Bill Text: IL SB0311 | 2021-2022 | 102nd General Assembly | Introduced

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Bill Title: Amends the Illinois Power Agency Act. 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. Provides that a public utility that provided electric service to at least 1,000,000 retail customers in Illinois and gas service to at least 500,000 retail customers in Illinois may elect to recover its natural gas delivery services costs through a performance-based rate. Provides that, beginning in 2022, without obtaining any approvals from the 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. Amends the Prevailing Wage Act to include specified facilities financed in whole or in part with renewable energy resources in the definition of "public works". Makes other changes. Effective immediately.

Spectrum: Bipartisan Bill

Status: (Introduced - Dead) 2021-05-21 - Rule 3-9(a) / Re-referred to Assignments [SB0311 Detail]

Download: Illinois-2021-SB0311-Introduced.html

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102ND GENERAL ASSEMBLY State of Illinois 2021 and 2022 SB0311 Introduced 2/19/2021, by Sen. Christopher Belt SYNOPSIS AS INTRODUCED:
See Index
Amends the Illinois Power Agency Act. 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. Provides that a public utility that provided electric service to at least 1,000,000 retail customers in Illinois and gas service to at least 500,000 retail customers in Illinois may elect to recover its natural gas delivery services costs through a performance-based rate. Provides that, beginning in 2022, without obtaining any approvals from the 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. Amends the Prevailing Wage Act to include specified facilities financed in whole or in part with renewable energy resources in the definition of "public works". Makes other changes. Effective immediately.
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A BILL FOR
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AN ACT concerning regulation.
Be it enacted by the People of the State of Illinois,
represented in the General Assembly:
Section 1. Findings.
(a) Over the last decade, the General Assembly has
empowered the State of Illinois to become a national leader in
the implementation of a progressive energy policy. The General
Assembly has enacted laws to increase investment in equitable
energy efficiency, clean and renewable energy, and continued
modernization of the electric grid. The General Assembly has
further encouraged and enabled investment in the clean energy
economy in Illinois to ensure that the State and its citizens,
including low-income individuals, are equipped to enjoy the
opportunities and benefits of a smart grid and smart metering
infrastructure platform, adopt and deploy cost-effective
distributed energy resource technologies and devices, and
benefit from investments in job training and job creation. To
ensure this progress can be sustained, the General Assembly
finds and declares the following:
(1) The State of Illinois is a geographically large
and diverse State and communities in central and southern
Illinois have different strengths and needs than those in
the northern region of the State.
(2) The changing energy marketplace is having a

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

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

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Agency under the federal Comprehensive Environmental
Response, Compensation, and Liability Act of 1980, as
amended;
(B) the United States Environmental Protection
Agency under the Corrective Action Program of the
federal Resource Conservation and Recovery Act, as
amended;
(C) the Illinois Environmental Protection Agency
under the Illinois Site Remediation Program; or
(D) the Illinois Environmental Protection Agency
under the Illinois Solid Waste Program.
"Clean coal facility" means an electric generating
facility that uses primarily coal as a feedstock and that
captures and sequesters carbon dioxide emissions at the
following levels: at least 50% of the total carbon dioxide
emissions that the facility would otherwise emit if, at the
time construction commences, the facility is scheduled to
commence operation before 2016, at least 70% of the total
carbon dioxide emissions that the facility would otherwise
emit if, at the time construction commences, the facility is
scheduled to commence operation during 2016 or 2017, and at
least 90% of the total carbon dioxide emissions that the
facility would otherwise emit if, at the time construction
commences, the facility is scheduled to commence operation
after 2017. The power block of the clean coal facility shall
not exceed allowable emission rates for sulfur dioxide,

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

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

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

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

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either an electric utility as defined in this Section, a
municipal utility as defined in this Section that owns or
operates electric distribution facilities, or a rural
electric cooperative as defined in Section 3-119 of the
Public Utilities Act;
(3) located on the customer side of the customer's
electric meter and is primarily used to offset that
customer's electricity load; and
(4) limited in nameplate capacity to less than or
equal to 2,000 kilowatts.
"Energy efficiency" means measures that reduce the amount
of electricity or natural gas consumed in order to achieve a
given end use. "Energy efficiency" includes voltage
optimization measures that optimize the voltage at points on
the electric distribution voltage system and thereby reduce
electricity consumption by electric customers' end use
devices. "Energy efficiency" also includes measures that
reduce the total Btus of electricity, natural gas, and other
fuels needed to meet the end use or uses. For electric
utilities that serve less than 3,000,000 retail customers but
more than 500,000 retail customers in this State, energy
efficiency measures that reduce the total Btus of electricity,
natural gas, or other fuels needed to meet the end use or uses,
shall include, but are not limited to, measures that educate
about, incentivize, encourage, or otherwise support the use of
electricity to power, in whole or in part, vehicles,

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including, but not limited to, cars, trucks, buses, trains,
trolleys, boats, on-road or off-road vehicles, or other
equipment or methods of transporting goods or people, and such
measures shall include, but are not limited to, measures that
educate about, incentivize, encourage, or otherwise support
the adoption of electric vehicles by retail customers of all
customer classes.
"Electric utility" has the same definition as found in
Section 16-102 of the Public Utilities Act.
"Facility" means an electric generating unit or a
co-generating unit that produces electricity along with
related equipment necessary to connect the facility to an
electric transmission or distribution system.
"Governmental aggregator" means one or more units of local
government that individually or collectively procure
electricity to serve residential retail electrical loads
located within its or their jurisdiction.
"Local government" means a unit of local government as
defined in Section 1 of Article VII of the Illinois
Constitution.
"Municipality" means a city, village, or incorporated
town.
"Municipal utility" means a public utility owned and
operated by any subdivision or municipal corporation of this
State.
"Nameplate capacity" means the aggregate inverter

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nameplate capacity in kilowatts AC.
"Person" means any natural person, firm, partnership,
corporation, either domestic or foreign, company, association,
limited liability company, joint stock company, or association
and includes any trustee, receiver, assignee, or personal
representative thereof.
"Project" means the planning, bidding, and construction of
a facility.
"Public utility" has the same definition as found in
Section 3-105 of the Public Utilities Act.
"Real property" means any interest in land together with
all structures, fixtures, and improvements thereon, including
lands under water and riparian rights, any easements,
covenants, licenses, leases, rights-of-way, uses, and other
interests, together with any liens, judgments, mortgages, or
other claims or security interests related to real property.
"Renewable energy credit" means a tradable credit that
represents the environmental attributes of one megawatt hour
of energy produced from a renewable energy resource.
"Renewable energy resources" includes energy and its
associated renewable energy credit or renewable energy credits
from wind, solar thermal energy, photovoltaic cells and
panels, biodiesel, anaerobic digestion, crops and untreated
and unadulterated organic waste biomass, tree waste, and
hydropower that does not involve new construction or
significant expansion of hydropower dams. For purposes of this

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

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

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electricity usage.
"Substitute natural gas" or "SNG" means a gas manufactured
by gasification of hydrocarbon feedstock, which is
substantially interchangeable in use and distribution with
conventional natural gas.
"Total resource cost test" or "TRC test" means a standard
that is met if, for an investment in energy efficiency or
demand-response measures, the benefit-cost ratio is greater
than one. The benefit-cost ratio is the ratio of the net
present value of the total benefits of the program to the net
present value of the total costs as calculated over the
lifetime of the measures. A total resource cost test compares
the sum of avoided electric utility costs, representing the
benefits that accrue to the system and the participant in the
delivery of those efficiency measures and including avoided
costs associated with reduced use of natural gas or other
fuels, avoided costs associated with reduced water
consumption, and avoided costs associated with reduced
operation and maintenance costs, as well as other quantifiable
societal benefits, to the sum of all incremental costs of
end-use measures that are implemented due to the program
(including both utility and participant contributions), plus
costs to administer, deliver, and evaluate each demand-side
program, to quantify the net savings obtained by substituting
the demand-side program for supply resources. In calculating
avoided costs of power and energy that an electric utility

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would otherwise have had to acquire, reasonable estimates
shall be included of financial costs likely to be imposed by
future regulations and legislation on emissions of greenhouse
gases. In discounting future societal costs and benefits for
the purpose of calculating net present values, a societal
discount rate based on actual, long-term Treasury bond yields
should be used. Notwithstanding anything to the contrary, the
TRC test shall not include or take into account a calculation
of market price suppression effects or demand reduction
induced price effects.
"Utility-scale solar project" means an electric generating
facility that:
(1) generates electricity using photovoltaic cells;
and
(2) has a nameplate capacity that is greater than
2,000 kilowatts.
"Utility-scale wind project" means an electric generating
facility that:
(1) generates electricity using wind; and
(2) has a nameplate capacity that is greater than
2,000 kilowatts.
"Zero emission credit" means a tradable credit that
represents the environmental attributes of one megawatt hour
of energy produced from a zero emission facility.
"Zero emission facility" means a facility that: (1) is
fueled by nuclear power; and (2) is interconnected with PJM

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Interconnection, LLC or the Midcontinent Independent System
Operator, Inc., or their successors.
(Source: P.A. 98-90, eff. 7-15-13; 99-906, eff. 6-1-17.)
(20 ILCS 3855/1-75)
Sec. 1-75. Planning and Procurement Bureau. The Planning
and Procurement Bureau has the following duties and
responsibilities:
(a) The Planning and Procurement Bureau shall each year,
beginning in 2008, develop procurement plans and conduct
competitive procurement processes in accordance with the
requirements of Section 16-111.5 of the Public Utilities Act
for the eligible retail customers of electric utilities that
on December 31, 2005 provided electric service to at least
100,000 customers in Illinois. Beginning with the delivery
year commencing on June 1, 2017, the Planning and Procurement
Bureau shall develop plans and processes for the procurement
of zero emission credits from zero emission facilities in
accordance with the requirements of subsection (d-5) of this
Section. The Planning and Procurement Bureau shall also
develop procurement plans and conduct competitive procurement
processes in accordance with the requirements of Section
16-111.5 of the Public Utilities Act for the eligible retail
customers of small multi-jurisdictional electric utilities
that (i) on December 31, 2005 served less than 100,000
customers in Illinois and (ii) request a procurement plan for

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their Illinois jurisdictional load. This Section shall not
apply to a small multi-jurisdictional utility until such time
as a small multi-jurisdictional utility requests the Agency to
prepare a procurement plan for their Illinois jurisdictional
load. For the purposes of this Section, the term "eligible
retail customers" has the same definition as found in Section
16-111.5(a) of the Public Utilities Act.
Beginning with the plan or plans to be implemented in the
2017 delivery year, the Agency shall no longer include the
procurement of renewable energy resources in the annual
procurement plans required by this subsection (a), except as
provided in subsection (q) of Section 16-111.5 of the Public
Utilities Act, and shall instead develop a long-term renewable
resources procurement plan in accordance with subsection (c)
of this Section and Section 16-111.5 of the Public Utilities
Act.
(1) The Agency shall each year, beginning in 2008, as
needed, issue a request for qualifications for experts or
expert consulting firms to develop the procurement plans
in accordance with Section 16-111.5 of the Public
Utilities Act. In order to qualify an expert or expert
consulting firm must have:
(A) direct previous experience assembling
large-scale power supply plans or portfolios for
end-use customers;
(B) an advanced degree in economics, mathematics,

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

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sector, including risk management experience;
(D) expertise in wholesale electricity market
rules, including those established by the Federal
Energy Regulatory Commission and regional transmission
organizations;
(E) expertise in credit and contract protocols;
(F) adequate resources to perform and fulfill the
required functions and responsibilities; and
(G) the absence of a conflict of interest and
inappropriate bias for or against potential bidders or
the affected electric utilities.
(3) The Agency shall provide affected utilities and
other interested parties with the lists of qualified
experts or expert consulting firms identified through the
request for qualifications processes that are under
consideration to develop the procurement plans and to
serve as the procurement administrator. The Agency shall
also provide each qualified expert's or expert consulting
firm's response to the request for qualifications. All
information provided under this subparagraph shall also be
provided to the Commission. The Agency may provide by rule
for fees associated with supplying the information to
utilities and other interested parties. These parties
shall, within 5 business days, notify the Agency in
writing if they object to any experts or expert consulting
firms on the lists. Objections shall be based on:

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(A) failure to satisfy qualification criteria;
(B) identification of a conflict of interest; or
(C) evidence of inappropriate bias for or against
potential bidders or the affected utilities.
The Agency shall remove experts or expert consulting
firms from the lists within 10 days if there is a
reasonable basis for an objection and provide the updated
lists to the affected utilities and other interested
parties. If the Agency fails to remove an expert or expert
consulting firm from a list, an objecting party may seek
review by the Commission within 5 days thereafter by
filing a petition, and the Commission shall render a
ruling on the petition within 10 days. There is no right of
appeal of the Commission's ruling.
(4) The Agency shall issue requests for proposals to
the qualified experts or expert consulting firms to
develop a procurement plan for the affected utilities and
to serve as procurement administrator.
(5) The Agency shall select an expert or expert
consulting firm to develop procurement plans based on the
proposals submitted and shall award contracts of up to 5
years to those selected.
(6) The Agency shall select an expert or expert
consulting firm, with approval of the Commission, to serve
as procurement administrator based on the proposals
submitted. If the Commission rejects, within 5 days, the

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Agency's selection, the Agency shall submit another
recommendation within 3 days based on the proposals
submitted. The Agency shall award a 5-year contract to the
expert or expert consulting firm so selected with
Commission approval.
(b) The experts or expert consulting firms retained by the
Agency shall, as appropriate, prepare procurement plans, and
conduct a competitive procurement process as prescribed in
Section 16-111.5 of the Public Utilities Act, to ensure
adequate, reliable, affordable, efficient, and environmentally
sustainable electric service at the lowest total cost over
time, taking into account any benefits of price stability, for
eligible retail customers of electric utilities that on
December 31, 2005 provided electric service to at least
100,000 customers in the State of Illinois, and for eligible
Illinois retail customers of small multi-jurisdictional
electric utilities that (i) on December 31, 2005 served less
than 100,000 customers in Illinois and (ii) request a
procurement plan for their Illinois jurisdictional load.
(c) Renewable portfolio standard.
(1)(A) The Agency shall develop a long-term renewable
resources procurement plan that shall include procurement
programs and competitive procurement events necessary to
meet the goals set forth in this subsection (c). The
initial long-term renewable resources procurement plan
shall be released for comment no later than 160 days after

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June 1, 2017 (the effective date of Public Act 99-906).
The Agency shall review, and may revise on an expedited
basis, the long-term renewable resources procurement plan
at least every 2 years, which shall be conducted in
conjunction with the procurement plan under Section
16-111.5 of the Public Utilities Act to the extent
practicable to minimize administrative expense. The
long-term renewable resources procurement plans shall be
subject to review and approval by the Commission under
Section 16-111.5 of the Public Utilities Act.
(B) Subject to subparagraph (F) of this paragraph (1),
for electric utilities that serve more than 3,000,000
retail customers in this State or less than 500,000 retail
customers in this State, the long-term renewable resources
procurement plan shall include the goals for procurement
of renewable energy credits to meet at least the following
overall percentages: 13% by the 2017 delivery year;
increasing by at least 1.5% each delivery year thereafter
to at least 25% by the 2025 delivery year; and continuing
at no less than 25% for each delivery year thereafter and
for electric utilities that serve less than 3,000,000
retail customers but more than 500,000 retail customers in
this State, the long-term renewable resources procurement
plan shall include the goals for procurement of renewable
energy credits to meet at least the following overall
percentages: 13% by the 2017 delivery year; increasing by

SB0311 - 23 - LRB102 15398 SPS 20761 b
at least 1.5% each delivery year thereafter to at least
25% by the 2025 delivery year, and by at least 1.5% every
year thereafter to at least 32.5% by the 2030 delivery
year; and continuing at no less than 32.5% for each
delivery year thereafter. In the event of a conflict
between these goals and the new wind and new photovoltaic
procurement requirements described in items (i) through
(iii) of subparagraph (C) of this paragraph (1), the
long-term plan shall prioritize compliance with the new
wind and new photovoltaic procurement requirements
described in items (i) through (iii) of subparagraph (C)
of this paragraph (1) over the annual percentage targets
described in this subparagraph (B).
For the delivery year beginning June 1, 2017, the
procurement plan shall include cost-effective renewable
energy resources equal to at least 13% of each utility's
load for eligible retail customers and 13% of the
applicable portion of each utility's load for retail
customers who are not eligible retail customers, which
applicable portion shall equal 50% of the utility's load
for retail customers who are not eligible retail customers
on February 28, 2017.
For the delivery year beginning June 1, 2018, the
procurement plan shall include cost-effective renewable
energy resources equal to at least 14.5% of each utility's
load for eligible retail customers and 14.5% of the

SB0311 - 24 - LRB102 15398 SPS 20761 b
applicable portion of each utility's load for retail
customers who are not eligible retail customers, which
applicable portion shall equal 75% of the utility's load
for retail customers who are not eligible retail customers
on February 28, 2017.
For the delivery year beginning June 1, 2019, and for
each year thereafter, the procurement plans shall include
cost-effective renewable energy resources equal to a
minimum percentage of each utility's load for all retail
customers as follows: for electric utilities that serve
more than 3,000,000 retail customers in this State or less
than 500,000 retail customers in this State, 16% by June
1, 2019; increasing by 1.5% each year thereafter to 25% by
June 1, 2025; and 25% by June 1, 2026 and each year
thereafter and for electric utilities that serve less than
3,000,000 retail customers but more than 500,000 retail
customers in this State, 16% by June 1, 2019; increasing
by 1.5% each year thereafter to 32.5% by June 1, 2030; and
32.5% by June 1, 2031 and each year thereafter.
For each delivery year, the Agency shall first
recognize each utility's obligations for that delivery
year under existing contracts. Any renewable energy
credits under existing contracts, including renewable
energy credits as part of renewable energy resources,
shall be used to meet the goals set forth in this
subsection (c) for the delivery year.

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(C) Of the renewable energy credits procured under
this subsection (c), at least 75% shall come from wind and
photovoltaic projects. The long-term renewable resources
procurement plan described in subparagraph (A) of this
paragraph (1) shall include the procurement of renewable
energy credits in amounts equal to at least the following:
(i) By the end of the 2020 delivery year:
At least 2,000,000 renewable energy credits
for each delivery year shall come from new wind
projects; and
At least 2,000,000 renewable energy credits
for each delivery year shall come from new
photovoltaic projects; of that amount, to the
extent possible, the Agency shall procure: at
least 50% from solar photovoltaic projects using
the program outlined in subparagraph (K) of this
paragraph (1) from distributed renewable energy
generation devices or community renewable
generation projects; at least 40% from
utility-scale solar projects; at least 2% from
brownfield site photovoltaic projects that are not
community renewable generation projects; and the
remainder shall be determined through the
long-term planning process described in
subparagraph (A) of this paragraph (1); however,
if the long-term renewable resources procurement

SB0311 - 26 - LRB102 15398 SPS 20761 b
plan includes the procurement of more than
2,000,000 renewable energy credits from new
photovoltaic projects, then the foregoing
allocations of renewable energy credits from the
program outlined in subparagraph (K) of this
paragraph (1), utility-scale solar projects, and
brownfield site photovoltaic projects that are not
community renewable generation projects shall not
apply to the portion of the renewable energy
credits procured in excess of the 2,000,000
renewable energy credits procured on behalf of
electric utilities that serve less than 3,000,000
retail customers but more than 500,000 retail
customers in this State and the allocation of such
procurement on behalf of electric utilities that
serve less than 3,000,000 retail customers but
more than 500,000 retail customers in this State
shall instead be based on the mix that produces
the lowest cost for the renewable energy credits
procured.
(ii) By the end of the 2025 delivery year:
At least 3,000,000 renewable energy credits
for each delivery year shall come from new wind
projects; and
At least 3,000,000 renewable energy credits
for each delivery year shall come from new

SB0311 - 27 - LRB102 15398 SPS 20761 b
photovoltaic projects; of that amount, to the
extent possible, the Agency shall procure: at
least 50% from solar photovoltaic projects using
the program outlined in subparagraph (K) of this
paragraph (1) from distributed renewable energy
devices or community renewable generation
projects; at least 40% from utility-scale solar
projects; at least 2% from brownfield site
photovoltaic projects that are not community
renewable generation projects; and the remainder
shall be determined through the long-term planning
process described in subparagraph (A) of this
paragraph (1); however, if the long-term renewable
resources procurement plan includes the
procurement of more than 3,000,000 renewable
energy credits from new photovoltaic projects,
then the foregoing allocations of renewable energy
credits from the program outlined in subparagraph
(K) of this paragraph (1), utility-scale solar
projects, and brownfield site photovoltaic
projects that are not community renewable
generation projects shall not apply to the portion
of the renewable energy credits procured in excess
of the 3,000,000 renewable energy credits procured
on behalf of electric utilities that serve less
than 3,000,000 retail customers but more than

SB0311 - 28 - LRB102 15398 SPS 20761 b
500,000 retail customers in this State and the
allocation of such procurement on behalf of
electric utilities that serve less than 3,000,000
retail customers but more than 500,000 retail
customers in this State shall instead be based on
the mix that produced the lowest cost for the
renewable energy credits procured.
(iii) By the end of the 2030 delivery year:
At least 4,000,000 renewable energy credits
for each delivery year shall come from new wind
projects; and
At least 4,000,000 renewable energy credits
for each delivery year shall come from new
photovoltaic projects; of that amount, to the
extent possible, the Agency shall procure: at
least 50% from solar photovoltaic projects using
the program outlined in subparagraph (K) of this
paragraph (1) from distributed renewable energy
devices or community renewable generation
projects; at least 40% from utility-scale solar
projects; at least 2% from brownfield site
photovoltaic projects that are not community
renewable generation projects; and the remainder
shall be determined through the long-term planning
process described in subparagraph (A) of this
paragraph (1); however, if the long-term renewable

SB0311 - 29 - LRB102 15398 SPS 20761 b
resources procurement plan includes the
procurement of more than 4,000,000 renewable
energy credits from new photovoltaic projects,
then the foregoing allocations of renewable energy
credits from the program outlined in subparagraph
(K) of this paragraph (1), utility-scale solar
projects, and brownfield site photovoltaic
projects that are not community renewable
generation projects shall not apply to the portion
of the renewable energy credits procured in excess
of the 4,000,000 renewable energy credits procured
on behalf of electric utilities that serve less
than 3,000,000 retail customers but more than
500,000 retail customers in this State and the
allocation of such procurement on behalf of
electric utilities that serve less than 3,000,000
retail customers but more than 500,000 retail
customers in this State shall instead be based on
the mix that produced the lowest cost for the
renewable energy credits procured.
For purposes of this Section:
"New wind projects" means wind renewable
energy facilities that are energized after June 1,
2017 for the delivery year commencing June 1, 2017
or within 3 years after the date the Commission
approves contracts for subsequent delivery years.

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"New photovoltaic projects" means photovoltaic
renewable energy facilities that are energized
after June 1, 2017. Photovoltaic projects
developed under Section 1-56 of this Act shall not
apply towards the new photovoltaic project
requirements in this subparagraph (C).
(D) Renewable energy credits shall be cost effective.
For purposes of this subsection (c), "cost effective"
means that the costs of procuring renewable energy
resources do not cause the limit stated in subparagraph
(E) of this paragraph (1) to be exceeded and, for
renewable energy credits procured through a competitive
procurement event, do not exceed benchmarks based on
market prices for like products in the region. For
purposes of this subsection (c), "like products" means
contracts for renewable energy credits from the same or
substantially similar technology, same or substantially
similar vintage (new or existing), the same or
substantially similar quantity, and the same or
substantially similar contract length and structure.
Benchmarks shall be developed by the procurement
administrator, in consultation with the Commission staff,
Agency staff, and the procurement monitor and shall be
subject to Commission review and approval. If price
benchmarks for like products in the region are not
available, the procurement administrator shall establish

SB0311 - 31 - LRB102 15398 SPS 20761 b
price benchmarks based on publicly available data on
regional technology costs and expected current and future
regional energy prices. The benchmarks in this Section
shall not be used to curtail or otherwise reduce
contractual obligations entered into by or through the
Agency prior to June 1, 2017 (the effective date of Public
Act 99-906).
(E) For purposes of this subsection (c), the required
procurement of cost-effective renewable energy resources
for a particular year commencing prior to June 1, 2017
shall be measured as a percentage of the actual amount of
electricity (megawatt-hours) supplied by the electric
utility to eligible retail customers in the delivery year
ending immediately prior to the procurement, and, for
delivery years commencing on and after June 1, 2017, the
required procurement of cost-effective renewable energy
resources for a particular year shall be measured as a
percentage of the actual amount of electricity
(megawatt-hours) delivered by the electric utility in the
delivery year ending immediately prior to the procurement,
to all retail customers in its service territory. For
purposes of this subsection (c), the amount paid per
kilowatthour means the total amount paid for electric
service expressed on a per kilowatthour basis. For
purposes of this subsection (c), the total amount paid for
electric service includes without limitation amounts paid

SB0311 - 32 - LRB102 15398 SPS 20761 b
for supply, transmission, distribution, surcharges, and
add-on taxes.
Notwithstanding the requirements of this subsection
(c), the total of renewable energy resources procured
under the procurement plan for any single year shall be
subject to the limitations of this subparagraph (E). Such
procurement shall be reduced for all retail customers
based on the amount necessary to limit the annual
estimated average net increase due to the costs of these
resources included in the amounts paid by eligible retail
customers in connection with electric service to no more
than the greater of 2.015% of the amount paid per
kilowatthour by those customers during the year ending May
31, 2007 or the incremental amount per kilowatthour paid
for these resources in 2011; however, procurements that
occur for procurement periods that begin on or after June
1, 2026 shall be reduced for all retail customers of
electric utilities that serve less than 3,000,000 retail
customers but more than 500,000 retail customers in this
State only by an amount necessary to limit the annual
estimated average net increase due to the costs of these
resources included in the amounts paid by eligible retail
customers in connection with electric service to no more
than the greater of 2.515% of the amount paid per
kilowatthour by those customers during the year ending May
31, 2007 or the incremental amount per kilowatthour paid

SB0311 - 33 - LRB102 15398 SPS 20761 b
for these resources in 2011. To arrive at a maximum dollar
amount of renewable energy resources to be procured for
the particular delivery year, the resulting per
kilowatthour amount shall be applied to the actual amount
of kilowatthours of electricity delivered, or applicable
portion of such amount as specified in paragraph (1) of
this subsection (c), as applicable, by the electric
utility in the delivery year immediately prior to the
procurement to all retail customers in its service
territory. The calculations required by this subparagraph
(E) shall be made only once for each delivery year at the
time that the renewable energy resources are procured.
Once the determination as to the amount of renewable
energy resources to procure is made based on the
calculations set forth in this subparagraph (E) and the
contracts procuring those amounts are executed, no
subsequent rate impact determinations shall be made and no
adjustments to those contract amounts shall be allowed.
All costs incurred under such contracts shall be fully
recoverable by the electric utility as provided in this
Section.
(F) If the limitation on the amount of renewable
energy resources procured in subparagraph (E) of this
paragraph (1) prevents the Agency from meeting all of the
goals in this subsection (c), the Agency's long-term plan
shall prioritize compliance with the requirements of this

