24        winning bids shall be selected based on public interest
25        criteria that include, but are not limited to,
26        minimizing carbon dioxide emissions that result from

 

 

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1        electricity consumed in Illinois and minimizing sulfur
2        dioxide, nitrogen oxide, and particulate matter
3        emissions that adversely affect the citizens of this
4        State. In particular, the selection of winning bids
5        shall take into account the incremental environmental
6        benefits resulting from the procurement, such as any
7        existing environmental benefits that are preserved by
8        the procurements held under Public Act 99-906 and would
9        cease to exist if the procurements were not held,
10        including the preservation of zero emission
11        facilities. The plan shall also describe in detail how
12        each public interest factor shall be considered and
13        weighted in the bid selection process to ensure that
14        the public interest criteria are applied to the
15        procurement and given full effect.
16            For purposes of developing the plan, the Agency
17        shall consider any reports issued by a State agency,
18        board, or commission under House Resolution 1146 of the
19        98th General Assembly and paragraph (4) of subsection
20        (d) of this Section, as well as publicly available
21        analyses and studies performed by or for regional
22        transmission organizations that serve the State and
23        their independent market monitors.
24            Upon publishing of the zero emission standard
25        procurement plan, copies of the plan shall be posted
26        and made publicly available on the Agency's website.

 

 

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1        All interested parties shall have 10 days following the
2        date of posting to provide comment to the Agency on the
3        plan. All comments shall be posted to the Agency's
4        website. Following the end of the comment period, but
5        no more than 60 days later than June 1, 2017 (the
6        effective date of Public Act 99-906), the Agency shall
7        revise the plan as necessary based on the comments
8        received and file its zero emission standard
9        procurement plan with the Commission.
10            If the Commission determines that the plan will
11        result in the procurement of cost-effective zero
12        emission credits, then the Commission shall, after
13        notice and hearing, but no later than 45 days after the
14        Agency filed the plan, approve the plan or approve with
15        modification. For purposes of this subsection (d-5),
16        "cost effective" means the projected costs of
17        procuring zero emission credits from zero emission
18        facilities do not cause the limit stated in paragraph
19        (2) of this subsection to be exceeded.
20            (C-5) As part of the Commission's review and
21        acceptance or rejection of the procurement results,
22        the Commission shall, in its public notice of
23        successful bidders:
24                (i) identify how the winning bids satisfy the
25            public interest criteria described in subparagraph
26            (C) of this paragraph (1) of minimizing carbon

 

 

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1            dioxide emissions that result from electricity
2            consumed in Illinois and minimizing sulfur
3            dioxide, nitrogen oxide, and particulate matter
4            emissions that adversely affect the citizens of
5            this State;
6                (ii) specifically address how the selection of
7            winning bids takes into account the incremental
8            environmental benefits resulting from the
9            procurement, including any existing environmental
10            benefits that are preserved by the procurements
11            held under Public Act 99-906 and would have ceased
12            to exist if the procurements had not been held,
13            such as the preservation of zero emission
14            facilities;
15                (iii) quantify the environmental benefit of
16            preserving the resources identified in item (ii)
17            of this subparagraph (C-5), including the
18            following:
19                    (aa) the value of avoided greenhouse gas
20                emissions measured as the product of the zero
21                emission facilities' output over the contract
22                term multiplied by the U.S. Environmental
23                Protection Agency eGrid subregion carbon
24                dioxide emission rate and the U.S. Interagency
25                Working Group on Social Cost of Carbon's price
26                in the August 2016 Technical Update using a 3%

 

 

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1                discount rate, adjusted for inflation for each
2                delivery year; and
3                    (bb) the costs of replacement with other
4                zero carbon dioxide resources, including wind
5                and photovoltaic, based upon the simple
6                average of the following:
7                        (I) the price, or if there is more than
8                    one price, the average of the prices, paid
9                    for renewable energy credits from new
10                    utility-scale wind projects in the
11                    procurement events specified in item (i)
12                    of subparagraph (G) of paragraph (1) of
13                    subsection (c) of this Section; and
14                        (II) the price, or if there is more
15                    than one price, the average of the prices,
16                    paid for renewable energy credits from new
17                    utility-scale solar projects and
18                    brownfield site photovoltaic projects in
19                    the procurement events specified in item
20                    (ii) of subparagraph (G) of paragraph (1)
21                    of subsection (c) of this Section and,
22                    after January 1, 2015, renewable energy
23                    credits from photovoltaic distributed
24                    generation projects in procurement events
25                    held under subsection (c) of this Section.
26            Each utility shall enter into binding contractual

 

 

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1        arrangements with the winning suppliers.
2            The procurement described in this subsection
3        (d-5), including, but not limited to, the execution of
4        all contracts procured, shall be completed no later
5        than May 10, 2017. Based on the effective date of
6        Public Act 99-906, the Agency and Commission may, as
7        appropriate, modify the various dates and timelines
8        under this subparagraph and subparagraphs (C) and (D)
9        of this paragraph (1). The procurement and plan
10        approval processes required by this subsection (d-5)
11        shall be conducted in conjunction with the procurement
12        and plan approval processes required by subsection (c)
13        of this Section and Section 16-111.5 of the Public
14        Utilities Act, to the extent practicable.
15        Notwithstanding whether a procurement event is
16        conducted under Section 16-111.5 of the Public
17        Utilities Act, the Agency shall immediately initiate a
18        procurement process on June 1, 2017 (the effective date
19        of Public Act 99-906).
20            (D) Following the procurement event described in
21        this paragraph (1) and consistent with subparagraph
22        (B) of this paragraph (1), the Agency shall calculate
23        the payments to be made under each contract for the
24        next delivery year based on the market price index for
25        that delivery year. The Agency shall publish the
26        payment calculations no later than May 25, 2017 and

 

 

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1        every May 25 thereafter.
2            (E) Notwithstanding the requirements of this
3        subsection (d-5), the contracts executed under this
4        subsection (d-5) shall provide that the zero emission
5        facility may, as applicable, suspend or terminate
6        performance under the contracts in the following
7        instances:
8                (i) A zero emission facility shall be excused
9            from its performance under the contract for any
10            cause beyond the control of the resource,
11            including, but not restricted to, acts of God,
12            flood, drought, earthquake, storm, fire,
13            lightning, epidemic, war, riot, civil disturbance
14            or disobedience, labor dispute, labor or material
15            shortage, sabotage, acts of public enemy,
16            explosions, orders, regulations or restrictions
17            imposed by governmental, military, or lawfully
18            established civilian authorities, which, in any of
19            the foregoing cases, by exercise of commercially
20            reasonable efforts the zero emission facility
21            could not reasonably have been expected to avoid,
22            and which, by the exercise of commercially
23            reasonable efforts, it has been unable to
24            overcome. In such event, the zero emission
25            facility shall be excused from performance for the
26            duration of the event, including, but not limited

 

 

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1            to, delivery of zero emission credits, and no
2            payment shall be due to the zero emission facility
3            during the duration of the event.
4                (ii) A zero emission facility shall be
5            permitted to terminate the contract if legislation
6            is enacted into law by the General Assembly that
7            imposes or authorizes a new tax, special
8            assessment, or fee on the generation of
9            electricity, the ownership or leasehold of a
10            generating unit, or the privilege or occupation of
11            such generation, ownership, or leasehold of
12            generation units by a zero emission facility.
13            However, the provisions of this item (ii) do not
14            apply to any generally applicable tax, special
15            assessment or fee, or requirements imposed by
16            federal law.
17                (iii) A zero emission facility shall be
18            permitted to terminate the contract in the event
19            that the resource requires capital expenditures in
20            excess of $40,000,000 that were neither known nor
21            reasonably foreseeable at the time it executed the
22            contract and that a prudent owner or operator of
23            such resource would not undertake.
24                (iv) A zero emission facility shall be
25            permitted to terminate the contract in the event
26            the Nuclear Regulatory Commission terminates the

 

 

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1            resource's license.
2            (F) If the zero emission facility elects to
3        terminate a contract under subparagraph (E) of this
4        paragraph (1), then the Commission shall reopen the
5        docket in which the Commission approved the zero
6        emission standard procurement plan under subparagraph
7        (C) of this paragraph (1) and, after notice and
8        hearing, enter an order acknowledging the contract
9        termination election if such termination is consistent
10        with the provisions of this subsection (d-5).
11        (2) For purposes of this subsection (d-5), the amount
12    paid per kilowatthour means the total amount paid for
13    electric service expressed on a per kilowatthour basis. For
14    purposes of this subsection (d-5), the total amount paid
15    for electric service includes, without limitation, amounts
16    paid for supply, transmission, distribution, surcharges,
17    and add-on taxes.
18        Notwithstanding the requirements of this subsection
19    (d-5), the contracts executed under this subsection (d-5)
20    shall provide that the total of zero emission credits
21    procured under a procurement plan shall be subject to the
22    limitations of this paragraph (2). For each delivery year,
23    the contractual volume receiving payments in such year
24    shall be reduced for all retail customers based on the
25    amount necessary to limit the net increase that delivery
26    year to the costs of those credits included in the amounts

 

 

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1    paid by eligible retail customers in connection with
2    electric service to no more than 1.65% of the amount paid
3    per kilowatthour by eligible retail customers during the
4    year ending May 31, 2009. The result of this computation
5    shall apply to and reduce the procurement for all retail
6    customers, and all those customers shall pay the same
7    single, uniform cents per kilowatthour charge under
8    subsection (k) of Section 16-108 of the Public Utilities
9    Act. To arrive at a maximum dollar amount of zero emission
10    credits to be paid for the particular delivery year, the
11    resulting per kilowatthour amount shall be applied to the
12    actual amount of kilowatthours of electricity delivered by
13    the electric utility in the delivery year immediately prior
14    to the procurement, to all retail customers in its service
15    territory. Unpaid contractual volume for any delivery year
16    shall be paid in any subsequent delivery year in which such
17    payments can be made without exceeding the amount specified
18    in this paragraph (2). The calculations required by this
19    paragraph (2) shall be made only once for each procurement
20    plan year. Once the determination as to the amount of zero
21    emission credits to be paid is made based on the
22    calculations set forth in this paragraph (2), no subsequent
23    rate impact determinations shall be made and no adjustments
24    to those contract amounts shall be allowed. All costs
25    incurred under those contracts and in implementing this
26    subsection (d-5) shall be recovered by the electric utility

 

 

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1    as provided in this Section.
2        No later than June 30, 2019, the Commission shall
3    review the limitation on the amount of zero emission
4    credits procured under this subsection (d-5) and report to
5    the General Assembly its findings as to whether that
6    limitation unduly constrains the procurement of
7    cost-effective zero emission credits.
8        (3) Six years after the execution of a contract under
9    this subsection (d-5), the Agency shall determine whether
10    the actual zero emission credit payments received by the
11    supplier over the 6-year period exceed the Average ZEC
12    Payment. In addition, at the end of the term of a contract
13    executed under this subsection (d-5), or at the time, if
14    any, a zero emission facility's contract is terminated
15    under subparagraph (E) of paragraph (1) of this subsection
16    (d-5), then the Agency shall determine whether the actual
17    zero emission credit payments received by the supplier over
18    the term of the contract exceed the Average ZEC Payment,
19    after taking into account any amounts previously credited
20    back to the utility under this paragraph (3). If the Agency
21    determines that the actual zero emission credit payments
22    received by the supplier over the relevant period exceed
23    the Average ZEC Payment, then the supplier shall credit the
24    difference back to the utility. The amount of the credit
25    shall be remitted to the applicable electric utility no
26    later than 120 days after the Agency's determination, which

 

 

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1    the utility shall reflect as a credit on its retail
2    customer bills as soon as practicable; however, the credit
3    remitted to the utility shall not exceed the total amount
4    of payments received by the facility under its contract.
5        For purposes of this Section, the Average ZEC Payment
6    shall be calculated by multiplying the quantity of zero
7    emission credits delivered under the contract times the
8    average contract price. The average contract price shall be
9    determined by subtracting the amount calculated under
10    subparagraph (B) of this paragraph (3) from the amount
11    calculated under subparagraph (A) of this paragraph (3), as
12    follows:
13            (A) The average of the Social Cost of Carbon, as
14        defined in subparagraph (B) of paragraph (1) of this
15        subsection (d-5), during the term of the contract.
16            (B) The average of the market price indices, as
17        defined in subparagraph (B) of paragraph (1) of this
18        subsection (d-5), during the term of the contract,
19        minus the baseline market price index, as defined in
20        subparagraph (B) of paragraph (1) of this subsection
21        (d-5).
22        If the subtraction yields a negative number, then the
23    Average ZEC Payment shall be zero.
24        (4) Cost-effective zero emission credits procured from
25    zero emission facilities shall satisfy the applicable
26    definitions set forth in Section 1-10 of this Act.

 

 

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1        (5) The electric utility shall retire all zero emission
2    credits used to comply with the requirements of this
3    subsection (d-5).
4        (6) Electric utilities shall be entitled to recover all
5    of the costs associated with the procurement of zero
6    emission credits through an automatic adjustment clause
7    tariff in accordance with subsection (k) and (m) of Section
8    16-108 of the Public Utilities Act, and the contracts
9    executed under this subsection (d-5) shall provide that the
10    utilities' payment obligations under such contracts shall
11    be reduced if an adjustment is required under subsection
12    (m) of Section 16-108 of the Public Utilities Act.
13        (7) This subsection (d-5) shall become inoperative on
14    January 1, 2028.
15    (e) The draft procurement plans are subject to public
16comment, as required by Section 16-111.5 of the Public
17Utilities Act.
18    (f) The Agency shall submit the final procurement plan to
19the Commission. The Agency shall revise a procurement plan if
20the Commission determines that it does not meet the standards
21set forth in Section 16-111.5 of the Public Utilities Act.
22    (g) The Agency shall assess fees to each affected utility
23to recover the costs incurred in preparation of the annual
24procurement plan for the utility.
25    (h) The Agency shall assess fees to each bidder to recover
26the costs incurred in connection with a competitive procurement

 

 

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1process.
2    (i) A renewable energy credit, carbon emission credit, or
3zero emission credit can only be used once to comply with a
4single portfolio or other standard as set forth in subsection
5(c), subsection (d), or subsection (d-5) of this Section,
6respectively. A renewable energy credit, carbon emission
7credit, or zero emission credit cannot be used to satisfy the
8requirements of more than one standard. If more than one type
9of credit is issued for the same megawatt hour of energy, only
10one credit can be used to satisfy the requirements of a single
11standard. After such use, the credit must be retired together
12with any other credits issued for the same megawatt hour of
13energy.
14(Source: P.A. 100-863, eff. 8-14-18; 101-81, eff. 7-12-19;
15101-113, eff. 1-1-20.)
 
16    Section 10. The Public Utilities Act is amended by changing
17Sections 8-103B, 16-102, 16-107.6, 16-108.5, and 16-128A and by
18adding Sections 8-218, 16-108.19 and 16-108.20 as follows:
 
19    (220 ILCS 5/8-103B)
20    Sec. 8-103B. Energy efficiency and demand-response
21measures.
22    (a) It is the policy of the State that electric utilities
23are required to use cost-effective energy efficiency and
24demand-response measures to reduce the total Btus of

 

 

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1electricity, natural gas, or other fuels needed to meet the end
2use or uses for all retail customers delivery load. Requiring
3investment in cost-effective energy efficiency and
4demand-response measures will reduce direct and indirect costs
5to consumers by decreasing environmental impacts and by
6avoiding or delaying the need for new generation, transmission,
7and distribution infrastructure. It serves the public interest
8to allow electric utilities to recover costs for reasonably and
9prudently incurred expenditures for energy efficiency and
10demand-response measures. As used in this Section,
11"cost-effective" means that the measures satisfy the total
12resource cost test. The low-income measures described in
13subsection (c) of this Section shall not be required to meet
14the total resource cost test. For purposes of this Section, the
15terms "energy-efficiency", "demand-response", "electric
16utility", and "total resource cost test" have the meanings set
17forth in the Illinois Power Agency Act.
18    (a-5) This Section applies to electric utilities serving
19more than 500,000 retail customers in the State for those
20multi-year plans commencing after December 31, 2017.
21    (b) For purposes of this Section, electric utilities
22subject to this Section that serve more than 3,000,000 retail
23customers in the State shall be deemed to have achieved a
24cumulative persisting annual savings of 6.6% from energy
25efficiency measures and programs implemented during the period
26beginning January 1, 2012 and ending December 31, 2017, which

 

 

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1percent is based on the deemed average weather normalized sales
2of electric power and energy during calendar years 2014, 2015,
3and 2016 of 88,000,000 MWhs. For the purposes of this
4subsection (b) and subsection (b-5), the 88,000,000 MWhs of
5deemed electric power and energy sales shall be reduced by the
6number of MWhs equal to the sum of the annual consumption of
7customers that are exempt from subsections (a) through (j) of
8this Section under subsection (l) of this Section, as averaged
9across the calendar years 2014, 2015, and 2016. After 2017, the
10deemed value of cumulative persisting annual savings from
11energy efficiency measures and programs implemented during the
12period beginning January 1, 2012 and ending December 31, 2017,
13shall be reduced each year, as follows, and the applicable
14value shall be applied to and count toward the utility's
15achievement of the cumulative persisting annual savings goals
16set forth in subsection (b-5):
17        (1) 5.8% deemed cumulative persisting annual savings
18    for the year ending December 31, 2018;
19        (2) 5.2% deemed cumulative persisting annual savings
20    for the year ending December 31, 2019;
21        (3) 4.5% deemed cumulative persisting annual savings
22    for the year ending December 31, 2020;
23        (4) 4.0% deemed cumulative persisting annual savings
24    for the year ending December 31, 2021;
25        (5) 3.5% deemed cumulative persisting annual savings
26    for the year ending December 31, 2022;

 

 

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1        (6) 3.1% deemed cumulative persisting annual savings
2    for the year ending December 31, 2023;
3        (7) 2.8% deemed cumulative persisting annual savings
4    for the year ending December 31, 2024;
5        (8) 2.5% deemed cumulative persisting annual savings
6    for the year ending December 31, 2025;
7        (9) 2.3% deemed cumulative persisting annual savings
8    for the year ending December 31, 2026;
9        (10) 2.1% deemed cumulative persisting annual savings
10    for the year ending December 31, 2027;
11        (11) 1.8% deemed cumulative persisting annual savings
12    for the year ending December 31, 2028;
13        (12) 1.7% deemed cumulative persisting annual savings
14    for the year ending December 31, 2029; and
15        (13) 1.5% deemed cumulative persisting annual savings
16    for the year ending December 31, 2030.
17    For purposes of this Section, "cumulative persisting
18annual savings" means the total electric energy savings in a
19given year from measures installed in that year or in previous
20years, but no earlier than January 1, 2012, that are still
21operational and providing savings in that year because the
22measures have not yet reached the end of their useful lives.
23    (b-5) Beginning in 2018, electric utilities subject to this
24Section that serve more than 3,000,000 retail customers in the
25State shall achieve the following cumulative persisting annual
26savings goals, as modified by subsection (f) of this Section

 

 

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1and as compared to the deemed baseline of 88,000,000 MWhs of
2electric power and energy sales set forth in subsection (b), as
3reduced by the number of MWhs equal to the sum of the annual
4consumption of customers that are exempt from subsections (a)
5through (j) of this Section under subsection (l) of this
6Section as averaged across the calendar years 2014, 2015, and
72016, through the implementation of energy efficiency measures
8during the applicable year and in prior years, but no earlier
9than January 1, 2012:
10        (1) 7.8% cumulative persisting annual savings for the
11    year ending December 31, 2018;
12        (2) 9.1% cumulative persisting annual savings for the
13    year ending December 31, 2019;
14        (3) 10.4% cumulative persisting annual savings for the
15    year ending December 31, 2020;
16        (4) 11.8% cumulative persisting annual savings for the
17    year ending December 31, 2021;
18        (5) 13.1% cumulative persisting annual savings for the
19    year ending December 31, 2022;
20        (6) 14.4% cumulative persisting annual savings for the
21    year ending December 31, 2023;
22        (7) 15.7% cumulative persisting annual savings for the
23    year ending December 31, 2024;
24        (8) 17% cumulative persisting annual savings for the
25    year ending December 31, 2025;
26        (9) 17.9% cumulative persisting annual savings for the

 

 

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1    year ending December 31, 2026;
2        (10) 18.8% cumulative persisting annual savings for
3    the year ending December 31, 2027;
4        (11) 19.7% cumulative persisting annual savings for
5    the year ending December 31, 2028;
6        (12) 20.6% cumulative persisting annual savings for
7    the year ending December 31, 2029; and
8        (13) 21.5% cumulative persisting annual savings for
9    the year ending December 31, 2030.
10    (b-10) For purposes of this Section, electric utilities
11subject to this Section that serve less than 3,000,000 retail
12customers but more than 500,000 retail customers in the State
13shall be deemed to have achieved a cumulative persisting annual
14savings of 6.6% from energy efficiency measures and programs
15implemented during the period beginning January 1, 2012 and
16ending December 31, 2017, which is based on the deemed average
17weather normalized sales of electric power and energy during
18calendar years 2014, 2015, and 2016 of 36,900,000 MWhs. For the
19purposes of this subsection (b-10) and subsection (b-15), the
2036,900,000 MWhs of deemed electric power and energy sales shall
21be reduced by the number of MWhs equal to the sum of the annual
22consumption of customers that are exempt from subsections (a)
23through (j) of this Section under subsection (l) of this
24Section, as averaged across the calendar years 2014, 2015, and
252016. After 2017, the deemed value of cumulative persisting
26annual savings from energy efficiency measures and programs

 

 

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1implemented during the period beginning January 1, 2012 and
2ending December 31, 2017, shall be reduced each year, as
3follows, and the applicable value shall be applied to and count
4toward the utility's achievement of the cumulative persisting
5annual savings goals set forth in subsection (b-15):
6        (1) 5.8% deemed cumulative persisting annual savings
7    for the year ending December 31, 2018;
8        (2) 5.2% deemed cumulative persisting annual savings
9    for the year ending December 31, 2019;
10        (3) 4.5% deemed cumulative persisting annual savings
11    for the year ending December 31, 2020;
12        (4) 4.0% deemed cumulative persisting annual savings
13    for the year ending December 31, 2021;
14        (5) 3.5% deemed cumulative persisting annual savings
15    for the year ending December 31, 2022;
16        (6) 3.1% deemed cumulative persisting annual savings
17    for the year ending December 31, 2023;
18        (7) 2.8% deemed cumulative persisting annual savings
19    for the year ending December 31, 2024;
20        (8) 2.5% deemed cumulative persisting annual savings
21    for the year ending December 31, 2025;
22        (9) 2.3% deemed cumulative persisting annual savings
23    for the year ending December 31, 2026;
24        (10) 2.1% deemed cumulative persisting annual savings
25    for the year ending December 31, 2027;
26        (11) 1.8% deemed cumulative persisting annual savings

 

 

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1    for the year ending December 31, 2028;
2        (12) 1.7% deemed cumulative persisting annual savings
3    for the year ending December 31, 2029; and
4        (13) 1.5% deemed cumulative persisting annual savings
5    for the year ending December 31, 2030.
6    (b-15) Beginning in 2018, electric utilities subject to
7this Section that serve less than 3,000,000 retail customers
8but more than 500,000 retail customers in the State shall
9achieve the following cumulative persisting annual savings
10goals, as modified by subsection (b-20) and subsection (f) of
11this Section and as compared to the deemed baseline as reduced
12by the number of MWhs equal to the sum of the annual
13consumption of customers that are exempt from subsections (a)
14through (j) of this Section under subsection (l) of this
15Section as averaged across the calendar years 2014, 2015, and
162016, through the implementation of energy efficiency measures
17during the applicable year and in prior years, but no earlier
18than January 1, 2012:
19        (1) 7.4% cumulative persisting annual savings for the
20    year ending December 31, 2018;
21        (2) 8.2% cumulative persisting annual savings for the
22    year ending December 31, 2019;
23        (3) 9.0% cumulative persisting annual savings for the
24    year ending December 31, 2020;
25        (4) 9.8% cumulative persisting annual savings for the
26    year ending December 31, 2021;

 

 