SB0311 - 34 - LRB102 15398 SPS 20761 b
subsection (c) regarding renewable energy credits in the
following order:
(i) renewable energy credits under existing
contractual obligations;
(i-5) funding for the Illinois Solar for All
Program, as described in subparagraph (O) of this
paragraph (1);
(ii) renewable energy credits necessary to comply
with the new wind and new photovoltaic procurement
requirements described in items (i) through (iii) of
subparagraph (C) of this paragraph (1); and
(iii) renewable energy credits necessary to meet
the remaining requirements of this subsection (c).
(G) The following provisions shall apply to the
Agency's procurement of renewable energy credits under
this subsection (c):
(i) Notwithstanding whether a long-term renewable
resources procurement plan has been approved, the
Agency shall conduct an initial forward procurement
for renewable energy credits from new utility-scale
wind projects within 160 days after June 1, 2017 (the
effective date of Public Act 99-906). For the purposes
of this initial forward procurement, the Agency shall
solicit 15-year contracts for delivery of 1,000,000
renewable energy credits delivered annually from new
utility-scale wind projects to begin delivery on June

SB0311 - 35 - LRB102 15398 SPS 20761 b
1, 2019, if available, but not later than June 1, 2021,
unless the project has delays in the establishment of
an operating interconnection with the applicable
transmission or distribution system as a result of the
actions or inactions of the transmission or
distribution provider, or other causes for force
majeure as outlined in the procurement contract, in
which case, not later than June 1, 2022. Payments to
suppliers of renewable energy credits shall commence
upon delivery. Renewable energy credits procured under
this initial procurement shall be included in the
Agency's long-term plan and shall apply to all
renewable energy goals in this subsection (c).
(ii) Notwithstanding whether a long-term renewable
resources procurement plan has been approved, the
Agency shall conduct an initial forward procurement
for renewable energy credits from new utility-scale
solar projects and brownfield site photovoltaic
projects within one year after June 1, 2017 (the
effective date of Public Act 99-906). For the purposes
of this initial forward procurement, the Agency shall
solicit 15-year contracts for delivery of 1,000,000
renewable energy credits delivered annually from new
utility-scale solar projects and brownfield site
photovoltaic projects to begin delivery on June 1,
2019, if available, but not later than June 1, 2021,

SB0311 - 36 - LRB102 15398 SPS 20761 b
unless the project has delays in the establishment of
an operating interconnection with the applicable
transmission or distribution system as a result of the
actions or inactions of the transmission or
distribution provider, or other causes for force
majeure as outlined in the procurement contract, in
which case, not later than June 1, 2022. The Agency may
structure this initial procurement in one or more
discrete procurement events. Payments to suppliers of
renewable energy credits shall commence upon delivery.
Renewable energy credits procured under this initial
procurement shall be included in the Agency's
long-term plan and shall apply to all renewable energy
goals in this subsection (c).
(iii) Subsequent forward procurements for
utility-scale wind projects shall solicit at least
1,000,000 renewable energy credits delivered annually
per procurement event and shall be planned, scheduled,
and designed such that the cumulative amount of
renewable energy credits delivered from all new wind
projects in each delivery year shall not exceed the
Agency's projection of the cumulative amount of
renewable energy credits that will be delivered from
all new photovoltaic projects, including utility-scale
and distributed photovoltaic devices, in the same
delivery year at the time scheduled for wind contract

SB0311 - 37 - LRB102 15398 SPS 20761 b
delivery.
(iv) If, at any time after the time set for
delivery of renewable energy credits pursuant to the
initial procurements in items (i) and (ii) of this
subparagraph (G), the cumulative amount of renewable
energy credits projected to be delivered from all new
wind projects in a given delivery year exceeds the
cumulative amount of renewable energy credits
projected to be delivered from all new photovoltaic
projects in that delivery year by 200,000 or more
renewable energy credits, then the Agency shall within
60 days adjust the procurement programs in the
long-term renewable resources procurement plan to
ensure that the projected cumulative amount of
renewable energy credits to be delivered from all new
wind projects does not exceed the projected cumulative
amount of renewable energy credits to be delivered
from all new photovoltaic projects by 200,000 or more
renewable energy credits, provided that nothing in
this Section shall preclude the projected cumulative
amount of renewable energy credits to be delivered
from all new photovoltaic projects from exceeding the
projected cumulative amount of renewable energy
credits to be delivered from all new wind projects in
each delivery year and provided further that nothing
in this item (iv) shall require the curtailment of an

SB0311 - 38 - LRB102 15398 SPS 20761 b
executed contract. The Agency shall update, on a
quarterly basis, its projection of the renewable
energy credits to be delivered from all projects in
each delivery year. Notwithstanding anything to the
contrary, the Agency may adjust the timing of
procurement events conducted under this subparagraph
(G). The long-term renewable resources procurement
plan shall set forth the process by which the
adjustments may be made.
(v) All procurements under this subparagraph (G)
shall comply with the geographic requirements in
subparagraph (I) of this paragraph (1) and shall
follow the procurement processes and procedures
described in this Section and Section 16-111.5 of the
Public Utilities Act to the extent practicable, and
these processes and procedures may be expedited to
accommodate the schedule established by this
subparagraph (G).
(H) The procurement of renewable energy resources for
a given delivery year shall be reduced as described in
this subparagraph (H) if an alternative retail electric
supplier meets the requirements described in this
subparagraph (H).
(i) Within 45 days after June 1, 2017 (the
effective date of Public Act 99-906), an alternative
retail electric supplier or its successor shall submit

SB0311 - 39 - LRB102 15398 SPS 20761 b
an informational filing to the Illinois Commerce
Commission certifying that, as of December 31, 2015,
the alternative retail electric supplier owned one or
more electric generating facilities that generates
renewable energy resources as defined in Section 1-10
of this Act, provided that such facilities are not
powered by wind or photovoltaics, and the facilities
generate one renewable energy credit for each
megawatthour of energy produced from the facility.
The informational filing shall identify each
facility that was eligible to satisfy the alternative
retail electric supplier's obligations under Section
16-115D of the Public Utilities Act as described in
this item (i).
(ii) For a given delivery year, the alternative
retail electric supplier may elect to supply its
retail customers with renewable energy credits from
the facility or facilities described in item (i) of
this subparagraph (H) that continue to be owned by the
alternative retail electric supplier.
(iii) The alternative retail electric supplier
shall notify the Agency and the applicable utility, no
later than February 28 of the year preceding the
applicable delivery year or 15 days after June 1, 2017
(the effective date of Public Act 99-906), whichever
is later, of its election under item (ii) of this

SB0311 - 40 - LRB102 15398 SPS 20761 b
subparagraph (H) to supply renewable energy credits to
retail customers of the utility. Such election shall
identify the amount of renewable energy credits to be
supplied by the alternative retail electric supplier
to the utility's retail customers and the source of
the renewable energy credits identified in the
informational filing as described in item (i) of this
subparagraph (H), subject to the following
limitations:
For the delivery year beginning June 1, 2018,
the maximum amount of renewable energy credits to
be supplied by an alternative retail electric
supplier under this subparagraph (H) shall be 68%
multiplied by 25% multiplied by 14.5% multiplied
by the amount of metered electricity
(megawatt-hours) delivered by the alternative
retail electric supplier to Illinois retail
customers during the delivery year ending May 31,
2016.
For delivery years beginning June 1, 2019 and
each year thereafter, the maximum amount of
renewable energy credits to be supplied by an
alternative retail electric supplier under this
subparagraph (H) shall be 68% multiplied by 50%
multiplied by 16% multiplied by the amount of
metered electricity (megawatt-hours) delivered by

SB0311 - 41 - LRB102 15398 SPS 20761 b
the alternative retail electric supplier to
Illinois retail customers during the delivery year
ending May 31, 2016, provided that the 16% value
shall increase by 1.5% each delivery year
thereafter to 25% by the delivery year beginning
June 1, 2025, and thereafter the 25% value shall
apply to each delivery year.
For each delivery year, the total amount of
renewable energy credits supplied by all alternative
retail electric suppliers under this subparagraph (H)
shall not exceed 9% of the Illinois target renewable
energy credit quantity. The Illinois target renewable
energy credit quantity for the delivery year beginning
June 1, 2018 is 14.5% multiplied by the total amount of
metered electricity (megawatt-hours) delivered in the
delivery year immediately preceding that delivery
year, provided that the 14.5% shall increase by 1.5%
each delivery year thereafter to 25% by the delivery
year beginning June 1, 2025, and thereafter the 25%
value shall apply to each delivery year.
If the requirements set forth in items (i) through
(iii) of this subparagraph (H) are met, the charges
that would otherwise be applicable to the retail
customers of the alternative retail electric supplier
under paragraph (6) of this subsection (c) for the
applicable delivery year shall be reduced by the ratio

SB0311 - 42 - LRB102 15398 SPS 20761 b
of the quantity of renewable energy credits supplied
by the alternative retail electric supplier compared
to that supplier's target renewable energy credit
quantity. The supplier's target renewable energy
credit quantity for the delivery year beginning June
1, 2018 is 14.5% multiplied by the total amount of
metered electricity (megawatt-hours) delivered by the
alternative retail supplier in that delivery year,
provided that the 14.5% shall increase by 1.5% each
delivery year thereafter to 25% by the delivery year
beginning June 1, 2025, and thereafter the 25% value
shall apply to each delivery year.
On or before April 1 of each year, the Agency shall
annually publish a report on its website that
identifies the aggregate amount of renewable energy
credits supplied by alternative retail electric
suppliers under this subparagraph (H).
(I) The Agency shall design its long-term renewable
energy procurement plan to maximize the State's interest
in the health, safety, and welfare of its residents,
including but not limited to minimizing sulfur dioxide,
nitrogen oxide, particulate matter and other pollution
that adversely affects public health in this State,
increasing fuel and resource diversity in this State,
enhancing the reliability and resiliency of the
electricity distribution system in this State, meeting

SB0311 - 43 - LRB102 15398 SPS 20761 b
goals to limit carbon dioxide emissions under federal or
State law, and contributing to a cleaner and healthier
environment for the citizens of this State, while
balancing these goals with the requirement to minimize the
cost to customers attributable to the procurement of
renewable energy credits set forth in subparagraph (C) of
paragraph (1) of this subsection (c). In order to further
these legislative purposes, renewable energy credits shall
be eligible to be counted toward the renewable energy
requirements of this subsection (c) if they are generated
from facilities located in this State. The Agency may
qualify renewable energy credits from facilities located
in states adjacent to Illinois if the generator
demonstrates and the Agency determines that the operation
of such facility or facilities will help promote the
State's interest in the health, safety, and welfare of its
residents based on the public interest criteria described
above. To ensure that the public interest criteria are
applied to the procurement and given full effect, the
Agency's long-term procurement plan shall describe in
detail how each public interest factor shall be considered
and weighted for facilities located in states adjacent to
Illinois.
(J) In order to promote the competitive development of
renewable energy resources in furtherance of the State's
interest in the health, safety, and welfare of its

SB0311 - 44 - LRB102 15398 SPS 20761 b
residents, renewable energy credits shall not be eligible
to be counted toward the renewable energy requirements of
this subsection (c) if they are sourced from a generating
unit whose costs were being recovered through rates
regulated by this State or any other state or states on or
after January 1, 2017. Each contract executed to purchase
renewable energy credits under this subsection (c) shall
provide for the contract's termination if the costs of the
generating unit supplying the renewable energy credits
subsequently begin to be recovered through rates regulated
by this State or any other state or states; and each
contract shall further provide that, in that event, the
supplier of the credits must return 110% of all payments
received under the contract. Amounts returned under the
requirements of this subparagraph (J) shall be retained by
the utility and all of these amounts shall be used for the
procurement of additional renewable energy credits from
new wind or new photovoltaic resources as defined in this
subsection (c). The long-term plan shall provide that
these renewable energy credits shall be procured in the
next procurement event.
Notwithstanding the limitations of this subparagraph
(J), renewable energy credits sourced from generating
units that are constructed, purchased, owned, or leased by
an electric utility as part of an approved project,
program, or pilot under Section 1-56 of this Act shall be

SB0311 - 45 - LRB102 15398 SPS 20761 b
eligible to be counted toward the renewable energy
requirements of this subsection (c), regardless of how the
costs of these units are recovered.
(K) The long-term renewable resources procurement plan
developed by the Agency in accordance with subparagraph
(A) of this paragraph (1) shall include an Adjustable
Block program for the procurement of renewable energy
credits from new photovoltaic projects that are
distributed renewable energy generation devices or new
photovoltaic community renewable generation projects on
behalf of electric utilities that serve more than
3,000,000 retail customers or less than 500,000 retail
customers in this State and a competitive procurement
process for the procurement of new photovoltaic community
renewable generation projects on behalf of electric
utilities that serve less than 3,000,000 retail customers
but more than 500,000 retail customers in this State. The
Adjustable Block program shall be designed to provide a
transparent schedule of prices and quantities to enable
the photovoltaic market to scale up and for renewable
energy credit prices to adjust at a predictable rate over
time. The prices set by the Adjustable Block program can
be reflected as a set value or as the product of a formula.
The Adjustable Block program shall include for each
category of eligible projects: a schedule of standard
block purchase prices to be offered; a series of steps,

SB0311 - 46 - LRB102 15398 SPS 20761 b
with associated nameplate capacity and purchase prices
that adjust from step to step; and automatic opening of
the next step as soon as the nameplate capacity and
available purchase prices for an open step are fully
committed or reserved. Only projects energized on or after
June 1, 2017 shall be eligible for the Adjustable Block
program. For each block group the Agency shall determine
the number of blocks, the amount of generation capacity in
each block, and the purchase price for each block,
provided that the purchase price provided and the total
amount of generation in all blocks for all block groups
shall be sufficient to meet the goals in this subsection
(c). The Agency may periodically review its prior
decisions establishing the number of blocks, the amount of
generation capacity in each block, and the purchase price
for each block, and may propose, on an expedited basis,
changes to these previously set values, including but not
limited to redistributing these amounts and the available
funds as necessary and appropriate, subject to Commission
approval as part of the periodic plan revision process
described in Section 16-111.5 of the Public Utilities Act.
The Agency may define different block sizes, purchase
prices, or other distinct terms and conditions for
projects located in different utility service territories
if the Agency deems it necessary to meet the goals in this
subsection (c); however, if, for any block to be procured

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on behalf of electric utilities that serve less than
3,000,000 retail customers but more than 500,000 retail
customers in this State, the quantity of renewable energy
credits sought by eligible projects exceeds the quantity
of renewable energy credits defined by the Agency for the
block, the Agency shall lower the price applicable to the
block and require eligible projects to affirm the
commitment to the quantity of renewable energy credits
sought. The Agency shall employ a stepped process of
lowering the price applicable to the block so as to
identify a price at which the quantity of renewable energy
credits sought by eligible projects balances with the
renewable energy credits sought by the Agency for the
block.
The competitive procurement process used for the
procurement of new photovoltaic community renewable
generation projects on behalf of electric utilities that
serve less than 3,000,000 retail customers but more than
500,000 retail customers in this State shall define the
quantity of renewable energy credits to be procured and
allow bidders to submit price offers to the Agency. The
Agency shall conduct the competitive procurement process
in a manner that results in the lowest cost for the
renewable energy credits procured.
The Adjustable Block program and competitive
procurement process shall include at least the following

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block groups in at least the following amounts, which may
be adjusted upon review by the Agency and approval by the
Commission as described in this subparagraph (K):
(i) At least 25% from distributed renewable energy
generation devices with a nameplate capacity of no
more than 10 kilowatts.
(ii) At least 25% from distributed renewable
energy generation devices with a nameplate capacity of
more than 10 kilowatts and no more than 2,000
kilowatts. The Agency may create sub-categories within
this category to account for the differences between
projects for small commercial customers, large
commercial customers, and public or non-profit
customers.
(iii) At least 25% from photovoltaic community
renewable generation projects.
(iv) The remaining 25% shall be allocated as
specified by the Agency in the long-term renewable
resources procurement plan.
The Adjustable Block program shall be designed to
ensure that renewable energy credits are procured from
photovoltaic distributed renewable energy generation
devices and new photovoltaic community renewable energy
generation projects in diverse locations and are not
concentrated in a few geographic areas.
(L) The procurement of photovoltaic renewable energy

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credits under items (i) through (iv) of subparagraph (K)
of this paragraph (1) shall be subject to the following
contract and payment terms:
(i) The Agency shall procure contracts of at least
15 years in length.
(ii) For those renewable energy credits that
qualify and are procured under item (i) of
subparagraph (K) of this paragraph (1), the renewable
energy credit purchase price shall be paid in full by
the contracting utilities at the time that the
facility producing the renewable energy credits is
interconnected at the distribution system level of the
utility and energized. The electric utility shall
receive and retire all renewable energy credits
generated by the project for the first 15 years of
operation.
(iii) For those renewable energy credits that
qualify and are procured under item (ii) and (iii) of
subparagraph (K) of this paragraph (1) and any
additional categories of distributed generation
included in the long-term renewable resources
procurement plan and approved by the Commission, 20
percent of the renewable energy credit purchase price
shall be paid by the contracting utilities at the time
that the facility producing the renewable energy
credits is interconnected at the distribution system

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level of the utility and energized. The remaining
portion shall be paid ratably over the subsequent
4-year period. The electric utility shall receive and
retire all renewable energy credits generated by the
project for the first 15 years of operation.
(iv) Each contract shall include provisions to
ensure the delivery of the renewable energy credits
for the full term of the contract.
(v) The utility shall be the counterparty to the
contracts executed under this subparagraph (L) that
are approved by the Commission under the process
described in Section 16-111.5 of the Public Utilities
Act. No contract shall be executed for an amount that
is less than one renewable energy credit per year.
(vi) If, at any time, approved applications for
the Adjustable Block program exceed funds collected by
the electric utility or would cause the Agency to
exceed the limitation described in subparagraph (E) of
this paragraph (1) on the amount of renewable energy
resources that may be procured, then the Agency shall
consider future uncommitted funds to be reserved for
these contracts on a first-come, first-served basis,
with the delivery of renewable energy credits required
beginning at the time that the reserved funds become
available.
(vii) Nothing in this Section shall require the

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utility to advance any payment or pay any amounts that
exceed the actual amount of revenues collected by the
utility under paragraph (6) of this subsection (c) and
subsection (k) of Section 16-108 of the Public
Utilities Act, and contracts executed under this
Section shall expressly incorporate this limitation.
(M) The Agency shall be authorized to retain one or
more experts or expert consulting firms to develop,
administer, implement, operate, and evaluate the
Adjustable Block program described in subparagraph (K) of
this paragraph (1), and the Agency shall retain the
consultant or consultants in the same manner, to the
extent practicable, as the Agency retains others to
administer provisions of this Act, including, but not
limited to, the procurement administrator. The selection
of experts and expert consulting firms and the procurement
process described in this subparagraph (M) are exempt from
the requirements of Section 20-10 of the Illinois
Procurement Code, under Section 20-10 of that Code. The
Agency shall strive to minimize administrative expenses in
the implementation of the Adjustable Block program.
The Agency and its consultant or consultants shall
monitor block activity, share program activity with
stakeholders and conduct regularly scheduled meetings to
discuss program activity and market conditions. If
necessary, the Agency may make prospective administrative

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adjustments to the Adjustable Block program design, such
as redistributing available funds or making adjustments to
purchase prices as necessary to achieve the goals of this
subsection (c). Program modifications to any price,
capacity block, or other program element that do not
deviate from the Commission's approved value by more than
25% shall take effect immediately and are not subject to
Commission review and approval. Program modifications to
any price, capacity block, or other program element that
deviate more than 25% from the Commission's approved value
must be approved by the Commission as a long-term plan
amendment under Section 16-111.5 of the Public Utilities
Act. The Agency shall consider stakeholder feedback when
making adjustments to the Adjustable Block design and
shall notify stakeholders in advance of any planned
changes.
(N) The long-term renewable resources procurement plan
required by this subsection (c) shall include a community
renewable generation program. The Agency shall establish
the terms, conditions, and program requirements for
community renewable generation projects with a goal to
expand renewable energy generating facility access to a
broader group of energy consumers, to ensure robust
participation opportunities for residential and small
commercial customers and those who cannot install
renewable energy on their own properties. Any plan

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approved by the Commission shall allow subscriptions to
community renewable generation projects to be portable and
transferable. For purposes of this subparagraph (N),
"portable" means that subscriptions may be retained by the
subscriber even if the subscriber relocates or changes its
address within the same utility service territory; and
"transferable" means that a subscriber may assign or sell
subscriptions to another person within the same utility
service territory.
Electric utilities shall provide a monetary credit to
a subscriber's subsequent bill for service for the
proportional output of a community renewable generation
project attributable to that subscriber as specified in
Section 16-107.5 of the Public Utilities Act.
The Agency shall purchase renewable energy credits
from subscribed shares of photovoltaic community renewable
generation projects through the Adjustable Block program
and the competitive procurement process described in
subparagraph (K) of this paragraph (1) or through the
Illinois Solar for All Program described in Section 1-56
of this Act. The electric utility shall purchase any
unsubscribed energy from community renewable generation
projects that are Qualifying Facilities ("QF") under the
electric utility's tariff for purchasing the output from
QFs under Public Utilities Regulatory Policies Act of
1978.

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The owners of and any subscribers to a community
renewable generation project shall not be considered
public utilities or alternative retail electricity
suppliers under the Public Utilities Act solely as a
result of their interest in or subscription to a community
renewable generation project and shall not be required to
become an alternative retail electric supplier by
participating in a community renewable generation project
with a public utility.
(O) For the delivery year beginning June 1, 2018, the
long-term renewable resources procurement plan required by
this subsection (c) shall provide for the Agency to
procure contracts to continue offering the Illinois Solar
for All Program described in subsection (b) of Section
1-56 of this Act, and the contracts approved by the
Commission shall be executed by the utilities that are
subject to this subsection (c). The long-term renewable
resources procurement plan shall allocate 5% of the funds
available under the plan for the applicable delivery year,
or $10,000,000 per delivery year, whichever is greater, to
fund the programs, and the plan shall determine the amount
of funding to be apportioned to the programs identified in
subsection (b) of Section 1-56 of this Act; provided that
for the delivery years beginning June 1, 2017, June 1,
2021, and June 1, 2025, the long-term renewable resources
procurement plan shall allocate 10% of the funds available

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under the plan for the applicable delivery year, or
$20,000,000 per delivery year, whichever is greater, and
$10,000,000 of such funds in such year shall be used by an
electric utility that serves more than 3,000,000 retail
customers in the State to implement a Commission-approved
plan under Section 16-108.12 of the Public Utilities Act.
In making the determinations required under this
subparagraph (O), the Commission shall consider the
experience and performance under the programs and any
evaluation reports. The Commission shall also provide for
an independent evaluation of those programs on a periodic
basis that are funded under this subparagraph (O).
(2) (Blank).
(3) (Blank).
(4) The electric utility shall retire all renewable
energy credits used to comply with the standard.
(5) Beginning with the 2010 delivery year and ending
June 1, 2017, an electric utility subject to this
subsection (c) shall apply the lesser of the maximum
alternative compliance payment rate or the most recent
estimated alternative compliance payment rate for its
service territory for the corresponding compliance period,
established pursuant to subsection (d) of Section 16-115D
of the Public Utilities Act to its retail customers that
take service pursuant to the electric utility's hourly
pricing tariff or tariffs. The electric utility shall

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retain all amounts collected as a result of the
application of the alternative compliance payment rate or
rates to such customers, and, beginning in 2011, the
utility shall include in the information provided under
item (1) of subsection (d) of Section 16-111.5 of the
Public Utilities Act the amounts collected under the
alternative compliance payment rate or rates for the prior
year ending May 31. Notwithstanding any limitation on the
procurement of renewable energy resources imposed by item
(2) of this subsection (c), the Agency shall increase its
spending on the purchase of renewable energy resources to
be procured by the electric utility for the next plan year
by an amount equal to the amounts collected by the utility
under the alternative compliance payment rate or rates in
the prior year ending May 31.
(6) The electric utility shall be entitled to recover
all of its costs associated with the procurement of
renewable energy credits under plans approved under this
Section and Section 16-111.5 of the Public Utilities Act.
These costs shall include associated reasonable expenses
for implementing the procurement programs, including, but
not limited to, the costs of administering and evaluating
the Adjustable Block program, through an automatic
adjustment clause tariff in accordance with subsection (k)
of Section 16-108 of the Public Utilities Act.
(7) Renewable energy credits procured from new

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photovoltaic projects or new distributed renewable energy
generation devices under this Section after June 1, 2017
(the effective date of Public Act 99-906) must be procured
from devices installed by a qualified person in compliance
with the requirements of Section 16-128A of the Public
Utilities Act and any rules or regulations adopted
thereunder.
In meeting the renewable energy requirements of this
subsection (c), to the extent feasible and consistent with
State and federal law, the renewable energy credit
procurements, Adjustable Block solar program, and
community renewable generation program shall provide
employment opportunities for all segments of the
population and workforce, including minority-owned and
woman-owned female-owned business enterprises, and shall
not, consistent with State and federal law, discriminate
based on race or socioeconomic status.
As part of any renewable resources procurement plan
required by this subsection (c), the Agency will compile
and publish a list of any seller of renewable energy
resources procured by the Agency that is not, as of
January 1 of the calendar year in which the procurement
plan will be filed for approval with the Commission, in
compliance with the reporting obligations of Section 5-117
of the Public Utilities Act, and the Agency shall not
procure any renewable energy resources from any entity not

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in compliance with the reporting obligations of Section
5-117 of the Public Utilities Act in the procurement plan.
Any entity that submits a bid to provide renewable
energy resources in any procurement event conducted
pursuant to this Section occurring after the effective
date of this amendatory Act of the 102nd General Assembly
shall certify that not less than the prevailing wage, as
determined pursuant to the Prevailing Wage Act, was or
will be paid to employees who are engaged in construction
activities associated with the renewable energy resources,
and the Agency shall not procure any renewable resources
from any entity not providing such a certification. Every
contract for the procurement of renewable energy resources
pursuant to this Section shall provide that failure to
comply with the terms of such certification shall
constitute an event of default, subject to termination of
the contract.
(d) Clean coal portfolio standard.
(1) The procurement plans shall include electricity
generated using clean coal. Each utility shall enter into
one or more sourcing agreements with the initial clean
coal facility, as provided in paragraph (3) of this
subsection (d), covering electricity generated by the
initial clean coal facility representing at least 5% of
each utility's total supply to serve the load of eligible
retail customers in 2015 and each year thereafter, as

SB0311 - 59 - LRB102 15398 SPS 20761 b
described in paragraph (3) of this subsection (d), subject
to the limits specified in paragraph (2) of this
subsection (d). It is the goal of the State that by January
1, 2025, 25% of the electricity used in the State shall be
generated by cost-effective clean coal facilities. For
purposes of this subsection (d), "cost-effective" means
that the expenditures pursuant to such sourcing agreements
do not cause the limit stated in paragraph (2) of this
subsection (d) to be exceeded and do not exceed cost-based
benchmarks, which shall be developed to assess all
expenditures pursuant to such sourcing agreements covering
electricity generated by clean coal facilities, other than
the initial clean coal facility, by the procurement
administrator, in consultation with the Commission staff,
Agency staff, and the procurement monitor and shall be
subject to Commission review and approval.
A utility party to a sourcing agreement shall
immediately retire any emission credits that it receives
in connection with the electricity covered by such
agreement.
Utilities shall maintain adequate records documenting
the purchases under the sourcing agreement to comply with
this subsection (d) and shall file an accounting with the
load forecast that must be filed with the Agency by July 15
of each year, in accordance with subsection (d) of Section
16-111.5 of the Public Utilities Act.