SB3977- 105 -LRB101 20818 JLS 70537 b

1        (5) 10.6% cumulative persisting annual savings for the
2    year ending December 31, 2022;
3        (6) 11.4% cumulative persisting annual savings for the
4    year ending December 31, 2023;
5        (7) 12.2% cumulative persisting annual savings for the
6    year ending December 31, 2024;
7        (8) 13% cumulative persisting annual savings for the
8    year ending December 31, 2025;
9        (9) 13.6% cumulative persisting annual savings for the
10    year ending December 31, 2026;
11        (10) 14.2% cumulative persisting annual savings for
12    the year ending December 31, 2027;
13        (11) 14.8% cumulative persisting annual savings for
14    the year ending December 31, 2028;
15        (12) 15.4% cumulative persisting annual savings for
16    the year ending December 31, 2029; and
17        (13) 16% cumulative persisting annual savings for the
18    year ending December 31, 2030.
19    The difference between the cumulative persisting annual
20savings goal for the applicable calendar year and the
21cumulative persisting annual savings goal for the immediately
22preceding calendar year is 0.8% for the period of January 1,
232018 through December 31, 2025 and 0.6% for the period of
24January 1, 2026 through December 31, 2030.
25    (b-20) Each electric utility subject to this Section may
26include cost-effective voltage optimization measures in its

 

 

SB3977- 106 -LRB101 20818 JLS 70537 b

1plans submitted under subsections (f) and (g) of this Section,
2and the costs incurred by a utility to implement the measures
3under a Commission-approved plan shall be recovered under the
4provisions of Article IX or Section 16-108.5 of this Act. For
5purposes of this Section, the measure life of voltage
6optimization measures shall be 15 years. The measure life
7period is independent of the depreciation rate of the voltage
8optimization assets deployed.
9    Within 270 days after June 1, 2017 (the effective date of
10Public Act 99-906), an electric utility that serves less than
113,000,000 retail customers but more than 500,000 retail
12customers in the State shall file a plan with the Commission
13that identifies the cost-effective voltage optimization
14investment the electric utility plans to undertake through
15December 31, 2024. The Commission, after notice and hearing,
16shall approve or approve with modification the plan within 120
17days after the plan's filing and, in the order approving or
18approving with modification the plan, the Commission shall
19adjust the applicable cumulative persisting annual savings
20goals set forth in subsection (b-15) to reflect any amount of
21cost-effective energy savings approved by the Commission that
22is greater than or less than the following cumulative
23persisting annual savings values attributable to voltage
24optimization for the applicable year:
25        (1) 0.0% of cumulative persisting annual savings for
26    the year ending December 31, 2018;

 

 

SB3977- 107 -LRB101 20818 JLS 70537 b

1        (2) 0.17% of cumulative persisting annual savings for
2    the year ending December 31, 2019;
3        (3) 0.17% of cumulative persisting annual savings for
4    the year ending December 31, 2020;
5        (4) 0.33% of cumulative persisting annual savings for
6    the year ending December 31, 2021;
7        (5) 0.5% of cumulative persisting annual savings for
8    the year ending December 31, 2022;
9        (6) 0.67% of cumulative persisting annual savings for
10    the year ending December 31, 2023;
11        (7) 0.83% of cumulative persisting annual savings for
12    the year ending December 31, 2024; and
13        (8) 1.0% of cumulative persisting annual savings for
14    the year ending December 31, 2025.
15    (b-25) In the event an electric utility jointly offers an
16energy efficiency measure or program with a gas utility under
17plans approved under this Section and Section 8-104 of this
18Act, the electric utility may continue offering the program,
19including the gas energy efficiency measures, in the event the
20gas utility discontinues funding the program. In that event,
21the energy savings value associated with such other fuels shall
22be converted to electric energy savings on an equivalent Btu
23basis for the premises. However, the electric utility shall
24prioritize programs for low-income residential customers to
25the extent practicable. An electric utility may recover the
26costs of offering the gas energy efficiency measures under this

 

 

SB3977- 108 -LRB101 20818 JLS 70537 b

1subsection (b-25).
2    For those energy efficiency measures or programs that save
3both electricity and other fuels but are not jointly offered
4with a gas utility under plans approved under this Section and
5Section 8-104 or not offered with an affiliated gas utility
6under paragraph (6) of subsection (f) of Section 8-104 of this
7Act, or for those energy efficiency measures that achieve
8savings of fuels other than electricity, an the electric
9utility may count savings of fuels other than electricity
10toward the achievement of its annual savings goal, and the
11energy savings value associated with such other fuels shall be
12converted to electric energy savings on an equivalent Btu basis
13at the premises.
14    In no event shall more than 10% of each year's applicable
15annual incremental goal as defined in paragraph (7) of
16subsection (g) of this Section be met through savings of fuels
17other than electricity; however, savings of fuels other than
18electricity achieved by measures that educate about,
19incentivize, encourage, or otherwise support the use of
20electricity to power, in whole or in part, vehicles, including,
21but not limited to, cars, trucks, buses, trains, trolleys,
22boats, on-road or off-road vehicles, or other equipment or
23methods of transporting goods or people, shall count towards
24the applicable annual incremental goal and shall not be
25included in the 10% limit set forth in this subsection (b-25).
26Such measures shall include, but are not limited to, measures

 

 

SB3977- 109 -LRB101 20818 JLS 70537 b

1that educate about, incentivize, encourage, or otherwise
2support the adoption of electric vehicles by retail customers
3of all customer classes.
4    (c) Electric utilities shall be responsible for overseeing
5the design, development, and filing of energy efficiency plans
6with the Commission and may, as part of that implementation,
7outsource various aspects of program development and
8implementation. A minimum of 10%, for electric utilities that
9serve more than 3,000,000 retail customers in the State, and a
10minimum of 7%, for electric utilities that serve less than
113,000,000 retail customers but more than 500,000 retail
12customers in the State, of the utility's entire portfolio
13funding level for a given year shall be used to procure
14cost-effective energy efficiency measures from units of local
15government, municipal corporations, school districts, public
16housing, and community college districts, provided that a
17minimum percentage of available funds shall be used to procure
18energy efficiency from public housing, which percentage shall
19be equal to public housing's share of public building energy
20consumption.
21    The utilities shall also implement energy efficiency
22measures targeted at low-income households, which, for
23purposes of this Section, shall be defined as households at or
24below 80% of area median income, and expenditures to implement
25the measures shall be no less than $25,000,000 per year for
26electric utilities that serve more than 3,000,000 retail

 

 

SB3977- 110 -LRB101 20818 JLS 70537 b

1customers in the State and no less than $8,350,000 per year for
2electric utilities that serve less than 3,000,000 retail
3customers but more than 500,000 retail customers in the State.
4    Each electric utility shall assess opportunities to
5implement cost-effective energy efficiency measures and
6programs through a public housing authority or authorities
7located in its service territory. If such opportunities are
8identified, the utility shall propose such measures and
9programs to address the opportunities. Expenditures to address
10such opportunities shall be credited toward the minimum
11procurement and expenditure requirements set forth in this
12subsection (c).
13    Implementation of energy efficiency measures and programs
14targeted at low-income households should be contracted, when it
15is practicable, to independent third parties that have
16demonstrated capabilities to serve such households, with a
17preference for not-for-profit entities and government agencies
18that have existing relationships with or experience serving
19low-income communities in the State.
20    Each electric utility shall develop and implement
21reporting procedures that address and assist in determining the
22amount of energy savings that can be applied to the low-income
23procurement and expenditure requirements set forth in this
24subsection (c).
25    The electric utilities shall also convene a low-income
26energy efficiency advisory committee to assist in the design

 

 

SB3977- 111 -LRB101 20818 JLS 70537 b

1and evaluation of the low-income energy efficiency programs.
2The committee shall be comprised of the electric utilities
3subject to the requirements of this Section, the gas utilities
4subject to the requirements of Section 8-104 of this Act, the
5utilities' low-income energy efficiency implementation
6contractors, and representatives of community-based
7organizations.
8    (d) Notwithstanding any other provision of law to the
9contrary, a utility providing approved energy efficiency
10measures and, if applicable, demand-response measures in the
11State shall be permitted to recover all reasonable and
12prudently incurred costs of those measures from all retail
13customers, except as provided in subsection (l) of this
14Section, as follows, provided that nothing in this subsection
15(d) permits the double recovery of such costs from customers:
16        (1) The utility may recover its costs through an
17    automatic adjustment clause tariff filed with and approved
18    by the Commission. The tariff shall be established outside
19    the context of a general rate case. Each year the
20    Commission shall initiate a review to reconcile any amounts
21    collected with the actual costs and to determine the
22    required adjustment to the annual tariff factor to match
23    annual expenditures. To enable the financing of the
24    incremental capital expenditures, including regulatory
25    assets, for electric utilities that serve less than
26    3,000,000 retail customers but more than 500,000 retail

 

 

SB3977- 112 -LRB101 20818 JLS 70537 b

1    customers in the State, the utility's actual year-end
2    capital structure that includes a common equity ratio,
3    excluding goodwill, of up to and including 50% of the total
4    capital structure shall be deemed reasonable and used to
5    set rates.
6        (2) A utility may recover its costs through an energy
7    efficiency formula rate approved by the Commission under a
8    filing under subsections (f) and (g) of this Section, which
9    shall specify the cost components that form the basis of
10    the rate charged to customers with sufficient specificity
11    to operate in a standardized manner and be updated annually
12    with transparent information that reflects the utility's
13    actual costs to be recovered during the applicable rate
14    year, which is the period beginning with the first billing
15    day of January and extending through the last billing day
16    of the following December. The energy efficiency formula
17    rate shall be implemented through a tariff filed with the
18    Commission under subsections (f) and (g) of this Section
19    that is consistent with the provisions of this paragraph
20    (2) and that shall be applicable to all delivery services
21    customers. The Commission shall conduct an investigation
22    of the tariff in a manner consistent with the provisions of
23    this paragraph (2), subsections (f) and (g) of this
24    Section, and the provisions of Article IX of this Act to
25    the extent they do not conflict with this paragraph (2).
26    The energy efficiency formula rate approved by the

 

 

SB3977- 113 -LRB101 20818 JLS 70537 b

1    Commission shall remain in effect at the discretion of the
2    utility and shall do the following:
3            (A) Provide for the recovery of the utility's
4        actual costs incurred under this Section that are
5        prudently incurred and reasonable in amount consistent
6        with Commission practice and law. The sole fact that a
7        cost differs from that incurred in a prior calendar
8        year or that an investment is different from that made
9        in a prior calendar year shall not imply the imprudence
10        or unreasonableness of that cost or investment.
11            (B) Reflect the utility's actual year-end capital
12        structure for the applicable calendar year, excluding
13        goodwill, subject to a determination of prudence and
14        reasonableness consistent with Commission practice and
15        law. To enable the financing of the incremental capital
16        expenditures, including regulatory assets, for
17        electric utilities that serve less than 3,000,000
18        retail customers but more than 500,000 retail
19        customers in the State, a participating electric
20        utility's actual year-end capital structure that
21        includes a common equity ratio, excluding goodwill, of
22        up to and including 50% of the total capital structure
23        shall be deemed reasonable and used to set rates.
24            (C) Include a cost of equity, which in all rate
25        years for electric utilities that serve 3,000,000 or
26        more retail customers in this State, and in each rate

 

 

SB3977- 114 -LRB101 20818 JLS 70537 b

1        year commencing before December 1, 2019 for electric
2        utilities that serve less than 3,000,000 retail
3        customers but more than 500,000 retail customers in
4        this State, shall be calculated as the sum of the
5        following:
6                (i) the average for the applicable calendar
7            year of the monthly average yields of 30-year U.S.
8            Treasury bonds published by the Board of Governors
9            of the Federal Reserve System in its weekly H.15
10            Statistical Release or successor publication; and
11                (ii) 580 basis points.
12            For electric utilities that serve less than
13        3,000,000 retail customers but more than 500,000
14        retail customers in the State, for each rate year
15        commencing after November 30, 2019, the cost of equity
16        shall be calculated as the sum of the following: (i)
17        the average for the applicable calendar year of the
18        monthly average yields of 30-year U.S. Treasury bonds
19        published by the Board of Governors of the Federal
20        Reserve System in its weekly H.15 Statistical Release
21        or successor publication; and (ii) 680 basis points;
22        however, if the cost of equity as calculated under this
23        subparagraph (C) of this paragraph (2) for each rate
24        year commencing after November 30, 2019, for electric
25        utilities that serve less than 3,000,000 retail
26        customers but more than 500,000 retail customers in

 

 

SB3977- 115 -LRB101 20818 JLS 70537 b

1        this State is greater than the national average cost of
2        equity for the rate year by 50 basis points or more,
3        then the Illinois Commerce Commission shall include a
4        cost of equity at a rate equal to the national average
5        cost of equity as calculated under this subparagraph
6        (C) of this paragraph (2) plus 50 basis points. For
7        purposes of this subparagraph (C) of this paragraph
8        (2), the national average cost of equity for a rate
9        year shall be the simple average of the cost of equity
10        approved in each order of a state regulatory
11        commission, other than the Commission, issued during
12        that rate year that is applicable to retail electric
13        service provided by an investor-owned public utility
14        company operating in the United States. No order shall
15        be excluded from the national average cost of equity
16        calculated under this subparagraph (C) of this
17        paragraph (2) on the grounds that it is subject to
18        rehearing or appeal. In the hearing during the first
19        rate year commencing after November 30, 2019, the
20        Commission shall set the cost of equity using the
21        method applicable to rate years commencing prior to
22        December 1, 2019. In the hearings in rate years
23        subsequent to such first rate year, the Commission
24        shall set the cost of equity using the method
25        applicable to rate years commencing after November 30,
26        2019, including the reconciliation of the first rate

 

 

SB3977- 116 -LRB101 20818 JLS 70537 b

1        year commencing after November 30, 2019. If, for any
2        rate year, there are fewer than 15 applicable orders of
3        state regulatory commissions with which to compute the
4        average cost of equity under this subparagraph (C) of
5        this paragraph (2), the Commission shall include in the
6        calculation of the national average the number of state
7        regulatory orders from the prior year or years
8        necessary to reach a total of 15, beginning with the
9        most recently issued and proceeding in reverse
10        chronological order.
11            At such time as the Board of Governors of the
12        Federal Reserve System ceases to include the monthly
13        average yields of 30-year U.S. Treasury bonds in its
14        weekly H.15 Statistical Release or successor
15        publication, the monthly average yields of the U.S.
16        Treasury bonds then having the longest duration
17        published by the Board of Governors in its weekly H.15
18        Statistical Release or successor publication shall
19        instead be used for purposes of this paragraph (2).
20            (D) Permit and set forth protocols, subject to a
21        determination of prudence and reasonableness
22        consistent with Commission practice and law, for the
23        following:
24                (i) recovery of incentive compensation expense
25            that is based on the achievement of operational
26            metrics, including metrics related to budget

 

 

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1            controls, outage duration and frequency, safety,
2            customer service, efficiency and productivity, and
3            environmental compliance; however, this protocol
4            shall not apply if such expense related to costs
5            incurred under this Section is recovered under
6            Article IX or Section 16-108.5 of this Act;
7            incentive compensation expense that is based on
8            net income or an affiliate's earnings per share
9            shall not be recoverable under the energy
10            efficiency formula rate;
11                (ii) recovery of pension and other
12            post-employment benefits expense, provided that
13            such costs are supported by an actuarial study;
14            however, this protocol shall not apply if such
15            expense related to costs incurred under this
16            Section is recovered under Article IX or Section
17            16-108.5 of this Act;
18                (iii) recovery of existing regulatory assets
19            over the periods previously authorized by the
20            Commission;
21                (iv) as described in subsection (e),
22            amortization of costs incurred under this Section;
23            and
24                (v) projected, weather normalized billing
25            determinants for the applicable rate year.
26            (E) Provide for an annual reconciliation, as

 

 

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1        described in paragraph (3) of this subsection (d), less
2        any deferred taxes related to the reconciliation, with
3        interest at an annual rate of return equal to the
4        utility's weighted average cost of capital, including
5        a revenue conversion factor calculated to recover or
6        refund all additional income taxes that may be payable
7        or receivable as a result of that return, of the energy
8        efficiency revenue requirement reflected in rates for
9        each calendar year, beginning with the calendar year in
10        which the utility files its energy efficiency formula
11        rate tariff under this paragraph (2), with what the
12        revenue requirement would have been had the actual cost
13        information for the applicable calendar year been
14        available at the filing date.
15        The utility shall file, together with its tariff, the
16    projected costs to be incurred by the utility during the
17    rate year under the utility's multi-year plan approved
18    under subsections (f) and (g) of this Section, including,
19    but not limited to, the projected capital investment costs
20    and projected regulatory asset balances with
21    correspondingly updated depreciation and amortization
22    reserves and expense, that shall populate the energy
23    efficiency formula rate and set the initial rates under the
24    formula.
25        The Commission shall review the proposed tariff in
26    conjunction with its review of a proposed multi-year plan,

 

 

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1    as specified in paragraph (5) of subsection (g) of this
2    Section. The review shall be based on the same evidentiary
3    standards, including, but not limited to, those concerning
4    the prudence and reasonableness of the costs incurred by
5    the utility, the Commission applies in a hearing to review
6    a filing for a general increase in rates under Article IX
7    of this Act. The initial rates shall take effect beginning
8    with the January monthly billing period following the
9    Commission's approval.
10        The tariff's rate design and cost allocation across
11    customer classes shall be consistent with the utility's
12    automatic adjustment clause tariff in effect on June 1,
13    2017 (the effective date of Public Act 99-906); however,
14    the Commission may revise the tariff's rate design and cost
15    allocation in subsequent proceedings under paragraph (3)
16    of this subsection (d).
17        If the energy efficiency formula rate is terminated,
18    the then current rates shall remain in effect until such
19    time as the energy efficiency costs are incorporated into
20    new rates that are set under this subsection (d) or Article
21    IX of this Act, subject to retroactive rate adjustment,
22    with interest, to reconcile rates charged with actual
23    costs.
24        (3) The provisions of this paragraph (3) shall only
25    apply to an electric utility that has elected to file an
26    energy efficiency formula rate under paragraph (2) of this

 

 

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1    subsection (d). Subsequent to the Commission's issuance of
2    an order approving the utility's energy efficiency formula
3    rate structure and protocols, and initial rates under
4    paragraph (2) of this subsection (d), the utility shall
5    file, on or before June 1 of each year, with the Chief
6    Clerk of the Commission its updated cost inputs to the
7    energy efficiency formula rate for the applicable rate year
8    and the corresponding new charges, as well as the
9    information described in paragraph (9) of subsection (g) of
10    this Section. Each such filing shall conform to the
11    following requirements and include the following
12    information:
13            (A) The inputs to the energy efficiency formula
14        rate for the applicable rate year shall be based on the
15        projected costs to be incurred by the utility during
16        the rate year under the utility's multi-year plan
17        approved under subsections (f) and (g) of this Section,
18        including, but not limited to, projected capital
19        investment costs and projected regulatory asset
20        balances with correspondingly updated depreciation and
21        amortization reserves and expense. The filing shall
22        also include a reconciliation of the energy efficiency
23        revenue requirement that was in effect for the prior
24        rate year (as set by the cost inputs for the prior rate
25        year) with the actual revenue requirement for the prior
26        rate year (determined using a year-end rate base) that

 

 

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1        uses amounts reflected in the applicable FERC Form 1
2        that reports the actual costs for the prior rate year.
3        Any over-collection or under-collection indicated by
4        such reconciliation shall be reflected as a credit
5        against, or recovered as an additional charge to,
6        respectively, with interest calculated at a rate equal
7        to the utility's weighted average cost of capital
8        approved by the Commission for the prior rate year, the
9        charges for the applicable rate year. Such
10        over-collection or under-collection shall be adjusted
11        to remove any deferred taxes related to the
12        reconciliation, for purposes of calculating interest
13        at an annual rate of return equal to the utility's
14        weighted average cost of capital approved by the
15        Commission for the prior rate year, including a revenue
16        conversion factor calculated to recover or refund all
17        additional income taxes that may be payable or
18        receivable as a result of that return. Each
19        reconciliation shall be certified by the participating
20        utility in the same manner that FERC Form 1 is
21        certified. The filing shall also include the charge or
22        credit, if any, resulting from the calculation
23        required by subparagraph (E) of paragraph (2) of this
24        subsection (d).
25            Notwithstanding any other provision of law to the
26        contrary, the intent of the reconciliation is to

 

 

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1        ultimately reconcile both the revenue requirement
2        reflected in rates for each calendar year, beginning
3        with the calendar year in which the utility files its
4        energy efficiency formula rate tariff under paragraph
5        (2) of this subsection (d), with what the revenue
6        requirement determined using a year-end rate base for
7        the applicable calendar year would have been had the
8        actual cost information for the applicable calendar
9        year been available at the filing date.
10            For purposes of this Section, "FERC Form 1" means
11        the Annual Report of Major Electric Utilities,
12        Licensees and Others that electric utilities are
13        required to file with the Federal Energy Regulatory
14        Commission under the Federal Power Act, Sections 3,
15        4(a), 304 and 209, modified as necessary to be
16        consistent with 83 Ill. Admin. Code Part 415 as of May
17        1, 2011. Nothing in this Section is intended to allow
18        costs that are not otherwise recoverable to be
19        recoverable by virtue of inclusion in FERC Form 1.
20            (B) The new charges shall take effect beginning on
21        the first billing day of the following January billing
22        period and remain in effect through the last billing
23        day of the next December billing period regardless of
24        whether the Commission enters upon a hearing under this
25        paragraph (3).
26            (C) The filing shall include relevant and

 

 

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1        necessary data and documentation for the applicable
2        rate year. Normalization adjustments shall not be
3        required.
4        Within 45 days after the utility files its annual
5    update of cost inputs to the energy efficiency formula
6    rate, the Commission shall with reasonable notice,
7    initiate a proceeding concerning whether the projected
8    costs to be incurred by the utility and recovered during
9    the applicable rate year, and that are reflected in the
10    inputs to the energy efficiency formula rate, are
11    consistent with the utility's approved multi-year plan
12    under subsections (f) and (g) of this Section and whether
13    the costs incurred by the utility during the prior rate
14    year were prudent and reasonable. The Commission shall also
15    have the authority to investigate the information and data
16    described in paragraph (9) of subsection (g) of this
17    Section, including the proposed adjustment to the
18    utility's return on equity component of its weighted
19    average cost of capital. During the course of the
20    proceeding, each objection shall be stated with
21    particularity and evidence provided in support thereof,
22    after which the utility shall have the opportunity to rebut
23    the evidence. Discovery shall be allowed consistent with
24    the Commission's Rules of Practice, which Rules of Practice
25    shall be enforced by the Commission or the assigned
26    administrative law judge. The Commission shall apply the

 

 

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1    same evidentiary standards, including, but not limited to,
2    those concerning the prudence and reasonableness of the
3    costs incurred by the utility, during the proceeding as it
4    would apply in a proceeding to review a filing for a
5    general increase in rates under Article IX of this Act. The
6    Commission shall not, however, have the authority in a
7    proceeding under this paragraph (3) to consider or order
8    any changes to the structure or protocols of the energy
9    efficiency formula rate approved under paragraph (2) of
10    this subsection (d). In a proceeding under this paragraph
11    (3), the Commission shall enter its order no later than the
12    earlier of 195 days after the utility's filing of its
13    annual update of cost inputs to the energy efficiency
14    formula rate or December 15. The utility's proposed return
15    on equity calculation, as described in paragraphs (7)
16    through (9) of subsection (g) of this Section, shall be
17    deemed the final, approved calculation on December 15 of
18    the year in which it is filed unless the Commission enters
19    an order on or before December 15, after notice and
20    hearing, that modifies such calculation consistent with
21    this Section. The Commission's determinations of the
22    prudence and reasonableness of the costs incurred, and
23    determination of such return on equity calculation, for the
24    applicable calendar year shall be final upon entry of the
25    Commission's order and shall not be subject to reopening,
26    reexamination, or collateral attack in any other

 

 

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1    Commission proceeding, case, docket, order, rule, or
2    regulation; however, nothing in this paragraph (3) shall
3    prohibit a party from petitioning the Commission to rehear
4    or appeal to the courts the order under the provisions of
5    this Act.
6    (e) Beginning on June 1, 2017 (the effective date of Public
7Act 99-906), a utility subject to the requirements of this
8Section may elect to defer, as a regulatory asset, up to the
9full amount of its expenditures incurred under this Section for
10each annual period, including, but not limited to, any
11expenditures incurred above the funding level set by subsection
12(f) of this Section for a given year. The total expenditures
13deferred as a regulatory asset in a given year shall be
14amortized and recovered over a period that is equal to the
15weighted average of the energy efficiency measure lives
16implemented for that year that are reflected in the regulatory
17asset. The unamortized balance shall be recognized as of
18December 31 for a given year. The utility shall also earn a
19return on the total of the unamortized balances of all of the
20energy efficiency regulatory assets, less any deferred taxes
21related to those unamortized balances, at an annual rate equal
22to the utility's weighted average cost of capital that
23includes, based on a year-end capital structure, the utility's
24actual cost of debt for the applicable calendar year and a cost
25of equity, which shall be calculated in accordance with the
26calculations set forth in subparagraph (C) of paragraph (2) of

 

 

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1subsection (d) of this Section as the sum of the (i) the
2average for the applicable calendar year of the monthly average
3yields of 30-year U.S. Treasury bonds published by the Board of
4Governors of the Federal Reserve System in its weekly H.15
5Statistical Release or successor publication; and (ii) 580
6basis points, including a revenue conversion factor calculated
7to recover or refund all additional income taxes that may be
8payable or receivable as a result of that return. Capital
9investment costs shall be depreciated and recovered over their
10useful lives consistent with generally accepted accounting
11principles. The weighted average cost of capital shall be
12applied to the capital investment cost balance, less any
13accumulated depreciation and accumulated deferred income
14taxes, as of December 31 for a given year.
15    When an electric utility creates a regulatory asset under
16the provisions of this Section, the costs are recovered over a
17period during which customers also receive a benefit which is
18in the public interest. Accordingly, it is the intent of the
19General Assembly that an electric utility that elects to create
20a regulatory asset under the provisions of this Section shall
21recover all of the associated costs as set forth in this
22Section. After the Commission has approved the prudence and
23reasonableness of the costs that comprise the regulatory asset,
24the electric utility shall be permitted to recover all such
25costs, and the value and recoverability through rates of the
26associated regulatory asset shall not be limited, altered,

 

 

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1impaired, or reduced.
2    (f) Beginning in 2017, each electric utility shall file an
3energy efficiency plan with the Commission to meet the energy
4efficiency standards for the next applicable multi-year period
5beginning January 1 of the year following the filing, according
6to the schedule set forth in paragraphs (1) through (3) of this
7subsection (f). If a utility does not file such a plan on or
8before the applicable filing deadline for the plan, it shall
9face a penalty of $100,000 per day until the plan is filed.
10        (1) No later than 30 days after June 1, 2017 (the
11    effective date of Public Act 99-906), each electric utility
12    shall file a 4-year energy efficiency plan commencing on
13    January 1, 2018 that is designed to achieve the cumulative
14    persisting annual savings goals specified in paragraphs
15    (1) through (4) of subsection (b-5) of this Section or in
16    paragraphs (1) through (4) of subsection (b-15) of this
17    Section, as applicable, through implementation of energy
18    efficiency measures; however, the goals may be reduced if
19    the utility's expenditures are limited pursuant to
20    subsection (m) of this Section or, for a utility that
21    serves less than 3,000,000 retail customers, if each of the
22    following conditions are met: (A) the plan's analysis and
23    forecasts of the utility's ability to acquire energy
24    savings demonstrate that achievement of such goals is not
25    cost effective; and (B) the amount of energy savings
26    achieved by the utility as determined by the independent

 

 

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1    evaluator for the most recent year for which savings have
2    been evaluated preceding the plan filing was less than the
3    average annual amount of savings required to achieve the
4    goals for the applicable 4-year plan period. Except as
5    provided in subsection (m) of this Section, annual
6    increases in cumulative persisting annual savings goals
7    during the applicable 4-year plan period shall not be
8    reduced to amounts that are less than the maximum amount of
9    cumulative persisting annual savings that is forecast to be
10    cost-effectively achievable during the 4-year plan period.
11    The Commission shall review any proposed goal reduction as
12    part of its review and approval of the utility's proposed
13    plan.
14        (2) No later than March 1, 2021, each electric utility
15    shall file a 4-year energy efficiency plan commencing on
16    January 1, 2022 that is designed to achieve the cumulative
17    persisting annual savings goals specified in paragraphs
18    (5) through (8) of subsection (b-5) of this Section or in
19    paragraphs (5) through (8) of subsection (b-15) of this
20    Section, as applicable, through implementation of energy
21    efficiency measures; however, the goals may be reduced if
22    the utility's expenditures are limited pursuant to
23    subsection (m) of this Section or, each of the following
24    conditions are met: (A) the plan's analysis and forecasts
25    of the utility's ability to acquire energy savings
26    demonstrate that achievement of such goals is not cost

 

 

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1    effective; and (B) the amount of energy savings achieved by
2    the utility as determined by the independent evaluator for
3    the most recent year for which savings have been evaluated
4    preceding the plan filing was less than the average annual
5    amount of savings required to achieve the goals for the
6    applicable 4-year plan period. Except as provided in
7    subsection (m) of this Section, annual increases in
8    cumulative persisting annual savings goals during the
9    applicable 4-year plan period shall not be reduced to
10    amounts that are less than the maximum amount of cumulative
11    persisting annual savings that is forecast to be
12    cost-effectively achievable during the 4-year plan period.
13    The Commission shall review any proposed goal reduction as
14    part of its review and approval of the utility's proposed
15    plan.
16        (3) No later than March 1, 2025, each electric utility
17    shall file a 5-year energy efficiency plan commencing on
18    January 1, 2026 that is designed to achieve the cumulative
19    persisting annual savings goals specified in paragraphs
20    (9) through (13) of subsection (b-5) of this Section or in
21    paragraphs (9) through (13) of subsection (b-15) of this
22    Section, as applicable, through implementation of energy
23    efficiency measures; however, the goals may be reduced if
24    the utility's expenditures are limited pursuant to
25    subsection (m) of this Section or, each of the following
26    conditions are met: (A) the plan's analysis and forecasts

 

 

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1    of the utility's ability to acquire energy savings
2    demonstrate that achievement of such goals is not cost
3    effective; and (B) the amount of energy savings achieved by
4    the utility as determined by the independent evaluator for
5    the most recent year for which savings have been evaluated
6    preceding the plan filing was less than the average annual
7    amount of savings required to achieve the goals for the
8    applicable 5-year plan period. Except as provided in
9    subsection (m) of this Section, annual increases in
10    cumulative persisting annual savings goals during the
11    applicable 5-year plan period shall not be reduced to
12    amounts that are less than the maximum amount of cumulative
13    persisting annual savings that is forecast to be
14    cost-effectively achievable during the 5-year plan period.
15    The Commission shall review any proposed goal reduction as
16    part of its review and approval of the utility's proposed
17    plan.
18    Each utility's plan shall set forth the utility's proposals
19to meet the energy efficiency standards identified in
20subsection (b-5) or (b-15), as applicable and as such standards
21may have been modified under this subsection (f), taking into
22account the unique circumstances of the utility's service
23territory. For those plans commencing on January 1, 2018, the
24Commission shall seek public comment on the utility's plan and
25shall issue an order approving or disapproving each plan no
26later than 105 days after June 1, 2017 (the effective date of

 

 

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1Public Act 99-906). For those plans commencing after December
231, 2021, the Commission shall seek public comment on the
3utility's plan and shall issue an order approving or
4disapproving each plan within 6 months after its submission. If
5the Commission disapproves a plan, the Commission shall, within
630 days, describe in detail the reasons for the disapproval and
7describe a path by which the utility may file a revised draft
8of the plan to address the Commission's concerns
9satisfactorily. If the utility does not refile with the
10Commission within 60 days, the utility shall be subject to
11penalties at a rate of $100,000 per day until the plan is
12filed. This process shall continue, and penalties shall accrue,
13until the utility has successfully filed a portfolio of energy
14efficiency and demand-response measures. Penalties shall be
15deposited into the Energy Efficiency Trust Fund.
16    (g) In submitting proposed plans and funding levels under
17subsection (f) of this Section to meet the savings goals
18identified in subsection (b-5) or (b-15) of this Section, as
19applicable, the utility shall:
20        (1) Demonstrate that its proposed energy efficiency
21    measures will achieve the applicable requirements that are
22    identified in subsection (b-5) or (b-15) of this Section,
23    as modified by subsection (f) of this Section.
24        (2) Present specific proposals to implement new
25    building and appliance standards that have been placed into
26    effect.

 

 

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1        (3) Demonstrate that its overall portfolio of
2    measures, not including low-income programs described in
3    subsection (c) of this Section, is cost-effective using the
4    total resource cost test or complies with paragraphs (1)
5    through (3) of subsection (f) of this Section and
6    represents a diverse cross-section of opportunities for
7    customers of all rate classes, other than those customers
8    described in subsection (l) of this Section, to participate
9    in the programs. Individual measures need not be cost
10    effective.
11        (4) Present a third-party energy efficiency
12    implementation program subject to the following
13    requirements:
14            (A) beginning with the year commencing January 1,
15        2019, electric utilities that serve more than
16        3,000,000 retail customers in the State shall fund
17        third-party energy efficiency programs in an amount
18        that is no less than $25,000,000 per year, and electric
19        utilities that serve less than 3,000,000 retail
20        customers but more than 500,000 retail customers in the
21        State shall fund third-party energy efficiency
22        programs in an amount that is no less than $8,350,000
23        per year;
24            (B) during 2018, the utility shall conduct a
25        solicitation process for purposes of requesting
26        proposals from third-party vendors for those

 

 

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1        third-party energy efficiency programs to be offered
2        during one or more of the years commencing January 1,
3        2019, January 1, 2020, and January 1, 2021; for those
4        multi-year plans commencing on January 1, 2022 and
5        January 1, 2026, the utility shall conduct a
6        solicitation process during 2021 and 2025,
7        respectively, for purposes of requesting proposals
8        from third-party vendors for those third-party energy
9        efficiency programs to be offered during one or more
10        years of the respective multi-year plan period; for
11        each solicitation process, the utility shall identify
12        the sector, technology, or geographical area for which
13        it is seeking requests for proposals;
14            (C) the utility shall propose the bidder
15        qualifications, performance measurement process, and
16        contract structure, which must include a performance
17        payment mechanism and general terms and conditions;
18        the proposed qualifications, process, and structure
19        shall be subject to Commission approval; and
20            (D) the utility shall retain an independent third
21        party to score the proposals received through the
22        solicitation process described in this paragraph (4),
23        rank them according to their cost per lifetime
24        kilowatt-hours saved, and assemble the portfolio of
25        third-party programs.
26        The electric utility shall recover all costs

 

 

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1    associated with Commission-approved, third-party
2    administered programs regardless of the success of those
3    programs.
4        (4.5) Implement cost-effective demand-response
5    measures to reduce peak demand by 0.1% over the prior year
6    for eligible retail customers, as defined in Section
7    16-111.5 of this Act, and for customers that elect hourly
8    service from the utility pursuant to Section 16-107 of this
9    Act, provided those customers have not been declared
10    competitive. This requirement continues until December 31,
11    2026.
12        (5) Include a proposed or revised cost-recovery tariff
13    mechanism, as provided for under subsection (d) of this
14    Section, to fund the proposed energy efficiency and
15    demand-response measures and to ensure the recovery of the
16    prudently and reasonably incurred costs of
17    Commission-approved programs.
18        (6) Provide for an annual independent evaluation of the
19    performance of the cost-effectiveness of the utility's
20    portfolio of measures, as well as a full review of the
21    multi-year plan results of the broader net program impacts
22    and, to the extent practical, for adjustment of the
23    measures on a going-forward basis as a result of the
24    evaluations. For purposes of evaluating the
25    cost-effectiveness of measures that incentivize,
26    encourage, or otherwise support the purchase of vehicles

 

 

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1    that use electricity for power, in whole or in part,
2    including, but not limited to, cars, trucks, buses, trains,
3    trolleys, boats, on-road or off-road vehicles, or other
4    equipment or methods of transporting goods or people,
5    including, but not limited to, measures that incentivize,
6    encourage, or otherwise support the adoption of electric
7    vehicles by retail customers of all customer classes, the
8    independent evaluation shall include valuation and
9    consideration of the reduction of carbon emissions and
10    avoided costs associated with the reduction in fossil fuel
11    consumption associated with the measures. The resources
12    dedicated to evaluation shall not exceed 3% of portfolio
13    resources in any given year.
14        (7) For electric utilities that serve more than
15    3,000,000 retail customers in the State:
16            (A) Through December 31, 2025, provide for an
17        adjustment to the return on equity component of the
18        utility's weighted average cost of capital calculated
19        under subsection (d) of this Section:
20                (i) If the independent evaluator determines
21            that the utility achieved a cumulative persisting
22            annual savings that is less than the applicable
23            annual incremental goal, then the return on equity
24            component shall be reduced by a maximum of 200
25            basis points in the event that the utility achieved
26            no more than 75% of such goal. If the utility

 

 

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1            achieved more than 75% of the applicable annual
2            incremental goal but less than 100% of such goal,
3            then the return on equity component shall be
4            reduced by 8 basis points for each percent by which
5            the utility failed to achieve the goal.
6                (ii) If the independent evaluator determines
7            that the utility achieved a cumulative persisting
8            annual savings that is more than the applicable
9            annual incremental goal, then the return on equity
10            component shall be increased by a maximum of 200
11            basis points in the event that the utility achieved
12            at least 125% of such goal. If the utility achieved
13            more than 100% of the applicable annual
14            incremental goal but less than 125% of such goal,
15            then the return on equity component shall be
16            increased by 8 basis points for each percent by
17            which the utility achieved above the goal. If the
18            applicable annual incremental goal was reduced
19            under paragraphs (1) or (2) of subsection (f) of
20            this Section, then the following adjustments shall
21            be made to the calculations described in this item
22            (ii):
23                    (aa) the calculation for determining
24                achievement that is at least 125% of the
25                applicable annual incremental goal shall use
26                the unreduced applicable annual incremental

 

 

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1                goal to set the value; and
2                    (bb) the calculation for determining
3                achievement that is less than 125% but more
4                than 100% of the applicable annual incremental
5                goal shall use the reduced applicable annual
6                incremental goal to set the value for 100%
7                achievement of the goal and shall use the
8                unreduced goal to set the value for 125%
9                achievement. The 8 basis point value shall also
10                be modified, as necessary, so that the 200
11                basis points are evenly apportioned among each
12                percentage point value between 100% and 125%
13                achievement.
14            (B) For the period January 1, 2026 through December
15        31, 2030, provide for an adjustment to the return on
16        equity component of the utility's weighted average
17        cost of capital calculated under subsection (d) of this
18        Section:
19                (i) If the independent evaluator determines
20            that the utility achieved a cumulative persisting
21            annual savings that is less than the applicable
22            annual incremental goal, then the return on equity
23            component shall be reduced by a maximum of 200
24            basis points in the event that the utility achieved
25            no more than 66% of such goal. If the utility
26            achieved more than 66% of the applicable annual

 

 

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1            incremental goal but less than 100% of such goal,
2            then the return on equity component shall be
3            reduced by 6 basis points for each percent by which
4            the utility failed to achieve the goal.
5                (ii) If the independent evaluator determines
6            that the utility achieved a cumulative persisting
7            annual savings that is more than the applicable
8            annual incremental goal, then the return on equity
9            component shall be increased by a maximum of 200
10            basis points in the event that the utility achieved
11            at least 134% of such goal. If the utility achieved
12            more than 100% of the applicable annual
13            incremental goal but less than 134% of such goal,
14            then the return on equity component shall be
15            increased by 6 basis points for each percent by
16            which the utility achieved above the goal. If the
17            applicable annual incremental goal was reduced
18            under paragraph (3) of subsection (f) of this
19            Section, then the following adjustments shall be
20            made to the calculations described in this item
21            (ii):
22                    (aa) the calculation for determining
23                achievement that is at least 134% of the
24                applicable annual incremental goal shall use
25                the unreduced applicable annual incremental
26                goal to set the value; and

 

 

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1                    (bb) the calculation for determining
2                achievement that is less than 134% but more
3                than 100% of the applicable annual incremental
4                goal shall use the reduced applicable annual
5                incremental goal to set the value for 100%
6                achievement of the goal and shall use the
7                unreduced goal to set the value for 134%
8                achievement. The 6 basis point value shall also
9                be modified, as necessary, so that the 200
10                basis points are evenly apportioned among each
11                percentage point value between 100% and 134%
12                achievement.
13        (7.5) For purposes of this Section, the term
14    "applicable annual incremental goal" means the difference
15    between the cumulative persisting annual savings goal for
16    the calendar year that is the subject of the independent
17    evaluator's determination and the cumulative persisting
18    annual savings goal for the immediately preceding calendar
19    year, as such goals are defined in subsections (b-5) and
20    (b-15) of this Section and as these goals may have been
21    modified as provided for under subsection (b-20) and
22    paragraphs (1) through (3) of subsection (f) of this
23    Section. Under subsections (b), (b-5), (b-10), and (b-15)
24    of this Section, a utility must first replace energy
25    savings from measures that have reached the end of their
26    measure lives and would otherwise have to be replaced to

 

 

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1    meet the applicable savings goals identified in subsection
2    (b-5) or (b-15) of this Section before any progress towards
3    achievement of its applicable annual incremental goal may
4    be counted. Notwithstanding anything else set forth in this
5    Section, the difference between the actual annual
6    incremental savings achieved in any given year, including
7    the replacement of energy savings from measures that have
8    expired, and the applicable annual incremental goal shall
9    not affect adjustments to the return on equity for
10    subsequent calendar years under this subsection (g).
11        (8) For electric utilities that serve less than
12    3,000,000 retail customers but more than 500,000 retail
13    customers in the State:
14            (A) Through December 31, 2025, the applicable
15        annual incremental goal shall be compared to the annual
16        incremental savings as determined by the independent
17        evaluator.
18                (i) The return on equity component shall be
19            reduced by 8 basis points for each percent by which
20            the utility did not achieve 84.4% of the applicable
21            annual incremental goal.
22                (ii) The return on equity component shall be
23            increased by 8 basis points for each percent by
24            which the utility exceeded 100% of the applicable
25            annual incremental goal.
26                (iii) The return on equity component shall not

 

 

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1            be increased or decreased if the annual
2            incremental savings as determined by the
3            independent evaluator is greater than 84.4% of the
4            applicable annual incremental goal and less than
5            100% of the applicable annual incremental goal.
6                (iv) The return on equity component shall not
7            be increased or decreased by an amount greater than
8            200 basis points pursuant to this subparagraph
9            (A).
10            (B) For the period of January 1, 2026 through
11        December 31, 2030, the applicable annual incremental
12        goal shall be compared to the annual incremental
13        savings as determined by the independent evaluator.
14                (i) The return on equity component shall be
15            reduced by 6 basis points for each percent by which
16            the utility did not achieve 100% of the applicable
17            annual incremental goal.
18                (ii) The return on equity component shall be
19            increased by 6 basis points for each percent by
20            which the utility exceeded 100% of the applicable
21            annual incremental goal.
22                (iii) The return on equity component shall not
23            be increased or decreased by an amount greater than
24            200 basis points pursuant to this subparagraph
25            (B).
26            (C) If the applicable annual incremental goal was

 

 

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1        reduced under paragraphs (1), (2) or (3) of subsection
2        (f) of this Section, then the following adjustments
3        shall be made to the calculations described in
4        subparagraphs (A) and (B) of this paragraph (8):
5                (i) The calculation for determining
6            achievement that is at least 125% or 134%, as
7            applicable, of the applicable annual incremental
8            goal shall use the unreduced applicable annual
9            incremental goal to set the value.
10                (ii) For the period through December 31, 2025,
11            the calculation for determining achievement that
12            is less than 125% but more than 100% of the
13            applicable annual incremental goal shall use the
14            reduced applicable annual incremental goal to set
15            the value for 100% achievement of the goal and
16            shall use the unreduced goal to set the value for
17            125% achievement. The 8 basis point value shall
18            also be modified, as necessary, so that the 200
19            basis points are evenly apportioned among each
20            percentage point value between 100% and 125%
21            achievement.
22                (iii) For the period of January 1, 2026 through
23            December 31, 2030, the calculation for determining
24            achievement that is less than 134% but more than
25            100% of the applicable annual incremental goal
26            shall use the reduced applicable annual

 

 

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1            incremental goal to set the value for 100%
2            achievement of the goal and shall use the unreduced
3            goal to set the value for 125% achievement. The 6
4            basis point value shall also be modified, as
5            necessary, so that the 200 basis points are evenly
6            apportioned among each percentage point value
7            between 100% and 134% achievement.
8        (8.5) Electric utilities that serve less than
9    3,000,000 retail customers but more than 500,000 retail
10    customers in this State may identify, at the electric
11    utility's sole discretion, cost-effective measures that
12    educate about, incentivize, encourage, or otherwise
13    support the use of electricity to power, in whole or in
14    part, vehicles, including, but not limited to, cars,
15    trucks, buses, trains, trolleys, boats, on-road or
16    off-road vehicles, or other equipment or methods of
17    transporting goods or people. Such measures may include,
18    but are not limited to, measures that educate about,
19    incentivize, encourage, or otherwise support the adoption
20    of electric vehicles by retail customers of all rate
21    classes.
22        (9) The utility shall submit the energy savings data to
23    the independent evaluator no later than 30 days after the
24    close of the plan year. The independent evaluator shall
25    determine the cumulative persisting annual savings for a
26    given plan year no later than 120 days after the close of

 

 

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1    the plan year. The utility shall submit an informational
2    filing to the Commission no later than 160 days after the
3    close of the plan year that attaches the independent
4    evaluator's final report identifying the cumulative
5    persisting annual savings for the year and calculates,
6    under paragraph (7) or (8) of this subsection (g), as
7    applicable, any resulting change to the utility's return on
8    equity component of the weighted average cost of capital
9    applicable to the next plan year beginning with the January
10    monthly billing period and extending through the December
11    monthly billing period. However, if the utility recovers
12    the costs incurred under this Section under paragraphs (2)
13    and (3) of subsection (d) of this Section, then the utility
14    shall not be required to submit such informational filing,
15    and shall instead submit the information that would
16    otherwise be included in the informational filing as part
17    of its filing under paragraph (3) of such subsection (d)
18    that is due on or before June 1 of each year.
19        For those utilities that must submit the informational
20    filing, the Commission may, on its own motion or by
21    petition, initiate an investigation of such filing,
22    provided, however, that the utility's proposed return on
23    equity calculation shall be deemed the final, approved
24    calculation on December 15 of the year in which it is filed
25    unless the Commission enters an order on or before December
26    15, after notice and hearing, that modifies such

 

 

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1    calculation consistent with this Section.
2        The adjustments to the return on equity component
3    described in paragraphs (7) and (8) of this subsection (g)
4    shall be applied as described in such paragraphs through a
5    separate tariff mechanism, which shall be filed by the
6    utility under subsections (f) and (g) of this Section.
7    (h) Other than measures authorized by subsection (n) of
8this Section or identified pursuant to paragraph (8.5) of
9subsection (g) of this Section, no No more than 6% of energy
10efficiency and demand-response program revenue may be
11allocated for research, development, or pilot deployment of new
12equipment or measures.
13    (i) When practicable, electric utilities shall incorporate
14advanced metering infrastructure data into the planning,
15implementation, and evaluation of energy efficiency measures
16and programs, subject to the data privacy and confidentiality
17protections of applicable law.
18    (j) The independent evaluator shall follow the guidelines
19and use the savings set forth in Commission-approved energy
20efficiency policy manuals and technical reference manuals, as
21each may be updated from time to time. Until such time as
22measure life values for energy efficiency measures implemented
23for low-income households under subsection (c) of this Section
24are incorporated into such Commission-approved manuals, the
25low-income measures shall have the same measure life values
26that are established for same measures implemented in

 

 

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1households that are not low-income households.
2    Commencing on the effective date of this amendatory Act of
3the 101st General Assembly, the following provisions shall
4apply to electric utilities that serve less than 3,000,000
5retail customers but more than 500,000 retail customers in this
6State:
7        (1) Starting in the year in which this amendatory Act
8    of the 101st General Assembly takes effect and continuing
9    for a period of 5 calendar years thereafter, the savings
10    achieved by energy efficiency measures authorized by
11    subsection (n) of this Section or identified pursuant to
12    paragraph (8.5) of subsection (g) of this Section, shall be
13    evaluated using the following parameters:
14            (A) the evaluation shall use a factor of 1.50 lbs
15        of carbon dioxide emitted per kilowatt hour of electric
16        energy used for vehicle operation, adjusted each year
17        starting with the year in which this amendatory Act of
18        the 101st General Assembly takes effect to reflect the
19        annual increase of renewable resource procurement as
20        set forth in subsection (c) of Section 1-75 of the
21        Illinois Power Agency Act;
22            (B) the evaluation shall use a heat rate of fossil
23        fuel electric generating units of 7,939 Btu per
24        kilowatt hour, adjusted each year starting with the
25        year in which this amendatory Act of the 101st General
26        Assembly takes effect to reflect the annual increase of