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A utility shall be deemed to have complied with the
clean coal portfolio standard specified in this subsection
(d) if the utility enters into a sourcing agreement as
required by this subsection (d).
(2) For purposes of this subsection (d), the required
execution of sourcing agreements with the initial clean
coal facility for a particular year shall be measured as a
percentage of the actual amount of electricity
(megawatt-hours) supplied by the electric utility to
eligible retail customers in the planning year ending
immediately prior to the agreement's execution. For
purposes of this subsection (d), the amount paid per
kilowatthour means the total amount paid for electric
service expressed on a per kilowatthour basis. For
purposes of this subsection (d), the total amount paid for
electric service includes without limitation amounts paid
for supply, transmission, distribution, surcharges and
add-on taxes.
Notwithstanding the requirements of this subsection
(d), the total amount paid under sourcing agreements with
clean coal facilities pursuant to the procurement plan for
any given year shall be reduced by an amount necessary to
limit the annual estimated average net increase due to the
costs of these resources included in the amounts paid by
eligible retail customers in connection with electric
service to:

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(A) in 2010, no more than 0.5% of the amount paid
per kilowatthour by those customers during the year
ending May 31, 2009;
(B) in 2011, the greater of an additional 0.5% of
the amount paid per kilowatthour by those customers
during the year ending May 31, 2010 or 1% of the amount
paid per kilowatthour by those customers during the
year ending May 31, 2009;
(C) in 2012, the greater of an additional 0.5% of
the amount paid per kilowatthour by those customers
during the year ending May 31, 2011 or 1.5% of the
amount paid per kilowatthour by those customers during
the year ending May 31, 2009;
(D) in 2013, the greater of an additional 0.5% of
the amount paid per kilowatthour by those customers
during the year ending May 31, 2012 or 2% of the amount
paid per kilowatthour by those customers during the
year ending May 31, 2009; and
(E) thereafter, the total amount paid under
sourcing agreements with clean coal facilities
pursuant to the procurement plan for any single year
shall be reduced by an amount necessary to limit the
estimated average net increase due to the cost of
these resources included in the amounts paid by
eligible retail customers in connection with electric
service to no more than the greater of (i) 2.015% of

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the amount paid per kilowatthour by those customers
during the year ending May 31, 2009 or (ii) the
incremental amount per kilowatthour paid for these
resources in 2013. These requirements may be altered
only as provided by statute.
No later than June 30, 2015, the Commission shall
review the limitation on the total amount paid under
sourcing agreements, if any, with clean coal facilities
pursuant to this subsection (d) and report to the General
Assembly its findings as to whether that limitation unduly
constrains the amount of electricity generated by
cost-effective clean coal facilities that is covered by
sourcing agreements.
(3) Initial clean coal facility. In order to promote
development of clean coal facilities in Illinois, each
electric utility subject to this Section shall execute a
sourcing agreement to source electricity from a proposed
clean coal facility in Illinois (the "initial clean coal
facility") that will have a nameplate capacity of at least
500 MW when commercial operation commences, that has a
final Clean Air Act permit on June 1, 2009 (the effective
date of Public Act 95-1027), and that will meet the
definition of clean coal facility in Section 1-10 of this
Act when commercial operation commences. The sourcing
agreements with this initial clean coal facility shall be
subject to both approval of the initial clean coal

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facility by the General Assembly and satisfaction of the
requirements of paragraph (4) of this subsection (d) and
shall be executed within 90 days after any such approval
by the General Assembly. The Agency and the Commission
shall have authority to inspect all books and records
associated with the initial clean coal facility during the
term of such a sourcing agreement. A utility's sourcing
agreement for electricity produced by the initial clean
coal facility shall include:
(A) a formula contractual price (the "contract
price") approved pursuant to paragraph (4) of this
subsection (d), which shall:
(i) be determined using a cost of service
methodology employing either a level or deferred
capital recovery component, based on a capital
structure consisting of 45% equity and 55% debt,
and a return on equity as may be approved by the
Federal Energy Regulatory Commission, which in any
case may not exceed the lower of 11.5% or the rate
of return approved by the General Assembly
pursuant to paragraph (4) of this subsection (d);
and
(ii) provide that all miscellaneous net
revenue, including but not limited to net revenue
from the sale of emission allowances, if any,
substitute natural gas, if any, grants or other

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support provided by the State of Illinois or the
United States Government, firm transmission
rights, if any, by-products produced by the
facility, energy or capacity derived from the
facility and not covered by a sourcing agreement
pursuant to paragraph (3) of this subsection (d)
or item (5) of subsection (d) of Section 16-115 of
the Public Utilities Act, whether generated from
the synthesis gas derived from coal, from SNG, or
from natural gas, shall be credited against the
revenue requirement for this initial clean coal
facility;
(B) power purchase provisions, which shall:
(i) provide that the utility party to such
sourcing agreement shall pay the contract price
for electricity delivered under such sourcing
agreement;
(ii) require delivery of electricity to the
regional transmission organization market of the
utility that is party to such sourcing agreement;
(iii) require the utility party to such
sourcing agreement to buy from the initial clean
coal facility in each hour an amount of energy
equal to all clean coal energy made available from
the initial clean coal facility during such hour
times a fraction, the numerator of which is such

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utility's retail market sales of electricity
(expressed in kilowatthours sold) in the State
during the prior calendar month and the
denominator of which is the total retail market
sales of electricity (expressed in kilowatthours
sold) in the State by utilities during such prior
month and the sales of electricity (expressed in
kilowatthours sold) in the State by alternative
retail electric suppliers during such prior month
that are subject to the requirements of this
subsection (d) and paragraph (5) of subsection (d)
of Section 16-115 of the Public Utilities Act,
provided that the amount purchased by the utility
in any year will be limited by paragraph (2) of
this subsection (d); and
(iv) be considered pre-existing contracts in
such utility's procurement plans for eligible
retail customers;
(C) contract for differences provisions, which
shall:
(i) require the utility party to such sourcing
agreement to contract with the initial clean coal
facility in each hour with respect to an amount of
energy equal to all clean coal energy made
available from the initial clean coal facility
during such hour times a fraction, the numerator

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of which is such utility's retail market sales of
electricity (expressed in kilowatthours sold) in
the utility's service territory in the State
during the prior calendar month and the
denominator of which is the total retail market
sales of electricity (expressed in kilowatthours
sold) in the State by utilities during such prior
month and the sales of electricity (expressed in
kilowatthours sold) in the State by alternative
retail electric suppliers during such prior month
that are subject to the requirements of this
subsection (d) and paragraph (5) of subsection (d)
of Section 16-115 of the Public Utilities Act,
provided that the amount paid by the utility in
any year will be limited by paragraph (2) of this
subsection (d);
(ii) provide that the utility's payment
obligation in respect of the quantity of
electricity determined pursuant to the preceding
clause (i) shall be limited to an amount equal to
(1) the difference between the contract price
determined pursuant to subparagraph (A) of
paragraph (3) of this subsection (d) and the
day-ahead price for electricity delivered to the
regional transmission organization market of the
utility that is party to such sourcing agreement

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(or any successor delivery point at which such
utility's supply obligations are financially
settled on an hourly basis) (the "reference
price") on the day preceding the day on which the
electricity is delivered to the initial clean coal
facility busbar, multiplied by (2) the quantity of
electricity determined pursuant to the preceding
clause (i); and
(iii) not require the utility to take physical
delivery of the electricity produced by the
facility;
(D) general provisions, which shall:
(i) specify a term of no more than 30 years,
commencing on the commercial operation date of the
facility;
(ii) provide that utilities shall maintain
adequate records documenting purchases under the
sourcing agreements entered into to comply with
this subsection (d) and shall file an accounting
with the load forecast that must be filed with the
Agency by July 15 of each year, in accordance with
subsection (d) of Section 16-111.5 of the Public
Utilities Act;
(iii) provide that all costs associated with
the initial clean coal facility will be
periodically reported to the Federal Energy

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Regulatory Commission and to purchasers in
accordance with applicable laws governing
cost-based wholesale power contracts;
(iv) permit the Illinois Power Agency to
assume ownership of the initial clean coal
facility, without monetary consideration and
otherwise on reasonable terms acceptable to the
Agency, if the Agency so requests no less than 3
years prior to the end of the stated contract
term;
(v) require the owner of the initial clean
coal facility to provide documentation to the
Commission each year, starting in the facility's
first year of commercial operation, accurately
reporting the quantity of carbon emissions from
the facility that have been captured and
sequestered and report any quantities of carbon
released from the site or sites at which carbon
emissions were sequestered in prior years, based
on continuous monitoring of such sites. If, in any
year after the first year of commercial operation,
the owner of the facility fails to demonstrate
that the initial clean coal facility captured and
sequestered at least 50% of the total carbon
emissions that the facility would otherwise emit
or that sequestration of emissions from prior

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years has failed, resulting in the release of
carbon dioxide into the atmosphere, the owner of
the facility must offset excess emissions. Any
such carbon offsets must be permanent, additional,
verifiable, real, located within the State of
Illinois, and legally and practicably enforceable.
The cost of such offsets for the facility that are
not recoverable shall not exceed $15 million in
any given year. No costs of any such purchases of
carbon offsets may be recovered from a utility or
its customers. All carbon offsets purchased for
this purpose and any carbon emission credits
associated with sequestration of carbon from the
facility must be permanently retired. The initial
clean coal facility shall not forfeit its
designation as a clean coal facility if the
facility fails to fully comply with the applicable
carbon sequestration requirements in any given
year, provided the requisite offsets are
purchased. However, the Attorney General, on
behalf of the People of the State of Illinois, may
specifically enforce the facility's sequestration
requirement and the other terms of this contract
provision. Compliance with the sequestration
requirements and offset purchase requirements
specified in paragraph (3) of this subsection (d)

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shall be reviewed annually by an independent
expert retained by the owner of the initial clean
coal facility, with the advance written approval
of the Attorney General. The Commission may, in
the course of the review specified in item (vii),
reduce the allowable return on equity for the
facility if the facility willfully fails to comply
with the carbon capture and sequestration
requirements set forth in this item (v);
(vi) include limits on, and accordingly
provide for modification of, the amount the
utility is required to source under the sourcing
agreement consistent with paragraph (2) of this
subsection (d);
(vii) require Commission review: (1) to
determine the justness, reasonableness, and
prudence of the inputs to the formula referenced
in subparagraphs (A)(i) through (A)(iii) of
paragraph (3) of this subsection (d), prior to an
adjustment in those inputs including, without
limitation, the capital structure and return on
equity, fuel costs, and other operations and
maintenance costs and (2) to approve the costs to
be passed through to customers under the sourcing
agreement by which the utility satisfies its
statutory obligations. Commission review shall

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occur no less than every 3 years, regardless of
whether any adjustments have been proposed, and
shall be completed within 9 months;
(viii) limit the utility's obligation to such
amount as the utility is allowed to recover
through tariffs filed with the Commission,
provided that neither the clean coal facility nor
the utility waives any right to assert federal
pre-emption or any other argument in response to a
purported disallowance of recovery costs;
(ix) limit the utility's or alternative retail
electric supplier's obligation to incur any
liability until such time as the facility is in
commercial operation and generating power and
energy and such power and energy is being
delivered to the facility busbar;
(x) provide that the owner or owners of the
initial clean coal facility, which is the
counterparty to such sourcing agreement, shall
have the right from time to time to elect whether
the obligations of the utility party thereto shall
be governed by the power purchase provisions or
the contract for differences provisions;
(xi) append documentation showing that the
formula rate and contract, insofar as they relate
to the power purchase provisions, have been

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approved by the Federal Energy Regulatory
Commission pursuant to Section 205 of the Federal
Power Act;
(xii) provide that any changes to the terms of
the contract, insofar as such changes relate to
the power purchase provisions, are subject to
review under the public interest standard applied
by the Federal Energy Regulatory Commission
pursuant to Sections 205 and 206 of the Federal
Power Act; and
(xiii) conform with customary lender
requirements in power purchase agreements used as
the basis for financing non-utility generators.
(4) Effective date of sourcing agreements with the
initial clean coal facility. Any proposed sourcing
agreement with the initial clean coal facility shall not
become effective unless the following reports are prepared
and submitted and authorizations and approvals obtained:
(i) Facility cost report. The owner of the initial
clean coal facility shall submit to the Commission,
the Agency, and the General Assembly a front-end
engineering and design study, a facility cost report,
method of financing (including but not limited to
structure and associated costs), and an operating and
maintenance cost quote for the facility (collectively
"facility cost report"), which shall be prepared in

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accordance with the requirements of this paragraph (4)
of subsection (d) of this Section, and shall provide
the Commission and the Agency access to the work
papers, relied upon documents, and any other backup
documentation related to the facility cost report.
(ii) Commission report. Within 6 months following
receipt of the facility cost report, the Commission,
in consultation with the Agency, shall submit a report
to the General Assembly setting forth its analysis of
the facility cost report. Such report shall include,
but not be limited to, a comparison of the costs
associated with electricity generated by the initial
clean coal facility to the costs associated with
electricity generated by other types of generation
facilities, an analysis of the rate impacts on
residential and small business customers over the life
of the sourcing agreements, and an analysis of the
likelihood that the initial clean coal facility will
commence commercial operation by and be delivering
power to the facility's busbar by 2016. To assist in
the preparation of its report, the Commission, in
consultation with the Agency, may hire one or more
experts or consultants, the costs of which shall be
paid for by the owner of the initial clean coal
facility. The Commission and Agency may begin the
process of selecting such experts or consultants prior

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to receipt of the facility cost report.
(iii) General Assembly approval. The proposed
sourcing agreements shall not take effect unless,
based on the facility cost report and the Commission's
report, the General Assembly enacts authorizing
legislation approving (A) the projected price, stated
in cents per kilowatthour, to be charged for
electricity generated by the initial clean coal
facility, (B) the projected impact on residential and
small business customers' bills over the life of the
sourcing agreements, and (C) the maximum allowable
return on equity for the project; and
(iv) Commission review. If the General Assembly
enacts authorizing legislation pursuant to
subparagraph (iii) approving a sourcing agreement, the
Commission shall, within 90 days of such enactment,
complete a review of such sourcing agreement. During
such time period, the Commission shall implement any
directive of the General Assembly, resolve any
disputes between the parties to the sourcing agreement
concerning the terms of such agreement, approve the
form of such agreement, and issue an order finding
that the sourcing agreement is prudent and reasonable.
The facility cost report shall be prepared as follows:
(A) The facility cost report shall be prepared by
duly licensed engineering and construction firms

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detailing the estimated capital costs payable to one
or more contractors or suppliers for the engineering,
procurement and construction of the components
comprising the initial clean coal facility and the
estimated costs of operation and maintenance of the
facility. The facility cost report shall include:
(i) an estimate of the capital cost of the
core plant based on one or more front end
engineering and design studies for the
gasification island and related facilities. The
core plant shall include all civil, structural,
mechanical, electrical, control, and safety
systems.
(ii) an estimate of the capital cost of the
balance of the plant, including any capital costs
associated with sequestration of carbon dioxide
emissions and all interconnects and interfaces
required to operate the facility, such as
transmission of electricity, construction or
backfeed power supply, pipelines to transport
substitute natural gas or carbon dioxide, potable
water supply, natural gas supply, water supply,
water discharge, landfill, access roads, and coal
delivery.
The quoted construction costs shall be expressed
in nominal dollars as of the date that the quote is

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prepared and shall include capitalized financing costs
during construction, taxes, insurance, and other
owner's costs, and an assumed escalation in materials
and labor beyond the date as of which the construction
cost quote is expressed.
(B) The front end engineering and design study for
the gasification island and the cost study for the
balance of plant shall include sufficient design work
to permit quantification of major categories of
materials, commodities and labor hours, and receipt of
quotes from vendors of major equipment required to
construct and operate the clean coal facility.
(C) The facility cost report shall also include an
operating and maintenance cost quote that will provide
the estimated cost of delivered fuel, personnel,
maintenance contracts, chemicals, catalysts,
consumables, spares, and other fixed and variable
operations and maintenance costs. The delivered fuel
cost estimate will be provided by a recognized third
party expert or experts in the fuel and transportation
industries. The balance of the operating and
maintenance cost quote, excluding delivered fuel
costs, will be developed based on the inputs provided
by duly licensed engineering and construction firms
performing the construction cost quote, potential
vendors under long-term service agreements and plant

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operating agreements, or recognized third party plant
operator or operators.
The operating and maintenance cost quote
(including the cost of the front end engineering and
design study) shall be expressed in nominal dollars as
of the date that the quote is prepared and shall
include taxes, insurance, and other owner's costs, and
an assumed escalation in materials and labor beyond
the date as of which the operating and maintenance
cost quote is expressed.
(D) The facility cost report shall also include an
analysis of the initial clean coal facility's ability
to deliver power and energy into the applicable
regional transmission organization markets and an
analysis of the expected capacity factor for the
initial clean coal facility.
(E) Amounts paid to third parties unrelated to the
owner or owners of the initial clean coal facility to
prepare the core plant construction cost quote,
including the front end engineering and design study,
and the operating and maintenance cost quote will be
reimbursed through Coal Development Bonds.
(5) Re-powering and retrofitting coal-fired power
plants previously owned by Illinois utilities to qualify
as clean coal facilities. During the 2009 procurement
planning process and thereafter, the Agency and the

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Commission shall consider sourcing agreements covering
electricity generated by power plants that were previously
owned by Illinois utilities and that have been or will be
converted into clean coal facilities, as defined by
Section 1-10 of this Act. Pursuant to such procurement
planning process, the owners of such facilities may
propose to the Agency sourcing agreements with utilities
and alternative retail electric suppliers required to
comply with subsection (d) of this Section and item (5) of
subsection (d) of Section 16-115 of the Public Utilities
Act, covering electricity generated by such facilities. In
the case of sourcing agreements that are power purchase
agreements, the contract price for electricity sales shall
be established on a cost of service basis. In the case of
sourcing agreements that are contracts for differences,
the contract price from which the reference price is
subtracted shall be established on a cost of service
basis. The Agency and the Commission may approve any such
utility sourcing agreements that do not exceed cost-based
benchmarks developed by the procurement administrator, in
consultation with the Commission staff, Agency staff and
the procurement monitor, subject to Commission review and
approval. The Commission shall have authority to inspect
all books and records associated with these clean coal
facilities during the term of any such contract.
(6) Costs incurred under this subsection (d) or

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pursuant to a contract entered into under this subsection
(d) shall be deemed prudently incurred and reasonable in
amount and the electric utility shall be entitled to full
cost recovery pursuant to the tariffs filed with the
Commission.
(d-5) Zero emission standard.
(1) Beginning with the delivery year commencing on
June 1, 2017, the Agency shall, for electric utilities
that serve at least 100,000 retail customers in this
State, procure contracts with zero emission facilities
that are reasonably capable of generating cost-effective
zero emission credits in an amount approximately equal to
16% of the actual amount of electricity delivered by each
electric utility to retail customers in the State during
calendar year 2014. For an electric utility serving fewer
than 100,000 retail customers in this State that
requested, under Section 16-111.5 of the Public Utilities
Act, that the Agency procure power and energy for all or a
portion of the utility's Illinois load for the delivery
year commencing June 1, 2016, the Agency shall procure
contracts with zero emission facilities that are
reasonably capable of generating cost-effective zero
emission credits in an amount approximately equal to 16%
of the portion of power and energy to be procured by the
Agency for the utility. The duration of the contracts
procured under this subsection (d-5) shall be for a term

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of 10 years ending May 31, 2027. The quantity of zero
emission credits to be procured under the contracts shall
be all of the zero emission credits generated by the zero
emission facility in each delivery year; however, if the
zero emission facility is owned by more than one entity,
then the quantity of zero emission credits to be procured
under the contracts shall be the amount of zero emission
credits that are generated from the portion of the zero
emission facility that is owned by the winning supplier.
The 16% value identified in this paragraph (1) is the
average of the percentage targets in subparagraph (B) of
paragraph (1) of subsection (c) of this Section for the 5
delivery years beginning June 1, 2017.
The procurement process shall be subject to the
following provisions:
(A) Those zero emission facilities that intend to
participate in the procurement shall submit to the
Agency the following eligibility information for each
zero emission facility on or before the date
established by the Agency:
(i) the in-service date and remaining useful
life of the zero emission facility;
(ii) the amount of power generated annually
for each of the years 2005 through 2015, and the
projected zero emission credits to be generated
over the remaining useful life of the zero

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emission facility, which shall be used to
determine the capability of each facility;
(iii) the annual zero emission facility cost
projections, expressed on a per megawatthour
basis, over the next 6 delivery years, which shall
include the following: operation and maintenance
expenses; fully allocated overhead costs, which
shall be allocated using the methodology developed
by the Institute for Nuclear Power Operations;
fuel expenditures; non-fuel capital expenditures;
spent fuel expenditures; a return on working
capital; the cost of operational and market risks
that could be avoided by ceasing operation; and
any other costs necessary for continued
operations, provided that "necessary" means, for
purposes of this item (iii), that the costs could
reasonably be avoided only by ceasing operations
of the zero emission facility; and
(iv) a commitment to continue operating, for
the duration of the contract or contracts executed
under the procurement held under this subsection
(d-5), the zero emission facility that produces
the zero emission credits to be procured in the
procurement.
The information described in item (iii) of this
subparagraph (A) may be submitted on a confidential

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basis and shall be treated and maintained by the
Agency, the procurement administrator, and the
Commission as confidential and proprietary and exempt
from disclosure under subparagraphs (a) and (g) of
paragraph (1) of Section 7 of the Freedom of
Information Act. The Office of Attorney General shall
have access to, and maintain the confidentiality of,
such information pursuant to Section 6.5 of the
Attorney General Act.
(B) The price for each zero emission credit
procured under this subsection (d-5) for each delivery
year shall be in an amount that equals the Social Cost
of Carbon, expressed on a price per megawatthour
basis. However, to ensure that the procurement remains
affordable to retail customers in this State if
electricity prices increase, the price in an
applicable delivery year shall be reduced below the
Social Cost of Carbon by the amount ("Price
Adjustment") by which the market price index for the
applicable delivery year exceeds the baseline market
price index for the consecutive 12-month period ending
May 31, 2016. If the Price Adjustment is greater than
or equal to the Social Cost of Carbon in an applicable
delivery year, then no payments shall be due in that
delivery year. The components of this calculation are
defined as follows:

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(i) Social Cost of Carbon: The Social Cost of
Carbon is $16.50 per megawatthour, which is based
on the U.S. Interagency Working Group on Social
Cost of Carbon's price in the August 2016
Technical Update using a 3% discount rate,
adjusted for inflation for each year of the
program. Beginning with the delivery year
commencing June 1, 2023, the price per
megawatthour shall increase by $1 per
megawatthour, and continue to increase by an
additional $1 per megawatthour each delivery year
thereafter.
(ii) Baseline market price index: The baseline
market price index for the consecutive 12-month
period ending May 31, 2016 is $31.40 per
megawatthour, which is based on the sum of (aa)
the average day-ahead energy price across all
hours of such 12-month period at the PJM
Interconnection LLC Northern Illinois Hub, (bb)
50% multiplied by the Base Residual Auction, or
its successor, capacity price for the rest of the
RTO zone group determined by PJM Interconnection
LLC, divided by 24 hours per day, and (cc) 50%
multiplied by the Planning Resource Auction, or
its successor, capacity price for Zone 4
determined by the Midcontinent Independent System

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Operator, Inc., divided by 24 hours per day.
(iii) Market price index: The market price
index for a delivery year shall be the sum of
projected energy prices and projected capacity
prices determined as follows:
(aa) Projected energy prices: the
projected energy prices for the applicable
delivery year shall be calculated once for the
year using the forward market price for the
PJM Interconnection, LLC Northern Illinois
Hub. The forward market price shall be
calculated as follows: the energy forward
prices for each month of the applicable
delivery year averaged for each trade date
during the calendar year immediately preceding
that delivery year to produce a single energy
forward price for the delivery year. The
forward market price calculation shall use
data published by the Intercontinental
Exchange, or its successor.
(bb) Projected capacity prices:
(I) For the delivery years commencing
June 1, 2017, June 1, 2018, and June 1,
2019, the projected capacity price shall
be equal to the sum of (1) 50% multiplied
by the Base Residual Auction, or its

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successor, price for the rest of the RTO
zone group as determined by PJM
Interconnection LLC, divided by 24 hours
per day and, (2) 50% multiplied by the
resource auction price determined in the
resource auction administered by the
Midcontinent Independent System Operator,
Inc., in which the largest percentage of
load cleared for Local Resource Zone 4,
divided by 24 hours per day, and where
such price is determined by the
Midcontinent Independent System Operator,
Inc.
(II) For the delivery year commencing
June 1, 2020, and each year thereafter,
the projected capacity price shall be
equal to the sum of (1) 50% multiplied by
the Base Residual Auction, or its
successor, price for the ComEd zone as
determined by PJM Interconnection LLC,
divided by 24 hours per day, and (2) 50%
multiplied by the resource auction price
determined in the resource auction
administered by the Midcontinent
Independent System Operator, Inc., in
which the largest percentage of load

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cleared for Local Resource Zone 4, divided
by 24 hours per day, and where such price
is determined by the Midcontinent
Independent System Operator, Inc.
For purposes of this subsection (d-5):
"Rest of the RTO" and "ComEd Zone" shall have
the meaning ascribed to them by PJM
Interconnection, LLC.
"RTO" means regional transmission
organization.
(C) No later than 45 days after June 1, 2017 (the
effective date of Public Act 99-906), the Agency shall
publish its proposed zero emission standard
procurement plan. The plan shall be consistent with
the provisions of this paragraph (1) and shall provide
that winning bids shall be selected based on public
interest criteria that include, but are not limited
to, minimizing carbon dioxide emissions that result
from electricity consumed in Illinois and minimizing
sulfur dioxide, nitrogen oxide, and particulate matter
emissions that adversely affect the citizens of this
State. In particular, the selection of winning bids
shall take into account the incremental environmental
benefits resulting from the procurement, such as any
existing environmental benefits that are preserved by
the procurements held under Public Act 99-906 and

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would cease to exist if the procurements were not
held, including the preservation of zero emission
facilities. The plan shall also describe in detail how
each public interest factor shall be considered and
weighted in the bid selection process to ensure that
the public interest criteria are applied to the
procurement and given full effect.
For purposes of developing the plan, the Agency
shall consider any reports issued by a State agency,
board, or commission under House Resolution 1146 of
the 98th General Assembly and paragraph (4) of
subsection (d) of this Section, as well as publicly
available analyses and studies performed by or for
regional transmission organizations that serve the
State and their independent market monitors.
Upon publishing of the zero emission standard
procurement plan, copies of the plan shall be posted
and made publicly available on the Agency's website.
All interested parties shall have 10 days following
the date of posting to provide comment to the Agency on
the plan. All comments shall be posted to the Agency's
website. Following the end of the comment period, but
no more than 60 days later than June 1, 2017 (the
effective date of Public Act 99-906), the Agency shall
revise the plan as necessary based on the comments
received and file its zero emission standard