 

 

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1        renewable resource procurement as set forth in
2        subsection (c) of Section 1-75 of the Illinois Power
3        Agency Act;
4            (C) the evaluation shall include any netting of
5        electricity used by the electric vehicle, as
6        calculated using the parameters provided for in
7        paragraph (2) of this subsection (j);
8            (D) the evaluation shall use a net to gross ratio
9        of 1.0 for each measure evaluated; and
10            (E) all savings achieved by the measures evaluated
11        shall persist for the life of the measure, without
12        degradation.
13        (2) Starting in the year in which this amendatory Act
14    of the 101st General Assembly takes effect and continuing
15    for a period of 5 calendar years thereafter, the savings
16    achieved by energy efficiency measures authorized by
17    subsection (n) of this Section or identified pursuant to
18    paragraph (8.5) of subsection (g) of this Section that are
19    applicable to passenger vehicles shall, in addition to the
20    parameters identified in paragraph (1) of this subsection
21    (j), be evaluated using the following parameters:
22            (A) the measure life of measures that incentivize
23        or otherwise encourage the purchase of electric
24        vehicles shall be 13 years from the date of original
25        purchase by the customer;
26            (B) the evaluation shall use a value of 11,500

 

 

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1        vehicle miles traveled for annual vehicle operation;
2            (C) the evaluation shall use a fossil fuel vehicle
3        economy value equal to 28 miles per gallon of fossil
4        fuel used for vehicle operation;
5            (D) the evaluation shall use a conversion factor of
6        120,429 Btus per gallon of fossil fuel used for vehicle
7        operation;
8            (E) the evaluation shall use a factor of 161 lbs of
9        carbon dioxide emitted per million Btu of fossil fuel
10        used for vehicle operation;
11            (F) the evaluation shall use a factor of 8.78 kg of
12        carbon dioxide emitted per gallon of fossil fuel used
13        for vehicle operation;
14            (G) the evaluation shall use an annual value of
15        fossil fuel saved of 50 MMBtu; and
16            (H) the evaluation shall use an electric vehicle
17        efficiency value of 30 kilowatt hours per 100 miles
18        traveled for vehicle operation.
19        (3) Any additional evaluation criteria not identified
20    in paragraphs (1) or (2) of this subsection (j) used to
21    evaluate savings achieved by energy efficiency measures
22    authorized by subsection (n) of this Section or identified
23    pursuant to paragraph (8.5) of subsection (g) of this
24    Section shall follow the guidelines and use the savings set
25    forth in Commission-approved energy efficiency policy
26    manuals and technical reference manuals, as each may be

 

 

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1    updated from time to time.
2    (k) Notwithstanding any provision of law to the contrary,
3an electric utility subject to the requirements of this Section
4may file a tariff cancelling an automatic adjustment clause
5tariff in effect under this Section or Section 8-103, which
6shall take effect no later than one business day after the date
7such tariff is filed. Thereafter, the utility shall be
8authorized to defer and recover its expenditures incurred under
9this Section through a new tariff authorized under subsection
10(d) of this Section or in the utility's next rate case under
11Article IX or Section 16-108.5 of this Act, with interest at an
12annual rate equal to the utility's weighted average cost of
13capital as approved by the Commission in such case. If the
14utility elects to file a new tariff under subsection (d) of
15this Section, the utility may file the tariff within 10 days
16after June 1, 2017 (the effective date of Public Act 99-906),
17and the cost inputs to such tariff shall be based on the
18projected costs to be incurred by the utility during the
19calendar year in which the new tariff is filed and that were
20not recovered under the tariff that was cancelled as provided
21for in this subsection. Such costs shall include those incurred
22or to be incurred by the utility under its multi-year plan
23approved under subsections (f) and (g) of this Section,
24including, but not limited to, projected capital investment
25costs and projected regulatory asset balances with
26correspondingly updated depreciation and amortization reserves

 

 

SB3977- 150 -LRB101 20818 JLS 70537 b

1and expense. The Commission shall, after notice and hearing,
2approve, or approve with modification, such tariff and cost
3inputs no later than 75 days after the utility filed the
4tariff, provided that such approval, or approval with
5modification, shall be consistent with the provisions of this
6Section to the extent they do not conflict with this subsection
7(k). The tariff approved by the Commission shall take effect no
8later than 5 days after the Commission enters its order
9approving the tariff.
10    No later than 60 days after the effective date of the
11tariff cancelling the utility's automatic adjustment clause
12tariff, the utility shall file a reconciliation that reconciles
13the moneys collected under its automatic adjustment clause
14tariff with the costs incurred during the period beginning June
151, 2016 and ending on the date that the electric utility's
16automatic adjustment clause tariff was cancelled. In the event
17the reconciliation reflects an under-collection, the utility
18shall recover the costs as specified in this subsection (k). If
19the reconciliation reflects an over-collection, the utility
20shall apply the amount of such over-collection as a one-time
21credit to retail customers' bills.
22    (l) For the calendar years covered by a multi-year plan
23commencing after December 31, 2017, subsections (a) through (j)
24of this Section do not apply to any retail customers of an
25electric utility that serves more than 3,000,000 retail
26customers in the State and whose total highest 30 minute demand

 

 

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1was more than 10,000 kilowatts, or any retail customers of an
2electric utility that serves less than 3,000,000 retail
3customers but more than 500,000 retail customers in the State
4and whose total highest 15 minute demand was more than 10,000
5kilowatts. For purposes of this subsection (l), "retail
6customer" has the meaning set forth in Section 16-102 of this
7Act. A determination of whether this subsection is applicable
8to a customer shall be made for each multi-year plan beginning
9after December 31, 2017. The criteria for determining whether
10this subsection (l) is applicable to a retail customer shall be
11based on the 12 consecutive billing periods prior to the start
12of the first year of each such multi-year plan.
13    (m) Notwithstanding the requirements of this Section, as
14part of a proceeding to approve a multi-year plan under
15subsections (f) and (g) of this Section, the Commission shall
16reduce the amount of energy efficiency measures implemented for
17any single year, and whose costs are recovered under subsection
18(d) of this Section, by an amount necessary to limit the
19estimated average net increase due to the cost of the measures
20to no more than
21        (1) 3.5% for each of the 4 years beginning January 1,
22    2018,
23        (2) 3.75% for each of the 4 years beginning January 1,
24    2022, and
25        (3) 4% for each of the 5 years beginning January 1,
26    2026,

 

 

SB3977- 152 -LRB101 20818 JLS 70537 b

1of the average amount paid per kilowatthour by residential
2eligible retail customers during calendar year 2015. To
3determine the total amount that may be spent by an electric
4utility in any single year, the applicable percentage of the
5average amount paid per kilowatthour shall be multiplied by the
6total amount of energy delivered by such electric utility in
7the calendar year 2015, adjusted to reflect the proportion of
8the utility's load attributable to customers who are exempt
9from subsections (a) through (j) of this Section under
10subsection (l) of this Section. For purposes of this subsection
11(m), the amount paid per kilowatthour includes, without
12limitation, estimated amounts paid for supply, transmission,
13distribution, surcharges, and add-on taxes. For purposes of
14this Section, "eligible retail customers" shall have the
15meaning set forth in Section 16-111.5 of this Act. Once the
16Commission has approved a plan under subsections (f) and (g) of
17this Section, no subsequent rate impact determinations shall be
18made.
19    (n) Starting on the effective date of this amendatory Act
20of the 101st General Assembly, electric utilities that serve
21less than 3,000,000 retail customers but more than 500,000
22retail customers in this State may administer programs and
23implement cost-effective measures that educate about,
24incentivize, encourage, or otherwise support the use of
25electricity to power, in whole or in part, vehicles, including,
26but not limited to, cars, trucks, buses, trains, trolleys,

 

 

SB3977- 153 -LRB101 20818 JLS 70537 b

1boats, on-road or off-road vehicles, or other equipment or
2methods of transporting goods or people. Such programs and
3measures may be implemented as part of a plan approved pursuant
4to subsection (f) of this Section and may include, but are not
5limited to, measures that educate about, incentivize,
6encourage, or otherwise support the adoption of electric
7vehicles by retail customers of all customer classes. Programs
8and measures authorized by this subsection (n) and identified
9pursuant to paragraph (8.5) of subsection (g) shall not be
10prohibited by the Commission as promotional practices under any
11rules or policies of the Commission, including, but not limited
12to, 83 Ill. Admin. Code Part 275.
13(Source: P.A. 100-840, eff. 8-13-18; 101-81, eff. 7-12-19.)
 
14    (220 ILCS 5/8-218 new)
15    Sec. 8-218. Electric photovoltaic generating facilities.
16    (a) The General Assembly finds and declares that the
17citizens and businesses of the State of Illinois would be
18well-served by the development of photovoltaic electricity
19production facilities in this State, which would both bring
20economic benefits and environmental benefits to the State and
21further expand access to renewable energy resources at an
22affordable cost to Illinois residents, particularly in those
23areas of the State that have been significantly and adversely
24affected by the retirement of coal-fired electric generating
25plants. To that end, the General Assembly seeks to encourage

 

 

SB3977- 154 -LRB101 20818 JLS 70537 b

1further development of photovoltaic electric production
2facilities of all scales in an efficient and cost-effective
3manner. Accordingly, the General Assembly finds that,
4notwithstanding other provisions of this Act to the contrary,
5it would be both prudent and reasonable for electric utilities
6in this State to plan for, construct, install, control, own,
7manage, or operate photovoltaic electricity production
8facilities pursuant to the provisions of this Section.
9    (b) An electric utility that serves less than 3,000,000
10retail customers but more than 500,000 customers in this State,
11may plan for, construct, install, control, own, manage, or
12operate photovoltaic electricity production facilities and any
13energy storage facilities as authorized under Section
1416-108.20 of this Act that are planned for, constructed,
15installed, controlled, owned, managed, or operated in
16connection with photovoltaic electricity production facilities
17authorized under this Section without obtaining a certificate
18of public convenience and necessity pursuant to Section 8-406
19of this Act, subject to the following terms and conditions:
20        (1) the electric utility may plan for, construct,
21    install, control, own, manage, or operate photovoltaic
22    electricity production facilities of any type or scale,
23    including, but not limited to, large scale (greater than 2
24    MW), small scale (less than or equal to 2 MW) and community
25    solar projects; for purposes of this Section, "community
26    solar projects" includes community solar facilities with a

 

 

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1    nameplate capacity up to and including 10,000 kilowatts
2    that are connected to either the distribution system or
3    transmission system of the electric utility;
4        (2) photovoltaic electricity production facilities
5    authorized pursuant to this Section shall be deemed for all
6    purposes under this Act as prudent and used and useful,
7    including under the provisions of Section 9-212 of this
8    Act, and, subject to the provisions set forth in this
9    Section, the Commission may not limit recovery of any
10    portion of the reasonable costs of the photovoltaic
11    electricity production facilities authorized pursuant to
12    this Section on the grounds that the facilities are not
13    prudent or used and useful;
14        (3) the electric utility's costs of planning for,
15    constructing, installing, controlling, owning, managing,
16    or operating the photovoltaic electricity production
17    facilities shall be recovered, on a kilowatt hour basis, in
18    the electric utility's rates for delivery service
19    established pursuant to Article XVI or Article IX of this
20    Act, and for purposes of cost recovery the photovoltaic
21    electricity production facilities, shall be treated as
22    distribution assets, provided: (1) the Commission shall
23    have the authority to determine the reasonableness of the
24    costs of the facilities, (2) any monetary value of power
25    and energy from the facilities shall be credited against
26    the delivery services revenue requirement, and (3) all

 

 

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1    renewable energy credits associated with the photovoltaic
2    electricity production facilities shall be retired on
3    behalf of the electric utility's distribution customers
4    and may not be sold or used for any other purposes by the
5    electric utility other than satisfying the electric
6    utility's requirements under subsection (c) of Section
7    1-75 of the Illinois Power Agency Act; and
8        (4) the annual quantity of renewable energy credits
9    generated from the photovoltaic electricity production
10    facilities placed in service by an electric utility
11    pursuant to this Section after the effective date of this
12    amendatory Act of the 101st General Assembly shall not
13    exceed 20% of the electric utility's requirements under
14    subsection (c) of Section 1-75 of the Illinois Power Agency
15    Act.
16    For purposes of this Section, "electric utility" has the
17meaning set forth in Section 16-102 of this Act.
18    (c) Notwithstanding anything to the contrary in the
19Illinois Power Agency Act or this Act, the Illinois Power
20Agency shall apply any renewable energy credits associated with
21photovoltaic electricity production facilities meeting the
22criteria set forth in subsection (b) of this Section to the
23electric utility's requirements under subsection (c) of
24Section 1-75 of the Illinois Power Agency Act. No cost
25associated with facilities placed in service pursuant to this
26Section shall be included when calculating the limitation under

 

 

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1subparagraph (E) of paragraph (1) of subsection (c) of Section
21-75 of the Illinois Power Agency Act.
 
3    (220 ILCS 5/16-102)
4    Sec. 16-102. Definitions. For the purposes of this Article
5the following terms shall be defined as set forth in this
6Section.
7    "Alternative retail electric supplier" means every person,
8cooperative, corporation, municipal corporation, company,
9association, joint stock company or association, firm,
10partnership, individual, or other entity, their lessees,
11trustees, or receivers appointed by any court whatsoever, that
12offers electric power or energy for sale, lease or in exchange
13for other value received to one or more retail customers, or
14that engages in the delivery or furnishing of electric power or
15energy to such retail customers, and shall include, without
16limitation, resellers, aggregators and power marketers, but
17shall not include (i) electric utilities (or any agent of the
18electric utility to the extent the electric utility provides
19tariffed services to retail customers through that agent), (ii)
20any electric cooperative or municipal system as defined in
21Section 17-100 to the extent that the electric cooperative or
22municipal system is serving retail customers within any area in
23which it is or would be entitled to provide service under the
24law in effect immediately prior to the effective date of this
25amendatory Act of 1997, (iii) a public utility that is owned

 

 

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1and operated by any public institution of higher education of
2this State, or a public utility that is owned by such public
3institution of higher education and operated by any of its
4lessees or operating agents, within any area in which it is or
5would be entitled to provide service under the law in effect
6immediately prior to the effective date of this amendatory Act
7of 1997, (iv) a retail customer to the extent that customer
8obtains its electric power and energy from that customer's own
9cogeneration or self-generation facilities, (v) an entity that
10owns, operates, sells, or arranges for the installation of a
11customer's own cogeneration or self-generation facilities, but
12only to the extent the entity is engaged in owning, selling or
13arranging for the installation of such facility, or operating
14the facility on behalf of such customer, provided however that
15any such third party owner or operator of a facility built
16after January 1, 1999, complies with the labor provisions of
17Section 16-128(a) as though such third party were an
18alternative retail electric supplier, or (vi) an industrial or
19manufacturing customer that owns its own distribution
20facilities, to the extent that the customer provides service
21from that distribution system to a third-party contractor
22located on the customer's premises that is integrally and
23predominantly engaged in the customer's industrial or
24manufacturing process; provided, that if the industrial or
25manufacturing customer has elected delivery services, the
26customer shall pay transition charges applicable to the

 

 

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1electric power and energy consumed by the third-party
2contractor unless such charges are otherwise paid by the third
3party contractor, which shall be calculated based on the usage
4of, and the base rates or the contract rates applicable to, the
5third-party contractor in accordance with Section 16-102.
6    An entity that furnishes the service of charging electric
7vehicles does not and shall not be deemed to sell electricity
8and is not and shall not be deemed an alternative retail
9electric supplier, and is not subject to regulation as such
10under this Act notwithstanding the basis on which the service
11is provided or billed. If, however, the entity is otherwise
12deemed an alternative retail electric supplier under this Act,
13or is otherwise subject to regulation under this Act, then that
14entity is not exempt from and remains subject to the otherwise
15applicable provisions of this Act. The installation,
16maintenance, and repair of an electric vehicle charging station
17shall comply with the requirements of subsection (a) of Section
1816-128 and Section 16-128A of this Act.
19    For purposes of this Section, the term "electric vehicles"
20has the meaning ascribed to that term in Section 10 of the
21Electric Vehicle Act.
22    "Base rates" means the rates for those tariffed services
23that the electric utility is required to offer pursuant to
24subsection (a) of Section 16-103 and that were identified in a
25rate order for collection of the electric utility's base rate
26revenue requirement, excluding (i) separate automatic rate

 

 

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1adjustment riders then in effect, (ii) special or negotiated
2contract rates, (iii) delivery services tariffs filed pursuant
3to Section 16-108, (iv) real-time pricing, or (v) tariffs that
4were in effect prior to October 1, 1996 and that based charges
5for services on an index or average of other utilities'
6charges, but including (vi) any subsequent redesign of such
7rates for tariffed services that is authorized by the
8Commission after notice and hearing.
9    "Competitive service" includes (i) any service that has
10been declared to be competitive pursuant to Section 16-113 of
11this Act, (ii) contract service, and (iii) services, other than
12tariffed services, that are related to, but not necessary for,
13the provision of electric power and energy or delivery
14services.
15    "Contract service" means (1) services, including the
16provision of electric power and energy or other services, that
17are provided by mutual agreement between an electric utility
18and a retail customer that is located in the electric utility's
19service area, provided that, delivery services shall not be a
20contract service until such services are declared competitive
21pursuant to Section 16-113; and also means (2) the provision of
22electric power and energy by an electric utility to retail
23customers outside the electric utility's service area pursuant
24to Section 16-116. Provided, however, contract service does not
25include electric utility services provided pursuant to (i)
26contracts that retail customers are required to execute as a

 

 

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1condition of receiving tariffed services, or (ii) special or
2negotiated rate contracts for electric utility services that
3were entered into between an electric utility and a retail
4customer prior to the effective date of this amendatory Act of
51997 and filed with the Commission.
6    "Delivery services" means those services provided by the
7electric utility that are necessary in order for the
8transmission and distribution systems to function so that
9retail customers located in the electric utility's service area
10can receive electric power and energy from suppliers other than
11the electric utility, and shall include, without limitation,
12standard metering and billing services.
13    "Electric utility" means a public utility, as defined in
14Section 3-105 of this Act, that has a franchise, license,
15permit or right to furnish or sell electricity to retail
16customers within a service area.
17    "Electric vehicle" means: (i) a battery-powered vehicle
18operated solely by electricity that can be recharged from an
19external source; or (ii) a plug-in hybrid electric vehicle that
20operates on electricity and another fuel and has a battery that
21can be recharged from an external source.
22    "Electric vehicle charging station" means any facility,
23infrastructure, or equipment that is used to charge a battery
24or other energy storage device of an electric vehicle.
25    "Energy storage" or "storage" means any infrastructure,
26facility, technology, or device used to store energy for use on

 

 

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1an electric distribution or transmission system and shall not
2include or be considered energy generation.
3    "Mandatory transition period" means the period from the
4effective date of this amendatory Act of 1997 through January
51, 2007.
6    "Municipal system" shall have the meaning set forth in
7Section 17-100.
8    "Real-time pricing" means tariffed retail charges for
9delivered electric power and energy that vary hour-to-hour and
10are determined from wholesale market prices using a methodology
11approved by the Illinois Commerce Commission.
12    "Retail customer" means a single entity using electric
13power or energy at a single premises and that (A) either (i) is
14receiving or is eligible to receive tariffed services from an
15electric utility, or (ii) that is served by a municipal system
16or electric cooperative within any area in which the municipal
17system or electric cooperative is or would be entitled to
18provide service under the law in effect immediately prior to
19the effective date of this amendatory Act of 1997, or (B) an
20entity which on the effective date of this Act was receiving
21electric service from a public utility and (i) was engaged in
22the practice of resale and redistribution of such electricity
23within a building prior to January 2, 1957, or (ii) was
24providing lighting services to tenants in a multi-occupancy
25building, but only to the extent such resale, redistribution or
26lighting service is authorized by the electric utility's

 

 

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1tariffs that were on file with the Commission on the effective
2date of this Act.
3    "Service area" means (i) the geographic area within which
4an electric utility was lawfully entitled to provide electric
5power and energy to retail customers as of the effective date
6of this amendatory Act of 1997, and includes (ii) the location
7of any retail customer to which the electric utility was
8lawfully providing electric utility services on such effective
9date.
10    "Small commercial retail customer" means those
11nonresidential retail customers of an electric utility
12consuming 15,000 kilowatt-hours or less of electricity
13annually in its service area.
14    "Tariffed service" means services provided to retail
15customers by an electric utility as defined by its rates on
16file with the Commission pursuant to the provisions of Article
17IX of this Act, but shall not include competitive services.
18    "Transition charge" means a charge expressed in cents per
19kilowatt-hour that is calculated for a customer or class of
20customers as follows for each year in which an electric utility
21is entitled to recover transition charges as provided in
22Section 16-108:
23        (1) the amount of revenue that an electric utility
24    would receive from the retail customer or customers if it
25    were serving such customers' electric power and energy
26    requirements as a tariffed service based on (A) all of the

 

 

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1    customers' actual usage during the 3 years ending 90 days
2    prior to the date on which such customers were first
3    eligible for delivery services pursuant to Section 16-104,
4    and (B) on (i) the base rates in effect on October 1, 1996
5    (adjusted for the reductions required by subsection (b) of
6    Section 16-111, for any reduction resulting from a rate
7    decrease under Section 16-101(b), for any restatement of
8    base rates made in conjunction with an elimination of the
9    fuel adjustment clause pursuant to subsection (b), (d), or
10    (f) of Section 9-220 and for any removal of decommissioning
11    costs from base rates pursuant to Section 16-114) and any
12    separate automatic rate adjustment riders (other than a
13    decommissioning rate as defined in Section 16-114) under
14    which the customers were receiving or, had they been
15    customers, would have received electric power and energy
16    from the electric utility during the year immediately
17    preceding the date on which such customers were first
18    eligible for delivery service pursuant to Section 16-104,
19    or (ii) to the extent applicable, any contract rates,
20    including contracts or rates for consolidated or
21    aggregated billing, under which such customers were
22    receiving electric power and energy from the electric
23    utility during such year;
24        (2) less the amount of revenue, other than revenue from
25    transition charges and decommissioning rates, that the
26    electric utility would receive from such retail customers

 

 

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1    for delivery services provided by the electric utility,
2    assuming such customers were taking delivery services for
3    all of their usage, based on the delivery services tariffs
4    in effect during the year for which the transition charge
5    is being calculated and on the usage identified in
6    paragraph (1);
7        (3) less the market value for the electric power and
8    energy that the electric utility would have used to supply
9    all of such customers' electric power and energy
10    requirements, as a tariffed service, based on the usage
11    identified in paragraph (1), with such market value
12    determined in accordance with Section 16-112 of this Act;
13        (4) less the following amount which represents the
14    amount to be attributed to new revenue sources and cost
15    reductions by the electric utility through the end of the
16    period for which transition costs are recovered pursuant to
17    Section 16-108, referred to in this Article XVI as a
18    "mitigation factor":
19            (A) for nonresidential retail customers, an amount
20        equal to the greater of (i) 0.5 cents per kilowatt-hour
21        during the period October 1, 1999 through December 31,
22        2004, 0.6 cents per kilowatt-hour in calendar year
23        2005, and 0.9 cents per kilowatt-hour in calendar year
24        2006, multiplied in each year by the usage identified
25        in paragraph (1), or (ii) an amount equal to the
26        following percentages of the amount produced by

 

 

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1        applying the applicable base rates (adjusted as
2        described in subparagraph (1)(B)) or contract rate to
3        the usage identified in paragraph (1): 8% for the
4        period October 1, 1999 through December 31, 2002, 10%
5        in calendar years 2003 and 2004, 11% in calendar year
6        2005 and 12% in calendar year 2006; and
7            (B) for residential retail customers, an amount
8        equal to the following percentages of the amount
9        produced by applying the base rates in effect on
10        October 1, 1996 (adjusted as described in subparagraph
11        (1)(B)) to the usage identified in paragraph (1): (i)
12        6% from May 1, 2002 through December 31, 2002, (ii) 7%
13        in calendar years 2003 and 2004, (iii) 8% in calendar
14        year 2005, and (iv) 10% in calendar year 2006;
15        (5) divided by the usage of such customers identified
16    in paragraph (1),
17provided that the transition charge shall never be less than
18zero.
19    "Unbundled service" means a component or constituent part
20of a tariffed service which the electric utility subsequently
21offers separately to its customers.
22(Source: P.A. 97-1128, eff. 8-28-12.)
 