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procurement plan with the Commission.
If the Commission determines that the plan will
result in the procurement of cost-effective zero
emission credits, then the Commission shall, after
notice and hearing, but no later than 45 days after the
Agency filed the plan, approve the plan or approve
with modification. For purposes of this subsection
(d-5), "cost effective" means the projected costs of
procuring zero emission credits from zero emission
facilities do not cause the limit stated in paragraph
(2) of this subsection to be exceeded.
(C-5) As part of the Commission's review and
acceptance or rejection of the procurement results,
the Commission shall, in its public notice of
successful bidders:
(i) identify how the winning bids satisfy the
public interest criteria described in subparagraph
(C) of this paragraph (1) of minimizing carbon
dioxide emissions that result from electricity
consumed in Illinois and minimizing sulfur
dioxide, nitrogen oxide, and particulate matter
emissions that adversely affect the citizens of
this State;
(ii) specifically address how the selection of
winning bids takes into account the incremental
environmental benefits resulting from the

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procurement, including any existing environmental
benefits that are preserved by the procurements
held under Public Act 99-906 and would have ceased
to exist if the procurements had not been held,
such as the preservation of zero emission
facilities;
(iii) quantify the environmental benefit of
preserving the resources identified in item (ii)
of this subparagraph (C-5), including the
following:
(aa) the value of avoided greenhouse gas
emissions measured as the product of the zero
emission facilities' output over the contract
term multiplied by the U.S. Environmental
Protection Agency eGrid subregion carbon
dioxide emission rate and the U.S. Interagency
Working Group on Social Cost of Carbon's price
in the August 2016 Technical Update using a 3%
discount rate, adjusted for inflation for each
delivery year; and
(bb) the costs of replacement with other
zero carbon dioxide resources, including wind
and photovoltaic, based upon the simple
average of the following:
(I) the price, or if there is more
than one price, the average of the prices,

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paid for renewable energy credits from new
utility-scale wind projects in the
procurement events specified in item (i)
of subparagraph (G) of paragraph (1) of
subsection (c) of this Section; and
(II) the price, or if there is more
than one price, the average of the prices,
paid for renewable energy credits from new
utility-scale solar projects and
brownfield site photovoltaic projects in
the procurement events specified in item
(ii) of subparagraph (G) of paragraph (1)
of subsection (c) of this Section and,
after January 1, 2015, renewable energy
credits from photovoltaic distributed
generation projects in procurement events
held under subsection (c) of this Section.
Each utility shall enter into binding contractual
arrangements with the winning suppliers.
The procurement described in this subsection
(d-5), including, but not limited to, the execution of
all contracts procured, shall be completed no later
than May 10, 2017. Based on the effective date of
Public Act 99-906, the Agency and Commission may, as
appropriate, modify the various dates and timelines
under this subparagraph and subparagraphs (C) and (D)

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of this paragraph (1). The procurement and plan
approval processes required by this subsection (d-5)
shall be conducted in conjunction with the procurement
and plan approval processes required by subsection (c)
of this Section and Section 16-111.5 of the Public
Utilities Act, to the extent practicable.
Notwithstanding whether a procurement event is
conducted under Section 16-111.5 of the Public
Utilities Act, the Agency shall immediately initiate a
procurement process on June 1, 2017 (the effective
date of Public Act 99-906).
(D) Following the procurement event described in
this paragraph (1) and consistent with subparagraph
(B) of this paragraph (1), the Agency shall calculate
the payments to be made under each contract for the
next delivery year based on the market price index for
that delivery year. The Agency shall publish the
payment calculations no later than May 25, 2017 and
every May 25 thereafter.
(E) Notwithstanding the requirements of this
subsection (d-5), the contracts executed under this
subsection (d-5) shall provide that the zero emission
facility may, as applicable, suspend or terminate
performance under the contracts in the following
instances:
(i) A zero emission facility shall be excused

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from its performance under the contract for any
cause beyond the control of the resource,
including, but not restricted to, acts of God,
flood, drought, earthquake, storm, fire,
lightning, epidemic, war, riot, civil disturbance
or disobedience, labor dispute, labor or material
shortage, sabotage, acts of public enemy,
explosions, orders, regulations or restrictions
imposed by governmental, military, or lawfully
established civilian authorities, which, in any of
the foregoing cases, by exercise of commercially
reasonable efforts the zero emission facility
could not reasonably have been expected to avoid,
and which, by the exercise of commercially
reasonable efforts, it has been unable to
overcome. In such event, the zero emission
facility shall be excused from performance for the
duration of the event, including, but not limited
to, delivery of zero emission credits, and no
payment shall be due to the zero emission facility
during the duration of the event.
(ii) A zero emission facility shall be
permitted to terminate the contract if legislation
is enacted into law by the General Assembly that
imposes or authorizes a new tax, special
assessment, or fee on the generation of

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electricity, the ownership or leasehold of a
generating unit, or the privilege or occupation of
such generation, ownership, or leasehold of
generation units by a zero emission facility.
However, the provisions of this item (ii) do not
apply to any generally applicable tax, special
assessment or fee, or requirements imposed by
federal law.
(iii) A zero emission facility shall be
permitted to terminate the contract in the event
that the resource requires capital expenditures in
excess of $40,000,000 that were neither known nor
reasonably foreseeable at the time it executed the
contract and that a prudent owner or operator of
such resource would not undertake.
(iv) A zero emission facility shall be
permitted to terminate the contract in the event
the Nuclear Regulatory Commission terminates the
resource's license.
(F) If the zero emission facility elects to
terminate a contract under subparagraph (E) of this
paragraph (1), then the Commission shall reopen the
docket in which the Commission approved the zero
emission standard procurement plan under subparagraph
(C) of this paragraph (1) and, after notice and
hearing, enter an order acknowledging the contract

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termination election if such termination is consistent
with the provisions of this subsection (d-5).
(2) For purposes of this subsection (d-5), the amount
paid per kilowatthour means the total amount paid for
electric service expressed on a per kilowatthour basis.
For purposes of this subsection (d-5), the total amount
paid for electric service includes, without limitation,
amounts paid for supply, transmission, distribution,
surcharges, and add-on taxes.
Notwithstanding the requirements of this subsection
(d-5), the contracts executed under this subsection (d-5)
shall provide that the total of zero emission credits
procured under a procurement plan shall be subject to the
limitations of this paragraph (2). For each delivery year,
the contractual volume receiving payments in such year
shall be reduced for all retail customers based on the
amount necessary to limit the net increase that delivery
year to the costs of those credits included in the amounts
paid by eligible retail customers in connection with
electric service to no more than 1.65% of the amount paid
per kilowatthour by eligible retail customers during the
year ending May 31, 2009. The result of this computation
shall apply to and reduce the procurement for all retail
customers, and all those customers shall pay the same
single, uniform cents per kilowatthour charge under
subsection (k) of Section 16-108 of the Public Utilities

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Act. To arrive at a maximum dollar amount of zero emission
credits to be paid for the particular delivery year, the
resulting per kilowatthour amount shall be applied to the
actual amount of kilowatthours of electricity delivered by
the electric utility in the delivery year immediately
prior to the procurement, to all retail customers in its
service territory. Unpaid contractual volume for any
delivery year shall be paid in any subsequent delivery
year in which such payments can be made without exceeding
the amount specified in this paragraph (2). The
calculations required by this paragraph (2) shall be made
only once for each procurement plan year. Once the
determination as to the amount of zero emission credits to
be paid is made based on the calculations set forth in this
paragraph (2), no subsequent rate impact determinations
shall be made and no adjustments to those contract amounts
shall be allowed. All costs incurred under those contracts
and in implementing this subsection (d-5) shall be
recovered by the electric utility as provided in this
Section.
No later than June 30, 2019, the Commission shall
review the limitation on the amount of zero emission
credits procured under this subsection (d-5) and report to
the General Assembly its findings as to whether that
limitation unduly constrains the procurement of
cost-effective zero emission credits.

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(3) Six years after the execution of a contract under
this subsection (d-5), the Agency shall determine whether
the actual zero emission credit payments received by the
supplier over the 6-year period exceed the Average ZEC
Payment. In addition, at the end of the term of a contract
executed under this subsection (d-5), or at the time, if
any, a zero emission facility's contract is terminated
under subparagraph (E) of paragraph (1) of this subsection
(d-5), then the Agency shall determine whether the actual
zero emission credit payments received by the supplier
over the term of the contract exceed the Average ZEC
Payment, after taking into account any amounts previously
credited back to the utility under this paragraph (3). If
the Agency determines that the actual zero emission credit
payments received by the supplier over the relevant period
exceed the Average ZEC Payment, then the supplier shall
credit the difference back to the utility. The amount of
the credit shall be remitted to the applicable electric
utility no later than 120 days after the Agency's
determination, which the utility shall reflect as a credit
on its retail customer bills as soon as practicable;
however, the credit remitted to the utility shall not
exceed the total amount of payments received by the
facility under its contract.
For purposes of this Section, the Average ZEC Payment
shall be calculated by multiplying the quantity of zero

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emission credits delivered under the contract times the
average contract price. The average contract price shall
be determined by subtracting the amount calculated under
subparagraph (B) of this paragraph (3) from the amount
calculated under subparagraph (A) of this paragraph (3),
as follows:
(A) The average of the Social Cost of Carbon, as
defined in subparagraph (B) of paragraph (1) of this
subsection (d-5), during the term of the contract.
(B) The average of the market price indices, as
defined in subparagraph (B) of paragraph (1) of this
subsection (d-5), during the term of the contract,
minus the baseline market price index, as defined in
subparagraph (B) of paragraph (1) of this subsection
(d-5).
If the subtraction yields a negative number, then the
Average ZEC Payment shall be zero.
(4) Cost-effective zero emission credits procured from
zero emission facilities shall satisfy the applicable
definitions set forth in Section 1-10 of this Act.
(5) The electric utility shall retire all zero
emission credits used to comply with the requirements of
this subsection (d-5).
(6) Electric utilities shall be entitled to recover
all of the costs associated with the procurement of zero
emission credits through an automatic adjustment clause

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tariff in accordance with subsection (k) and (m) of
Section 16-108 of the Public Utilities Act, and the
contracts executed under this subsection (d-5) shall
provide that the utilities' payment obligations under such
contracts shall be reduced if an adjustment is required
under subsection (m) of Section 16-108 of the Public
Utilities Act.
(7) This subsection (d-5) shall become inoperative on
January 1, 2028.
(e) The draft procurement plans are subject to public
comment, as required by Section 16-111.5 of the Public
Utilities Act.
(f) The Agency shall submit the final procurement plan to
the Commission. The Agency shall revise a procurement plan if
the Commission determines that it does not meet the standards
set forth in Section 16-111.5 of the Public Utilities Act.
(g) The Agency shall assess fees to each affected utility
to recover the costs incurred in preparation of the annual
procurement plan for the utility.
(h) The Agency shall assess fees to each bidder to recover
the costs incurred in connection with a competitive
procurement process.
(i) A renewable energy credit, carbon emission credit, or
zero emission credit can only be used once to comply with a
single portfolio or other standard as set forth in subsection
(c), subsection (d), or subsection (d-5) of this Section,

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respectively. A renewable energy credit, carbon emission
credit, or zero emission credit cannot be used to satisfy the
requirements of more than one standard. If more than one type
of credit is issued for the same megawatt hour of energy, only
one credit can be used to satisfy the requirements of a single
standard. After such use, the credit must be retired together
with any other credits issued for the same megawatt hour of
energy.
(Source: P.A. 100-863, eff. 8-14-18; 101-81, eff. 7-12-19;
101-113, eff. 1-1-20.)
Section 10. The Public Utilities Act is amended by
changing Sections 5-117, 8-103B, 16-102, 16-107.6, 16-108.5,
16-111.5, and 16-128A and by adding Sections 8-218, 9-244.5,
16-108.19 and 16-108.20 as follows:
(220 ILCS 5/5-117)
Sec. 5-117. Supplier diversity goals.
(a) The public policy of this State is to collaboratively
work with companies that serve Illinois residents to improve
their supplier diversity in a non-antagonistic manner.
(b) The Commission shall require all gas, electric, and
water companies with at least 100,000 customers under its
authority, as well as suppliers of wind energy, solar energy,
hydroelectricity, nuclear energy, and any other supplier of
energy within this State, including, but not limited to, any

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party selling renewable energy resources procured by the
Illinois Power Agency pursuant to Section 16-111.5 of this Act
and Section 1-75 of the Illinois Power Agency Act, to submit an
annual report by April 15, 2015 and every April 15 thereafter,
in a searchable Adobe PDF format, on all procurement goals and
actual spending for woman-owned female-owned, minority-owned,
veteran-owned, and small business enterprises in the previous
calendar year. These goals shall be expressed as a percentage
of the total work performed by the entity submitting the
report, and the actual spending for all woman-owned
female-owned, minority-owned, veteran-owned, and small
business enterprises shall also be expressed as a percentage
of the total work performed by the entity submitting the
report. Nothing in this subsection (b) shall require any
entity that was not required to file a report pursuant to this
subsection (b) prior to the effective date of this amendatory
Act of the 102nd General Assembly to file reports for calendar
years prior to 2021.
(c) Each participating company in its annual report shall
include the following information:
(1) an explanation of the plan for the next year to
increase participation;
(2) an explanation of the plan to increase the goals;
(3) the areas of procurement each company shall be
actively seeking more participation in in the next year;
(4) an outline of the plan to alert and encourage

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potential vendors in that area to seek business from the
company;
(5) an explanation of the challenges faced in finding
quality vendors and offer any suggestions for what the
Commission could do to be helpful to identify those
vendors;
(6) a list of the certifications the company
recognizes;
(7) the point of contact for any potential vendor who
wishes to do business with the company and explain the
process for a vendor to enroll with the company as a
minority-owned, women-owned, or veteran-owned company; and
(8) any particular success stories to encourage other
companies to emulate best practices.
(d) Each annual report shall include as much
State-specific data as possible. If the submitting entity does
not submit State-specific data, then the company shall include
any national data it does have and explain why it could not
submit State-specific data and how it intends to do so in
future reports, if possible.
(e) Each annual report shall include the rules,
regulations, and definitions used for the procurement goals in
the company's annual report.
(f) The Commission and all participating entities shall
hold an annual workshop open to the public in 2015 and every
year thereafter on the state of supplier diversity to

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collaboratively seek solutions to structural impediments to
achieving stated goals, including testimony from each
participating entity as well as subject matter experts and
advocates. The Commission shall publish a database on its
website of the point of contact for each participating entity
for supplier diversity, along with a list of certifications
each company recognizes from the information submitted in each
annual report. The Commission shall publish each annual report
on its website and shall maintain each annual report for at
least 5 years.
(Source: P.A. 98-1056, eff. 8-26-14; 99-906, eff. 6-1-17;
revised 7-22-19.)
(220 ILCS 5/8-103B)
Sec. 8-103B. Energy efficiency and demand-response
measures.
(a) It is the policy of the State that electric utilities
are required to use cost-effective energy efficiency and
demand-response measures to reduce the total Btus of
electricity, natural gas, or other fuels needed to meet the
end use or uses for all retail customers delivery load.
Requiring investment in cost-effective energy efficiency and
demand-response measures will reduce direct and indirect costs
to consumers by decreasing environmental impacts and by
avoiding or delaying the need for new generation,
transmission, and distribution infrastructure. It serves the

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public interest to allow electric utilities to recover costs
for reasonably and prudently incurred expenditures for energy
efficiency and demand-response measures. As used in this
Section, "cost-effective" means that the measures satisfy the
total resource cost test. The low-income measures described in
subsection (c) of this Section shall not be required to meet
the total resource cost test. For purposes of this Section,
the terms "energy-efficiency", "demand-response", "electric
utility", and "total resource cost test" have the meanings set
forth in the Illinois Power Agency Act.
(a-5) This Section applies to electric utilities serving
more than 500,000 retail customers in the State for those
multi-year plans commencing after December 31, 2017.
(b) For purposes of this Section, electric utilities
subject to this Section that serve more than 3,000,000 retail
customers in the State shall be deemed to have achieved a
cumulative persisting annual savings of 6.6% from energy
efficiency measures and programs implemented during the period
beginning January 1, 2012 and ending December 31, 2017, which
percent is based on the deemed average weather normalized
sales of electric power and energy during calendar years 2014,
2015, and 2016 of 88,000,000 MWhs. For the purposes of this
subsection (b) and subsection (b-5), the 88,000,000 MWhs of
deemed electric power and energy sales shall be reduced by the
number of MWhs equal to the sum of the annual consumption of
customers that are exempt from subsections (a) through (j) of

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this Section under subsection (l) of this Section, as averaged
across the calendar years 2014, 2015, and 2016. After 2017,
the deemed value of cumulative persisting annual savings from
energy efficiency measures and programs implemented during the
period beginning January 1, 2012 and ending December 31, 2017,
shall be reduced each year, as follows, and the applicable
value shall be applied to and count toward the utility's
achievement of the cumulative persisting annual savings goals
set forth in subsection (b-5):
(1) 5.8% deemed cumulative persisting annual savings
for the year ending December 31, 2018;
(2) 5.2% deemed cumulative persisting annual savings
for the year ending December 31, 2019;
(3) 4.5% deemed cumulative persisting annual savings
for the year ending December 31, 2020;
(4) 4.0% deemed cumulative persisting annual savings
for the year ending December 31, 2021;
(5) 3.5% deemed cumulative persisting annual savings
for the year ending December 31, 2022;
(6) 3.1% deemed cumulative persisting annual savings
for the year ending December 31, 2023;
(7) 2.8% deemed cumulative persisting annual savings
for the year ending December 31, 2024;
(8) 2.5% deemed cumulative persisting annual savings
for the year ending December 31, 2025;
(9) 2.3% deemed cumulative persisting annual savings

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for the year ending December 31, 2026;
(10) 2.1% deemed cumulative persisting annual savings
for the year ending December 31, 2027;
(11) 1.8% deemed cumulative persisting annual savings
for the year ending December 31, 2028;
(12) 1.7% deemed cumulative persisting annual savings
for the year ending December 31, 2029; and
(13) 1.5% deemed cumulative persisting annual savings
for the year ending December 31, 2030.
For purposes of this Section, "cumulative persisting
annual savings" means the total electric energy savings in a
given year from measures installed in that year or in previous
years, but no earlier than January 1, 2012, that are still
operational and providing savings in that year because the
measures have not yet reached the end of their useful lives.
(b-5) Beginning in 2018, electric utilities subject to
this Section that serve more than 3,000,000 retail customers
in the State shall achieve the following cumulative persisting
annual savings goals, as modified by subsection (f) of this
Section and as compared to the deemed baseline of 88,000,000
MWhs of electric power and energy sales set forth in
subsection (b), as reduced by the number of MWhs equal to the
sum of the annual consumption of customers that are exempt
from subsections (a) through (j) of this Section under
subsection (l) of this Section as averaged across the calendar
years 2014, 2015, and 2016, through the implementation of

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energy efficiency measures during the applicable year and in
prior years, but no earlier than January 1, 2012:
(1) 7.8% cumulative persisting annual savings for the
year ending December 31, 2018;
(2) 9.1% cumulative persisting annual savings for the
year ending December 31, 2019;
(3) 10.4% cumulative persisting annual savings for the
year ending December 31, 2020;
(4) 11.8% cumulative persisting annual savings for the
year ending December 31, 2021;
(5) 13.1% cumulative persisting annual savings for the
year ending December 31, 2022;
(6) 14.4% cumulative persisting annual savings for the
year ending December 31, 2023;
(7) 15.7% cumulative persisting annual savings for the
year ending December 31, 2024;
(8) 17% cumulative persisting annual savings for the
year ending December 31, 2025;
(9) 17.9% cumulative persisting annual savings for the
year ending December 31, 2026;
(10) 18.8% cumulative persisting annual savings for
the year ending December 31, 2027;
(11) 19.7% cumulative persisting annual savings for
the year ending December 31, 2028;
(12) 20.6% cumulative persisting annual savings for
the year ending December 31, 2029; and

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(13) 21.5% cumulative persisting annual savings for
the year ending December 31, 2030.
(b-10) For purposes of this Section, electric utilities
subject to this Section that serve less than 3,000,000 retail
customers but more than 500,000 retail customers in the State
shall be deemed to have achieved a cumulative persisting
annual savings of 6.6% from energy efficiency measures and
programs implemented during the period beginning January 1,
2012 and ending December 31, 2017, which is based on the deemed
average weather normalized sales of electric power and energy
during calendar years 2014, 2015, and 2016 of 36,900,000 MWhs.
For the purposes of this subsection (b-10) and subsection
(b-15), the 36,900,000 MWhs of deemed electric power and
energy sales shall be reduced by the number of MWhs equal to
the sum of the annual consumption of customers that are exempt
from subsections (a) through (j) of this Section under
subsection (l) of this Section, as averaged across the
calendar years 2014, 2015, and 2016. After 2017, the deemed
value of cumulative persisting annual savings from energy
efficiency measures and programs implemented during the period
beginning January 1, 2012 and ending December 31, 2017, shall
be reduced each year, as follows, and the applicable value
shall be applied to and count toward the utility's achievement
of the cumulative persisting annual savings goals set forth in
subsection (b-15):
(1) 5.8% deemed cumulative persisting annual savings

SB0311 - 108 - LRB102 15398 SPS 20761 b
for the year ending December 31, 2018;
(2) 5.2% deemed cumulative persisting annual savings
for the year ending December 31, 2019;
(3) 4.5% deemed cumulative persisting annual savings
for the year ending December 31, 2020;
(4) 4.0% deemed cumulative persisting annual savings
for the year ending December 31, 2021;
(5) 3.5% deemed cumulative persisting annual savings
for the year ending December 31, 2022;
(6) 3.1% deemed cumulative persisting annual savings
for the year ending December 31, 2023;
(7) 2.8% deemed cumulative persisting annual savings
for the year ending December 31, 2024;
(8) 2.5% deemed cumulative persisting annual savings
for the year ending December 31, 2025;
(9) 2.3% deemed cumulative persisting annual savings
for the year ending December 31, 2026;
(10) 2.1% deemed cumulative persisting annual savings
for the year ending December 31, 2027;
(11) 1.8% deemed cumulative persisting annual savings
for the year ending December 31, 2028;
(12) 1.7% deemed cumulative persisting annual savings
for the year ending December 31, 2029; and
(13) 1.5% deemed cumulative persisting annual savings
for the year ending December 31, 2030.
(b-15) Beginning in 2018, electric utilities subject to

SB0311 - 109 - LRB102 15398 SPS 20761 b
this Section that serve less than 3,000,000 retail customers
but more than 500,000 retail customers in the State shall
achieve the following cumulative persisting annual savings
goals, as modified by subsection (b-20) and subsection (f) of
this Section and as compared to the deemed baseline as reduced
by the number of MWhs equal to the sum of the annual
consumption of customers that are exempt from subsections (a)
through (j) of this Section under subsection (l) of this
Section as averaged across the calendar years 2014, 2015, and
2016, through the implementation of energy efficiency measures
during the applicable year and in prior years, but no earlier
than January 1, 2012:
(1) 7.4% cumulative persisting annual savings for the
year ending December 31, 2018;
(2) 8.2% cumulative persisting annual savings for the
year ending December 31, 2019;
(3) 9.0% cumulative persisting annual savings for the
year ending December 31, 2020;
(4) 9.8% cumulative persisting annual savings for the
year ending December 31, 2021;
(5) 10.6% cumulative persisting annual savings for the
year ending December 31, 2022;
(6) 11.4% cumulative persisting annual savings for the
year ending December 31, 2023;
(7) 12.2% cumulative persisting annual savings for the
year ending December 31, 2024;

SB0311 - 110 - LRB102 15398 SPS 20761 b
(8) 13% cumulative persisting annual savings for the
year ending December 31, 2025;
(9) 13.6% cumulative persisting annual savings for the
year ending December 31, 2026;
(10) 14.2% cumulative persisting annual savings for
the year ending December 31, 2027;
(11) 14.8% cumulative persisting annual savings for
the year ending December 31, 2028;
(12) 15.4% cumulative persisting annual savings for
the year ending December 31, 2029; and
(13) 16% cumulative persisting annual savings for the
year ending December 31, 2030.
The difference between the cumulative persisting annual
savings goal for the applicable calendar year and the
cumulative persisting annual savings goal for the immediately
preceding calendar year is 0.8% for the period of January 1,
2018 through December 31, 2025 and 0.6% for the period of
January 1, 2026 through December 31, 2030.
(b-20) Each electric utility subject to this Section may
include cost-effective voltage optimization measures in its
plans submitted under subsections (f) and (g) of this Section,
and the costs incurred by a utility to implement the measures
under a Commission-approved plan shall be recovered under the
provisions of Article IX or Section 16-108.5 of this Act. For
purposes of this Section, the measure life of voltage
optimization measures shall be 15 years. The measure life

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period is independent of the depreciation rate of the voltage
optimization assets deployed.
Within 270 days after June 1, 2017 (the effective date of
Public Act 99-906), an electric utility that serves less than
3,000,000 retail customers but more than 500,000 retail
customers in the State shall file a plan with the Commission
that identifies the cost-effective voltage optimization
investment the electric utility plans to undertake through
December 31, 2024. The Commission, after notice and hearing,
shall approve or approve with modification the plan within 120
days after the plan's filing and, in the order approving or
approving with modification the plan, the Commission shall
adjust the applicable cumulative persisting annual savings
goals set forth in subsection (b-15) to reflect any amount of
cost-effective energy savings approved by the Commission that
is greater than or less than the following cumulative
persisting annual savings values attributable to voltage
optimization for the applicable year:
(1) 0.0% of cumulative persisting annual savings for
the year ending December 31, 2018;
(2) 0.17% of cumulative persisting annual savings for
the year ending December 31, 2019;
(3) 0.17% of cumulative persisting annual savings for
the year ending December 31, 2020;
(4) 0.33% of cumulative persisting annual savings for
the year ending December 31, 2021;

SB0311 - 112 - LRB102 15398 SPS 20761 b
(5) 0.5% of cumulative persisting annual savings for
the year ending December 31, 2022;
(6) 0.67% of cumulative persisting annual savings for
the year ending December 31, 2023;
(7) 0.83% of cumulative persisting annual savings for
the year ending December 31, 2024; and
(8) 1.0% of cumulative persisting annual savings for
the year ending December 31, 2025.
(b-25) In the event an electric utility jointly offers an
energy efficiency measure or program with a gas utility under
plans approved under this Section and Section 8-104 of this
Act, the electric utility may continue offering the program,
including the gas energy efficiency measures, in the event the
gas utility discontinues funding the program. In that event,
the energy savings value associated with such other fuels
shall be converted to electric energy savings on an equivalent
Btu basis for the premises. However, the electric utility
shall prioritize programs for low-income residential customers
to the extent practicable. An electric utility may recover the
costs of offering the gas energy efficiency measures under
this subsection (b-25).
For those energy efficiency measures or programs that save
both electricity and other fuels but are not jointly offered
with a gas utility under plans approved under this Section and
Section 8-104 or not offered with an affiliated gas utility
under paragraph (6) of subsection (f) of Section 8-104 of this

SB0311 - 113 - LRB102 15398 SPS 20761 b
Act, or for those energy efficiency measures that achieve
savings of fuels other than electricity, an the electric
utility may count savings of fuels other than electricity
toward the achievement of its annual savings goal, and the
energy savings value associated with such other fuels shall be
converted to electric energy savings on an equivalent Btu
basis at the premises.
In no event shall more than 10% of each year's applicable
annual incremental goal as defined in paragraph (7) of
subsection (g) of this Section be met through savings of fuels
other than electricity; however, savings of fuels other than
electricity achieved by measures that educate about,
incentivize, encourage, or otherwise support the use of
electricity to power, in whole or in part, vehicles,
including, but not limited to, cars, trucks, buses, trains,
trolleys, boats, on-road or off-road vehicles, or other
equipment or methods of transporting goods or people, shall
count towards the applicable annual incremental goal and shall
not be included in the 10% limit set forth in this subsection
(b-25). Such measures shall include, but are not limited to,
measures that educate about, incentivize, encourage, or
otherwise support the adoption of electric vehicles by retail
customers of all customer classes.
(c) Electric utilities shall be responsible for overseeing
the design, development, and filing of energy efficiency plans
with the Commission and may, as part of that implementation,

SB0311 - 114 - LRB102 15398 SPS 20761 b
outsource various aspects of program development and
implementation. A minimum of 10%, for electric utilities that
serve more than 3,000,000 retail customers in the State, and a
minimum of 7%, for electric utilities that serve less than
3,000,000 retail customers but more than 500,000 retail
customers in the State, of the utility's entire portfolio
funding level for a given year shall be used to procure
cost-effective energy efficiency measures from units of local
government, municipal corporations, school districts, public
housing, and community college districts, provided that a
minimum percentage of available funds shall be used to procure
energy efficiency from public housing, which percentage shall
be equal to public housing's share of public building energy
consumption.
The utilities shall also implement energy efficiency
measures targeted at low-income households, which, for
purposes of this Section, shall be defined as households at or
below 80% of area median income, and expenditures to implement
the measures shall be no less than $25,000,000 per year for
electric utilities that serve more than 3,000,000 retail
customers in the State and no less than $8,350,000 per year for
electric utilities that serve less than 3,000,000 retail
customers but more than 500,000 retail customers in the State.
Each electric utility shall assess opportunities to
implement cost-effective energy efficiency measures and
programs through a public housing authority or authorities

SB0311 - 115 - LRB102 15398 SPS 20761 b
located in its service territory. If such opportunities are
identified, the utility shall propose such measures and
programs to address the opportunities. Expenditures to address
such opportunities shall be credited toward the minimum
procurement and expenditure requirements set forth in this
subsection (c).
Implementation of energy efficiency measures and programs
targeted at low-income households should be contracted, when
it is practicable, to independent third parties that have
demonstrated capabilities to serve such households, with a
preference for not-for-profit entities and government agencies
that have existing relationships with or experience serving
low-income communities in the State.
Each electric utility shall develop and implement
reporting procedures that address and assist in determining
the amount of energy savings that can be applied to the
low-income procurement and expenditure requirements set forth
in this subsection (c).
The electric utilities shall also convene a low-income
energy efficiency advisory committee to assist in the design
and evaluation of the low-income energy efficiency programs.
The committee shall be comprised of the electric utilities
subject to the requirements of this Section, the gas utilities
subject to the requirements of Section 8-104 of this Act, the
utilities' low-income energy efficiency implementation
contractors, and representatives of community-based

SB0311 - 116 - LRB102 15398 SPS 20761 b
organizations.
(d) Notwithstanding any other provision of law to the
contrary, a utility providing approved energy efficiency
measures and, if applicable, demand-response measures in the
State shall be permitted to recover all reasonable and
prudently incurred costs of those measures from all retail
customers, except as provided in subsection (l) of this
Section, as follows, provided that nothing in this subsection
(d) permits the double recovery of such costs from customers:
(1) The utility may recover its costs through an
automatic adjustment clause tariff filed with and approved
by the Commission. The tariff shall be established outside
the context of a general rate case. Each year the
Commission shall initiate a review to reconcile any
amounts collected with the actual costs and to determine
the required adjustment to the annual tariff factor to
match annual expenditures. To enable the financing of the
incremental capital expenditures, including regulatory
assets, for electric utilities that serve less than
3,000,000 retail customers but more than 500,000 retail
customers in the State, the utility's actual year-end
capital structure that includes a common equity ratio,
excluding goodwill, of up to and including 54% 50% of the
total capital structure shall be deemed reasonable and
used to set rates.
(2) A utility may recover its costs through an energy

SB0311 - 117 - LRB102 15398 SPS 20761 b
efficiency formula rate approved by the Commission under a
filing under subsections (f) and (g) of this Section,
which shall specify the cost components that form the
basis of the rate charged to customers with sufficient
specificity to operate in a standardized manner and be
updated annually with transparent information that
reflects the utility's actual costs to be recovered during
the applicable rate year, which is the period beginning
with the first billing day of January and extending
through the last billing day of the following December.
The energy efficiency formula rate shall be implemented
through a tariff filed with the Commission under
subsections (f) and (g) of this Section that is consistent
with the provisions of this paragraph (2) and that shall
be applicable to all delivery services customers. The
Commission shall conduct an investigation of the tariff in
a manner consistent with the provisions of this paragraph
(2), subsections (f) and (g) of this Section, and the
provisions of Article IX of this Act to the extent they do
not conflict with this paragraph (2). The energy
efficiency formula rate approved by the Commission shall
remain in effect at the discretion of the utility and
shall do the following:
(A) Provide for the recovery of the utility's
actual costs incurred under this Section that are
prudently incurred and reasonable in amount consistent

SB0311 - 118 - LRB102 15398 SPS 20761 b
with Commission practice and law. The sole fact that a
cost differs from that incurred in a prior calendar
year or that an investment is different from that made
in a prior calendar year shall not imply the
imprudence or unreasonableness of that cost or
investment.
(B) Reflect the utility's actual year-end capital
structure for the applicable calendar year, excluding
goodwill, subject to a determination of prudence and
reasonableness consistent with Commission practice and
law. To enable the financing of the incremental
capital expenditures, including regulatory assets, for
electric utilities that serve less than 3,000,000
retail customers but more than 500,000 retail
customers in the State, a participating electric
utility's actual year-end capital structure that
includes a common equity ratio, excluding goodwill, of
up to and including 54% 50% of the total capital
structure shall be deemed reasonable and used to set
rates.
(C) Include a cost of equity, which in all
calendar years for electric utilities that serve
3,000,000 or more retail customers in this State, and
in each calendar year commencing before January 1,
2021 for electric utilities that serve less than
3,000,000 retail customers but more than 500,000

SB0311 - 119 - LRB102 15398 SPS 20761 b
retail customers in this State, shall be calculated as
the sum of the following:
(i) the average for the applicable calendar
year of the monthly average yields of 30-year U.S.
Treasury bonds published by the Board of Governors
of the Federal Reserve System in its weekly H.15
Statistical Release or successor publication; and
(ii) 580 basis points.
For electric utilities that serve less than
3,000,000 retail customers but more than 500,000
retail customers in this State, for each calendar year
commencing after December 31, 2020, the cost of equity
shall be equal to the national average cost of equity
as calculated under this subparagraph (C) of this
paragraph (2). For purposes of this subparagraph (C)
of this paragraph (2), the national average cost of
equity for an applicable calendar year shall be the
simple average of the cost of equity specified and
approved in each order of a state regulatory
commission, other than the Commission, issued during
such calendar year that is applicable to base rates
for retail electric service provided by an
investor-owned public utility company operating in the
United States. No order shall be excluded from the
national average cost of equity calculated under this
subparagraph (C) of this paragraph (2) on the grounds

SB0311 - 120 - LRB102 15398 SPS 20761 b
that it was arrived at by stipulation or agreement or
is subject to rehearing or appeal. In its final order
in the proceeding, occurring pursuant to subsection
(d) of this Section during calendar year 2021, the
Commission shall set the cost of equity using the
method applicable to calendar years commencing prior
to January 1, 2021. In its final orders in the
proceedings, occurring pursuant to subsection (d) of
this Section in years subsequent to calendar year
2021, including the reconciliation of the 2021 rate
year, the Commission shall set the cost of equity
using the method applicable to calendar years
commencing after December 31, 2020. If, for any
calendar year, there are fewer than 15 applicable
orders of state regulatory commissions with which to
compute the average cost of equity under this
subparagraph (C) of this paragraph (2), the Commission
shall include in the calculation of the national
average the number of state regulatory orders from the
year or years immediately preceding such calendar year
necessary to reach a total of 15, beginning with the
most recently issued and proceeding in reverse
chronological order.
At such time as the Board of Governors of the
Federal Reserve System ceases to include the monthly
average yields of 30-year U.S. Treasury bonds in its

SB0311 - 121 - LRB102 15398 SPS 20761 b
weekly H.15 Statistical Release or successor
publication, the monthly average yields of the U.S.
Treasury bonds then having the longest duration
published by the Board of Governors in its weekly H.15
Statistical Release or successor publication shall
instead be used for purposes of this paragraph (2).
(D) Permit and set forth protocols, subject to a
determination of prudence and reasonableness
consistent with Commission practice and law, for the
following:
(i) recovery of incentive compensation expense
that is based on the achievement of operational
metrics, including metrics related to budget
controls, outage duration and frequency, safety,
customer service, efficiency and productivity, and
environmental compliance; however, this protocol
shall not apply if such expense related to costs
incurred under this Section is recovered under
Article IX or Section 16-108.5 of this Act;
incentive compensation expense that is based on
net income or an affiliate's earnings per share
shall not be recoverable under the energy
efficiency formula rate;
(ii) recovery of pension and other
post-employment benefits expense, provided that
such costs are supported by an actuarial study;

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however, this protocol shall not apply if such
expense related to costs incurred under this
Section is recovered under Article IX or Section
16-108.5 of this Act;
(iii) recovery of existing regulatory assets
over the periods previously authorized by the
Commission;
(iv) as described in subsection (e),
amortization of costs incurred under this Section;
and
(v) projected, weather normalized billing
determinants for the applicable rate year.
(E) Provide for an annual reconciliation, as
described in paragraph (3) of this subsection (d),
less any deferred taxes related to the reconciliation,
with interest at an annual rate of return equal to the
utility's weighted average cost of capital, including
a revenue conversion factor calculated to recover or
refund all additional income taxes that may be payable
or receivable as a result of that return, of the energy
efficiency revenue requirement reflected in rates for
each calendar year, beginning with the calendar year
in which the utility files its energy efficiency
formula rate tariff under this paragraph (2), with
what the revenue requirement would have been had the
actual cost information for the applicable calendar

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year been available at the filing date.
The utility shall file, together with its tariff, the
projected costs to be incurred by the utility during the
rate year under the utility's multi-year plan approved
under subsections (f) and (g) of this Section, including,
but not limited to, the projected capital investment costs
and projected regulatory asset balances with
correspondingly updated depreciation and amortization
reserves and expense, that shall populate the energy
efficiency formula rate and set the initial rates under
the formula.
The Commission shall review the proposed tariff in
conjunction with its review of a proposed multi-year plan,
as specified in paragraph (5) of subsection (g) of this
Section. The review shall be based on the same evidentiary
standards, including, but not limited to, those concerning
the prudence and reasonableness of the costs incurred by
the utility, the Commission applies in a hearing to review
a filing for a general increase in rates under Article IX
of this Act. The initial rates shall take effect beginning
with the January monthly billing period following the
Commission's approval.
The tariff's rate design and cost allocation across
customer classes shall be consistent with the utility's
automatic adjustment clause tariff in effect on June 1,
2017 (the effective date of Public Act 99-906); however,

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the Commission may revise the tariff's rate design and
cost allocation in subsequent proceedings under paragraph
(3) of this subsection (d).
If the energy efficiency formula rate is terminated,
the then current rates shall remain in effect until such
time as the energy efficiency costs are incorporated into
new rates that are set under this subsection (d) or
Article IX of this Act, subject to retroactive rate
adjustment, with interest, to reconcile rates charged with
actual costs.
(3) The provisions of this paragraph (3) shall only
apply to an electric utility that has elected to file an
energy efficiency formula rate under paragraph (2) of this
subsection (d). Subsequent to the Commission's issuance of
an order approving the utility's energy efficiency formula
rate structure and protocols, and initial rates under
paragraph (2) of this subsection (d), the utility shall
file, on or before June 1 of each year, with the Chief
Clerk of the Commission its updated cost inputs to the
energy efficiency formula rate for the applicable rate
year and the corresponding new charges, as well as the
information described in paragraph (9) of subsection (g)
of this Section. Each such filing shall conform to the
following requirements and include the following
information:
(A) The inputs to the energy efficiency formula

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rate for the applicable rate year shall be based on the
projected costs to be incurred by the utility during
the rate year under the utility's multi-year plan
approved under subsections (f) and (g) of this
Section, including, but not limited to, projected
capital investment costs and projected regulatory
asset balances with correspondingly updated
depreciation and amortization reserves and expense.
The filing shall also include a reconciliation of the
energy efficiency revenue requirement that was in
effect for the prior rate year (as set by the cost
inputs for the prior rate year) with the actual
revenue requirement for the prior rate year
(determined using a year-end rate base) that uses
amounts reflected in the applicable FERC Form 1 that
reports the actual costs for the prior rate year. Any
over-collection or under-collection indicated by such
reconciliation shall be reflected as a credit against,
or recovered as an additional charge to, respectively,
with interest calculated at a rate equal to the
utility's weighted average cost of capital approved by
the Commission for the prior rate year, the charges
for the applicable rate year. Such over-collection or
under-collection shall be adjusted to remove any
deferred taxes related to the reconciliation, for
purposes of calculating interest at an annual rate of

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return equal to the utility's weighted average cost of
capital approved by the Commission for the prior rate
year, including a revenue conversion factor calculated
to recover or refund all additional income taxes that
may be payable or receivable as a result of that
return. Each reconciliation shall be certified by the
participating utility in the same manner that FERC
Form 1 is certified. The filing shall also include the
charge or credit, if any, resulting from the
calculation required by subparagraph (E) of paragraph
(2) of this subsection (d).
Notwithstanding any other provision of law to the
contrary, the intent of the reconciliation is to
ultimately reconcile both the revenue requirement
reflected in rates for each calendar year, beginning
with the calendar year in which the utility files its
energy efficiency formula rate tariff under paragraph
(2) of this subsection (d), with what the revenue
requirement determined using a year-end rate base for
the applicable calendar year would have been had the
actual cost information for the applicable calendar
year been available at the filing date.
For purposes of this Section, "FERC Form 1" means
the Annual Report of Major Electric Utilities,
Licensees and Others that electric utilities are
required to file with the Federal Energy Regulatory

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Commission under the Federal Power Act, Sections 3,
4(a), 304 and 209, modified as necessary to be
consistent with 83 Ill. Admin. Code Part 415 as of May
1, 2011. Nothing in this Section is intended to allow
costs that are not otherwise recoverable to be
recoverable by virtue of inclusion in FERC Form 1.
(B) The new charges shall take effect beginning on
the first billing day of the following January billing
period and remain in effect through the last billing
day of the next December billing period regardless of
whether the Commission enters upon a hearing under
this paragraph (3).
(C) The filing shall include relevant and
necessary data and documentation for the applicable
rate year. Normalization adjustments shall not be
required.
Within 45 days after the utility files its annual
update of cost inputs to the energy efficiency formula
rate, the Commission shall with reasonable notice,
initiate a proceeding concerning whether the projected
costs to be incurred by the utility and recovered during
the applicable rate year, and that are reflected in the
inputs to the energy efficiency formula rate, are
consistent with the utility's approved multi-year plan
under subsections (f) and (g) of this Section and whether
the costs incurred by the utility during the prior rate

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year were prudent and reasonable. The Commission shall
also have the authority to investigate the information and
data described in paragraph (9) of subsection (g) of this
Section, including the proposed adjustment to the
utility's return on equity component of its weighted
average cost of capital. During the course of the
proceeding, each objection shall be stated with
particularity and evidence provided in support thereof,
after which the utility shall have the opportunity to
rebut the evidence. Discovery shall be allowed consistent
with the Commission's Rules of Practice, which Rules of
Practice shall be enforced by the Commission or the
assigned administrative law judge. The Commission shall
apply the same evidentiary standards, including, but not
limited to, those concerning the prudence and
reasonableness of the costs incurred by the utility,
during the proceeding as it would apply in a proceeding to
review a filing for a general increase in rates under
Article IX of this Act. The Commission shall not, however,
have the authority in a proceeding under this paragraph
(3) to consider or order any changes to the structure or
protocols of the energy efficiency formula rate approved
under paragraph (2) of this subsection (d). In a
proceeding under this paragraph (3), the Commission shall
enter its order no later than the earlier of 195 days after
the utility's filing of its annual update of cost inputs

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to the energy efficiency formula rate or December 15. The
utility's proposed return on equity calculation, as
described in paragraphs (7) through (9) of subsection (g)
of this Section, shall be deemed the final, approved
calculation on December 15 of the year in which it is filed
unless the Commission enters an order on or before
December 15, after notice and hearing, that modifies such
calculation consistent with this Section. The Commission's
determinations of the prudence and reasonableness of the
costs incurred, and determination of such return on equity
calculation, for the applicable calendar year shall be
final upon entry of the Commission's order and shall not
be subject to reopening, reexamination, or collateral
attack in any other Commission proceeding, case, docket,
order, rule, or regulation; however, nothing in this
paragraph (3) shall prohibit a party from petitioning the
Commission to rehear or appeal to the courts the order
under the provisions of this Act.
(e) Beginning on June 1, 2017 (the effective date of
Public Act 99-906), a utility subject to the requirements of
this Section may elect to defer, as a regulatory asset, up to
the full amount of its expenditures incurred under this
Section for each annual period, including, but not limited to,
any expenditures incurred above the funding level set by
subsection (f) of this Section for a given year. The total
expenditures deferred as a regulatory asset in a given year

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shall be amortized and recovered over a period that is equal to
the weighted average of the energy efficiency measure lives
implemented for that year that are reflected in the regulatory
asset. The unamortized balance shall be recognized as of
December 31 for a given year. The utility shall also earn a
return on the total of the unamortized balances of all of the
energy efficiency regulatory assets, less any deferred taxes
related to those unamortized balances, at an annual rate equal
to the utility's weighted average cost of capital that
includes, based on a year-end capital structure, the utility's
actual cost of debt for the applicable calendar year and a cost
of equity, which shall be calculated in accordance with the
calculations set forth in subparagraph (C) of paragraph (2) of
subsection (d) of this Section as the sum of the (i) the
average for the applicable calendar year of the monthly
average yields of 30-year U.S. Treasury bonds published by the
Board of Governors of the Federal Reserve System in its weekly
H.15 Statistical Release or successor publication; and (ii)
580 basis points, including a revenue conversion factor
calculated to recover or refund all additional income taxes
that may be payable or receivable as a result of that return.
Capital investment costs shall be depreciated and recovered
over their useful lives consistent with generally accepted
accounting principles. The weighted average cost of capital
shall be applied to the capital investment cost balance, less
any accumulated depreciation and accumulated deferred income

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taxes, as of December 31 for a given year.
When an electric utility creates a regulatory asset under
the provisions of this Section, the costs are recovered over a
period during which customers also receive a benefit which is
in the public interest. Accordingly, it is the intent of the
General Assembly that an electric utility that elects to
create a regulatory asset under the provisions of this Section
shall recover all of the associated costs as set forth in this
Section. After the Commission has approved the prudence and
reasonableness of the costs that comprise the regulatory
asset, the electric utility shall be permitted to recover all
such costs, and the value and recoverability through rates of
the associated regulatory asset shall not be limited, altered,
impaired, or reduced.
(f) Beginning in 2017, each electric utility shall file an
energy efficiency plan with the Commission to meet the energy
efficiency standards for the next applicable multi-year period
beginning January 1 of the year following the filing,
according to the schedule set forth in paragraphs (1) through
(3) of this subsection (f). If a utility does not file such a
plan on or before the applicable filing deadline for the plan,
it shall face a penalty of $100,000 per day until the plan is
filed.
(1) No later than 30 days after June 1, 2017 (the
effective date of Public Act 99-906), each electric
utility shall file a 4-year energy efficiency plan

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commencing on January 1, 2018 that is designed to achieve
the cumulative persisting annual savings goals specified
in paragraphs (1) through (4) of subsection (b-5) of this
Section or in paragraphs (1) through (4) of subsection
(b-15) of this Section, as applicable, through
implementation of energy efficiency measures; however, the
goals may be reduced if the utility's expenditures are
limited pursuant to subsection (m) of this Section or, for
a utility that serves less than 3,000,000 retail
customers, if each of the following conditions are met:
(A) the plan's analysis and forecasts of the utility's
ability to acquire energy savings demonstrate that
achievement of such goals is not cost effective; and (B)
the amount of energy savings achieved by the utility as
determined by the independent evaluator for the most
recent year for which savings have been evaluated
preceding the plan filing was less than the average annual
amount of savings required to achieve the goals for the
applicable 4-year plan period. Except as provided in
subsection (m) of this Section, annual increases in
cumulative persisting annual savings goals during the
applicable 4-year plan period shall not be reduced to
amounts that are less than the maximum amount of
cumulative persisting annual savings that is forecast to
be cost-effectively achievable during the 4-year plan
period. The Commission shall review any proposed goal

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reduction as part of its review and approval of the
utility's proposed plan.
(2) No later than March 1, 2021, each electric utility
shall file a 4-year energy efficiency plan commencing on
January 1, 2022 that is designed to achieve the cumulative
persisting annual savings goals specified in paragraphs
(5) through (8) of subsection (b-5) of this Section or in
paragraphs (5) through (8) of subsection (b-15) of this
Section, as applicable, through implementation of energy
efficiency measures; however, the goals may be reduced if
the utility's expenditures are limited pursuant to
subsection (m) of this Section or, each of the following
conditions are met: (A) the plan's analysis and forecasts
of the utility's ability to acquire energy savings
demonstrate that achievement of such goals is not cost
effective; and (B) the amount of energy savings achieved
by the utility as determined by the independent evaluator
for the most recent year for which savings have been
evaluated preceding the plan filing was less than the
average annual amount of savings required to achieve the
goals for the applicable 4-year plan period. Except as
provided in subsection (m) of this Section, annual
increases in cumulative persisting annual savings goals
during the applicable 4-year plan period shall not be
reduced to amounts that are less than the maximum amount
of cumulative persisting annual savings that is forecast

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

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reduced to amounts that are less than the maximum amount
of cumulative persisting annual savings that is forecast
to be cost-effectively achievable during the 5-year plan
period. The Commission shall review any proposed goal
reduction as part of its review and approval of the
utility's proposed plan.
Each utility's plan shall set forth the utility's
proposals to meet the energy efficiency standards identified
in subsection (b-5) or (b-15), as applicable and as such
standards may have been modified under this subsection (f),
taking into account the unique circumstances of the utility's
service territory. For those plans commencing on January 1,
2018, the Commission shall seek public comment on the
utility's plan and shall issue an order approving or
disapproving each plan no later than 105 days after June 1,
2017 (the effective date of Public Act 99-906). For those
plans commencing after December 31, 2021, the Commission shall
seek public comment on the utility's plan and shall issue an
order approving or disapproving each plan within 6 months
after its submission. If the Commission disapproves a plan,
the Commission shall, within 30 days, describe in detail the
reasons for the disapproval and describe a path by which the
utility may file a revised draft of the plan to address the
Commission's concerns satisfactorily. If the utility does not
refile with the Commission within 60 days, the utility shall
be subject to penalties at a rate of $100,000 per day until the

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plan is filed. This process shall continue, and penalties
shall accrue, until the utility has successfully filed a
portfolio of energy efficiency and demand-response measures.
Penalties shall be deposited into the Energy Efficiency Trust
Fund.
(g) In submitting proposed plans and funding levels under
subsection (f) of this Section to meet the savings goals
identified in subsection (b-5) or (b-15) of this Section, as
applicable, the utility shall:
(1) Demonstrate that its proposed energy efficiency
measures will achieve the applicable requirements that are
identified in subsection (b-5) or (b-15) of this Section,
as modified by subsection (f) of this Section.
(2) Present specific proposals to implement new
building and appliance standards that have been placed
into effect.
(3) Demonstrate that its overall portfolio of
measures, not including low-income programs described in
subsection (c) of this Section, is cost-effective using
the total resource cost test or complies with paragraphs
(1) through (3) of subsection (f) of this Section and
represents a diverse cross-section of opportunities for
customers of all rate classes, other than those customers
described in subsection (l) of this Section, to
participate in the programs. Individual measures need not
be cost effective.