23    (220 ILCS 5/16-107.6)
24    Sec. 16-107.6. Distributed generation rebate.
25    (a) In this Section:

 

 

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1    "Smart inverter" means a device that converts direct
2current into alternating current and can autonomously
3contribute to grid support during excursions from normal
4operating voltage and frequency conditions by providing each of
5the following: dynamic reactive and real power support, voltage
6and frequency ride-through, ramp rate controls, communication
7systems with ability to accept external commands, and other
8functions from the electric utility.
9    "Subscriber" has the meaning set forth in Section 1-10 of
10the Illinois Power Agency Act.
11    "Subscription" has the meaning set forth in Section 1-10 of
12the Illinois Power Agency Act.
13    "Threshold date" means the date on which the load of an
14electricity provider's net metering customers equals 5% of the
15total peak demand supplied by that electricity provider during
16the previous year, as specified under subsection (j) of Section
1716-107.5 of this Act.
18    (b) An electric utility that serves more than 200,000
19customers in the State shall file a petition with the
20Commission requesting approval of the utility's tariff to
21provide a rebate to a retail customer who owns or operates
22distributed generation that meets the following criteria:
23        (1) has a nameplate generating capacity no greater than
24    2,000 kilowatts and is primarily used to offset that
25    customer's electricity load;
26        (2) is located on the customer's premises, for the

 

 

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1    customer's own use, and not for commercial use or sales,
2    including, but not limited to, wholesale sales of electric
3    power and energy;
4        (3) is located in the electric utility's service
5    territory; and
6        (4) is interconnected under rules adopted by the
7    Commission by means of the inverter or smart inverter
8    required by this Section, as applicable.
9    For purposes of this Section, "distributed generation"
10shall satisfy the definition of distributed renewable energy
11generation device set forth in Section 1-10 of the Illinois
12Power Agency Act to the extent such definition is consistent
13with the requirements of this Section.
14    In addition, any new photovoltaic distributed generation
15that is installed after the effective date of this amendatory
16Act of the 99th General Assembly must be installed by a
17qualified person, as defined by subsection (i) of Section 1-56
18of the Illinois Power Agency Act.
19    The tariff shall provide that the utility shall be
20permitted to operate and control the smart inverter associated
21with the distributed generation that is the subject of the
22rebate for the purpose of preserving reliability during
23distribution system reliability events and shall address the
24terms and conditions of the operation and the compensation
25associated with the operation. Nothing in this Section shall
26negate or supersede Institute of Electrical and Electronics

 

 

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1Engineers interconnection requirements or standards or other
2similar standards or requirements. The tariff shall also
3provide for additional uses of the smart inverter that shall be
4separately compensated and which may include, but are not
5limited to, voltage and VAR support, regulation, and other grid
6services. As part of the proceeding described in subsection (e)
7of this Section, the Commission shall review and determine
8whether smart inverters can provide any additional uses or
9services. If the Commission determines that an additional use
10or service would be beneficial, the Commission shall determine
11the terms and conditions of the operation and how the use or
12service should be separately compensated.
13    (c) The proposed tariff authorized by subsection (b) of
14this Section shall include the following participation terms
15and formulae to calculate the value of the rebates to be
16applied under this Section for distributed generation that
17satisfies the criteria set forth in subsection (b) of this
18Section:
19        (1) Until the utility files its tariff or tariffs to
20    place into effect the rebate values established by the
21    Commission under subsection (e) of this Section,
22    non-residential customers that are taking service under a
23    net metering program offered by an electricity provider
24    under the terms of Section 16-107.5 of this Act may apply
25    for a rebate as provided for in this Section. The value of
26    the rebate shall be $250 per kilowatt of nameplate

 

 

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1    generating capacity, measured as nominal DC power output,
2    of a non-residential customer's distributed generation.
3        (2) After the utility's tariff or tariffs setting the
4    new rebate values established under subsection (d) of this
5    Section take effect, retail customers may, as applicable,
6    make the following elections:
7            (A) Residential customers that are taking service
8        under a net metering program offered by an electricity
9        provider under the terms of Section 16-107.5 of this
10        Act on the threshold date may elect to either continue
11        to take such service under the terms of such program as
12        in effect on such threshold date for the useful life of
13        the customer's eligible renewable electric generating
14        facility as defined in such Section, or file an
15        application to receive a rebate under the terms of this
16        Section, provided that such application must be
17        submitted within 6 months after the effective date of
18        the tariff approved under subsection (d) of this
19        Section. The value of the rebate shall be the amount
20        established by the Commission and reflected in the
21        utility's tariff pursuant to subsection (e) of this
22        Section.
23            (B) Non-residential customers that are taking
24        service under a net metering program offered by an
25        electricity provider under the terms of Section
26        16-107.5 of this Act on the threshold date may apply

 

 

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1        for a rebate as provided for in this Section. The value
2        of the rebate shall be the amount established by the
3        Commission and reflected in the utility's tariff
4        pursuant to subsection (e) of this Section.
5        (3) Upon approval of a rebate application submitted
6    under this subsection (c), the retail customer shall no
7    longer be entitled to receive any delivery service credits
8    for the excess electricity generated by its facility and
9    shall be subject to the provisions of subsection (n) of
10    Section 16-107.5 of this Act.
11        (4) To be eligible for a rebate described in this
12    subsection (c), customers who begin taking service after
13    the effective date of this amendatory Act of the 99th
14    General Assembly under a net metering program offered by an
15    electricity provider under the terms of Section 16-107.5 of
16    this Act must have a smart inverter associated with the
17    customer's distributed generation.
18    (d) The Commission shall review the proposed tariff
19submitted under subsections (b) and (c) of this Section and may
20make changes to the tariff that are consistent with this
21Section and with the Commission's authority under Article IX of
22this Act, subject to notice and hearing. Following notice and
23hearing, the Commission shall issue an order approving, or
24approving with modification, such tariff no later than 240 days
25after the utility files its tariff.
26    (e) When the total generating capacity of the electricity

 

 

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1provider's net metering customers is equal to 3%, the
2Commission shall open an investigation into an annual process
3and formula for calculating the value of rebates for the retail
4customers described in subsections (b) and (f) of this Section
5that submit rebate applications after the threshold date for an
6electric utility that elected to file a tariff pursuant to this
7Section. The investigation shall include diverse sets of
8stakeholders, calculations for valuing distributed energy
9resource benefits to the grid based on best practices, and
10assessments of present and future technological capabilities
11of distributed energy resources. The value of such rebates
12shall reflect the value of the distributed generation to the
13distribution system at the location at which it is
14interconnected, taking into account the geographic,
15time-based, and performance-based benefits, as well as
16technological capabilities and present and future grid needs.
17No later than 10 days after the Commission enters its final
18order under this subsection (e), the utility shall file its
19tariff or tariffs in compliance with the order, and the
20Commission shall approve, or approve with modification, the
21tariff or tariffs within 45 days after the utility's filing.
22For those rebate applications filed after the threshold date
23but before the utility's tariff or tariffs filed pursuant to
24this subsection (e) take effect, the value of the rebate shall
25remain at the value established in subsection (c) of this
26Section until the tariff is approved.

 

 

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1    (f) Notwithstanding any provision of this Act to the
2contrary, the owner, developer, or subscriber of a generation
3facility that is part of a net metering program provided under
4subsection (l) of Section 16-107.5 shall also be eligible to
5apply for the rebate described in this Section. A subscriber to
6the generation facility may apply for a rebate in the amount of
7the subscriber's subscription only if the owner, developer, or
8previous subscriber to the same panel or panels has not already
9submitted an application, and, regardless of whether the
10subscriber is a residential or non-residential customer, may be
11allowed the amount identified in paragraph (1) of subsection
12(c) or in subsection (e) of this Section applicable to such
13customer on the date that the application is submitted. An
14application for a rebate for a portion of a project described
15in this subsection (f) may be submitted at or after the time
16that a related request for net metering is made.
17    (g) No later than 60 days after the utility receives an
18application for a rebate under its tariff approved under
19subsection (d) or (e) of this Section, the utility shall issue
20a rebate to the applicant under the terms of the tariff. In the
21event the application is incomplete or the utility is otherwise
22unable to calculate the payment based on the information
23provided by the owner, the utility shall issue the payment no
24later than 60 days after the application is complete or all
25requested information is received.
26    (h) An electric utility shall recover from its retail

 

 

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1customers all of the costs of the rebates made under a tariff
2or tariffs placed into effect under this Section, including,
3but not limited to, the value of the rebates and all costs
4incurred by the utility to comply with and implement this
5Section, consistent with the following provisions:
6        (1) The utility shall defer the full amount of its
7    costs incurred under this Section as a regulatory asset.
8    The total costs deferred as a regulatory asset shall be
9    amortized over a 15-year period. The unamortized balance
10    shall be recognized as of December 31 for a given year. The
11    utility shall also earn a return on the total of the
12    unamortized balance of the regulatory assets, less any
13    deferred taxes related to the unamortized balance, at an
14    annual rate equal to the utility's weighted average cost of
15    capital that includes, based on a year-end capital
16    structure, the utility's actual cost of debt for the
17    applicable calendar year and a cost of equity, which in all
18    rate years for electric utilities that serve more than
19    3,000,000 retail customers in this State, and in each rate
20    year commencing before December 1, 2019 for electric
21    utilities that serve less than 3,000,000 retail customers
22    but more than 500,000 retail customers in this State, shall
23    be calculated as the sum of (i) the average for the
24    applicable calendar year of the monthly average yields of
25    30-year U.S. Treasury bonds published by the Board of
26    Governors of the Federal Reserve System in its weekly H.15

 

 

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1    Statistical Release or successor publication; and (ii) 580
2    basis points, including a revenue conversion factor
3    calculated to recover or refund all additional income taxes
4    that may be payable or receivable as a result of that
5    return. For electric utilities that serve less than
6    3,000,000 retail customers but more than 500,000 retail
7    customers in this State, for each rate year commencing
8    after November 30, 2019, the cost of equity shall be
9    calculated as the sum of the following: (i) the average for
10    the applicable calendar year of the monthly average yields
11    of 30-year U.S. Treasury bonds published by the Board of
12    Governors of the Federal Reserve System in its weekly H.15
13    Statistical Release or successor publication; and (ii) 680
14    basis points; however, if the cost of equity as calculated
15    under this paragraph (1) for each rate year commencing
16    after November 30, 2019, for electric utilities that serve
17    less than 3,000,000 retail customers but more than 500,000
18    retail customers in this State is greater than the national
19    average cost of equity for the rate year by 50 basis points
20    or more, then the Illinois Commerce Commission shall
21    include a cost of equity at a rate equal to the national
22    average cost of equity as calculated under this paragraph
23    (1) plus 50 basis points. For purposes of this paragraph
24    (1), the national average cost of equity for a rate year
25    shall be the simple average of the cost of equity approved
26    in each order of a state regulatory commission, other than

 

 

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1    the Commission, issued during that rate year that is
2    applicable to retail electric service provided by an
3    investor-owned public utility company operating in the
4    United States. No order shall be excluded from the national
5    average cost of equity calculated under this paragraph (1)
6    on the grounds that it is subject to rehearing or appeal.
7    In the hearing during the first rate year commencing after
8    November 30, 2019, the Commission shall set the cost of
9    equity using the method applicable to rate years commencing
10    prior to December 1, 2019. In the hearings in rate years
11    subsequent to such first rate year, the Commission shall
12    set the cost of equity using the method applicable to rate
13    years commencing after November 30, 2019, including the
14    reconciliation of the first rate year commencing after
15    November 30, 2019. If, for any rate year, there are fewer
16    than 15 applicable orders of state regulatory commissions
17    with which to compute the average cost of equity, the
18    Commission shall include in the calculation of the national
19    average the number of state regulatory orders from the
20    prior year or years necessary to reach a total of 15,
21    beginning with the most recently issued and proceeding in
22    reverse chronological order.
23        When an electric utility creates a regulatory asset
24    under the provisions of this Section, the costs are
25    recovered over a period during which customers also receive
26    a benefit, which is in the public interest. Accordingly, it

 

 

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1    is the intent of the General Assembly that an electric
2    utility that elects to create a regulatory asset under the
3    provisions of this Section shall recover all of the
4    associated costs, including, but not limited to, its cost
5    of capital as set forth in this Section. After the
6    Commission has approved the prudence and reasonableness of
7    the costs that comprise the regulatory asset, the electric
8    utility shall be permitted to recover all such costs, and
9    the value and recoverability through rates of the
10    associated regulatory asset shall not be limited, altered,
11    impaired, or reduced. To enable the financing of the
12    incremental capital expenditures, including regulatory
13    assets, for electric utilities that serve less than
14    3,000,000 retail customers but more than 500,000 retail
15    customers in the State, the utility's actual year-end
16    capital structure that includes a common equity ratio,
17    excluding goodwill, of up to and including 50% of the total
18    capital structure shall be deemed reasonable and used to
19    set rates.
20        (2) The utility, at its election, may recover all of
21    the costs it incurs under this Section as part of a filing
22    for a general increase in rates under Article IX of this
23    Act, as part of an annual filing to update a
24    performance-based formula rate under subsection (d) of
25    Section 16-108.5 of this Act, or through an automatic
26    adjustment clause tariff, provided that nothing in this

 

 

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1    paragraph (2) permits the double recovery of such costs
2    from customers. If the utility elects to recover the costs
3    it incurs under this Section through an automatic
4    adjustment clause tariff, the utility may file its proposed
5    tariff together with the tariff it files under subsection
6    (b) of this Section or at a later time. The proposed tariff
7    shall provide for an annual reconciliation, less any
8    deferred taxes related to the reconciliation, with
9    interest at an annual rate of return equal to the utility's
10    weighted average cost of capital as calculated under
11    paragraph (1) of this subsection (h), including a revenue
12    conversion factor calculated to recover or refund all
13    additional income taxes that may be payable or receivable
14    as a result of that return, of the revenue requirement
15    reflected in rates for each calendar year, beginning with
16    the calendar year in which the utility files its automatic
17    adjustment clause tariff under this subsection (h), with
18    what the revenue requirement would have been had the actual
19    cost information for the applicable calendar year been
20    available at the filing date. The Commission shall review
21    the proposed tariff and may make changes to the tariff that
22    are consistent with this Section and with the Commission's
23    authority under Article IX of this Act, subject to notice
24    and hearing. Following notice and hearing, the Commission
25    shall issue an order approving, or approving with
26    modification, such tariff no later than 240 days after the

 

 

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1    utility files its tariff.
2    (i) No later than 90 days after the Commission enters an
3order, or order on rehearing, whichever is later, approving an
4electric utility's proposed tariff under subsection (d) of this
5Section, the electric utility shall provide notice of the
6availability of rebates under this Section. Subsequent to the
7utility's notice, any entity that offers in the State, for sale
8or lease, distributed generation and estimates the dollar
9saving attributable to such distributed generation shall
10provide estimates based on both delivery service credits and
11the rebates available under this Section.
12(Source: P.A. 99-906, eff. 6-1-17.)
 
13    (220 ILCS 5/16-108.5)
14    Sec. 16-108.5. Infrastructure investment and
15modernization; regulatory reform.
16    (a) (Blank).
17    (b) For purposes of this Section, "participating utility"
18means an electric utility or a combination utility serving more
19than 1,000,000 customers in Illinois that voluntarily elects
20and commits to undertake (i) the infrastructure investment
21program consisting of the commitments and obligations
22described in this subsection (b) and (ii) the customer
23assistance program consisting of the commitments and
24obligations described in subsection (b-10) of this Section,
25notwithstanding any other provisions of this Act and without

 

 

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1obtaining any approvals from the Commission or any other agency
2other than as set forth in this Section, regardless of whether
3any such approval would otherwise be required. "Combination
4utility" means a utility that, as of January 1, 2011, provided
5electric service to at least one million retail customers in
6Illinois and gas service to at least 500,000 retail customers
7in Illinois. A participating utility shall recover the
8expenditures made under the infrastructure investment program
9through the ratemaking process, including, but not limited to,
10the performance-based formula rate and process set forth in
11this Section.
12    During the infrastructure investment program's peak
13program year, a participating utility other than a combination
14utility shall create 2,000 full-time equivalent jobs in
15Illinois, and a participating utility that is a combination
16utility shall create 450 full-time equivalent jobs in Illinois
17related to the provision of electric service. These jobs shall
18include direct jobs, contractor positions, and induced jobs,
19but shall not include any portion of a job commitment, not
20specifically contingent on an amendatory Act of the 97th
21General Assembly becoming law, between a participating utility
22and a labor union that existed on December 30, 2011 (the
23effective date of Public Act 97-646) and that has not yet been
24fulfilled. A portion of the full-time equivalent jobs created
25by each participating utility shall include incremental
26personnel hired subsequent to December 30, 2011 (the effective

 

 

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1date of Public Act 97-646). For purposes of this Section, "peak
2program year" means the consecutive 12-month period with the
3highest number of full-time equivalent jobs that occurs between
4the beginning of investment year 2 and the end of investment
5year 4.
6    A participating utility shall meet one of the following
7commitments, as applicable:
8        (1) Beginning no later than 180 days after a
9    participating utility other than a combination utility
10    files a performance-based formula rate tariff pursuant to
11    subsection (c) of this Section, or, beginning no later than
12    January 1, 2012 if such utility files such
13    performance-based formula rate tariff within 14 days of
14    October 26, 2011 (the effective date of Public Act 97-616),
15    the participating utility shall, except as provided in
16    subsection (b-5):
17            (A) over a 5-year period, invest an estimated
18        $1,300,000,000 in electric system upgrades,
19        modernization projects, and training facilities,
20        including, but not limited to:
21                (i) distribution infrastructure improvements
22            totaling an estimated $1,000,000,000, including
23            underground residential distribution cable
24            injection and replacement and mainline cable
25            system refurbishment and replacement projects;
26                (ii) training facility construction or upgrade

 

 

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

 

 

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1            and the ability to provide the greatest customer
2            benefit upon completion of the improvements; to be
3            eligible for improvement, the participating
4            utility's ability to maintain proper tree
5            clearances surrounding the overhead circuit must
6            not have been impeded by third parties; and
7            (B) over a 10-year period, invest an estimated
8        $1,300,000,000 to upgrade and modernize its
9        transmission and distribution infrastructure and in
10        Smart Grid electric system upgrades, including, but
11        not limited to:
12                (i) additional smart meters;
13                (ii) distribution automation;
14                (iii) associated cyber secure data
15            communication network; and
16                (iv) substation micro-processor relay
17            upgrades.
18        (2) Beginning no later than 180 days after a
19    participating utility that is a combination utility files a
20    performance-based formula rate tariff pursuant to
21    subsection (c) of this Section, or, beginning no later than
22    January 1, 2012 if such utility files such
23    performance-based formula rate tariff within 14 days of
24    October 26, 2011 (the effective date of Public Act 97-616),
25    the participating utility shall, except as provided in
26    subsection (b-5):

 

 

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1            (A) over a 10-year period, invest an estimated
2        $265,000,000 in electric system upgrades,
3        modernization projects, and training facilities,
4        including, but not limited to:
5                (i) distribution infrastructure improvements
6            totaling an estimated $245,000,000, which may
7            include bulk supply substations, transformers,
8            reconductoring, and rebuilding overhead
9            distribution and sub-transmission lines,
10            underground residential distribution cable
11            injection and replacement and mainline cable
12            system refurbishment and replacement projects;
13                (ii) training facility construction or upgrade
14            projects totaling an estimated $1,000,000; any
15            such new facility must be designed for the purpose
16            of obtaining, and the owner of the facility shall
17            apply for, certification under the United States
18            Green Building Council's Leadership in Energy
19            Efficiency Design Green Building Rating System;
20            and
21                (iii) wood pole inspection, treatment, and
22            replacement programs; and
23            (B) over a 10-year period, invest an estimated
24        $360,000,000 to upgrade and modernize its transmission
25        and distribution infrastructure and in Smart Grid
26        electric system upgrades, including, but not limited

 

 

SB3977- 185 -LRB101 20818 JLS 70537 b

1        to:
2                (i) additional smart meters;
3                (ii) distribution automation;
4                (iii) associated cyber secure data
5            communication network; and
6                (iv) substation micro-processor relay
7            upgrades.
8    For purposes of this Section, "Smart Grid electric system
9upgrades" shall have the meaning set forth in subsection (a) of
10Section 16-108.6 of this Act.
11    The investments in the infrastructure investment program
12described in this subsection (b) shall be incremental to the
13participating utility's annual capital investment program, as
14defined by, for purposes of this subsection (b), the
15participating utility's average capital spend for calendar
16years 2008, 2009, and 2010 as reported in the applicable
17Federal Energy Regulatory Commission (FERC) Form 1; provided
18that where one or more utilities have merged, the average
19capital spend shall be determined using the aggregate of the
20merged utilities' capital spend reported in FERC Form 1 for the
21years 2008, 2009, and 2010. A participating utility may add
22reasonable construction ramp-up and ramp-down time to the
23investment periods specified in this subsection (b). For each
24such investment period, the ramp-up and ramp-down time shall
25not exceed a total of 6 months.
26    Within 60 days after filing a tariff under subsection (c)

 

 

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1of this Section, a participating utility shall submit to the
2Commission its plan, including scope, schedule, and staffing,
3for satisfying its infrastructure investment program
4commitments pursuant to this subsection (b). The submitted plan
5shall include a schedule and staffing plan for the next
6calendar year. The plan shall also include a plan for the
7creation, operation, and administration of a Smart Grid test
8bed as described in subsection (c) of Section 16-108.8. The
9plan need not allocate the work equally over the respective
10periods, but should allocate material increments throughout
11such periods commensurate with the work to be undertaken. No
12later than April 1 of each subsequent year, the utility shall
13submit to the Commission a report that includes any updates to
14the plan, a schedule for the next calendar year, the
15expenditures made for the prior calendar year and cumulatively,
16and the number of full-time equivalent jobs created for the
17prior calendar year and cumulatively. If the utility is
18materially deficient in satisfying a schedule or staffing plan,
19then the report must also include a corrective action plan to
20address the deficiency. The fact that the plan, implementation
21of the plan, or a schedule changes shall not imply the
22imprudence or unreasonableness of the infrastructure
23investment program, plan, or schedule. Further, no later than
2445 days following the last day of the first, second, and third
25quarters of each year of the plan, a participating utility
26shall submit to the Commission a verified quarterly report for

 

 

SB3977- 187 -LRB101 20818 JLS 70537 b

1the prior quarter that includes (i) the total number of
2full-time equivalent jobs created during the prior quarter,
3(ii) the total number of employees as of the last day of the
4prior quarter, (iii) the total number of full-time equivalent
5hours in each job classification or job title, (iv) the total
6number of incremental employees and contractors in support of
7the investments undertaken pursuant to this subsection (b) for
8the prior quarter, and (v) any other information that the
9Commission may require by rule.
10    With respect to the participating utility's peak job
11commitment, if, after considering the utility's corrective
12action plan and compliance thereunder, the Commission enters an
13order finding, after notice and hearing, that a participating
14utility did not satisfy its peak job commitment described in
15this subsection (b) for reasons that are reasonably within its
16control, then the Commission shall also determine, after
17consideration of the evidence, including, but not limited to,
18evidence submitted by the Department of Commerce and Economic
19Opportunity and the utility, the deficiency in the number of
20full-time equivalent jobs during the peak program year due to
21such failure. The Commission shall notify the Department of any
22proceeding that is initiated pursuant to this paragraph. For
23each full-time equivalent job deficiency during the peak
24program year that the Commission finds as set forth in this
25paragraph, the participating utility shall, within 30 days
26after the entry of the Commission's order, pay $6,000 to a fund

 

 

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

 

 

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

 

 

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

 

 