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(4) Present a third-party energy efficiency
implementation program subject to the following
requirements:
(A) beginning with the year commencing January 1,
2019, electric utilities that serve more than
3,000,000 retail customers in the State shall fund
third-party energy efficiency programs in an amount
that is no less than $25,000,000 per year, and
electric utilities that serve less than 3,000,000
retail customers but more than 500,000 retail
customers in the State shall fund third-party energy
efficiency programs in an amount that is no less than
$8,350,000 per year;
(B) during 2018, the utility shall conduct a
solicitation process for purposes of requesting
proposals from third-party vendors for those
third-party energy efficiency programs to be offered
during one or more of the years commencing January 1,
2019, January 1, 2020, and January 1, 2021; for those
multi-year plans commencing on January 1, 2022 and
January 1, 2026, the utility shall conduct a
solicitation process during 2021 and 2025,
respectively, for purposes of requesting proposals
from third-party vendors for those third-party energy
efficiency programs to be offered during one or more
years of the respective multi-year plan period; for

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each solicitation process, the utility shall identify
the sector, technology, or geographical area for which
it is seeking requests for proposals;
(C) the utility shall propose the bidder
qualifications, performance measurement process, and
contract structure, which must include a performance
payment mechanism and general terms and conditions;
the proposed qualifications, process, and structure
shall be subject to Commission approval; and
(D) the utility shall retain an independent third
party to score the proposals received through the
solicitation process described in this paragraph (4),
rank them according to their cost per lifetime
kilowatt-hours saved, and assemble the portfolio of
third-party programs.
The electric utility shall recover all costs
associated with Commission-approved, third-party
administered programs regardless of the success of those
programs.
(4.5) Implement cost-effective demand-response
measures to reduce peak demand by 0.1% over the prior year
for eligible retail customers, as defined in Section
16-111.5 of this Act, and for customers that elect hourly
service from the utility pursuant to Section 16-107 of
this Act, provided those customers have not been declared
competitive. This requirement continues until December 31,

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2026.
(5) Include a proposed or revised cost-recovery tariff
mechanism, as provided for under subsection (d) of this
Section, to fund the proposed energy efficiency and
demand-response measures and to ensure the recovery of the
prudently and reasonably incurred costs of
Commission-approved programs.
(6) Provide for an annual independent evaluation of
the performance of the cost-effectiveness of the utility's
portfolio of measures, as well as a full review of the
multi-year plan results of the broader net program impacts
and, to the extent practical, for adjustment of the
measures on a going-forward basis as a result of the
evaluations. For purposes of evaluating the
cost-effectiveness of measures that incentivize,
encourage, or otherwise support the purchase of vehicles
that use electricity for power, in whole or in part,
including, but not limited to, cars, trucks, buses,
trains, trolleys, boats, on-road or off-road vehicles, or
other equipment or methods of transporting goods or
people, including, but not limited to, measures that
incentivize, encourage, or otherwise support the adoption
of electric vehicles by retail customers of all customer
classes, the independent evaluation shall include
valuation and consideration of the reduction of carbon
emissions and avoided costs associated with the reduction

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in fossil fuel consumption associated with the measures.
The resources dedicated to evaluation shall not exceed 3%
of portfolio resources in any given year.
(7) For electric utilities that serve more than
3,000,000 retail customers in the State:
(A) Through December 31, 2025, provide for an
adjustment to the return on equity component of the
utility's weighted average cost of capital calculated
under subsection (d) of this Section:
(i) If the independent evaluator determines
that the utility achieved a cumulative persisting
annual savings that is less than the applicable
annual incremental goal, then the return on equity
component shall be reduced by a maximum of 200
basis points in the event that the utility
achieved no more than 75% of such goal. If the
utility achieved more than 75% of the applicable
annual incremental goal but less than 100% of such
goal, then the return on equity component shall be
reduced by 8 basis points for each percent by
which the utility failed to achieve the goal.
(ii) If the independent evaluator determines
that the utility achieved a cumulative persisting
annual savings that is more than the applicable
annual incremental goal, then the return on equity
component shall be increased by a maximum of 200

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basis points in the event that the utility
achieved at least 125% of such goal. If the
utility achieved more than 100% of the applicable
annual incremental goal but less than 125% of such
goal, then the return on equity component shall be
increased by 8 basis points for each percent by
which the utility achieved above the goal. If the
applicable annual incremental goal was reduced
under paragraphs (1) or (2) of subsection (f) of
this Section, then the following adjustments shall
be made to the calculations described in this item
(ii):
(aa) the calculation for determining
achievement that is at least 125% of the
applicable annual incremental goal shall use
the unreduced applicable annual incremental
goal to set the value; and
(bb) the calculation for determining
achievement that is less than 125% but more
than 100% of the applicable annual incremental
goal shall use the reduced applicable annual
incremental goal to set the value for 100%
achievement of the goal and shall use the
unreduced goal to set the value for 125%
achievement. The 8 basis point value shall
also be modified, as necessary, so that the

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200 basis points are evenly apportioned among
each percentage point value between 100% and
125% achievement.
(B) For the period January 1, 2026 through
December 31, 2030, provide for an adjustment to the
return on equity component of the utility's weighted
average cost of capital calculated under subsection
(d) of this Section:
(i) If the independent evaluator determines
that the utility achieved a cumulative persisting
annual savings that is less than the applicable
annual incremental goal, then the return on equity
component shall be reduced by a maximum of 200
basis points in the event that the utility
achieved no more than 66% of such goal. If the
utility achieved more than 66% of the applicable
annual incremental goal but less than 100% of such
goal, then the return on equity component shall be
reduced by 6 basis points for each percent by
which the utility failed to achieve the goal.
(ii) If the independent evaluator determines
that the utility achieved a cumulative persisting
annual savings that is more than the applicable
annual incremental goal, then the return on equity
component shall be increased by a maximum of 200
basis points in the event that the utility

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achieved at least 134% of such goal. If the
utility achieved more than 100% of the applicable
annual incremental goal but less than 134% of such
goal, then the return on equity component shall be
increased by 6 basis points for each percent by
which the utility achieved above the goal. If the
applicable annual incremental goal was reduced
under paragraph (3) of subsection (f) of this
Section, then the following adjustments shall be
made to the calculations described in this item
(ii):
(aa) the calculation for determining
achievement that is at least 134% of the
applicable annual incremental goal shall use
the unreduced applicable annual incremental
goal to set the value; and
(bb) the calculation for determining
achievement that is less than 134% but more
than 100% of the applicable annual incremental
goal shall use the reduced applicable annual
incremental goal to set the value for 100%
achievement of the goal and shall use the
unreduced goal to set the value for 134%
achievement. The 6 basis point value shall
also be modified, as necessary, so that the
200 basis points are evenly apportioned among

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each percentage point value between 100% and
134% achievement.
(7.5) For purposes of this Section, the term
"applicable annual incremental goal" means the difference
between the cumulative persisting annual savings goal for
the calendar year that is the subject of the independent
evaluator's determination and the cumulative persisting
annual savings goal for the immediately preceding calendar
year, as such goals are defined in subsections (b-5) and
(b-15) of this Section and as these goals may have been
modified as provided for under subsection (b-20) and
paragraphs (1) through (3) of subsection (f) of this
Section. Under subsections (b), (b-5), (b-10), and (b-15)
of this Section, a utility must first replace energy
savings from measures that have reached the end of their
measure lives and would otherwise have to be replaced to
meet the applicable savings goals identified in subsection
(b-5) or (b-15) of this Section before any progress
towards achievement of its applicable annual incremental
goal may be counted. Notwithstanding anything else set
forth in this Section, the difference between the actual
annual incremental savings achieved in any given year,
including the replacement of energy savings from measures
that have expired, and the applicable annual incremental
goal shall not affect adjustments to the return on equity
for subsequent calendar years under this subsection (g).

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(8) For electric utilities that serve less than
3,000,000 retail customers but more than 500,000 retail
customers in the State:
(A) Through December 31, 2025, the applicable
annual incremental goal shall be compared to the
annual incremental savings as determined by the
independent evaluator.
(i) The return on equity component shall be
reduced by 8 basis points for each percent by
which the utility did not achieve 84.4% of the
applicable annual incremental goal.
(ii) The return on equity component shall be
increased by 8 basis points for each percent by
which the utility exceeded 100% of the applicable
annual incremental goal.
(iii) The return on equity component shall not
be increased or decreased if the annual
incremental savings as determined by the
independent evaluator is greater than 84.4% of the
applicable annual incremental goal and less than
100% of the applicable annual incremental goal.
(iv) The return on equity component shall not
be increased or decreased by an amount greater
than 200 basis points pursuant to this
subparagraph (A).
(B) For the period of January 1, 2026 through

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December 31, 2030, the applicable annual incremental
goal shall be compared to the annual incremental
savings as determined by the independent evaluator.
(i) The return on equity component shall be
reduced by 6 basis points for each percent by
which the utility did not achieve 100% of the
applicable annual incremental goal.
(ii) The return on equity component shall be
increased by 6 basis points for each percent by
which the utility exceeded 100% of the applicable
annual incremental goal.
(iii) The return on equity component shall not
be increased or decreased by an amount greater
than 200 basis points pursuant to this
subparagraph (B).
(C) If the applicable annual incremental goal was
reduced under paragraphs (1), (2) or (3) of subsection
(f) of this Section, then the following adjustments
shall be made to the calculations described in
subparagraphs (A) and (B) of this paragraph (8):
(i) The calculation for determining
achievement that is at least 125% or 134%, as
applicable, of the applicable annual incremental
goal shall use the unreduced applicable annual
incremental goal to set the value.
(ii) For the period through December 31, 2025,

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the calculation for determining achievement that
is less than 125% but more than 100% of the
applicable annual incremental goal shall use the
reduced applicable annual incremental goal to set
the value for 100% achievement of the goal and
shall use the unreduced goal to set the value for
125% achievement. The 8 basis point value shall
also be modified, as necessary, so that the 200
basis points are evenly apportioned among each
percentage point value between 100% and 125%
achievement.
(iii) For the period of January 1, 2026
through December 31, 2030, the calculation for
determining achievement that is less than 134% but
more than 100% of the applicable annual
incremental goal shall use the reduced applicable
annual incremental goal to set the value for 100%
achievement of the goal and shall use the
unreduced goal to set the value for 125%
achievement. The 6 basis point value shall also be
modified, as necessary, so that the 200 basis
points are evenly apportioned among each
percentage point value between 100% and 134%
achievement.
(8.5) Electric utilities that serve less than
3,000,000 retail customers but more than 500,000 retail

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customers in this State may identify, at the electric
utility's sole discretion, cost-effective measures that
educate about, incentivize, encourage, or otherwise
support the use of electricity to power, in whole or in
part, vehicles, including, but not limited to, cars,
trucks, buses, trains, trolleys, boats, on-road or
off-road vehicles, or other equipment or methods of
transporting goods or people. Such measures may include,
but are not limited to, measures that educate about,
incentivize, encourage, or otherwise support the adoption
of electric vehicles by retail customers of all rate
classes.
(9) The utility shall submit the energy savings data
to the independent evaluator no later than 30 days after
the close of the plan year. The independent evaluator
shall determine the cumulative persisting annual savings
for a given plan year no later than 120 days after the
close of the plan year. The utility shall submit an
informational filing to the Commission no later than 160
days after the close of the plan year that attaches the
independent evaluator's final report identifying the
cumulative persisting annual savings for the year and
calculates, under paragraph (7) or (8) of this subsection
(g), as applicable, any resulting change to the utility's
return on equity component of the weighted average cost of
capital applicable to the next plan year beginning with

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the January monthly billing period and extending through
the December monthly billing period. However, if the
utility recovers the costs incurred under this Section
under paragraphs (2) and (3) of subsection (d) of this
Section, then the utility shall not be required to submit
such informational filing, and shall instead submit the
information that would otherwise be included in the
informational filing as part of its filing under paragraph
(3) of such subsection (d) that is due on or before June 1
of each year.
For those utilities that must submit the informational
filing, the Commission may, on its own motion or by
petition, initiate an investigation of such filing,
provided, however, that the utility's proposed return on
equity calculation shall be deemed the final, approved
calculation on December 15 of the year in which it is filed
unless the Commission enters an order on or before
December 15, after notice and hearing, that modifies such
calculation consistent with this Section.
The adjustments to the return on equity component
described in paragraphs (7) and (8) of this subsection (g)
shall be applied as described in such paragraphs through a
separate tariff mechanism, which shall be filed by the
utility under subsections (f) and (g) of this Section.
(h) Other than measures authorized by subsection (n) of
this Section or identified pursuant to paragraph (8.5) of

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subsection (g) of this Section, no No more than 6% of energy
efficiency and demand-response program revenue may be
allocated for research, development, or pilot deployment of
new equipment or measures.
(i) When practicable, electric utilities shall incorporate
advanced metering infrastructure data into the planning,
implementation, and evaluation of energy efficiency measures
and programs, subject to the data privacy and confidentiality
protections of applicable law.
(j) The independent evaluator shall follow the guidelines
and use the savings set forth in Commission-approved energy
efficiency policy manuals and technical reference manuals, as
each may be updated from time to time. Until such time as
measure life values for energy efficiency measures implemented
for low-income households under subsection (c) of this Section
are incorporated into such Commission-approved manuals, the
low-income measures shall have the same measure life values
that are established for same measures implemented in
households that are not low-income households.
Commencing on the effective date of this amendatory Act of
the 102nd General Assembly, the following provisions shall
apply to electric utilities that serve less than 3,000,000
retail customers but more than 500,000 retail customers in
this State:
(1) Starting in the year in which this amendatory Act
of the 102nd General Assembly takes effect and continuing

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for a period of 5 calendar years thereafter, the savings
achieved by energy efficiency measures authorized by
subsection (n) of this Section or identified pursuant to
paragraph (8.5) of subsection (g) of this Section, shall
be evaluated using the following parameters:
(A) the evaluation shall use a factor of 1.50
pounds of carbon dioxide emitted per kilowatt hour of
electric energy used for vehicle operation, adjusted
each year starting with the year in which this
amendatory Act of the 102nd General Assembly takes
effect to reflect the annual increase of renewable
resource procurement as set forth in subsection (c) of
Section 1-75 of the Illinois Power Agency Act;
(B) the evaluation shall use a heat rate of fossil
fuel electric generating units of 7,939 Btu per
kilowatt hour, adjusted each year starting with the
year in which this amendatory Act of the 102nd General
Assembly takes effect to reflect the annual increase
of renewable resource procurement as set forth in
subsection (c) of Section 1-75 of the Illinois Power
Agency Act;
(C) the evaluation shall include any netting of
electricity used by the electric vehicle, as
calculated using the parameters provided for in
paragraph (2) of this subsection (j);
(D) the evaluation shall use a net to gross ratio

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of 1.0 for each measure evaluated; and
(E) all savings achieved by the measures evaluated
shall persist for the life of the measure, without
degradation.
(2) Starting in the year in which this amendatory Act
of the 102nd General Assembly takes effect and continuing
for a period of 5 calendar years thereafter, the savings
achieved by energy efficiency measures authorized by
subsection (n) of this Section or identified pursuant to
paragraph (8.5) of subsection (g) of this Section that are
applicable to passenger vehicles shall, in addition to the
parameters identified in paragraph (1) of this subsection
(j), be evaluated using the following parameters:
(A) the measure life of measures that incentivize
or otherwise encourage the purchase of electric
vehicles shall be 13 years from the date of original
purchase by the customer;
(B) the evaluation shall use a value of 11,500
vehicle miles traveled for annual vehicle operation;
(C) the evaluation shall use a fossil fuel vehicle
economy value equal to 28 miles per gallon of fossil
fuel used for vehicle operation;
(D) the evaluation shall use a conversion factor
of 120,429 Btus per gallon of fossil fuel used for
vehicle operation;
(E) the evaluation shall use a factor of 161

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pounds of carbon dioxide emitted per million Btu of
fossil fuel used for vehicle operation;
(F) the evaluation shall use a factor of 8.78
kilograms of carbon dioxide emitted per gallon of
fossil fuel used for vehicle operation;
(G) the evaluation shall use an annual value of
fossil fuel saved of 50 MMBtu; and
(H) the evaluation shall use an electric vehicle
efficiency value of 30 kilowatt hours per 100 miles
traveled for vehicle operation.
(3) Any additional evaluation criteria not identified
in paragraph (1) or (2) of this subsection (j) used to
evaluate savings achieved by energy efficiency measures
authorized by subsection (n) of this Section or identified
pursuant to paragraph (8.5) of subsection (g) of this
Section shall follow the guidelines and use the savings
set forth in Commission-approved energy efficiency policy
manuals and technical reference manuals, as each may be
updated from time to time.
(k) Notwithstanding any provision of law to the contrary,
an electric utility subject to the requirements of this
Section may file a tariff cancelling an automatic adjustment
clause tariff in effect under this Section or Section 8-103,
which shall take effect no later than one business day after
the date such tariff is filed. Thereafter, the utility shall
be authorized to defer and recover its expenditures incurred

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under this Section through a new tariff authorized under
subsection (d) of this Section or in the utility's next rate
case under Article IX or Section 16-108.5 of this Act, with
interest at an annual rate equal to the utility's weighted
average cost of capital as approved by the Commission in such
case. If the utility elects to file a new tariff under
subsection (d) of this Section, the utility may file the
tariff within 10 days after June 1, 2017 (the effective date of
Public Act 99-906), and the cost inputs to such tariff shall be
based on the projected costs to be incurred by the utility
during the calendar year in which the new tariff is filed and
that were not recovered under the tariff that was cancelled as
provided for in this subsection. Such costs shall include
those incurred or to be incurred by the utility under its
multi-year plan approved under subsections (f) and (g) of this
Section, including, but not limited to, projected capital
investment costs and projected regulatory asset balances with
correspondingly updated depreciation and amortization reserves
and expense. The Commission shall, after notice and hearing,
approve, or approve with modification, such tariff and cost
inputs no later than 75 days after the utility filed the
tariff, provided that such approval, or approval with
modification, shall be consistent with the provisions of this
Section to the extent they do not conflict with this
subsection (k). The tariff approved by the Commission shall
take effect no later than 5 days after the Commission enters

SB0311 - 155 - LRB102 15398 SPS 20761 b
its order approving the tariff.
No later than 60 days after the effective date of the
tariff cancelling the utility's automatic adjustment clause
tariff, the utility shall file a reconciliation that
reconciles the moneys collected under its automatic adjustment
clause tariff with the costs incurred during the period
beginning June 1, 2016 and ending on the date that the electric
utility's automatic adjustment clause tariff was cancelled. In
the event the reconciliation reflects an under-collection, the
utility shall recover the costs as specified in this
subsection (k). If the reconciliation reflects an
over-collection, the utility shall apply the amount of such
over-collection as a one-time credit to retail customers'
bills.
(l) For the calendar years covered by a multi-year plan
commencing after December 31, 2017, subsections (a) through
(j) of this Section do not apply to any retail customers of an
electric utility that serves more than 3,000,000 retail
customers in the State and whose total highest 30 minute
demand was more than 10,000 kilowatts, or any retail customers
of an electric utility that serves less than 3,000,000 retail
customers but more than 500,000 retail customers in the State
and whose total highest 15 minute demand was more than 10,000
kilowatts. For purposes of this subsection (l), "retail
customer" has the meaning set forth in Section 16-102 of this
Act. A determination of whether this subsection is applicable

SB0311 - 156 - LRB102 15398 SPS 20761 b
to a customer shall be made for each multi-year plan beginning
after December 31, 2017. The criteria for determining whether
this subsection (l) is applicable to a retail customer shall
be based on the 12 consecutive billing periods prior to the
start of the first year of each such multi-year plan.
(m) Notwithstanding the requirements of this Section, as
part of a proceeding to approve a multi-year plan under
subsections (f) and (g) of this Section, the Commission shall
reduce the amount of energy efficiency measures implemented
for any single year, and whose costs are recovered under
subsection (d) of this Section, by an amount necessary to
limit the estimated average net increase due to the cost of the
measures to no more than
(1) 3.5% for each of the 4 years beginning January 1,
2018,
(2) 3.75% for each of the 4 years beginning January 1,
2022, and
(3) 4% for each of the 5 years beginning January 1,
2026,
of the average amount paid per kilowatthour by residential
eligible retail customers during calendar year 2015. To
determine the total amount that may be spent by an electric
utility in any single year, the applicable percentage of the
average amount paid per kilowatthour shall be multiplied by
the total amount of energy delivered by such electric utility
in the calendar year 2015, adjusted to reflect the proportion

SB0311 - 157 - LRB102 15398 SPS 20761 b
of the utility's load attributable to customers who are exempt
from subsections (a) through (j) of this Section under
subsection (l) of this Section. For purposes of this
subsection (m), the amount paid per kilowatthour includes,
without limitation, estimated amounts paid for supply,
transmission, distribution, surcharges, and add-on taxes. For
purposes of this Section, "eligible retail customers" shall
have the meaning set forth in Section 16-111.5 of this Act.
Once the Commission has approved a plan under subsections (f)
and (g) of this Section, no subsequent rate impact
determinations shall be made.
(n) Starting on the effective date of this amendatory Act
of the 102nd General Assembly, electric utilities that serve
less than 3,000,000 retail customers but more than 500,000
retail customers in this State may administer programs and
implement cost-effective measures that educate about,
incentivize, encourage, or otherwise support the use of
electricity to power, in whole or in part, vehicles,
including, but not limited to, cars, trucks, buses, trains,
trolleys, boats, on-road or off-road vehicles, or other
equipment or methods of transporting goods or people. Such
programs and measures may be implemented as part of a plan
approved pursuant to subsection (f) of this Section and may
include, but are not limited to, measures that educate about,
incentivize, encourage, or otherwise support the adoption of
electric vehicles by retail customers of all customer classes.

SB0311 - 158 - LRB102 15398 SPS 20761 b
Programs and measures authorized by this subsection (n) and
identified pursuant to paragraph (8.5) of subsection (g) shall
not be prohibited by the Commission as promotional practices
under any rules or policies of the Commission, including, but
not limited to, 83 Ill. Adm. Code Part 275.
(Source: P.A. 100-840, eff. 8-13-18; 101-81, eff. 7-12-19.)
(220 ILCS 5/8-218 new)
Sec. 8-218. Electric photovoltaic generating facilities.
(a) The General Assembly finds and declares that the
citizens and businesses of the State of Illinois would be
well-served by the development of photovoltaic electricity
production facilities in this State, which would both bring
economic benefits and environmental benefits to the State and
further expand access to renewable energy resources at an
affordable cost to Illinois residents, particularly in those
areas of the State that have been significantly and adversely
affected by the retirement of coal-fired electric generating
plants. To that end, the General Assembly seeks to encourage
further development of photovoltaic electric production
facilities of all scales in an efficient and cost-effective
manner. Accordingly, the General Assembly finds that,
notwithstanding other provisions of this Act to the contrary,
it would be both prudent and reasonable for electric utilities
in this State to plan for, construct, install, control, own,
manage, or operate photovoltaic electricity production

SB0311 - 159 - LRB102 15398 SPS 20761 b
facilities pursuant to the provisions of this Section.
(b) 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 as authorized under Section
16-108.20 of this Act that are planned for, constructed,
installed, controlled, owned, managed, or operated in
connection with photovoltaic electricity production facilities
authorized under this Section without obtaining a certificate
of public convenience and necessity pursuant to Section 8-406
of this Act, subject to the following terms and conditions:
(1) the electric utility may plan for, construct,
install, control, own, manage, or operate photovoltaic
electricity production facilities of any type or scale,
including, but not limited to, large scale (greater than 2
MW), small scale (less than or equal to 2 MW), and
community solar projects; for purposes of this Section,
"community solar projects" includes community solar
facilities with a nameplate capacity up to and including
10,000 kilowatts that are connected to either the
distribution system or transmission system of the electric
utility;
(2) photovoltaic electricity production facilities
authorized pursuant to this Section shall be deemed for
all purposes under this Act as prudent and used and

SB0311 - 160 - LRB102 15398 SPS 20761 b
useful, including under the provisions of Section 9-212 of
this Act, and, subject to the provisions set forth in this
Section, the Commission may not limit recovery of any
portion of the reasonable costs of the photovoltaic
electricity production facilities authorized pursuant to
this Section on the grounds that the facilities are not
prudent or used and useful;
(3) the electric utility's costs of planning for,
constructing, installing, controlling, owning, managing,
or operating the photovoltaic electricity production
facilities shall be recovered, on a kilowatt hour basis,
in the electric utility's rates for delivery service
established pursuant to Article XVI or Article IX of this
Act, and for purposes of cost recovery the photovoltaic
electricity production facilities, shall be treated as
distribution assets, provided: (1) the Commission shall
have the authority to determine the reasonableness of the
costs of the facilities, (2) any monetary value of power
and energy from the facilities shall be credited against
the delivery services revenue requirement, and (3) all
renewable energy credits associated with the photovoltaic
electricity production facilities shall be retired on
behalf of the electric utility's distribution customers
and may not be sold or used for any other purposes by the
electric utility other than satisfying the electric
utility's requirements under subsection (c) of Section

SB0311 - 161 - LRB102 15398 SPS 20761 b
1-75 of the Illinois Power Agency Act;
(4) the annual quantity of renewable energy credits
generated from the photovoltaic electricity production
facilities placed in service by an electric utility
pursuant to this Section after the effective date of this
amendatory Act of the 102nd General Assembly shall not
exceed 20% of the electric utility's requirements under
subsection (c) of Section 1-75 of the Illinois Power
Agency Act; and
(5) the electric utility shall certify that not less
than the prevailing wage, as determined pursuant to the
Prevailing Wage Act, was or will be paid to employees who
are engaged in construction activities associated with the
photovoltaic electric production facilities authorized
under this Section.
If an electric utility requires approval under Section
7-101 or 7-102 of this Act in connection with the
construction, installation, control, ownership, management, or
operation of photovoltaic electricity production facilities
pursuant to this Section, the Commission shall issue its Order
granting or denying such approval within 150 days after a
petition for such approval is filed.
For purposes of this Section, "electric utility" has the
meaning set forth in Section 16-102 of this Act.
(c) Notwithstanding anything to the contrary in the
Illinois Power Agency Act or this Act, the Illinois Power

SB0311 - 162 - LRB102 15398 SPS 20761 b
Agency shall apply any renewable energy credits associated
with photovoltaic electricity production facilities meeting
the criteria set forth in subsection (b) of this Section to the
electric utility's requirements under subsection (c) of
Section 1-75 of the Illinois Power Agency Act. No cost
associated with facilities placed in service pursuant to this
Section shall be included when calculating the limitation
under subparagraph (E) of paragraph (1) of subsection (c) of
Section 1-75 of the Illinois Power Agency Act.
(220 ILCS 5/9-244.5 new)
Sec. 9-244.5. Natural gas investment and modernization;
regulatory reform.
(a) The General Assembly finds that regulatory reform
measures that increase predictability, stability, and
transparency in the ratemaking process are needed to promote
prudent, long-term infrastructure investment and to mutually
benefit the State's natural gas utilities and their customers,
regulators, and investors.
(b) For purposes of this Section, "participating gas
utility" means a public utility that, as of January 1, 2020,
provided electric service to at least 1,000,000 retail
customers in Illinois and gas service to at least 500,000
retail customers in Illinois.
(c) A participating gas utility may elect to recover its
natural gas delivery services costs through a

SB0311 - 163 - LRB102 15398 SPS 20761 b
performance-based rate, which shall be approved by the
Commission and which shall specify the cost components that
form the basis of the rate charged to customers with
sufficient specificity to operate in a standardized manner and
be updated annually with transparent information that reflects
the participating gas utility's actual costs to be recovered
during the applicable year, which is the period beginning with
the first billing day of January and extending through the
last billing day of the following December. In the event the
participating gas utility recovers a portion of its costs
through automatic adjustment clause tariffs on the effective
date of the Act, other than a surcharge tariff under paragraph
(3) of subsection (a) of Section 9-220.3, the participating
gas utility may elect to continue to recover these costs
through such tariffs, but such costs shall not be recovered
through the performance based rate as long as the
participating gas utility elects to recover such costs through
such automatic adjustment clause tariffs.
The performance-based rate shall be implemented through a
tariff filed with the Commission consistent with the
provisions of this subsection (c) that shall be applicable to
all natural gas delivery services customers. The Commission
shall initiate and conduct an investigation of the tariff in a
manner consistent with the provisions of this subsection (c)
and the provisions of Article IX of this Act to the extent they
do not conflict with this subsection (c). The

SB0311 - 164 - LRB102 15398 SPS 20761 b
performance-based rate shall remain in effect at the
discretion of the participating gas utility.
The performance-based rate approved by the Commission
shall do the following:
(1) Provide for the recovery of the participating gas
utility's actual costs of natural gas delivery services
that are prudently incurred and reasonable in amount
consistent with Commission practice and law. The sole fact
that a cost differs from that incurred in a prior calendar
year or that an investment is different from that made in a
prior calendar year shall not imply the imprudence or
unreasonableness of that cost or investment.
(2) Reflect the utility's actual year-end capital
structure for the applicable calendar year, excluding
goodwill, subject to a determination of prudence and
reasonableness consistent with Commission practice and
law. To enable the financing of the incremental capital
expenditures, including regulatory assets, a participating
gas utility's actual year-end capital structure that
includes a common equity ratio, excluding goodwill, of up
to and including 54% of the total capital structure shall
be deemed reasonable and used to set rates.
(3) Include a cost of equity equal to the national
average cost of equity. For purposes of this paragraph (3)
of this subsection (c), the national average cost of
equity applicable to a calendar year shall be the simple

SB0311 - 165 - LRB102 15398 SPS 20761 b
average of the cost of equity specified and approved in
each order of a state regulatory commission, other than
the Commission, issued during such calendar year that is
applicable to base rates for retail natural gas delivery
service provided by an investor-owned public utility
company operating in the United States. No order shall be
excluded from the national average cost of equity
calculated under this paragraph (3) on the grounds that it
was arrived at by stipulation or agreement or is subject
to rehearing or appeal. If, for any calendar year, there
are fewer than 15 applicable orders of state regulatory
commissions with which to compute the average cost of
equity, the Commission shall include in the calculation of
the national average the number of state regulatory orders
from the year or years immediately preceding such calendar
year necessary to reach a total of 15, beginning with the
most recently issued and proceeding in reverse
chronological order.
(4) Permit and set forth protocols, subject to a
determination of prudence and reasonableness consistent
with Commission practice and law, for the following:
(A) irrespective of the form of award, recovery of
expense of incentive compensation that is awarded
based on non-financial criteria such as the
achievement of operational metrics, including metrics
related to budget controls, safety, customer service,

SB0311 - 166 - LRB102 15398 SPS 20761 b
efficiency and productivity, and environmental
compliance. The expense of incentive compensation
expense that is awarded based on net income or an
affiliate's earnings per share shall not be
recoverable under the performance-based rate;
(B) recovery of pension and other post-employment
benefits expense, provided that such costs are
supported by an actuarial study;
(C) recovery of severance costs, provided that if
the amount is over $2,500,000, then the full amount
shall be amortized consistent with subparagraph (F) of
this paragraph (4);
(D) investment return at a rate equal to the
participating gas utility's weighted average cost of
long-term debt on the pension assets as, and in the
amount, reported in Account 182.3 and 186 (or in such
other Account or Accounts as such asset may
subsequently be recorded) of the utility's most
recently filed ICC Form 21, FERC Form 1, or FERC Form
2, as applicable, net of deferred tax benefits;
(E) recovery of the expenses related to the
Commission proceeding under this subsection (c) to
approve this performance-based rate and initial rates
or to subsequent proceedings related to the formula,
provided that the recovery shall be amortized over a
3-year period; recovery of expenses related to the

SB0311 - 167 - LRB102 15398 SPS 20761 b
annual Commission proceedings under subsection (e) of
this Section to review the inputs to the
performance-based rate shall be expensed and recovered
through the performance-based rate;
(F) amortization over a 5-year period of the full
amount of each charge or credit that exceeds the
amount specified in subparagraph (C) of this paragraph
(4) and that relates to a workforce reduction
program's severance costs, changes in accounting
rules, changes in law, compliance with any
Commission-initiated audit, or other extraordinary
expense, provided that any unamortized balance shall
be reflected in rate base. For purposes of this
subparagraph (F), changes in law include any
enactment, repeal, or amendment in a law, ordinance,
rule, regulation, interpretation, permit, license,
consent, or order, including those relating to taxes,
accounting, or to environmental matters, or in the
interpretation or application thereof by any
governmental authority occurring after the effective
date of the Act;
(G) recovery of existing regulatory assets over
the periods previously authorized by the Commission;
(H) historical weather normalized billing
determinants; and
(I) allocation methods for common costs.

SB0311 - 168 - LRB102 15398 SPS 20761 b
(5) Provide that if the participating gas utility's
earned rate of return on common equity related to the
provision of natural gas delivery services for the prior
rate year (calculated using costs and capital structure
approved by the Commission as provided in subparagraphs
(2) and (3) of this subsection (c), consistent with this
Section, in accordance with Commission rules and orders,
including, but not limited to, adjustments for goodwill,
and after any Commission-ordered disallowances and taxes)
is higher than the rate of return on common equity
calculated pursuant to paragraph (3) of this subsection
(c) (after any adjustments to the rate of return on common
equity applied pursuant to the performance metrics
provision of subsection (g) or (h) of this Section, as
applicable), then the participating gas utility shall
apply a credit through the performance-based rate that
reflects an amount equal to the value of that portion of
the earned rate of return on common equity that is higher
than the rate of return on common equity calculated
pursuant to paragraph (3) of this subsection (c) (after
any adjustments to the rate of return on common equity
applied pursuant to the performance metrics provision of
subsection (g) or (h) of this Section, as applicable) for
the prior rate year, adjusted for taxes. If the
participating gas utility's earned rate of return on
common equity related to the provision of natural gas

SB0311 - 169 - LRB102 15398 SPS 20761 b
delivery services for the prior rate year (calculated
using costs and capital structure approved by the
Commission as provided in paragraphs (2) and (3) of this
subsection (c), consistent with this Section, in
accordance with Commission rules and orders, including,
but not limited to, adjustments for goodwill, and after
any Commission-ordered disallowances and taxes) is less
than the return on common equity calculated pursuant to
paragraph (3) of this subsection (c) (after any
adjustments to the rate of return on common equity applied
pursuant to the performance metrics provision of
subsections (g) or (h) of this Section, as applicable),
then the participating gas utility shall apply a charge
through the performance-based rate that reflects an amount
equal to the value of that portion of the earned rate of
return on common equity that is less than the rate of
return on common equity calculated pursuant to paragraph
(3) of this subsection (c) (after any adjustments to the
rate of return on common equity applied pursuant to the
performance metrics provision of subsections (g) or (h) of
this Section, as applicable) for the prior rate year,
adjusted for taxes.
(6) Provide for annual reconciliations, as described
in subsection (e) of this Section, with interest, of the
revenue requirement reflected in rates for each calendar
year, beginning with the calendar year in which the

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participating gas utility files its performance-based rate
tariff pursuant to subsection (c) of this Section, with
what the revenue requirement would have been had the
actual cost information for the applicable calendar year
been available at the filing date.
(7) Any surcharge tariff of a participating gas
utility authorized by paragraph (3) of subsection (a) of
Section 9-220.3 of the Act that is in effect as of the
effective date of the performance-based rate tariff
approved by the Commission for that utility pursuant to
the provisions of this Section will be suspended by
operation of law as of the effective date of that
performance-based rate tariff. Notwithstanding anything in
paragraph (4) of subsection (a) and paragraph (2) of
subsection (e) of Section 9-220.3, a participating gas
utility shall not file a petition to initiate a final
reconciliation of amounts collected under such a surcharge
tariff on account of qualifying infrastructure investment
(as that term is defined in Section 9-220.3(b)) that
occurred during any calendar year for which a
reconciliation will be made under subsection (c), and no
adjustment to the participating gas utility's initial
rates as calculated under paragraph (1) of subsection (c)
shall be made based on the fact that the utility had such a
tariff in effect or recovered any portion of its revenue
requirement through such a tariff.

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The participating gas utility shall file, together with
its tariff, final data based on its most recently filed ICC
Form 21, FERC Form 1, or FERC Form 2, as applicable, subject to
the adjustments specified in subsection (c), plus projected
plant additions and correspondingly updated depreciation
reserve and expense for the calendar year in which the tariff
and data are filed, that shall populate the performance-based
rate and set the initial gas delivery services rates under the
formula. For purposes of this Section, "ICC Form 21" means the
"Annual Report of Electric Utilities and/or Natural Gas
Utilities" or any successor to that report that natural gas
utilities are required to file with the Commission under
Section 5-109 of this Act. Nothing in this Section is intended
to allow costs that are not otherwise recoverable to be
recoverable by virtue of inclusion in ICC Form 21, FERC Form 1,
or FERC Form 2.
After the participating gas utility files its proposed
performance-based rate structure and protocols and initial
rates, the Commission shall initiate a docket to review the
filing. The Commission shall enter an order approving, or
approving as modified, the performance-based rate, including
the initial rates, as just and reasonable within 270 days
after the date on which the tariff was filed. Such review shall
be based on the same evidentiary standards, including, but not
limited to, those concerning the prudence and reasonableness
of the costs incurred by the utility, the Commission applies

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in a hearing to review a filing for a general increase in rates
under Article IX of this Act. The initial rates shall take
effect within 30 days after the Commission's order approving
the performance-based rate tariff.
Until the Commission approves a different rate design and
cost allocation pursuant to subsection (f) of this Section,
rate design and cost allocation across customer classes shall
be consistent with the Commission's most recent order
regarding the participating gas utility's request for a
general increase in its delivery services rates.
Subsequent changes to the performance-based rate structure
or protocols shall be made as set forth in Section 9-201 of
this Act, but nothing in this subsection (c) is intended to
limit the Commission's authority under Article IX and other
provisions of this Act to initiate an investigation of a
participating gas utility's performance-based rate tariff,
provided that any such changes shall be consistent with
paragraphs (1) through (7) of this subsection (c). Any change
ordered by the Commission shall be made at the same time new
rates take effect following the Commission's next order
pursuant to subsection (e) of this Section, provided that the
new rates take effect no less than 30 days after the date on
which the Commission issues an order adopting the change.
In the event the performance-based rate is terminated, the
then current rates shall remain in effect until such time as
new rates are set pursuant to Article IX of this Act, subject

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to retroactive rate adjustment, with interest, to reconcile
rates charged with actual costs.
(d) Beginning in the first calendar year following the
year in which this reporting requirement becomes effective, a
participating gas utility shall, within 45 days after the
close of each of the participating gas utility's fiscal
quarters, submit to the Commission a report that summarizes
the additions to utility plant that were placed into service
during the prior quarter, which for purposes of the report
shall be the most recently closed fiscal quarter, as well as
what utility plant the participating gas utility projects will
place into service through the end of the calendar year in
which the report is filed. The quarterly report provided will
be used for informational purposes only, and any estimates
therein shall not bind or limit the participating gas
utility's future decisions to invest in any utility plant or
other projects and may not be used in any Commission
proceeding to support any finding as to imprudence,
unreasonableness, or lack of use or usefulness of any
individual or aggregate level of utility plant or other
investment. Within 7 days of receiving a quarterly report, the
Commission shall make such report available to the public.
Each quarterly report shall include the following detail:
(1) the total dollar value of the additions to utility
plant placed in service during the prior quarter;
(2) a list of standing work orders for utility plant

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placed in service during the prior quarter, including the
total dollar amount for the work reflected in each
standing work order as of the last day of the quarterly
reporting period, and a summary description of the
standing work order;
(3) a list of specific work orders for utility plant
placed in service during the prior quarter for utility
plant placed in service with a total dollar value as of the
last day of the quarterly reporting period that is equal
to or greater than $500,000, inclusive of the dollar
amount reflected in each specific work order, and a
summary description of the specific work order;
(4) the estimated total dollar value of the additions
to utility plant projected to be placed in service through
the end of the calendar year in which the report is filed;
(5) a list of standing work orders for utility plant
projected to be placed in service through the end of the
calendar year in which the report is filed, including the
estimated dollar amount for the work reflected in each
standing work order, and a summary description of the
standing work order; and
(6) a list of specific work orders for utility plant
projected to be placed in service through the end of the
calendar year in which the report is filed with an
estimated dollar value that is equal to or greater than
$500,000, inclusive of the estimated dollar amount for the

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work reflected in each specific work order, and a summary
description of the specific work order.
(e) Subsequent to the Commission's issuance of an order
approving the participating gas utility's performance-based
rate structure and protocols, and initial rates under
subsection (c) of this Section, the utility shall file, on or
before May 1 of each year, with the Chief Clerk of the
Commission its updated cost inputs to the performance-based
rate for the applicable rate year and the corresponding new
charges. Each such filing shall conform to the following
requirements and include the following information:
(1) The inputs to the performance-based rate for the
applicable rate year shall be based on final historical
data reflected in the participating gas utility's most
recently filed annual ICC Form 21, or FERC Form 1, or FERC
Form 2, as applicable, subject to adjustments specified in
subsection (c) of this Section, plus projected plant
additions and correspondingly updated depreciation reserve
and expense for the calendar year in which the inputs are
filed. The filing shall also include a reconciliation of
the revenue requirement that was in effect for the prior
rate year (as set by the cost inputs for the prior rate
year) with the actual revenue requirement for the prior
rate year (determined using a year-end rate base) that
uses amounts reflected in the applicable ICC Form 21, FERC
Form 1, or FERC Form 2, that reports the actual costs for

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the prior rate year. Any over-collection or
under-collection indicated by such reconciliation shall be
reflected as a credit against, or recovered as an
additional charge to, respectively, with interest
calculated at a rate equal to the participating gas
utility's weighted average cost of capital approved by the
Commission for the prior rate year, the charges for the
applicable rate year. Provided, however, that the first
such reconciliation shall be for the calendar year in
which the participating gas utility files its
performance-based rate tariff pursuant to subsection (c)
of this Section and shall reconcile (i) the revenue
requirement or revenue requirements established by the
rate order or rate orders in effect from time to time
during such calendar year (weighted, as applicable),
including any surcharge tariff authorized for the
participating gas utility pursuant to paragraph (3) of
subsection (a) of Section 9-220.3 of the Act with (ii) the
revenue requirement determined using a year-end rate base
for that calendar year calculated pursuant to the
performance-based rate using actual costs for that year as
reflected in the applicable ICC Form 21, FERC Form 1, or
FERC Form 2, as applicable, subject to adjustments
specified in subsection (c) of this Section. The first
such reconciliation is not intended to provide for the
recovery of costs previously excluded from rates based on

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a prior Commission order finding of imprudence or
unreasonableness. Each reconciliation shall be certified
by the participating gas utility in the same manner that
ICC Form 21 is certified. The filing shall also include
the charge or credit, if any, resulting from the
calculation required by paragraph (6) of subsection (c) of
this Section.
Notwithstanding anything that may be to the contrary,
the intent of the reconciliations is to ultimately
reconcile the revenue requirement reflected in rates for
such calendar year, beginning with the calendar year in
which the participating gas utility files its
performance-based rate tariff pursuant to subsection (c)
of this Section, with what the revenue requirement
determined using a year-end rate base for the applicable
calendar year would have been had actual cost information
for the applicable calendar year been available at the
filing date.
(2) The new charges shall take effect beginning on the
first billing day of the following January billing period
and remain in effect through the last billing day of the
next December billing period regardless of whether the
Commission enters upon a hearing pursuant to this
subsection (e).
(3) The filing shall include relevant and necessary
data and documentation for the applicable rate year that

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is consistent with the Commission's rules applicable to a
filing for a general increase in rates or any rules
adopted by the Commission to implement this Section.
Normalization adjustments shall not be required.
Notwithstanding any other provision of this Section or Act
or any rule or other requirement adopted by the
Commission, a participating gas utility with more than one
rate zone shall not be required to file a separate set of
such data and documentation for each rate zone and may
combine such data and documentation into a single set of
schedules.
Within 45 days after the participating gas utility files
its annual update of cost inputs to the performance-based
rate, the Commission shall have the authority, either upon
complaint or its own initiative, but with reasonable notice,
to enter upon a hearing concerning the prudence and
reasonableness of the costs incurred by the participating gas
utility to be recovered during the applicable rate year that
are reflected in the inputs to the performance-based rate
derived from the participating gas utility's ICC Form 21, FERC
Form 1, or FERC Form 2. During the course of the hearing, each
objection shall be stated with particularity and evidence
provided in support thereof, after which the utility shall
have the opportunity to rebut the evidence. Discovery shall be
allowed consistent with the Commission's Rules of Practice,
which Rules shall be enforced by the Commission or the

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assigned administrative law judge. The Commission shall apply
the same evidentiary standards, including, but not limited to,
those concerning the prudence and reasonableness of the costs
incurred by the participating gas utility, in the hearing as
it would apply in a hearing to review a filing for a general
increase in rates under Article IX of this Act. The Commission
shall not, however, have the authority in a proceeding under
this subsection (e) to consider or order any changes to the
structure or protocols of the performance-based rate approved
pursuant to subsection (c) of this Section. In a proceeding
under this subsection (e), the Commission shall enter its
order no later than the earlier of 240 days after the utility's
filing of its annual update of cost inputs to the
performance-based rate or December 31. The Commission's
determinations of the prudence and reasonableness of the costs
incurred for the applicable calendar year shall be final upon
entry of the Commission's order and shall not be subject to
reopening, reexamination, or collateral attack in any other
Commission proceeding, case, docket, order, rule, or
regulation, provided, however, that nothing in this subsection
(e) shall prohibit a party from petitioning the Commission to
rehear or appeal to the courts the order pursuant to the
provisions of this Act.
In the event the Commission does not, either upon
complaint or its own initiative, enter upon a hearing within
45 days after the participating gas utility files the annual

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update of cost inputs to its performance-based rate, then the
costs incurred for the applicable calendar year shall be
deemed prudent and reasonable, and the filed charges shall not
be subject to reopening, reexamination, or collateral attack
in any other proceeding, case, docket, order, rule, or
regulation.
A participating gas utility's first filing of the updated
cost inputs, and any Commission investigation of such inputs
pursuant to this subsection (e) shall proceed notwithstanding
the fact that the Commission's investigation under subsection
(c) of this Section is still pending and notwithstanding any
other law, order, rule, or Commission practice to the
contrary.
(f) Nothing in subsections (c) or (e) of this Section
shall prohibit the Commission from investigating, or a
participating gas utility from filing, revenue-neutral tariff
changes related to rate design of a performance-based rate
that has been placed into effect for the utility. Following
approval of a participating gas utility's performance-based
rate tariff pursuant to subsection (c) of this Section, the
utility shall make a filing with the Commission within one
year after the effective date of the performance-based rate
tariff that proposes changes to the tariff to incorporate the
findings of any final rate design orders of the Commission
applicable to the participating gas utility and entered
subsequent to the Commission's approval of the tariff. The

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Commission shall, after notice and hearing, enter its order
approving, or approving with modification, the proposed
changes to the performance-based rate tariff within 240 days
after the utility's filing. Following such approval, the
utility shall make a filing with the Commission during each
subsequent 3-year period that either proposes revenue-neutral
tariff changes or re-files the existing tariffs without
change, which shall present the Commission with an opportunity
to suspend the tariffs and consider revenue-neutral tariff
changes related to rate design.
(g) Within 30 days after the filing of a tariff pursuant to
subsection (c) of this Section, each participating gas utility
shall develop and file with the Commission multi-year metrics.
For each participating gas utility, the following metrics
shall be designed to achieve, ratably (in equal annual
segments, unless otherwise specified) over a 10-year period,
improvement over baseline performance values as follows:
(1) System Integrity, Reliability, and Pipeline Safety
Improvement (under 49 CFR Part 192): Reduce the number of
outstanding, underground gas leaks on a participating gas
utility's gas system by 50% resulting in reduced methane
emissions into the environment, using a baseline of year
end 2020.
(2) System Integrity, Reliability, and Pipeline Safety
Improvement (under 49 CFR Part 192): Reduce the number of
outstanding above-ground gas leaks on a participating gas

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utility's gas system by 50% resulting in reduced methane
emissions into the environment, using a baseline of year
end 2020.
(3) System Integrity, Reliability and Pipeline Safety
Improvement: Reduce the known quantity of gas transmission
pipeline facilities (including mains and associated
facilities) that do not have complete records to support
the maximum allowable operating pressures in accordance
with Federal Department of Transportation pipeline safety
regulations by 50% using a baseline of year end 2020.
(4) System Integrity, Reliability, and Pipeline Safety
Improvement: Reduce the known quantity of mechanically
coupled steel gas distribution pipeline facilities
(including mains, services, and associated facilities)
that are prone to leakage by 70% using a baseline of year
end 2020.
(5) Opportunities for minority-owned, woman-owned, and
veteran-owned business enterprises: design a performance
metric regarding the creation of opportunities for
minority-owned, woman-owned and veteran-owned business
enterprises consistent with State and federal law using a
base performance value of the percentage of the
participating gas utility's capital expenditures that were
paid to minority-owned, woman-owned and veteran-owned
business enterprises in the years 2018, 2019 and 2020.
The metrics shall include incremental performance goals

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for each year of the 10-year period, which shall be designed to
demonstrate that the participating gas utility is on track to
achieve the performance goal in each category at the end of the
10-year period. The participating gas utility shall elect when
the 10-year period shall commence for the metrics set forth in
this subsection (g), provided that it begins no later than 14
months following the date on which the participating gas
utility files a tariff pursuant to subsection (c).
(h) The financial adjustments applicable to the metrics
described in subparagraphs (1) through (4) of subsection (g),
as applicable, shall be applied through an adjustment to the
participating gas utility's return on equity of no more than a
total of 40 basis points in any year, as follows:
(1) With respect to the incremental annual performance
goal established pursuant to subparagraph (1) of
subsection (g), for each year that a participating gas
utility does not achieve at least 95% of such goal, the
participating gas utility's return on equity shall be
reduced by 10 basis points; and for each year in which the
participating utility achieves 105% or more of such goal,
the participating gas utility's return on equity shall be
increased by 10 basis points.
(2) With respect to the incremental annual performance
goal established pursuant to subparagraph (2) of
subsection (g), for each year that a participating gas
utility does not achieve at least 95% of such goal, the

SB0311 - 184 - LRB102 15398 SPS 20761 b
participating gas utility's return on equity shall be
reduced by 10 basis points; and for each year that a
participating gas utility achieves 105% or more of such
goal, the participating gas utility's return on equity
shall be increased by 10 basis points.
(3) With respect to the incremental annual performance
goal established pursuant to subparagraph (3) of
subsection (g), for each year that a participating gas
utility does not achieve at least 95% of such goal, the
participating gas utility's return on equity shall be
reduced by 10 basis points; and for each year that a
participating gas utility achieves 105% or more of such
goal, the participating gas utility's return on equity
shall be increased by 10 basis points.
(4) With respect to the incremental annual performance
goals established pursuant to subparagraph (4) of
subsection (g), for each year that a participating gas
utility does not achieve at least 95% of such goal, the
participating gas utility's return on equity shall be
reduced by 10 basis points; and for each year that a
participating gas utility achieves 105% or more of such
goal, the participating gas utility's return on equity
shall be increased by 10 basis points.
(i) The financial adjustments shall be applied as
described in subsection (h), as applicable, for the 12-month
period in which they accrued through a separate tariff

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mechanism, which shall be filed by the participating gas
utility together with its metrics. In the event the
performance-based formula rate tariff established pursuant to
subsection (c) of this Section terminates, the participating
gas utility's obligations under subsection (g), as applicable,
and subsection (h), as applicable, of this Section and this
subsection (i) shall also terminate; provided, however, that
the tariff mechanism established pursuant to subsection (g) of
this Section and subsection (h), as applicable, and this
subsection (i) shall remain in effect until the remaining
balance of any financial adjustments at the time of such
termination is fully amortized.
The Commission shall, after notice and hearing, enter an
order within 120 days after the metrics are filed approving,
or approving with modification, a participating gas utility's
tariff or mechanism to satisfy the metrics set forth in
subsection (g), as applicable, of this Section and subsection
(h), as applicable, of this Section. On June 1 of each
subsequent year, each participating gas utility shall file a
report with the Commission that includes, among other things,
a description of how the participating gas utility performed
under each metric and an identification of any extraordinary
events that adversely impacted the participating gas utility's
performance. Whenever a participating gas utility's report on
its performance shows that a financial adjustment is warranted
under subsection (h) of this Section, the Commission shall,

SB0311 - 186 - LRB102 15398 SPS 20761 b
after notice and hearing, enter an order approving any
financial adjustments in accordance with subsection (h) of
this Section. The Commission-approved financial adjustments
shall be applied beginning with the next rate year.
(j) This Section, other than this subsection (j), is
inoperative after December 31, 2032, for every participating
gas utility, after which time a participating gas utility
shall no longer be eligible to annually update the
performance-based rate tariff pursuant to subsection (e) of
this Section. At such time, the then current rates shall
remain in effect until such time as new rates are set pursuant
to Article IX of this Act, subject to retroactive adjustment,
with interest, to reconcile rates charged with actual costs.
The fact that this Section becomes inoperative as set
forth in this subsection shall not be construed to mean that
the Commission may reexamine or otherwise reopen prudence or
reasonableness determinations already made.
(220 ILCS 5/16-102)
Sec. 16-102. Definitions. For the purposes of this Article
the following terms shall be defined as set forth in this
Section.
"Alternative retail electric supplier" means every person,
cooperative, corporation, municipal corporation, company,
association, joint stock company or association, firm,
partnership, individual, or other entity, their lessees,

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trustees, or receivers appointed by any court whatsoever, that
offers electric power or energy for sale, lease or in exchange
for other value received to one or more retail customers, or
that engages in the delivery or furnishing of electric power
or energy to such retail customers, and shall include, without
limitation, resellers, aggregators and power marketers, but
shall not include (i) electric utilities (or any agent of the
electric utility to the extent the electric utility provides
tariffed services to retail customers through that agent),
(ii) any electric cooperative or municipal system as defined
in Section 17-100 to the extent that the electric cooperative
or municipal system is serving retail customers within any
area in which it is or would be entitled to provide service
under the law in effect immediately prior to the effective
date of this amendatory Act of 1997, (iii) a public utility
that is owned and operated by any public institution of higher
education of this State, or a public utility that is owned by
such public institution of higher education and operated by
any of its lessees or operating agents, within any area in
which it is or would be entitled to provide service under the
law in effect immediately prior to the effective date of this
amendatory Act of 1997, (iv) a retail customer to the extent
that customer obtains its electric power and energy from that
customer's own cogeneration or self-generation facilities, (v)
an entity that owns, operates, sells, or arranges for the
installation of a customer's own cogeneration or

SB0311 - 188 - LRB102 15398 SPS 20761 b
self-generation facilities, but only to the extent the entity
is engaged in owning, selling or arranging for the
installation of such facility, or operating the facility on
behalf of such customer, provided however that any such third
party owner or operator of a facility built after January 1,
1999, complies with the labor provisions of Section 16-128(a)
as though such third party were an alternative retail electric
supplier, or (vi) an industrial or manufacturing customer that
owns its own distribution facilities, to the extent that the
customer provides service from that distribution system to a
third-party contractor located on the customer's premises that
is integrally and predominantly engaged in the customer's
industrial or manufacturing process; provided, that if the
industrial or manufacturing customer has elected delivery
services, the customer shall pay transition charges applicable
to the electric power and energy consumed by the third-party
contractor unless such charges are otherwise paid by the third
party contractor, which shall be calculated based on the usage
of, and the base rates or the contract rates applicable to, the
third-party contractor in accordance with Section 16-102.
An entity that furnishes the service of charging electric
vehicles does not and shall not be deemed to sell electricity
and is not and shall not be deemed an alternative retail
electric supplier, and is not subject to regulation as such
under this Act notwithstanding the basis on which the service
is provided or billed. If, however, the entity is otherwise

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deemed an alternative retail electric supplier under this Act,
or is otherwise subject to regulation under this Act, then
that entity is not exempt from and remains subject to the
otherwise applicable provisions of this Act. The installation,
maintenance, and repair of an electric vehicle charging
station shall comply with the requirements of subsection (a)
of Section 16-128 and Section 16-128A of this Act.
For purposes of this Section, the term "electric vehicles"
has the meaning ascribed to that term in Section 10 of the
Electric Vehicle Act.
"Base rates" means the rates for those tariffed services
that the electric utility is required to offer pursuant to
subsection (a) of Section 16-103 and that were identified in a
rate order for collection of the electric utility's base rate
revenue requirement, excluding (i) separate automatic rate
adjustment riders then in effect, (ii) special or negotiated
contract rates, (iii) delivery services tariffs filed pursuant
to Section 16-108, (iv) real-time pricing, or (v) tariffs that
were in effect prior to October 1, 1996 and that based charges
for services on an index or average of other utilities'
charges, but including (vi) any subsequent redesign of such
rates for tariffed services that is authorized by the
Commission after notice and hearing.
"Competitive service" includes (i) any service that has
been declared to be competitive pursuant to Section 16-113 of
this Act, (ii) contract service, and (iii) services, other

SB0311 - 190 - LRB102 15398 SPS 20761 b
than tariffed services, that are related to, but not necessary
for, the provision of electric power and energy or delivery
services.
"Contract service" means (1) services, including the
provision of electric power and energy or other services, that
are provided by mutual agreement between an electric utility
and a retail customer that is located in the electric
utility's service area, provided that, delivery services shall
not be a contract service until such services are declared
competitive pursuant to Section 16-113; and also means (2) the
provision of electric power and energy by an electric utility
to retail customers outside the electric utility's service
area pursuant to Section 16-116. Provided, however, contract
service does not include electric utility services provided
pursuant to (i) contracts that retail customers are required
to execute as a condition of receiving tariffed services, or
(ii) special or negotiated rate contracts for electric utility
services that were entered into between an electric utility
and a retail customer prior to the effective date of this
amendatory Act of 1997 and filed with the Commission.
"Delivery services" means those services provided by the
electric utility that are necessary in order for the
transmission and distribution systems to function so that
retail customers located in the electric utility's service
area can receive electric power and energy from suppliers
other than the electric utility, and shall include, without

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limitation, standard metering and billing services.
"Electric utility" means a public utility, as defined in
Section 3-105 of this Act, that has a franchise, license,
permit or right to furnish or sell electricity to retail
customers within a service area.
"Electric vehicle" means: (i) a battery-powered vehicle
operated solely by electricity that can be recharged from an
external source; or (ii) a plug-in hybrid electric vehicle
that operates on electricity and another fuel and has a
battery that can be recharged from an external source.
"Electric vehicle charging station" means any facility,
infrastructure, or equipment that is used to charge a battery
or other energy storage device of an electric vehicle.
"Energy storage" or "storage" means any infrastructure,
facility, technology, or device used to store energy for use
on an electric distribution or transmission system and shall
not include or be considered energy generation.
"Mandatory transition period" means the period from the
effective date of this amendatory Act of 1997 through January
1, 2007.
"Municipal system" shall have the meaning set forth in
Section 17-100.
"Real-time pricing" means tariffed retail charges for
delivered electric power and energy that vary hour-to-hour and
are determined from wholesale market prices using a
methodology approved by the Illinois Commerce Commission.