SB3977- 191 -LRB101 20818 JLS 70537 b

1to subsection (f) of this Section accordingly.
2    (b-10) All participating utilities shall make
3contributions for an energy low-income and support program in
4accordance with this subsection. Beginning no later than 180
5days after a participating utility files a performance-based
6formula rate tariff pursuant to subsection (c) of this Section,
7or beginning no later than January 1, 2012 if such utility
8files such performance-based formula rate tariff within 14 days
9of December 30, 2011 (the effective date of Public Act 97-646),
10and without obtaining any approvals from the Commission or any
11other agency other than as set forth in this Section,
12regardless of whether any such approval would otherwise be
13required, a participating utility other than a combination
14utility shall pay $10,000,000 per year for 5 years and a
15participating utility that is a combination utility shall pay
16$1,000,000 per year for 10 years to the energy low-income and
17support program, which is intended to fund customer assistance
18programs with the primary purpose being avoidance of imminent
19disconnection. Such programs may include:
20        (1) a residential hardship program that may partner
21    with community-based organizations, including senior
22    citizen organizations, and provides grants to low-income
23    residential customers, including low-income senior
24    citizens, who demonstrate a hardship;
25        (2) a program that provides grants and other bill
26    payment concessions to veterans with disabilities who

 

 

SB3977- 192 -LRB101 20818 JLS 70537 b

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

 

 

SB3977- 193 -LRB101 20818 JLS 70537 b

1implemented through tariffs that are filed with and reviewed by
2the Commission. If a utility elects to file tariffs with the
3Commission to implement all or a portion of the programs, those
4tariffs shall, regardless of the date actually filed, be deemed
5accepted and approved, and shall become effective on December
630, 2011 (the effective date of Public Act 97-646). The
7participating utilities whose customers benefit from the funds
8that are disbursed as contemplated in this Section shall file
9annual reports documenting the disbursement of those funds with
10the Commission. The Commission has the authority to audit
11disbursement of the funds to ensure they were disbursed
12consistently with this Section.
13    If the Commission finds that a participating utility is no
14longer eligible to update the performance-based formula rate
15tariff pursuant to subsection (d) of this Section, or the
16performance-based formula rate is otherwise terminated, then
17the participating utility's voluntary commitments and
18obligations under this subsection (b-10) shall immediately
19terminate.
20    (b-15) Beginning in 2022, without obtaining any approvals
21from the Commission or any other agency, regardless of whether
22any such approval would otherwise be required, a participating
23utility that is a combination utility shall pay $1,000,000 per
24year for 10 years to the energy low-income and support program,
25which is intended to fund customer assistance programs with the
26primary purpose of avoidance of imminent disconnection and

 

 

SB3977- 194 -LRB101 20818 JLS 70537 b

1reconnecting customers who have been disconnected for
2nonpayment. Such programs may include those described in
3paragraphs (1) through (5) of subsection (b-10) of this
4Section.
5    The payments made by a participating utility pursuant to
6this subsection (b-15) is not a recoverable expense. A
7participating utility may elect to fund either new or existing
8customer assistance programs, including, but not limited to,
9those that are administered by the utility.
10    Programs that use funds that are provided by a
11participating utility to reduce utility bills may be
12implemented through tariffs that are filed with and reviewed by
13the Commission. If a utility elects to file tariffs with the
14Commission to implement all or a portion of the programs, those
15tariffs shall, regardless of the date actually filed, be deemed
16accepted and approved, and shall become effective on the first
17business day after they are filed. The participating utilities
18whose customers benefit from the funds that are disbursed as
19contemplated in this subsection (b-15) shall file annual
20reports documenting the disbursement of those funds with the
21Commission. The Commission has the authority to audit
22disbursement of the funds to ensure they were disbursed
23consistently with this subsection (b-15).
24    If the Commission finds that a participating utility is no
25longer eligible to update the performance-based formula rate
26tariff pursuant to subsection (d) of this Section, or the

 

 

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1performance-based formula rate is otherwise terminated, then
2the participating utility's voluntary commitments and
3obligations under this subsection (b-15) shall immediately
4terminate.
5    (c) A participating utility may elect to recover its
6delivery services costs through a performance-based formula
7rate approved by the Commission, which shall specify the cost
8components that form the basis of the rate charged to customers
9with sufficient specificity to operate in a standardized manner
10and be updated annually with transparent information that
11reflects the utility's actual costs to be recovered during the
12applicable rate year, which is the period beginning with the
13first billing day of January and extending through the last
14billing day of the following December. In the event the utility
15recovers a portion of its costs through automatic adjustment
16clause tariffs on October 26, 2011 (the effective date of
17Public Act 97-616), the utility may elect to continue to
18recover these costs through such tariffs, but then these costs
19shall not be recovered through the performance-based formula
20rate. In the event the participating utility, prior to December
2130, 2011 (the effective date of Public Act 97-646), filed
22electric delivery services tariffs with the Commission
23pursuant to Section 9-201 of this Act that are related to the
24recovery of its electric delivery services costs that are still
25pending on December 30, 2011 (the effective date of Public Act
2697-646), the participating utility shall, at the time it files

 

 

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1its performance-based formula rate tariff with the Commission,
2also file a notice of withdrawal with the Commission to
3withdraw the electric delivery services tariffs previously
4filed pursuant to Section 9-201 of this Act. Upon receipt of
5such notice, the Commission shall dismiss with prejudice any
6docket that had been initiated to investigate the electric
7delivery services tariffs filed pursuant to Section 9-201 of
8this Act, and such tariffs and the record related thereto shall
9not be the subject of any further hearing, investigation, or
10proceeding of any kind related to rates for electric delivery
11services.
12    The performance-based formula rate shall be implemented
13through a tariff filed with the Commission consistent with the
14provisions of this subsection (c) that shall be applicable to
15all delivery services customers. The Commission shall initiate
16and conduct an investigation of the tariff in a manner
17consistent with the provisions of this subsection (c) and the
18provisions of Article IX of this Act to the extent they do not
19conflict with this subsection (c). Except in the case where the
20Commission finds, after notice and hearing, that a
21participating utility is not satisfying its investment amount
22commitments under subsection (b) of this Section, the
23performance-based formula rate shall remain in effect at the
24discretion of the utility. The performance-based formula rate
25approved by the Commission shall do the following:
26        (1) Provide for the recovery of the utility's actual

 

 

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1    costs of delivery services that are prudently incurred and
2    reasonable in amount consistent with Commission practice
3    and law. The sole fact that a cost differs from that
4    incurred in a prior calendar year or that an investment is
5    different from that made in a prior calendar year shall not
6    imply the imprudence or unreasonableness of that cost or
7    investment.
8        (2) Reflect the utility's actual year-end capital
9    structure for the applicable calendar year, excluding
10    goodwill, subject to a determination of prudence and
11    reasonableness consistent with Commission practice and
12    law. To enable the financing of the incremental capital
13    expenditures, including regulatory assets, for electric
14    utilities that serve less than 3,000,000 retail customers
15    but more than 500,000 retail customers in the State, a
16    participating electric utility's actual year-end capital
17    structure that includes a common equity ratio, excluding
18    goodwill, of up to and including 50% of the total capital
19    structure shall be deemed reasonable and used to set rates.
20        (3) Include a cost of equity, which in all rate years
21    for a participating utility that is not a combination
22    utility, and in each rate year commencing before December
23    1, 2019 for a participating utility that is a combination
24    utility, shall be calculated as the sum of the following:
25            (A) the average for the applicable calendar year of
26        the monthly average yields of 30-year U.S. Treasury

 

 

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1        bonds published by the Board of Governors of the
2        Federal Reserve System in its weekly H.15 Statistical
3        Release or successor publication; and
4            (B) 580 basis points.
5        For a participating utility that is a combination
6    utility, for each rate year commencing after November 30,
7    2019, the cost of equity shall be calculated as the sum of
8    the following: (i) the average for the applicable calendar
9    year of the monthly average yields of 30-year U.S. Treasury
10    bonds published by the Board of Governors of the Federal
11    Reserve System in its weekly H.15 Statistical Release or
12    successor publication; and (ii) 680 basis points; however,
13    if the cost of equity as calculated under this paragraph
14    (3) for each rate year commencing after November 30, 2019,
15    for electric utilities that serve less than 3,000,000
16    retail customers but more than 500,000 retail customers in
17    this State is greater than the national average cost of
18    equity for the rate year by 50 basis points or more, then
19    the Illinois Commerce Commission shall include a cost of
20    equity at a rate equal to the national average cost of
21    equity as calculated under this paragraph (3) plus 50 basis
22    points. For purposes of this paragraph (3), the national
23    average cost of equity for a rate year shall be the simple
24    average of the cost of equity approved in each order of a
25    state regulatory commission, other than the Commission,
26    issued during that rate year that is applicable to retail

 

 

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1    electric service provided by an investor-owned public
2    utility company operating in the United States. No order
3    shall be excluded from the national average cost of equity
4    calculated under this paragraph (3) on the grounds that it
5    is subject to rehearing or appeal. In the hearing during
6    the first rate year commencing after November 30, 2019, the
7    Commission shall set the cost of equity using the method
8    applicable to rate years commencing prior to December 1,
9    2019. In the hearings in rate years subsequent to such
10    first rate year, the Commission shall set the cost of
11    equity using the method applicable to rate years commencing
12    after November 30, 2019, including the reconciliation of
13    the first rate year commencing after November 30, 2019. If,
14    for any rate year, there are fewer than 15 applicable
15    orders of state regulatory commissions with which to
16    compute the average cost of equity, the Commission shall
17    include in the calculation of the national average the
18    number of state regulatory orders from the prior year or
19    years necessary to reach a total of 15, beginning with the
20    most recently issued and proceeding in reverse
21    chronological order.
22        At such time as the Board of Governors of the Federal
23    Reserve System ceases to include the monthly average yields
24    of 30-year U.S. Treasury bonds in its weekly H.15
25    Statistical Release or successor publication, the monthly
26    average yields of the U.S. Treasury bonds then having the

 

 

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

 

 

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1        utility's weighted average cost of long-term debt, on
2        the pension assets as, and in the amount, reported in
3        Account 186 (or in such other Account or Accounts as
4        such asset may subsequently be recorded) of the
5        utility's most recently filed FERC Form 1, net of
6        deferred tax benefits;
7            (E) recovery of the expenses related to the
8        Commission proceeding under this subsection (c) to
9        approve this performance-based formula rate and
10        initial rates or to subsequent proceedings related to
11        the formula, provided that the recovery shall be
12        amortized over a 3-year period; recovery of expenses
13        related to the annual Commission proceedings under
14        subsection (d) of this Section to review the inputs to
15        the performance-based formula rate shall be expensed
16        and recovered through the performance-based formula
17        rate;
18            (F) amortization over a 5-year period of the full
19        amount of each charge or credit that exceeds $3,700,000
20        for a participating utility that is a combination
21        utility or $10,000,000 for a participating utility
22        that serves more than 3 million retail customers in the
23        applicable calendar year and that relates to a
24        workforce reduction program's severance costs, changes
25        in accounting rules, changes in law, compliance with
26        any Commission-initiated audit, or a single storm or

 

 

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1        other similar expense, provided that any unamortized
2        balance shall be reflected in rate base. For purposes
3        of this subparagraph (F), changes in law includes any
4        enactment, repeal, or amendment in a law, ordinance,
5        rule, regulation, interpretation, permit, license,
6        consent, or order, including those relating to taxes,
7        accounting, or to environmental matters, or in the
8        interpretation or application thereof by any
9        governmental authority occurring after October 26,
10        2011 (the effective date of Public Act 97-616);
11            (G) recovery of existing regulatory assets over
12        the periods previously authorized by the Commission;
13            (H) historical weather normalized billing
14        determinants; and
15            (I) allocation methods for common costs.
16        (5) Provide that if the participating utility's earned
17    rate of return on common equity related to the provision of
18    delivery services for the prior rate year (calculated using
19    costs and capital structure approved by the Commission as
20    provided in subparagraph (2) of this subsection (c),
21    consistent with this Section, in accordance with
22    Commission rules and orders, including, but not limited to,
23    adjustments for goodwill, and after any Commission-ordered
24    disallowances and taxes) is more than 50 basis points
25    higher than the rate of return on common equity calculated
26    pursuant to paragraph (3) of this subsection (c) (after

 

 

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

 

 

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1    provision of subsection (f), (f-5), or (f-10) of this
2    Section, as applicable), then the participating utility
3    shall apply a charge through the performance-based formula
4    rate that reflects an amount equal to the value of that
5    portion of the earned rate of return on common equity that
6    is more than 50 basis points less than the rate of return
7    on common equity calculated pursuant to paragraph (3) of
8    this subsection (c) (after adjusting for any penalties to
9    the rate of return on common equity applied pursuant to the
10    performance metrics provision of subsection (f), (f-5), or
11    (f-10) of this Section, as applicable) for the prior rate
12    year, adjusted for taxes.
13        (6) Provide for an annual reconciliation, as described
14    in subsection (d) of this Section, with interest, of the
15    revenue requirement reflected in rates for each calendar
16    year, beginning with the calendar year in which the utility
17    files its performance-based formula rate tariff pursuant
18    to subsection (c) of this Section, with what the revenue
19    requirement would have been had the actual cost information
20    for the applicable calendar year been available at the
21    filing date.
22    The utility shall file, together with its tariff, final
23data based on its most recently filed FERC Form 1, plus
24projected plant additions and correspondingly updated
25depreciation reserve and expense for the calendar year in which
26the tariff and data are filed, that shall populate the

 

 

SB3977- 205 -LRB101 20818 JLS 70537 b

1performance-based formula rate and set the initial delivery
2services rates under the formula. For purposes of this Section,
3"FERC Form 1" means the Annual Report of Major Electric
4Utilities, Licensees and Others that electric utilities are
5required to file with the Federal Energy Regulatory Commission
6under the Federal Power Act, Sections 3, 4(a), 304 and 209,
7modified as necessary to be consistent with 83 Ill. Admin. Code
8Part 415 as of May 1, 2011. Nothing in this Section is intended
9to allow costs that are not otherwise recoverable to be
10recoverable by virtue of inclusion in FERC Form 1.
11    After the utility files its proposed performance-based
12formula rate structure and protocols and initial rates, the
13Commission shall initiate a docket to review the filing. The
14Commission shall enter an order approving, or approving as
15modified, the performance-based formula rate, including the
16initial rates, as just and reasonable within 270 days after the
17date on which the tariff was filed, or, if the tariff is filed
18within 14 days after October 26, 2011 (the effective date of
19Public Act 97-616), then by May 31, 2012. Such review shall be
20based on the same evidentiary standards, including, but not
21limited to, those concerning the prudence and reasonableness of
22the costs incurred by the utility, the Commission applies in a
23hearing to review a filing for a general increase in rates
24under Article IX of this Act. The initial rates shall take
25effect within 30 days after the Commission's order approving
26the performance-based formula rate tariff.

 

 

SB3977- 206 -LRB101 20818 JLS 70537 b

1    Until such time as the Commission approves a different rate
2design and cost allocation pursuant to subsection (e) of this
3Section, rate design and cost allocation across customer
4classes shall be consistent with the Commission's most recent
5order regarding the participating utility's request for a
6general increase in its delivery services rates.
7    Subsequent changes to the performance-based formula rate
8structure or protocols shall be made as set forth in Section
99-201 of this Act, but nothing in this subsection (c) is
10intended to limit the Commission's authority under Article IX
11and other provisions of this Act to initiate an investigation
12of a participating utility's performance-based formula rate
13tariff, provided that any such changes shall be consistent with
14paragraphs (1) through (6) of this subsection (c). Any change
15ordered by the Commission shall be made at the same time new
16rates take effect following the Commission's next order
17pursuant to subsection (d) of this Section, provided that the
18new rates take effect no less than 30 days after the date on
19which the Commission issues an order adopting the change.
20    A participating utility that files a tariff pursuant to
21this subsection (c) must submit a one-time $200,000 filing fee
22at the time the Chief Clerk of the Commission accepts the
23filing, which shall be a recoverable expense.
24    In the event the performance-based formula rate is
25terminated, the then current rates shall remain in effect until
26such time as new rates are set pursuant to Article IX of this

 

 

SB3977- 207 -LRB101 20818 JLS 70537 b

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

 

 

SB3977- 208 -LRB101 20818 JLS 70537 b

1    actual revenue requirement for the prior rate year
2    (determined using a year-end rate base) that uses amounts
3    reflected in the applicable FERC Form 1 that reports the
4    actual costs for the prior rate year. Any over-collection
5    or under-collection indicated by such reconciliation shall
6    be reflected as a credit against, or recovered as an
7    additional charge to, respectively, with interest
8    calculated at a rate equal to the utility's weighted
9    average cost of capital approved by the Commission for the
10    prior rate year, the charges for the applicable rate year.
11    Provided, however, that the first such reconciliation
12    shall be for the calendar year in which the utility files
13    its performance-based formula rate tariff pursuant to
14    subsection (c) of this Section and shall reconcile (i) the
15    revenue requirement or requirements established by the
16    rate order or orders in effect from time to time during
17    such calendar year (weighted, as applicable) with (ii) the
18    revenue requirement determined using a year-end rate base
19    for that calendar year calculated pursuant to the
20    performance-based formula rate using (A) actual costs for
21    that year as reflected in the applicable FERC Form 1, and
22    (B) for the first such reconciliation only, the cost of
23    equity, which shall be calculated as the sum of 590 basis
24    points plus the average for the applicable calendar year of
25    the monthly average yields of 30-year U.S. Treasury bonds
26    published by the Board of Governors of the Federal Reserve

 

 

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1    System in its weekly H.15 Statistical Release or successor
2    publication. The first such reconciliation is not intended
3    to provide for the recovery of costs previously excluded
4    from rates based on a prior Commission order finding of
5    imprudence or unreasonableness. Each reconciliation shall
6    be certified by the participating utility in the same
7    manner that FERC Form 1 is certified. The filing shall also
8    include the charge or credit, if any, resulting from the
9    calculation required by paragraph (6) of subsection (c) of
10    this Section.
11        Notwithstanding anything that may be to the contrary,
12    the intent of the reconciliation is to ultimately reconcile
13    the revenue requirement reflected in rates for each
14    calendar year, beginning with the calendar year in which
15    the utility files its performance-based formula rate
16    tariff pursuant to subsection (c) of this Section, with
17    what the revenue requirement determined using a year-end
18    rate base for the applicable calendar year would have been
19    had the actual cost information for the applicable calendar
20    year been available at the filing date.
21        (2) The new charges shall take effect beginning on the
22    first billing day of the following January billing period
23    and remain in effect through the last billing day of the
24    next December billing period regardless of whether the
25    Commission enters upon a hearing pursuant to this
26    subsection (d).

 

 

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

 

 

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1enforced by the Commission or the assigned administrative law
2judge. The Commission shall apply the same evidentiary
3standards, including, but not limited to, those concerning the
4prudence and reasonableness of the costs incurred by the
5utility, in the hearing as it would apply in a hearing to
6review a filing for a general increase in rates under Article
7IX of this Act. The Commission shall not, however, have the
8authority in a proceeding under this subsection (d) to consider
9or order any changes to the structure or protocols of the
10performance-based formula rate approved pursuant to subsection
11(c) of this Section. In a proceeding under this subsection (d),
12the Commission shall enter its order no later than the earlier
13of 240 days after the utility's filing of its annual update of
14cost inputs to the performance-based formula rate or December
1531. The Commission's determinations of the prudence and
16reasonableness of the costs incurred for the applicable
17calendar year shall be final upon entry of the Commission's
18order and shall not be subject to reopening, reexamination, or
19collateral attack in any other Commission proceeding, case,
20docket, order, rule or regulation, provided, however, that
21nothing in this subsection (d) shall prohibit a party from
22petitioning the Commission to rehear or appeal to the courts
23the order pursuant to the provisions of this Act.
24    In the event the Commission does not, either upon complaint
25or its own initiative, enter upon a hearing within 45 days
26after the utility files the annual update of cost inputs to its

 

 

SB3977- 212 -LRB101 20818 JLS 70537 b

1performance-based formula rate, then the costs incurred for the
2applicable calendar year shall be deemed prudent and
3reasonable, and the filed charges shall not be subject to
4reopening, reexamination, or collateral attack in any other
5proceeding, case, docket, order, rule, or regulation.
6    A participating utility's first filing of the updated cost
7inputs, and any Commission investigation of such inputs
8pursuant to this subsection (d) shall proceed notwithstanding
9the fact that the Commission's investigation under subsection
10(c) of this Section is still pending and notwithstanding any
11other law, order, rule, or Commission practice to the contrary.
12    (e) Nothing in subsections (c) or (d) of this Section shall
13prohibit the Commission from investigating, or a participating
14utility from filing, revenue-neutral tariff changes related to
15rate design of a performance-based formula rate that has been
16placed into effect for the utility. Following approval of a
17participating utility's performance-based formula rate tariff
18pursuant to subsection (c) of this Section, the utility shall
19make a filing with the Commission within one year after the
20effective date of the performance-based formula rate tariff
21that proposes changes to the tariff to incorporate the findings
22of any final rate design orders of the Commission applicable to
23the participating utility and entered subsequent to the
24Commission's approval of the tariff. The Commission shall,
25after notice and hearing, enter its order approving, or
26approving with modification, the proposed changes to the

 

 

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1performance-based formula rate tariff within 240 days after the
2utility's filing. Following such approval, the utility shall
3make a filing with the Commission during each subsequent 3-year
4period that either proposes revenue-neutral tariff changes or
5re-files the existing tariffs without change, which shall
6present the Commission with an opportunity to suspend the
7tariffs and consider revenue-neutral tariff changes related to
8rate design.
9    (f) Within 30 days after the filing of a tariff pursuant to
10subsection (c) of this Section, each participating utility
11shall develop and file with the Commission multi-year metrics
12designed to achieve, ratably (i.e., in equal segments) over a
1310-year period, improvement over baseline performance values
14as follows:
15        (1) Twenty percent improvement in the System Average
16    Interruption Frequency Index, using a baseline of the
17    average of the data from 2001 through 2010.
18        (2) Fifteen percent improvement in the system Customer
19    Average Interruption Duration Index, using a baseline of
20    the average of the data from 2001 through 2010.
21        (3) For a participating utility other than a
22    combination utility, 20% improvement in the System Average
23    Interruption Frequency Index for its Southern Region,
24    using a baseline of the average of the data from 2001
25    through 2010. For purposes of this paragraph (3), Southern
26    Region shall have the meaning set forth in the

 

 

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1    participating utility's most recent report filed pursuant
2    to Section 16-125 of this Act.
3        (3.5) For a participating utility other than a
4    combination utility, 20% improvement in the System Average
5    Interruption Frequency Index for its Northeastern Region,
6    using a baseline of the average of the data from 2001
7    through 2010. For purposes of this paragraph (3.5),
8    Northeastern Region shall have the meaning set forth in the
9    participating utility's most recent report filed pursuant
10    to Section 16-125 of this Act.
11        (4) Seventy-five percent improvement in the total
12    number of customers who exceed the service reliability
13    targets as set forth in subparagraphs (A) through (C) of
14    paragraph (4) of subsection (b) of 83 Ill. Admin. Code Part
15    411.140 as of May 1, 2011, using 2010 as the baseline year.
16        (5) Reduction in issuance of estimated electric bills:
17    90% improvement for a participating utility other than a
18    combination utility, and 56% improvement for a
19    participating utility that is a combination utility, using
20    a baseline of the average number of estimated bills for the
21    years 2008 through 2010.
22        (6) Consumption on inactive meters: 90% improvement
23    for a participating utility other than a combination
24    utility, and 56% improvement for a participating utility
25    that is a combination utility, using a baseline of the
26    average unbilled kilowatthours for the years 2009 and 2010.

 

 

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1        (7) Unaccounted for energy: 50% improvement for a
2    participating utility other than a combination utility
3    using a baseline of the non-technical line loss unaccounted
4    for energy kilowatthours for the year 2009.
5        (8) Uncollectible expense: reduce uncollectible
6    expense by at least $30,000,000 for a participating utility
7    other than a combination utility and by at least $3,500,000
8    for a participating utility that is a combination utility,
9    using a baseline of the average uncollectible expense for
10    the years 2008 through 2010.
11        (9) Opportunities for minority-owned and female-owned
12    business enterprises: design a performance metric
13    regarding the creation of opportunities for minority-owned
14    and female-owned business enterprises consistent with
15    State and federal law using a base performance value of the
16    percentage of the participating utility's capital
17    expenditures that were paid to minority-owned and
18    female-owned business enterprises in 2010.
19    The definitions set forth in 83 Ill. Admin. Code Part
20411.20 as of May 1, 2011 shall be used for purposes of
21calculating performance under paragraphs (1) through (3.5) of
22this subsection (f), provided, however, that the participating
23utility may exclude up to 9 extreme weather event days from
24such calculation for each year, and provided further that the
25participating utility shall exclude 9 extreme weather event
26days when calculating each year of the baseline period to the

 

 

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1extent that there are 9 such days in a given year of the
2baseline period. For purposes of this Section, an extreme
3weather event day is a 24-hour calendar day (beginning at 12:00
4a.m. and ending at 11:59 p.m.) during which any weather event
5(e.g., storm, tornado) caused interruptions for 10,000 or more
6of the participating utility's customers for 3 hours or more.
7If there are more than 9 extreme weather event days in a year,
8then the utility may choose no more than 9 extreme weather
9event days to exclude, provided that the same extreme weather
10event days are excluded from each of the calculations performed
11under paragraphs (1) through (3.5) of this subsection (f).
12    The metrics shall include incremental performance goals
13for each year of the 10-year period, which shall be designed to
14demonstrate that the utility is on track to achieve the
15performance goal in each category at the end of the 10-year
16period. The utility shall elect when the 10-year period shall
17commence for the metrics set forth in subparagraphs (1) through
18(4) and (9) of this subsection (f), provided that it begins no
19later than 14 months following the date on which the utility
20begins investing pursuant to subsection (b) of this Section,
21and when the 10-year period shall commence for the metrics set
22forth in subparagraphs (5) through (8) of this subsection (f),
23provided that it begins no later than 14 months following the
24date on which the Commission enters its order approving the
25utility's Advanced Metering Infrastructure Deployment Plan
26pursuant to subsection (c) of Section 16-108.6 of this Act.

 

 

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1    The metrics and performance goals set forth in
2subparagraphs (5) through (8) of this subsection (f) are based
3on the assumptions that the participating utility may fully
4implement the technology described in subsection (b) of this
5Section, including utilizing the full functionality of such
6technology and that there is no requirement for personal
7on-site notification. If the utility is unable to meet the
8metrics and performance goals set forth in subparagraphs (5)
9through (8) of this subsection (f) for such reasons, and the
10Commission so finds after notice and hearing, then the utility
11shall be excused from compliance, but only to the limited
12extent achievement of the affected metrics and performance
13goals was hindered by the less than full implementation.
14    (f-5) The financial penalties applicable to the metrics
15described in subparagraphs (1) through (8) of subsection (f) of
16this Section, as applicable, shall be applied through an
17adjustment to the participating utility's return on equity of
18no more than a total of 30 basis points in each of the first 3
19years, of no more than a total of 34 basis points in each of the
203 years thereafter, and of no more than a total of 38 basis
21points in each of the 4 years thereafter, as follows:
22        (1) With respect to each of the incremental annual
23    performance goals established pursuant to paragraph (1) of
24    subsection (f) of this Section,
25            (A) for each year that a participating utility
26        other than a combination utility does not achieve the

 

 

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

 

 

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1    during years 1 through 3, by 5 basis points; during years 4
2    through 6, by 6 basis points; and during years 7 through
3    10, by 7 basis points.
4        (4) With respect to each of the incremental annual
5    performance goals established pursuant to paragraph (4) of
6    subsection (f) of this Section, for each year that the
7    participating utility does not achieve each such goal, the
8    participating utility's return on equity shall be reduced
9    as follows: during years 1 through 3, by 5 basis points;
10    during years 4 through 6, by 6 basis points; and during
11    years 7 through 10, by 7 basis points.
12        (5) With respect to each of the incremental annual
13    performance goals established pursuant to subparagraph (5)
14    of subsection (f) of this Section, for each year that the
15    participating utility does not achieve at least 95% of each
16    such goal, the participating utility's return on equity
17    shall be reduced by 5 basis points for each such unachieved
18    goal.
19        (6) With respect to each of the incremental annual
20    performance goals established pursuant to paragraphs (6),
21    (7), and (8) of subsection (f) of this Section, as
22    applicable, which together measure non-operational
23    customer savings and benefits relating to the
24    implementation of the Advanced Metering Infrastructure
25    Deployment Plan, as defined in Section 16-108.6 of this
26    Act, the performance under each such goal shall be

 

 

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1    calculated in terms of the percentage of the goal achieved.
2    The percentage of goal achieved for each of the goals shall
3    be aggregated, and an average percentage value calculated,
4    for each year of the 10-year period. If the utility does
5    not achieve an average percentage value in a given year of
6    at least 95%, the participating utility's return on equity
7    shall be reduced by 5 basis points.
8    The financial penalties shall be applied as described in
9this subsection (f-5) for the 12-month period in which the
10deficiency occurred through a separate tariff mechanism, which
11shall be filed by the utility together with its metrics. In the
12event the formula rate tariff established pursuant to
13subsection (c) of this Section terminates, the utility's
14obligations under subsection (f) of this Section and this
15subsection (f-5) shall also terminate, provided, however, that
16the tariff mechanism established pursuant to subsection (f) of
17this Section and this subsection (f-5) shall remain in effect
18until any penalties due and owing at the time of such
19termination are applied.
20    The Commission shall, after notice and hearing, enter an
21order within 120 days after the metrics are filed approving, or
22approving with modification, a participating utility's tariff
23or mechanism to satisfy the metrics set forth in subsection (f)
24of this Section. On June 1 of each subsequent year, each
25participating utility shall file a report with the Commission
26that includes, among other things, a description of how the

 

 

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1participating utility performed under each metric and an
2identification of any extraordinary events that adversely
3impacted the utility's performance. Whenever a participating
4utility does not satisfy the metrics required pursuant to
5subsection (f) of this Section, the Commission shall, after
6notice and hearing, enter an order approving financial
7penalties in accordance with this subsection (f-5). The
8Commission-approved financial penalties shall be applied
9beginning with the next rate year. Nothing in this Section
10shall authorize the Commission to reduce or otherwise obviate
11the imposition of financial penalties for failing to achieve
12one or more of the metrics established pursuant to subparagraph
13(1) through (4) of subsection (f) of this Section.
14    (f-10) Each applicable 10-year period previously approved
15by the Commission pursuant to subsections (f) and (f-5) of this
16Section for a participating utility that is a combination
17utility shall be extended for an additional 10-year period that
18commences immediately after the termination of the previous
1910-year period. The performance goals and financial penalties
20applicable to each year of an additional 10-year period shall
21be fixed at, and the same as, the performance goals applicable
22to year 10 that were previously approved by the Commission
23pursuant to subsections (f) and (f-5) of this Section and the
24financial penalties applicable to year 10 set forth in
25subsection (f-5) of this Section. The total amount of financial
26penalties applicable in any given year shall not exceed 38

 

 

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1basis points. During the additional 10-year period, each
2participating utility shall continue to file the annual reports
3required by subsection (f-5) of this Section, and the
4requirements of subsection (f-5) related to Commission
5approval of any financial penalties shall continue to apply.
6The tariff or tariffs approved under subsection (f-5) of this
7Section for each participating utility that is a combination
8utility shall remain in effect during the additional 10-year
9period, and each participating utility that is a combination
10utility is authorized to submit a compliance filing after the
11effective date of this amendatory Act of the 101st General
12Assembly conforming its tariff or tariffs to the provisions of
13this subsection (f-10). In the event the formula rate tariff
14established pursuant to subsection (c) of this Section
15terminates, the utility's obligations under this subsection
16(f-10) shall also terminate; however, the tariff mechanism
17established pursuant to subsections (f) and (f-5) of this
18Section, and extended under this subsection (f-10), shall
19remain in effect until any penalties due and owing at the time
20of such termination are applied.
21    The metrics and performance goals set forth in paragraphs
22(5) through (8) of subsection (f) of this Section and extended
23under this subsection (f-10), are based on the assumption that
24the participating utility may fully implement the technology
25described in subsection (b) of this Section, including
26utilizing the full functionality of such technology and that

 

 

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1there is no requirement for personal on-site notification. If
2the utility is unable to meet the metrics and performance goals
3applicable to paragraphs (5) through (8) of subsection (f) of
4this Section for such reasons during the additional 10-year
5period, as those metrics and goals are set by this subsection
6(f-10), and the Commission so finds after notice and hearing,
7then the utility shall be excused from compliance, but only to
8the limited extent achievement of the affected metrics and
9performance goals was hindered by the less than full
10implementation.
11    (g) On or before July 31, 2014, each participating utility
12shall file a report with the Commission that sets forth the
13average annual increase in the average amount paid per
14kilowatthour for residential eligible retail customers,
15exclusive of the effects of energy efficiency programs,
16comparing the 12-month period ending May 31, 2012; the 12-month
17period ending May 31, 2013; and the 12-month period ending May
1831, 2014. For a participating utility that is a combination
19utility with more than one rate zone, the weighted average
20aggregate increase shall be provided. The report shall be filed
21together with a statement from an independent auditor attesting
22to the accuracy of the report. The cost of the independent
23auditor shall be borne by the participating utility and shall
24not be a recoverable expense. "The average amount paid per
25kilowatthour" shall be based on the participating utility's
26tariffed rates actually in effect and shall not be calculated

 

 

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1using any hypothetical rate or adjustments to actual charges
2(other than as specified for energy efficiency) as an input.
3    In the event that the average annual increase exceeds 2.5%
4as calculated pursuant to this subsection (g), then Sections
516-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act, other
6than this subsection, shall be inoperative as they relate to
7the utility and its service area as of the date of the report
8due to be submitted pursuant to this subsection and the utility
9shall no longer be eligible to annually update the
10performance-based formula rate tariff pursuant to subsection
11(d) of this Section. In such event, the then current rates
12shall remain in effect until such time as new rates are set
13pursuant to Article IX of this Act, subject to retroactive
14adjustment, with interest, to reconcile rates charged with
15actual costs, and the participating utility's voluntary
16commitments and obligations under subsection (b) of this
17Section shall immediately terminate, except for the utility's
18obligation to pay an amount already owed to the fund for
19training grants pursuant to a Commission order issued under
20subsection (b) of this Section.
21    In the event that the average annual increase is 2.5% or
22less as calculated pursuant to this subsection (g), then the
23performance-based formula rate shall remain in effect as set
24forth in this Section.
25    For purposes of this Section, the amount per kilowatthour
26means the total amount paid for electric service expressed on a

 

 

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1per kilowatthour basis, and the total amount paid for electric
2service includes without limitation amounts paid for supply,
3transmission, distribution, surcharges, and add-on taxes
4exclusive of any increases in taxes or new taxes imposed after
5October 26, 2011 (the effective date of Public Act 97-616). For
6purposes of this Section, "eligible retail customers" shall
7have the meaning set forth in Section 16-111.5 of this Act.
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    (h) By December 31, 2017, the Commission shall prepare and
13file with 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    This Section, other than this subsection (h), and Sections
2416-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act, other
25than this subsection (h), are inoperative after December 31,
262022 for every participating utility other than a combination

 

 

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1utility, after which time a participating utility other than a
2combination utility shall no longer be eligible to annually
3update the performance-based formula rate tariff pursuant to
4subsection (d) of this Section. At such time, the then current
5rates shall remain in effect until such time as new rates are
6set pursuant to Article IX of this Act, subject to retroactive
7adjustment, with interest, to reconcile rates charged with
8actual costs.
9    This Section, other than this subsection (h), and Sections
1016-108.6, 16-108.7, and 16-108.8 of this Act are inoperative
11after December 31, 2032 for every participating utility that is
12a combination utility, after which time a participating utility
13that is a combination utility shall no longer be eligible to
14annually update the performance-based formula rate tariff
15pursuant to subsection (d) of this Section. At such time, the
16then current rates shall remain in effect until new rates are
17set pursuant to Article IX of this Act, subject to retroactive
18adjustment, with interest, to reconcile rates charged with
19actual costs.
20    The fact that this Section becomes inoperative as set forth
21in this subsection shall not be construed to mean that the
22Commission may reexamine or otherwise reopen prudence or
23reasonableness determinations already made.
24    (i) While a participating utility may use, develop, and
25maintain broadband systems and the delivery of broadband
26services, voice-over-internet-protocol services,

 

 

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1telecommunications services, and cable and video programming
2services for use in providing delivery services and Smart Grid
3functionality or application to its retail customers,
4including, but not limited to, the installation,
5implementation and maintenance of Smart Grid electric system
6upgrades as defined in Section 16-108.6 of this Act, a
7participating utility is prohibited from offering to its retail
8customers broadband services or the delivery of broadband
9services, voice-over-internet-protocol services,
10telecommunications services, or cable or video programming
11services, unless they are part of a service directly related to
12delivery services or Smart Grid functionality or applications
13as defined in Section 16-108.6 of this Act, and from recovering
14the costs of such offerings from retail customers.
15    (j) Nothing in this Section is intended to legislatively
16overturn the opinion issued in Commonwealth Edison Co. v. Ill.
17Commerce Comm'n, Nos. 2-08-0959, 2-08-1037, 2-08-1137,
181-08-3008, 1-08-3030, 1-08-3054, 1-08-3313 cons. (Ill. App.
19Ct. 2d Dist. Sept. 30, 2010). Public Act 97-616 shall not be
20construed as creating a contract between the General Assembly
21and the participating utility, and shall not establish a
22property right in the participating utility.
23    (k) The changes made in subsections (c) and (d) of this
24Section by Public Act 98-15 are intended to be a restatement
25and clarification of existing law, and intended to give binding
26effect to the provisions of House Resolution 1157 adopted by

 

 

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1the House of Representatives of the 97th General Assembly and
2Senate Resolution 821 adopted by the Senate of the 97th General
3Assembly that are reflected in paragraph (3) of this
4subsection. In addition, Public Act 98-15 preempts and
5supersedes any final Commission orders entered in Docket Nos.
611-0721, 12-0001, 12-0293, and 12-0321 to the extent
7inconsistent with the amendatory language added to subsections
8(c) and (d).
9        (1) No earlier than 5 business days after May 22, 2013
10    (the effective date of Public Act 98-15), each
11    participating utility shall file any tariff changes
12    necessary to implement the amendatory language set forth in
13    subsections (c) and (d) of this Section by Public Act 98-15
14    and a revised revenue requirement under the participating
15    utility's performance-based formula rate. The Commission
16    shall enter a final order approving such tariff changes and
17    revised revenue requirement within 21 days after the
18    participating utility's filing.
19        (2) Notwithstanding anything that may be to the
20    contrary, a participating utility may file a tariff to
21    retroactively recover its previously unrecovered actual
22    costs of delivery service that are no longer subject to
23    recovery through a reconciliation adjustment under
24    subsection (d) of this Section. This retroactive recovery
25    shall include any derivative adjustments resulting from
26    the changes to subsections (c) and (d) of this Section by

 

 

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1    Public Act 98-15. Such tariff shall allow the utility to
2    assess, on current customer bills over a period of 12
3    monthly billing periods, a charge or credit related to
4    those unrecovered costs with interest at the utility's
5    weighted average cost of capital during the period in which
6    those costs were unrecovered. A participating utility may
7    file a tariff that implements a retroactive charge or
8    credit as described in this paragraph for amounts not
9    otherwise included in the tariff filing provided for in
10    paragraph (1) of this subsection (k). The Commission shall
11    enter a final order approving such tariff within 21 days
12    after the participating utility's filing.
13        (3) The tariff changes described in paragraphs (1) and
14    (2) of this subsection (k) shall relate only to, and be
15    consistent with, the following provisions of Public Act
16    98-15: paragraph (2) of subsection (c) regarding year-end
17    capital structure, subparagraph (D) of paragraph (4) of
18    subsection (c) regarding pension assets, and subsection
19    (d) regarding the reconciliation components related to
20    year-end rate base and interest calculated at a rate equal
21    to the utility's weighted average cost of capital.
22        (4) Nothing in this subsection is intended to effect a
23    dismissal of or otherwise affect an appeal from any final
24    Commission orders entered in Docket Nos. 11-0721, 12-0001,
25    12-0293, and 12-0321 other than to the extent of the
26    amendatory language contained in subsections (c) and (d) of

 

 

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1    this Section of Public Act 98-15.
2    (l) Each participating utility shall be deemed to have been
3in full compliance with all requirements of subsection (b) of
4this Section, subsection (c) of this Section, Section 16-108.6
5of this Act, and all Commission orders entered pursuant to
6Sections 16-108.5 and 16-108.6 of this Act, up to and including
7May 22, 2013 (the effective date of Public Act 98-15). The
8Commission shall not undertake any investigation of such
9compliance and no penalty shall be assessed or adverse action
10taken against a participating utility for noncompliance with
11Commission orders associated with subsection (b) of this
12Section, subsection (c) of this Section, and Section 16-108.6
13of this Act prior to such date. Each participating utility
14other than a combination utility shall be permitted, without
15penalty, a period of 12 months after such effective date to
16take actions required to ensure its infrastructure investment
17program is in compliance with subsection (b) of this Section
18and with Section 16-108.6 of this Act. Provided further, the
19following subparagraphs shall apply to a participating utility
20other than a combination utility:
21        (A) if the Commission has initiated a proceeding
22    pursuant to subsection (e) of Section 16-108.6 of this Act
23    that is pending as of May 22, 2013 (the effective date of
24    Public Act 98-15), then the order entered in such
25    proceeding shall, after notice and hearing, accelerate the
26    commencement of the meter deployment schedule approved in

 

 

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1    the final Commission order on rehearing entered in Docket
2    No. 12-0298;
3        (B) if the Commission has entered an order pursuant to
4    subsection (e) of Section 16-108.6 of this Act prior to May
5    22, 2013 (the effective date of Public Act 98-15) that does
6    not accelerate the commencement of the meter deployment
7    schedule approved in the final Commission order on
8    rehearing entered in Docket No. 12-0298, then the utility
9    shall file with the Commission, within 45 days after such
10    effective date, a plan for accelerating the commencement of
11    the utility's meter deployment schedule approved in the
12    final Commission order on rehearing entered in Docket No.
13    12-0298; the Commission shall reopen the proceeding in
14    which it entered its order pursuant to subsection (e) of
15    Section 16-108.6 of this Act and shall, after notice and
16    hearing, enter an amendatory order that approves or
17    approves as modified such accelerated plan within 90 days
18    after the utility's filing; or
19        (C) if the Commission has not initiated a proceeding
20    pursuant to subsection (e) of Section 16-108.6 of this Act
21    prior to May 22, 2013 (the effective date of Public Act
22    98-15), then the utility shall file with the Commission,
23    within 45 days after such effective date, a plan for
24    accelerating the commencement of the utility's meter
25    deployment schedule approved in the final Commission order
26    on rehearing entered in Docket No. 12-0298 and the

 

 

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1    Commission shall, after notice and hearing, approve or
2    approve as modified such plan within 90 days after the
3    utility's filing.
4    Any schedule for meter deployment approved by the
5Commission pursuant to this subsection (l) shall take into
6consideration procurement times for meters and other equipment
7and operational issues. Nothing in Public Act 98-15 shall
8shorten or extend the end dates for the 5-year or 10-year
9periods set forth in subsection (b) of this Section or Section
1016-108.6 of this Act. Nothing in this subsection is intended to
11address whether a participating utility has, or has not,
12satisfied any or all of the metrics and performance goals
13established pursuant to subsection (f) of this Section.
14    (m) The provisions of Public Act 98-15 are severable under
15Section 1.31 of the Statute on Statutes.
16(Source: P.A. 99-143, eff. 7-27-15; 99-642, eff. 7-28-16;
1799-906, eff. 6-1-17; 100-840, eff. 8-13-18.)
 
18    (220 ILCS 5/16-108.19 new)
19    Sec. 16-108.19. Electric vehicle charging station
20infrastructure.
21    (a) Notwithstanding any other provisions of this Act and
22without obtaining any approvals from the Commission or any
23other agency, including, but not limited to, approvals
24otherwise required under Section 8-406 of this Act, regardless
25of whether any such approval would otherwise be required,

 

 

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1electric utilities that serve less than 3,000,000 retail
2customers but more than 500,000 retail customers in this State
3are authorized to, but are not required to, plan for,
4construct, install, control, own, manage, or operate electric
5vehicle charging infrastructure, including, but not limited
6to, electric vehicle charging stations within their service
7territories. Electric utilities that serve less than 3,000,000
8retail customers but more than 500,000 retail customers in this
9State may construct electric vehicle charging infrastructure
10on private property or publicly owned property; however, the
11Commission may not authorize an electric utility under Section
128-509 of this Act to acquire property rights by eminent domain
13for the construction of any electric vehicle charging station.
14Electric utilities that serve less than 3,000,000 retail
15customers but more than 500,000 retail customers in this State
16shall be allowed to recover all reasonable and prudent costs
17associated with investment in the electric vehicle charging
18infrastructure, including, but not limited to, costs to plan
19for, construct, install, control, own, manage, or operate under
20this Section through the applicable provisions of this Article
21XVI or Article IX of this Act.
22    (b) Electric utilities that serve less than 3,000,000
23retail customers but more than 500,000 retail customers in this
24State may file with the Commission an electric vehicle charging
25infrastructure deployment and charging facility rebate plan,
26the purpose of which shall be to encourage the adoption of

 

 

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1electric vehicles in this State, including in the service
2territory of the electric utilities subject to this Section.
3The plan filed by an electric utility subject to this Section
4shall identify a system of publicly accessible electric vehicle
5charging stations and a schedule of rebates that would be
6available to: (1) retail customers taking electric service from
7the electric utility at an address in the electric utility's
8service territory; and (2) any third party that would
9construct, own, or operate a publicly accessible electric
10vehicle charging station as authorized by this Section. The
11Commission shall review the plan for compliance with the
12provisions of this Section 16-108.19 and issue an order either
13approving or modifying the plan within 180 days after the
14initial filing. If the Commission finds that the plan filed
15pursuant to this subsection (b) of this Section complies with
16the requirements of subsections (c) and (d) of this Section,
17the Commission shall approve the plan and the electric utility
18shall implement it in accordance with the Commission approval.
19If the Commission modifies the plan, the electric utility shall
20notify the Commission in writing within 90 days after service
21of the Commission's order modifying the plan as to whether the
22electric utility accepts the Commission's modifications. If
23the electric utility notifies the Commission in writing that it
24does not accept the Commission's modifications, the electric
25utility shall have no further obligations with respect to the
26plan, including any obligation to implement the plan as

 

 

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1modified and may, at its discretion, file a new plan with the
2Commission in the future. Upon approval by the Commission and
3acceptance by the electric utility of a plan filed under this
4subsection (b) of this Section, no further approvals by the
5Commission other than those approvals set forth in this Section
6shall be necessary and the electric utility shall implement the
7approved plan in accordance with the Commission's approval.
8    (c) A plan filed under subsection (b) of this Section shall
9include, at a minimum, the following categories of information
10regarding the proposed deployment of electric vehicle charging
11stations:
12        (1) Identification of existing publicly accessible
13    electric vehicle charging station infrastructure installed
14    in the electric utility's service territory.
15        (2) Sufficient detail to identify the proposed general
16    location and type of electric vehicle charging station
17    infrastructure that could be installed on private or
18    publicly owned land along proposed electric vehicle
19    charging corridors or other public spaces within the
20    electric utility's service territory, including the
21    general identification of any proposed location and type of
22    electric vehicle charging station infrastructure that the
23    electric utility proposes to be part of the third-party
24    request for proposals process set forth in paragraph (3) of
25    this subsection (c);
26        (3) A proposed request for proposals process to be

 

 

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1    managed by the electric utility, which shall request
2    proposals from third parties to compete for utility rebates
3    for the construction, ownership, and operation of the
4    electric vehicle charging stations within the electric
5    utility's service territory. The request for proposals
6    process shall address at least the following information
7    for the proposed electric vehicle charging infrastructure:
8            (A) requirements for electric vehicle charging
9        station infrastructure owners and operators regarding
10        construction, installation, operation, and maintenance
11        for each proposed general location;
12            (B) criteria by which the bids will be reviewed and
13        assessed; however, bids shall address the proposed
14        ownership and ongoing operation of the electric
15        vehicle charging station and the bids may be contingent
16        on securing State or federal funds, including any tax
17        incentives, available for electric vehicle charging
18        station development or deployment;
19            (C) provisions for how rebates will be made
20        available to electric vehicle charging station winning
21        bidders, which shall be designed to encourage
22        participation in the request for proposals process and
23        actual construction, installation, ownership, and
24        operation of the electric vehicle charging station at
25        each proposed location; and
26            (D) a proposal that provides the electric utility

 

 

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1        the option to plan for, construct, install, control,
2        own, manage, or operate any electric vehicle charging
3        infrastructure at any location identified for
4        inclusion in the request for proposals, but for which
5        no third-party bid was received or awarded under the
6        criteria identified pursuant to this paragraph (3).
7    (d) In addition to the information set forth in subsection
8(c) of this Section, a plan filed under subsection (b) of this
9Section shall also include the following categories of
10information:
11        (1) The proposed rebates offered by the electric
12    utility to customers taking service from the electric
13    utility at an address within its service territory for
14    electric vehicle charging infrastructure or facilities,
15    which should include, but not be limited to, the following
16    information:
17            (A) identification of available rebates for
18        electric utility residential customers who purchase
19        electric vehicles and install home electric vehicle
20        charging facilities subsequent to the effective date
21        of this amendatory Act of the 101st General Assembly;
22            (B) identification of available rebates for
23        multi-family residential buildings and non-residential
24        customers that, subsequent to the effective date of
25        this amendatory Act of the 101st General Assembly,
26        install and provide access to electric vehicle

 

 

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1        charging facilities located in a common area generally
2        available to residents or the public;
3            (C) identification of available rebates designed
4        to promote the use of electric vehicles serving
5        low-income or moderate-income communities, including,
6        but not limited to, any rebates available to shared
7        electric vehicles, ride share electric vehicles, and
8        public transportation fleets or school districts using
9        electric vehicles; and
10            (D) the manner and timing of the payment of the
11        proposed rebates; however, the rebates identified
12        pursuant to this paragraph (1) may be paid through a
13        monthly bill credit spread fairly and reasonably
14        across a 12-month period, and provided any customer
15        receiving a rebate must sign up for and remain on a
16        3-part delivery service rate, if available.
17        (2) An estimated budget for the electric utility to
18    develop and implement an education and engagement strategy
19    that encourages the adoption of electric vehicles in the
20    electric utility's service territory, including, but not
21    limited to, programs to be delivered to entities that
22    educate and promote the adoption of electric vehicles,
23    including, but not limited to, car dealerships and
24    elementary, middle, and high schools.
25    (e) An electric utility implementing a plan approved
26pursuant to subsection (b) of this Section, may update its plan

 

 

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1at any time by filing such update with the Commission in the
2same docket in which the Commission originally approved the
3plan. Any updated filing made pursuant to this subsection (e)
4must identify the updates to be implemented and any updates
5shall be deemed approved as reasonable 45 days after the filing
6unless the Commission initiates an investigation into the
7updated actions. Any final order regarding the investigation
8initiated pursuant to this subsection (e) must be issued within
9180 days of the initiating order.
10    (f) Notwithstanding any other provision of law to the
11contrary, electric utilities that serve less than 3,000,000
12retail customers but more than 500,000 retail customers in this
13State shall be permitted to recover all reasonable and
14prudently incurred costs incurred under this Section,
15including, but not limited to, any costs incurred to make any
16location identified pursuant to subsections (b) and (c) of this
17Section ready for installation and connection of an electric
18vehicle charging station to the distribution system; the costs
19incurred to provide the rebates identified pursuant to
20subsections (b), (c), and (d) of this Section; the costs
21incurred to undertake the education and engagement activities
22authorized under this Section; and other costs incurred by the
23utility to comply with and implement the requirements of this
24Section, including any amounts that reasonably exceed any
25estimates provided as part of the plan filed pursuant to
26subsection (b) of this Section. Electric utilities that serve

 

 

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1less than 3,000,000 retail customers but more than 500,000
2retail customers in this State are authorized to recover any
3costs identified in this subsection (f) by way of a tariff or
4tariffs approved by the Illinois Commerce Commission,
5consistent with the following provisions:
6        (1) An electric utility subject to this Section shall
7    be permitted to recover all reasonable and prudently
8    incurred costs incurred to make any location identified
9    pursuant to subsections (b) and (c) of this Section ready
10    for installation and connection of an electric vehicle
11    charging station to the distribution system through its
12    delivery service rates, as authorized by the applicable
13    provisions of Article IX or this Article XVI. For any
14    electric vehicle infrastructure identified in any plan
15    filed pursuant to subsections (b) and (c) of this Section,
16    distribution extension free allowances up to and including
17    $1,500 per kilowatt of electric vehicle charging station
18    expected peak demand shall be deemed reasonable and shall
19    not limit the use of alternate extension provisions
20    demonstrated to be more favorable and approved by the
21    Illinois Commerce Commission.
22        (2) Beginning on the effective date of this amendatory
23    Act of the 101st General Assembly Act, an electric utility
24    subject to this Section shall have authority to defer up to
25    the full amount of its costs incurred under this Section,
26    other than those costs not being recovered pursuant to

 

 

SB3977- 241 -LRB101 20818 JLS 70537 b

1    paragraph (1) of this subsection (f) of this Section, as a
2    regulatory asset, to be amortized over a 15-year period.
3    The unamortized balance shall be recognized as of December
4    31 for a given year. The utility shall also earn a return
5    on the total of the unamortized balance of the regulatory
6    asset authorized under this Section, less any deferred
7    taxes related to the unamortized balance, at an annual rate
8    equal to the utility's weighted average cost of capital
9    that includes, based on a year-end capital structure, the
10    utility's actual cost of debt for the applicable calendar
11    year and a cost of equity, which shall be calculated as the
12    sum of the following: (i) the average for the applicable
13    calendar year of the monthly average yields of 30-year U.S.
14    Treasury bonds published by the Board of Governors of the
15    Federal Reserve System in its weekly H.15 Statistical
16    Release or successor publication; and (ii) 680 basis
17    points; however, if the cost of equity as calculated under
18    this paragraph (2) is greater than the national average
19    cost of equity for the rate year by 50 basis points or
20    more, then the Illinois Commerce Commission shall include a
21    cost of equity at a rate equal to the national average cost
22    of equity as calculated under this paragraph (2) plus 50
23    basis points. For purposes of this paragraph (2), the
24    national average cost of equity for a rate year shall be
25    the simple average of the cost of equity approved in each
26    order of a state regulatory commission, other than the

 

 

SB3977- 242 -LRB101 20818 JLS 70537 b

1    Commission, issued during that rate year that is applicable
2    to retail electric service provided by an investor-owned
3    public utility company operating in the United States. No
4    order shall be excluded from the national average cost of
5    equity calculated under this paragraph (2) on the grounds
6    that it is subject to rehearing or appeal. If, for any rate
7    year, there are fewer than 15 applicable orders of state
8    regulatory commissions with which to compute the average
9    cost of equity, the Commission shall include in the
10    calculation of the national average the number of state
11    regulatory orders from the prior year or years necessary to
12    reach a total of 15, beginning with the most recently
13    issued and proceeding in reverse chronological order. At
14    such time as the Board of Governors of the Federal Reserve
15    System ceases to include the monthly average yields of
16    30-year U.S. Treasury bonds in its weekly H.15 Statistical
17    Release or successor publication, the monthly average
18    yields of the U.S. Treasury bonds then having the longest
19    duration published by the Board of Governors in its weekly
20    H.15 Statistical Release or successor publication shall
21    instead be used for purposes of this paragraph (2).
22        (3) When an electric utility subject to this Section
23    creates a regulatory asset under the provisions of this
24    Section, the costs shall be recovered over a period during
25    which customers also receive a benefit, which is in the
26    public interest. Accordingly, it is the intent of the

 

 

SB3977- 243 -LRB101 20818 JLS 70537 b

1    General Assembly that an electric utility that elects to
2    create a regulatory asset under the provisions of this
3    Section shall recover all of the associated costs,
4    including, but not limited to, its cost of capital as set
5    forth in this Section. After the Commission has approved,
6    as set forth in this Section, the prudence and
7    reasonableness of the costs that comprise the regulatory
8    asset, the electric utility shall be permitted to recover
9    all such costs, and the value and recoverability through
10    rates of the associated regulatory asset shall not be
11    limited, altered, impaired, or reduced. To enable the
12    financing of the incremental capital expenditures,
13    including regulatory assets, for electric utilities
14    subject to this Section, the utility's actual year-end
15    capital structure that includes a common equity ratio,
16    excluding goodwill, of up to and including 50% of the total
17    capital structure shall be deemed reasonable and used to
18    set rates.
19        (4) Notwithstanding paragraph (1) of this subsection
20    (f), an electric utility subject to this Section may, at
21    its election, recover some or all of the costs it incurs
22    under this Section as part of a filing for a general
23    increase in rates under Article IX of this Act, as part of
24    an annual filing to update a performance-based formula rate
25    under subsection (d) of Section 16-108.5 of this Act or
26    subsection (d) of Section 8-103B, or through an automatic

 

 

SB3977- 244 -LRB101 20818 JLS 70537 b

1    adjustment clause tariff; provided that nothing in this
2    paragraph (4) of this subsection (f) permits the double
3    recovery of such costs from customers. Such costs shall be
4    allocated across all classes of retail customers in
5    proportion to delivery service revenue revenue requirement
6    attributed to a class. If the electric utility elects to
7    recover the costs it incurs under this Section through an
8    automatic adjustment clause tariff, the utility may file
9    its proposed tariff together with the plan it files under
10    subsection (b) of this Section or at a later time. The
11    proposed tariff shall provide for an annual
12    reconciliation, less any deferred taxes related to the
13    reconciliation, with interest at an annual rate of return
14    equal to the utility's weighted average cost of capital as
15    calculated under paragraph (2) of this subsection (f),
16    including a revenue conversion factor calculated to
17    recover or refund all additional income taxes that may be
18    payable or receivable as a result of that return, of the
19    revenue requirement reflected in rates for each calendar
20    year, beginning with the calendar year in which the utility
21    files its automatic adjustment clause tariff under this
22    subsection (f), with what the revenue requirement would
23    have been had the actual cost information for the
24    applicable calendar year been available at the filing date.
25    The tariff may permit recovery of costs through a single
26    cents per kilowatt-hour charge applicable to each retail

 

 

SB3977- 245 -LRB101 20818 JLS 70537 b

1    class. The Commission shall review the proposed tariff and
2    may make changes to the tariff that are consistent with
3    this Section and with the Commission's authority under
4    Article IX of this Act, subject to notice and hearing, as
5    required. Following notice and hearing, as required, the
6    Commission shall issue an order approving, or approving
7    with modification, such tariff no later than 240 days after
8    the electric utility files its tariff.
9    (g) Any electric vehicle charging infrastructure,
10including, but not limited to, an electric vehicle charging
11station, constructed, installed, controlled, owned, managed,
12or operated by an electric utility pursuant to this Section
13shall be treated as jurisdictional distribution plant assets
14for ratemaking purposes. The investment in, and the costs to
15construct, install, control, own, manage, or operate electric
16vehicle charging infrastructure owned by the electric utility
17shall be fully recovered in delivery service rates. The
18electric utility shall charge, pursuant to a tariff on file
19with the Commission, market rates for electricity sold through
20every such electric vehicle charging station, and all revenue
21from such sales shall be credited to distribution customers in
22the applicable ratemaking process.
23    (h) In addition to the plan authorized in subsection (b),
24electric utilities that serve less than 3,000,000 retail
25customers but more than 500,000 retail customers in this State
26shall be permitted to administer programs designed to encourage

 

 

SB3977- 246 -LRB101 20818 JLS 70537 b

1or incentivize the adoption of electric vehicles by Illinois
2electric consumers, and such programs shall not be prohibited
3by the Commission as promotional practices under any rules or
4policies of the Commission, including, but not limited to, 83
5Ill. Adm. Code Part 275.
 
6    (220 ILCS 5/16-108.20 new)
7    Sec. 16-108.20. Electric energy storage.
8    (a) An electric utility may plan for, construct, install,
9control, own, manage, or operate energy storage as part of its
10distribution system when such electric utility has reasonably
11and prudently assessed and determined that such energy storage
12will preserve, maintain, or improve stability and reliability
13of the electric utility's distribution system.
14    (b) Notwithstanding any other provision of law to the
15contrary, an electric utility subject to this Section shall be
16permitted to recover all reasonable and prudently incurred
17costs incurred under this Section, including, but not limited
18to, the costs incurred to plan for, construct, control, own,
19manage, or operate the infrastructure and undertake activities
20identified in this Section in a reasonable and prudent manner
21pursuant to Article IX or this Article XVI, as applicable, and
22for purposes of cost recovery the energy storage facilities
23shall be treated as distribution assets; provided that: (1) the
24Commission shall have the authority to determine the
25reasonableness of the costs of the facilities; and (2) any

 

 

SB3977- 247 -LRB101 20818 JLS 70537 b

1monetary value of power and energy from the facilities shall be
2credited against the delivery services revenue requirement. An
3electric utility subject to this Section shall operate storage
4for the primary purpose of facilitating stable and reliable
5delivery service, and any loss incidental to the operation of
6storage facilities shall also be recoverable to the extent such
7losses were prudently incurred as a result of the operation of
8the facility.
 
9    (220 ILCS 5/16-128A)
10    Sec. 16-128A. Certification of installers, maintainers, or
11repairers.
12    (a) Within 18 months of the effective date of this
13amendatory Act of the 97th General Assembly, the Commission
14shall adopt rules, including emergency rules, establishing
15certification requirements ensuring that entities installing
16distributed generation facilities are in compliance with the
17requirements of subsection (a) of Section 16-128 of this Act.
18    For purposes of this Section, the phrase "entities
19installing distributed generation facilities" shall include,
20but not be limited to, all entities that are exempt from the
21definition of "alternative retail electric supplier" under
22item (v) of Section 16-102 of this Act. For purposes of this
23Section, the phrase "self-installer" means an individual who
24(i) leases or purchases a cogeneration facility for his or her
25own personal use and (ii) installs such cogeneration or

 

 

SB3977- 248 -LRB101 20818 JLS 70537 b

1self-generation facility on his or her own premises without the
2assistance of any other person.
3    (b) In addition to any authority granted to the Commission
4under this Act, the Commission is also authorized to: (1)
5determine which entities are subject to certification under
6this Section; (2) impose reasonable certification fees and
7penalties; (3) adopt disciplinary procedures; (4) investigate
8any and all activities subject to this Section, including
9violations thereof; (5) adopt procedures to issue or renew, or
10to refuse to issue or renew, a certification or to revoke,
11suspend, place on probation, reprimand, or otherwise
12discipline a certified entity under this Act or take other
13enforcement action against an entity subject to this Section;
14and (6) prescribe forms to be issued for the administration and
15enforcement of this Section.
16    (c) No electric utility shall provide a retail customer
17with net metering service related to interconnection of that
18customer's distributed generation facility unless the customer
19provides the electric utility with (i) a certification that the
20customer installing the distributed generation facility was a
21self-installer or (ii) evidence that the distributed
22generation facility was installed by an entity certified under
23this Section that is also in good standing with the Commission.
24For purposes of this subsection, a retail customer includes
25that customer's employees, officers, and agents. An electric
26utility shall file a tariff or tariffs with the Commission

 

 

SB3977- 249 -LRB101 20818 JLS 70537 b

1setting forth the documentation, as specified by Commission
2rule, that a retail customer must provide to an electric
3utility. The provisions of this subsection (c) shall apply on
4or after the effective date of the Commission's rules
5prescribed pursuant to subsection (a) of this Section.
6    (d) Within 180 days after the effective date of this
7amendatory Act of the 97th General Assembly, the Commission
8shall initiate a rulemaking proceeding to establish
9certification requirements that shall be applicable to persons
10or entities that install, maintain, or repair electric vehicle
11charging stations. The notification and certification
12requirements of this Section shall only be applicable to
13individuals or entities that perform work on or within an
14electric vehicle charging station, including, but not limited
15to, connection of power to an electric vehicle charging
16station.
17    For the purposes of this Section "electric vehicle charging
18station" means any facility or equipment that is used to charge
19a battery or other energy storage device of an electric
20vehicle.
21    Rules regulating the installation, maintenance, or repair
22of electric vehicle charging stations, in which the Commission
23may establish separate requirements based upon the
24characteristics of electric vehicle charging stations, so long
25as it is in accordance with the requirements of subsection (a)
26of Section 16-128 and Section 16-128A of this Act, shall:

 

 

SB3977- 250 -LRB101 20818 JLS 70537 b

1        (1) establish a certification process for persons or
2    entities that install, maintain, or repair of electric
3    vehicle charging stations;
4        (2) require persons or entities that install,
5    maintain, or repair electric vehicle stations to be
6    certified to do business and to be bonded in the State;
7        (3) ensure that persons or entities that install,
8    maintain, or repair electric vehicle charging stations
9    have the requisite knowledge, skills, training,
10    experience, and competence to perform functions in a safe
11    and reliable manner as required under subsection (a) of
12    Section 16-128 of this Act;
13        (4) impose reasonable certification fees and penalties
14    on persons or entities that install, maintain, or repair of
15    electric vehicle charging stations for noncompliance of
16    the rules adopted under this subsection;
17        (5) ensure that all persons or entities that install,
18    maintain, or repair electric vehicle charging stations
19    conform to applicable building and electrical codes;
20        (6) ensure that all electric vehicle charging stations
21    meet recognized industry standards as the Commission deems
22    appropriate, such as the National Electric Code (NEC) and
23    standards developed or created by the Institute of
24    Electrical and Electronics Engineers (IEEE), the Electric
25    Power Research Institute (EPRI), the Detroit Edison
26    Institute (DTE), the Underwriters Laboratory (UL), the

 

 

SB3977- 251 -LRB101 20818 JLS 70537 b

1    Society of Automotive Engineers (SAE), and the National
2    Institute of Standards and Technology (NIST);
3        (7) include any additional requirements that the
4    Commission deems reasonable to ensure that persons or
5    entities that install, maintain, or repair electric
6    vehicle charging stations meet adequate training,
7    financial, and competency requirements;
8        (8) ensure that the obligations required under this
9    Section and subsection (a) of Section 16-128 of this Act
10    are met prior to the interconnection of any electric
11    vehicle charging station;
12        (9) ensure electric vehicle charging stations
13    installed by a self-installer are not used for any
14    commercial purpose;
15        (10) establish an inspection procedure for the
16    conversion of electric vehicle charging stations installed
17    by a self-installer if it is determined that the
18    self-installed electric vehicle charging station is being
19    used for commercial purposes;
20        (11) establish the requirement that all persons or
21    entities that install electric vehicle charging stations
22    shall notify the servicing electric utility in writing of
23    plans to install an electric vehicle charging station and
24    shall notify the servicing electric utility in writing when
25    installation is complete;
26        (12) ensure that all persons or entities that install,

 

 

SB3977- 252 -LRB101 20818 JLS 70537 b

1    maintain, or repair electric vehicle charging stations
2    obtain certificates of insurance in sufficient amounts and
3    coverages that the Commission so determines and, if
4    necessary as determined by the Commission, names the
5    affected public utility as an additional insured; and
6        (13) identify and determine the training or other
7    programs by which persons or entities may obtain the
8    requisite training, skills, or experience necessary to
9    achieve and maintain compliance with the requirements set
10    forth in this subsection and subsection (a) of Section
11    16-128 to install, maintain, or repair electric vehicle
12    charging stations.
13    Within 18 months after the effective date of this
14amendatory Act of the 97th General Assembly, the Commission
15shall adopt rules, and may, if it deems necessary, adopt
16emergency rules, for the installation, maintenance, or repair
17of electric vehicle charging stations.
18    All retail customers who own, maintain, or repair an
19electric vehicle charging station shall provide the servicing
20electric utility (i) a certification that the customer
21installing the electric vehicle charging station was a
22self-installer or (ii) evidence that the electric vehicle
23charging station was installed by an entity certified under
24this subsection (d) that is also in good standing with the
25Commission. For purposes of this subsection (d), a retail
26customer includes that retail customer's employees, officers,

 

 

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1and agents. If the electric vehicle charging station was not
2installed by a self-installer, then the person or entity that
3plans to install the electric vehicle charging station shall
4provide notice to the servicing electric utility prior to
5installation and when installation is complete and provide any
6other information required by the Commission's rules
7established under subsection (d) of this Section. An electric
8utility shall file a tariff or tariffs with the Commission
9setting forth the documentation, as specified by Commission
10rule, that a retail customer who owns, uses, operates, or
11maintains an electric vehicle charging station must provide to
12an electric utility.
13    For the purposes of this subsection, an electric vehicle
14charging station shall constitute a distribution facility or
15equipment as that term is used in subsection (a) of Section
1616-128 of this Act. The phrase "self-installer" means an
17individual who (i) leases or purchases an electric vehicle
18charging station for his or her own personal use and (ii)
19installs an electric vehicle charging station on his or her own
20premises without the assistance of any other person.
21    (e) Fees and penalties collected under this Section shall
22be deposited into the Public Utility Fund and used to fund the
23Commission's compliance with the obligations imposed by this
24Section.
25    (f) The rules established under subsection (d) of this
26Section shall specify the initial dates for compliance with the

 

 

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1rules.
2    (g) Within 18 months of the effective date of this
3amendatory Act of the 99th General Assembly, the Commission
4shall adopt rules, including emergency rules, establishing a
5process for entities installing a new utility-scale solar
6project to certify compliance with the requirements of this
7Section. For purposes of this Section, the phrase "entities
8installing a new utility-scale solar project" shall include,
9but is not limited to, any entity installing new photovoltaic
10projects as such terms are defined in subsection (c) of Section
111-75 of the Illinois Power Agency Act.
12    The process shall include an option to complete the
13certification electronically by completing forms on-line. An
14entity installing a new utility-scale solar project shall be
15permitted to complete certification after the subject work has
16been completed. The Commission shall maintain on its website a
17list of entities installing new utility-scale solar projects
18measures that have successfully completed the certification
19process.
20    (h) In addition to any authority granted to the Commission
21under this Act, the Commission is also authorized to: (1)
22determine which entities are subject to certification under
23subsection (g) of this Section; (2) impose reasonable
24certification fees and penalties; (3) adopt disciplinary
25procedures; (4) investigate any and all activities subject to
26subsection (g) or this subsection (h) of this Section,

 

 

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1including violations thereof; (5) adopt procedures to issue or
2renew, or to refuse to issue or renew, a certification or to
3revoke, suspend, place on probation, reprimand, or otherwise
4discipline a certified entity under subsection (g) of this
5Section or take other enforcement action against an entity
6subject to subsection (g) or this subsection (h) of this
7Section; (6) prescribe forms to be issued for the
8administration and enforcement of subsection (g) and this
9subsection (h) of this Section; and (7) establish requirements
10to ensure that entities installing a new photovoltaic project
11have the requisite knowledge, skills, training, experience,
12and competence to perform in a safe and reliable manner as
13required by subsection (a) of Section 16-128 of this Act.
14    (i) The certification of persons or entities that install,
15maintain, or repair new photovoltaic projects, distributed
16generation facilities, and electric vehicle charging stations
17as set forth in this Section is an exclusive power and function
18of the State. A home rule unit or other units of local
19government authority may subject persons or entities that
20install, maintain, or repair new photovoltaic projects,
21distributed generation facilities, or electric vehicle
22charging stations as set forth in this Section to any
23applicable local licensing, siting, and permitting
24requirements otherwise permitted under law so long as only
25Commission-certified persons or entities are authorized to
26install, maintain, or repair new photovoltaic projects,

 

 

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1distributed generation facilities, or electric vehicle
2charging stations. This Section is a limitation under
3subsection (h) of Section 6 of Article VII of the Illinois
4Constitution on the exercise by home rule units of powers and
5functions exclusively exercised by the State.
6(Source: P.A. 99-906, eff. 6-1-17; 100-16, eff. 6-30-17.)
 
7    Section 97. Severability. The provisions of this Act are
8severable under Section 1.31 of the Statute on Statutes.
 
9    Section 99. Effective date. This Act takes effect upon
10becoming law.

 

 

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1 INDEX
2 Statutes amended in order of appearance
3    20 ILCS 3855/1-10
4    20 ILCS 3855/1-75
5    220 ILCS 5/8-103B
6    220 ILCS 5/8-218 new
7    220 ILCS 5/16-102
8    220 ILCS 5/16-107.6
9    220 ILCS 5/16-108.5
10    220 ILCS 5/16-108.19 new
11    220 ILCS 5/16-108.20 new
12    220 ILCS 5/16-128A