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"Retail customer" means a single entity using electric
power or energy at a single premises and that (A) either (i) is
receiving or is eligible to receive tariffed services from an
electric utility, or (ii) that is served by a municipal system
or electric cooperative within any area in which the municipal
system or electric cooperative is or would be entitled to
provide service under the law in effect immediately prior to
the effective date of this amendatory Act of 1997, or (B) an
entity which on the effective date of this Act was receiving
electric service from a public utility and (i) was engaged in
the practice of resale and redistribution of such electricity
within a building prior to January 2, 1957, or (ii) was
providing lighting services to tenants in a multi-occupancy
building, but only to the extent such resale, redistribution
or lighting service is authorized by the electric utility's
tariffs that were on file with the Commission on the effective
date of this Act.
"Service area" means (i) the geographic area within which
an electric utility was lawfully entitled to provide electric
power and energy to retail customers as of the effective date
of this amendatory Act of 1997, and includes (ii) the location
of any retail customer to which the electric utility was
lawfully providing electric utility services on such effective
date.
"Small commercial retail customer" means those
nonresidential retail customers of an electric utility

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consuming 15,000 kilowatt-hours or less of electricity
annually in its service area.
"Tariffed service" means services provided to retail
customers by an electric utility as defined by its rates on
file with the Commission pursuant to the provisions of Article
IX of this Act, but shall not include competitive services.
"Transition charge" means a charge expressed in cents per
kilowatt-hour that is calculated for a customer or class of
customers as follows for each year in which an electric
utility is entitled to recover transition charges as provided
in Section 16-108:
(1) the amount of revenue that an electric utility
would receive from the retail customer or customers if it
were serving such customers' electric power and energy
requirements as a tariffed service based on (A) all of the
customers' actual usage during the 3 years ending 90 days
prior to the date on which such customers were first
eligible for delivery services pursuant to Section 16-104,
and (B) on (i) the base rates in effect on October 1, 1996
(adjusted for the reductions required by subsection (b) of
Section 16-111, for any reduction resulting from a rate
decrease under Section 16-101(b), for any restatement of
base rates made in conjunction with an elimination of the
fuel adjustment clause pursuant to subsection (b), (d), or
(f) of Section 9-220 and for any removal of
decommissioning costs from base rates pursuant to Section

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16-114) and any separate automatic rate adjustment riders
(other than a decommissioning rate as defined in Section
16-114) under which the customers were receiving or, had
they been customers, would have received electric power
and energy from the electric utility during the year
immediately preceding the date on which such customers
were first eligible for delivery service pursuant to
Section 16-104, or (ii) to the extent applicable, any
contract rates, including contracts or rates for
consolidated or aggregated billing, under which such
customers were receiving electric power and energy from
the electric utility during such year;
(2) less the amount of revenue, other than revenue
from transition charges and decommissioning rates, that
the electric utility would receive from such retail
customers for delivery services provided by the electric
utility, assuming such customers were taking delivery
services for all of their usage, based on the delivery
services tariffs in effect during the year for which the
transition charge is being calculated and on the usage
identified in paragraph (1);
(3) less the market value for the electric power and
energy that the electric utility would have used to supply
all of such customers' electric power and energy
requirements, as a tariffed service, based on the usage
identified in paragraph (1), with such market value

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determined in accordance with Section 16-112 of this Act;
(4) less the following amount which represents the
amount to be attributed to new revenue sources and cost
reductions by the electric utility through the end of the
period for which transition costs are recovered pursuant
to Section 16-108, referred to in this Article XVI as a
"mitigation factor":
(A) for nonresidential retail customers, an amount
equal to the greater of (i) 0.5 cents per
kilowatt-hour during the period October 1, 1999
through December 31, 2004, 0.6 cents per kilowatt-hour
in calendar year 2005, and 0.9 cents per kilowatt-hour
in calendar year 2006, multiplied in each year by the
usage identified in paragraph (1), or (ii) an amount
equal to the following percentages of the amount
produced by applying the applicable base rates
(adjusted as described in subparagraph (1)(B)) or
contract rate to the usage identified in paragraph
(1): 8% for the period October 1, 1999 through
December 31, 2002, 10% in calendar years 2003 and
2004, 11% in calendar year 2005 and 12% in calendar
year 2006; and
(B) for residential retail customers, an amount
equal to the following percentages of the amount
produced by applying the base rates in effect on
October 1, 1996 (adjusted as described in subparagraph

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(1)(B)) to the usage identified in paragraph (1): (i)
6% from May 1, 2002 through December 31, 2002, (ii) 7%
in calendar years 2003 and 2004, (iii) 8% in calendar
year 2005, and (iv) 10% in calendar year 2006;
(5) divided by the usage of such customers identified
in paragraph (1),
provided that the transition charge shall never be less than
zero.
"Unbundled service" means a component or constituent part
of a tariffed service which the electric utility subsequently
offers separately to its customers.
(Source: P.A. 97-1128, eff. 8-28-12.)
(220 ILCS 5/16-107.6)
Sec. 16-107.6. Distributed generation rebate.
(a) In this Section:
"Smart inverter" means a device that converts direct
current into alternating current and can autonomously
contribute to grid support during excursions from normal
operating voltage and frequency conditions by providing each
of the following: dynamic reactive and real power support,
voltage and frequency ride-through, ramp rate controls,
communication systems with ability to accept external
commands, and other functions from the electric utility.
"Subscriber" has the meaning set forth in Section 1-10 of
the Illinois Power Agency Act.

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"Subscription" has the meaning set forth in Section 1-10
of the Illinois Power Agency Act.
"Threshold date" means the date on which the load of an
electricity provider's net metering customers equals 5% of the
total peak demand supplied by that electricity provider during
the previous year, as specified under subsection (j) of
Section 16-107.5 of this Act.
(b) An electric utility that serves more than 200,000
customers in the State shall file a petition with the
Commission requesting approval of the utility's tariff to
provide a rebate to a retail customer who owns or operates
distributed generation that meets the following criteria:
(1) has a nameplate generating capacity no greater
than 2,000 kilowatts and is primarily used to offset that
customer's electricity load;
(2) is located on the customer's premises, for the
customer's own use, and not for commercial use or sales,
including, but not limited to, wholesale sales of electric
power and energy;
(3) is located in the electric utility's service
territory; and
(4) is interconnected under rules adopted by the
Commission by means of the inverter or smart inverter
required by this Section, as applicable.
For purposes of this Section, "distributed generation"
shall satisfy the definition of distributed renewable energy

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generation device set forth in Section 1-10 of the Illinois
Power Agency Act to the extent such definition is consistent
with the requirements of this Section.
In addition, any new photovoltaic distributed generation
that is installed after the effective date of this amendatory
Act of the 99th General Assembly must be installed by a
qualified person, as defined by subsection (i) of Section 1-56
of the Illinois Power Agency Act.
The tariff shall provide that the utility shall be
permitted to operate and control the smart inverter associated
with the distributed generation that is the subject of the
rebate for the purpose of preserving reliability during
distribution system reliability events and shall address the
terms and conditions of the operation and the compensation
associated with the operation. Nothing in this Section shall
negate or supersede Institute of Electrical and Electronics
Engineers interconnection requirements or standards or other
similar standards or requirements. The tariff shall also
provide for additional uses of the smart inverter that shall
be separately compensated and which may include, but are not
limited to, voltage and VAR support, regulation, and other
grid services. As part of the proceeding described in
subsection (e) of this Section, the Commission shall review
and determine whether smart inverters can provide any
additional uses or services. If the Commission determines that
an additional use or service would be beneficial, the

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Commission shall determine the terms and conditions of the
operation and how the use or service should be separately
compensated.
(c) The proposed tariff authorized by subsection (b) of
this Section shall include the following participation terms
and formulae to calculate the value of the rebates to be
applied under this Section for distributed generation that
satisfies the criteria set forth in subsection (b) of this
Section:
(1) Until the utility files its tariff or tariffs to
place into effect the rebate values established by the
Commission under subsection (e) of this Section,
non-residential customers that are taking service under a
net metering program offered by an electricity provider
under the terms of Section 16-107.5 of this Act may apply
for a rebate as provided for in this Section. The value of
the rebate shall be $250 per kilowatt of nameplate
generating capacity, measured as nominal DC power output,
of a non-residential customer's distributed generation.
(2) After the utility's tariff or tariffs setting the
new rebate values established under subsection (d) of this
Section take effect, retail customers may, as applicable,
make the following elections:
(A) Residential customers that are taking service
under a net metering program offered by an electricity
provider under the terms of Section 16-107.5 of this

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Act on the threshold date may elect to either continue
to take such service under the terms of such program as
in effect on such threshold date for the useful life of
the customer's eligible renewable electric generating
facility as defined in such Section, or file an
application to receive a rebate under the terms of
this Section, provided that such application must be
submitted within 6 months after the effective date of
the tariff approved under subsection (d) of this
Section. The value of the rebate shall be the amount
established by the Commission and reflected in the
utility's tariff pursuant to subsection (e) of this
Section.
(B) Non-residential customers that are taking
service under a net metering program offered by an
electricity provider under the terms of Section
16-107.5 of this Act on the threshold date may apply
for a rebate as provided for in this Section. The value
of the rebate shall be the amount established by the
Commission and reflected in the utility's tariff
pursuant to subsection (e) of this Section.
(3) Upon approval of a rebate application submitted
under this subsection (c), the retail customer shall no
longer be entitled to receive any delivery service credits
for the excess electricity generated by its facility and
shall be subject to the provisions of subsection (n) of

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Section 16-107.5 of this Act.
(4) To be eligible for a rebate described in this
subsection (c), customers who begin taking service after
the effective date of this amendatory Act of the 99th
General Assembly under a net metering program offered by
an electricity provider under the terms of Section
16-107.5 of this Act must have a smart inverter associated
with the customer's distributed generation.
(d) The Commission shall review the proposed tariff
submitted under subsections (b) and (c) of this Section and
may make changes to the tariff that are consistent with this
Section and with the Commission's authority under Article IX
of this Act, subject to notice and hearing. Following notice
and hearing, the Commission shall issue an order approving, or
approving with modification, such tariff no later than 240
days after the utility files its tariff.
(e) When the total generating capacity of the electricity
provider's net metering customers is equal to 3%, the
Commission shall open an investigation into an annual process
and formula for calculating the value of rebates for the
retail customers described in subsections (b) and (f) of this
Section that submit rebate applications after the threshold
date for an electric utility that elected to file a tariff
pursuant to this Section. The investigation shall include
diverse sets of stakeholders, calculations for valuing
distributed energy resource benefits to the grid based on best

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practices, and assessments of present and future technological
capabilities of distributed energy resources. The value of
such rebates shall reflect the value of the distributed
generation to the distribution system at the location at which
it is interconnected, taking into account the geographic,
time-based, and performance-based benefits, as well as
technological capabilities and present and future grid needs.
No later than 10 days after the Commission enters its final
order under this subsection (e), the utility shall file its
tariff or tariffs in compliance with the order, and the
Commission shall approve, or approve with modification, the
tariff or tariffs within 45 days after the utility's filing.
For those rebate applications filed after the threshold date
but before the utility's tariff or tariffs filed pursuant to
this subsection (e) take effect, the value of the rebate shall
remain at the value established in subsection (c) of this
Section until the tariff is approved.
(f) Notwithstanding any provision of this Act to the
contrary, the owner, developer, or subscriber of a generation
facility that is part of a net metering program provided under
subsection (l) of Section 16-107.5 shall also be eligible to
apply for the rebate described in this Section. A subscriber
to the generation facility may apply for a rebate in the amount
of the subscriber's subscription only if the owner, developer,
or previous subscriber to the same panel or panels has not
already submitted an application, and, regardless of whether

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the subscriber is a residential or non-residential customer,
may be allowed the amount identified in paragraph (1) of
subsection (c) or in subsection (e) of this Section applicable
to such customer on the date that the application is
submitted. An application for a rebate for a portion of a
project described in this subsection (f) may be submitted at
or after the time that a related request for net metering is
made.
(g) No later than 60 days after the utility receives an
application for a rebate under its tariff approved under
subsection (d) or (e) of this Section, the utility shall issue
a rebate to the applicant under the terms of the tariff. In the
event the application is incomplete or the utility is
otherwise unable to calculate the payment based on the
information provided by the owner, the utility shall issue the
payment no later than 60 days after the application is
complete or all requested information is received.
(h) An electric utility shall recover from its retail
customers all of the costs of the rebates made under a tariff
or tariffs placed into effect under this Section, including,
but not limited to, the value of the rebates and all costs
incurred by the utility to comply with and implement this
Section, consistent with the following provisions:
(1) The utility shall defer the full amount of its
costs incurred under this Section as a regulatory asset.
The total costs deferred as a regulatory asset shall be

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amortized over a 15-year period. The unamortized balance
shall be recognized as of December 31 for a given year. The
utility shall also earn a return on the total of the
unamortized balance of the regulatory assets, less any
deferred taxes related to the unamortized balance, at an
annual rate equal to the utility's weighted average cost
of capital that includes, based on a year-end capital
structure, the utility's actual cost of debt for the
applicable calendar year and a cost of equity, which in
all years for electric utilities that serve more than
3,000,000 retail customers in this State, and in each
calendar year commencing before January 1, 2021 for
electric utilities that serve less than 3,000,000 retail
customers but more than 500,000 retail customers in this
State, shall be calculated as the sum of (i) the average
for the applicable calendar year of the monthly average
yields of 30-year U.S. Treasury bonds published by the
Board of Governors of the Federal Reserve System in its
weekly H.15 Statistical Release or successor publication;
and (ii) 580 basis points, including a revenue conversion
factor calculated to recover or refund all additional
income taxes that may be payable or receivable as a result
of that return. For electric utilities that serve less
than 3,000,000 retail customers but more than 500,000
retail customers in this State, for each calendar year
commencing after December 31, 2020, the cost of equity

SB0311 - 205 - LRB102 15398 SPS 20761 b
shall be equal to the national average cost of equity as
calculated under this paragraph (1). For purposes of this
paragraph (1), the national average cost of equity for an
applicable calendar year shall be the simple average of
the cost of equity specified and approved in each order of
a state regulatory commission, other than the Commission,
issued during such calendar year that is applicable to
base rates for retail electric service provided by an
investor-owned public utility company operating in the
United States. No order shall be excluded from the
national average cost of equity calculated under this
paragraph (1) on the grounds that it was arrived at by
stipulation or agreement or is subject to rehearing or
appeal. In its final order in the proceeding occurring
pursuant to this subsection (h) of this Section during
calendar year 2021, the Commission shall set the cost of
equity using the method applicable to calendar years
commencing prior to January 1, 2021. In its final orders
in the proceedings occurring pursuant to subsection (h) of
this Section in years subsequent to calendar year 2021,
including the reconciliation of the 2021 rate year, the
Commission shall set the cost of equity using the method
applicable to calendar years commencing after December 31,
2020. If, for any calendar year, there are fewer than 15
applicable orders of state regulatory commissions with
which to compute the average cost of equity, the

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Commission shall include in the calculation of the
national average the number of state regulatory orders
from the year or years immediately preceding such calendar
year necessary to reach a total of 15, beginning with the
most recently issued and proceeding in reverse
chronological order.
When an electric utility creates a regulatory asset
under the provisions of this Section, the costs are
recovered over a period during which customers also
receive a benefit, which is in the public interest.
Accordingly, it is the intent of the General Assembly that
an electric utility that elects to create a regulatory
asset under the provisions of this Section shall recover
all of the associated costs, including, but not limited
to, its cost of capital as set forth in this Section. After
the Commission has approved the prudence and
reasonableness of the costs that comprise the regulatory
asset, the electric utility shall be permitted to recover
all such costs, and the value and recoverability through
rates of the associated regulatory asset shall not be
limited, altered, impaired, or reduced. To enable the
financing of the incremental capital expenditures,
including regulatory assets, for electric utilities that
serve less than 3,000,000 retail customers but more than
500,000 retail customers in the State, the utility's
actual year-end capital structure that includes a common

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equity ratio, excluding goodwill, of up to and including
54% 50% of the total capital structure shall be deemed
reasonable and used to set rates.
(2) The utility, at its election, may recover all of
the costs it incurs under this Section as part of a filing
for a general increase in rates under Article IX of this
Act, as part of an annual filing to update a
performance-based formula rate under subsection (d) of
Section 16-108.5 of this Act, or through an automatic
adjustment clause tariff, provided that nothing in this
paragraph (2) permits the double recovery of such costs
from customers. If the utility elects to recover the costs
it incurs under this Section through an automatic
adjustment clause tariff, the utility may file its
proposed tariff together with the tariff it files under
subsection (b) of this Section or at a later time. The
proposed tariff shall provide for an annual
reconciliation, less any deferred taxes related to the
reconciliation, with interest at an annual rate of return
equal to the utility's weighted average cost of capital as
calculated under paragraph (1) of this subsection (h),
including a revenue conversion factor calculated to
recover or refund all additional income taxes that may be
payable or receivable as a result of that return, of the
revenue requirement reflected in rates for each calendar
year, beginning with the calendar year in which the

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utility files its automatic adjustment clause tariff under
this subsection (h), with what the revenue requirement
would have been had the actual cost information for the
applicable calendar year been available at the filing
date. The Commission shall review the proposed tariff and
may make changes to the tariff that are consistent with
this Section and with the Commission's authority under
Article IX of this Act, subject to notice and hearing.
Following notice and hearing, the Commission shall issue
an order approving, or approving with modification, such
tariff no later than 240 days after the utility files its
tariff.
(i) No later than 90 days after the Commission enters an
order, or order on rehearing, whichever is later, approving an
electric utility's proposed tariff under subsection (d) of
this Section, the electric utility shall provide notice of the
availability of rebates under this Section. Subsequent to the
utility's notice, any entity that offers in the State, for
sale or lease, distributed generation and estimates the dollar
saving attributable to such distributed generation shall
provide estimates based on both delivery service credits and
the rebates available under this Section.
(Source: P.A. 99-906, eff. 6-1-17.)
(220 ILCS 5/16-108.5)
Sec. 16-108.5. Infrastructure investment and

SB0311 - 209 - LRB102 15398 SPS 20761 b
modernization; regulatory reform.
(a) (Blank).
(b) For purposes of this Section, "participating utility"
means an electric utility or a combination utility serving
more than 1,000,000 customers in Illinois that voluntarily
elects and commits to undertake (i) the infrastructure
investment program consisting of the commitments and
obligations described in this subsection (b) and (ii) the
customer assistance program consisting of the commitments and
obligations described in subsection (b-10) of this Section,
notwithstanding any other provisions of this Act and without
obtaining any approvals from the Commission or any other
agency other than as set forth in this Section, regardless of
whether any such approval would otherwise be required.
"Combination utility" means a utility that, as of January 1,
2011, provided electric service to at least one million retail
customers in Illinois and gas service to at least 500,000
retail customers in Illinois. A participating utility shall
recover the expenditures made under the infrastructure
investment program through the ratemaking process, including,
but not limited to, the performance-based formula rate and
process set forth in this Section.
During the infrastructure investment program's peak
program year, a participating utility other than a combination
utility shall create 2,000 full-time equivalent jobs in
Illinois, and a participating utility that is a combination

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utility shall create 450 full-time equivalent jobs in Illinois
related to the provision of electric service. These jobs shall
include direct jobs, contractor positions, and induced jobs,
but shall not include any portion of a job commitment, not
specifically contingent on an amendatory Act of the 97th
General Assembly becoming law, between a participating utility
and a labor union that existed on December 30, 2011 (the
effective date of Public Act 97-646) and that has not yet been
fulfilled. A portion of the full-time equivalent jobs created
by each participating utility shall include incremental
personnel hired subsequent to December 30, 2011 (the effective
date of Public Act 97-646). For purposes of this Section,
"peak program year" means the consecutive 12-month period with
the highest number of full-time equivalent jobs that occurs
between the beginning of investment year 2 and the end of
investment year 4.
A participating utility shall meet one of the following
commitments, as applicable:
(1) Beginning no later than 180 days after a
participating utility other than a combination utility
files a performance-based formula rate tariff pursuant to
subsection (c) of this Section, or, beginning no later
than January 1, 2012 if such utility files such
performance-based formula rate tariff within 14 days of
October 26, 2011 (the effective date of Public Act
97-616), the participating utility shall, except as

SB0311 - 211 - LRB102 15398 SPS 20761 b
provided in subsection (b-5):
(A) over a 5-year period, invest an estimated
$1,300,000,000 in electric system upgrades,
modernization projects, and training facilities,
including, but not limited to:
(i) distribution infrastructure improvements
totaling an estimated $1,000,000,000, including
underground residential distribution cable
injection and replacement and mainline cable
system refurbishment and replacement projects;
(ii) training facility construction or upgrade
projects totaling an estimated $10,000,000,
provided that, at a minimum, one such facility
shall be located in a municipality having a
population of more than 2 million residents and
one such facility shall be located in a
municipality having a population of more than
150,000 residents but fewer than 170,000
residents; any such new facility located in a
municipality having a population of more than 2
million residents must be designed for the purpose
of obtaining, and the owner of the facility shall
apply for, certification under the United States
Green Building Council's Leadership in Energy
Efficiency Design Green Building Rating System;
(iii) wood pole inspection, treatment, and

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replacement programs;
(iv) an estimated $200,000,000 for reducing
the susceptibility of certain circuits to
storm-related damage, including, but not limited
to, high winds, thunderstorms, and ice storms;
improvements may include, but are not limited to,
overhead to underground conversion and other
engineered outcomes for circuits; the
participating utility shall prioritize the
selection of circuits based on each circuit's
historical susceptibility to storm-related damage
and the ability to provide the greatest customer
benefit upon completion of the improvements; to be
eligible for improvement, the participating
utility's ability to maintain proper tree
clearances surrounding the overhead circuit must
not have been impeded by third parties; and
(B) over a 10-year period, invest an estimated
$1,300,000,000 to upgrade and modernize its
transmission and distribution infrastructure and in
Smart Grid electric system upgrades, including, but
not limited to:
(i) additional smart meters;
(ii) distribution automation;
(iii) associated cyber secure data
communication network; and

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(iv) substation micro-processor relay
upgrades.
(2) Beginning no later than 180 days after a
participating utility that is a combination utility files
a performance-based formula rate tariff pursuant to
subsection (c) of this Section, or, beginning no later
than January 1, 2012 if such utility files such
performance-based formula rate tariff within 14 days of
October 26, 2011 (the effective date of Public Act
97-616), the participating utility shall, except as
provided in subsection (b-5):
(A) over a 10-year period, invest an estimated
$265,000,000 in electric system upgrades,
modernization projects, and training facilities,
including, but not limited to:
(i) distribution infrastructure improvements
totaling an estimated $245,000,000, which may
include bulk supply substations, transformers,
reconductoring, and rebuilding overhead
distribution and sub-transmission lines,
underground residential distribution cable
injection and replacement and mainline cable
system refurbishment and replacement projects;
(ii) training facility construction or upgrade
projects totaling an estimated $1,000,000; any
such new facility must be designed for the purpose

SB0311 - 214 - LRB102 15398 SPS 20761 b
of obtaining, and the owner of the facility shall
apply for, certification under the United States
Green Building Council's Leadership in Energy
Efficiency Design Green Building Rating System;
and
(iii) wood pole inspection, treatment, and
replacement programs; and
(B) over a 10-year period, invest an estimated
$360,000,000 to upgrade and modernize its transmission
and distribution infrastructure and in Smart Grid
electric system upgrades, including, but not limited
to:
(i) additional smart meters;
(ii) distribution automation;
(iii) associated cyber secure data
communication network; and
(iv) substation micro-processor relay
upgrades.
For purposes of this Section, "Smart Grid electric system
upgrades" shall have the meaning set forth in subsection (a)
of Section 16-108.6 of this Act.
The investments in the infrastructure investment program
described in this subsection (b) shall be incremental to the
participating utility's annual capital investment program, as
defined by, for purposes of this subsection (b), the
participating utility's average capital spend for calendar

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years 2008, 2009, and 2010 as reported in the applicable
Federal Energy Regulatory Commission (FERC) Form 1; provided
that where one or more utilities have merged, the average
capital spend shall be determined using the aggregate of the
merged utilities' capital spend reported in FERC Form 1 for
the years 2008, 2009, and 2010. A participating utility may
add reasonable construction ramp-up and ramp-down time to the
investment periods specified in this subsection (b). For each
such investment period, the ramp-up and ramp-down time shall
not exceed a total of 6 months.
Within 60 days after filing a tariff under subsection (c)
of this Section, a participating utility shall submit to the
Commission its plan, including scope, schedule, and staffing,
for satisfying its infrastructure investment program
commitments pursuant to this subsection (b). The submitted
plan shall include a schedule and staffing plan for the next
calendar year. The plan shall also include a plan for the
creation, operation, and administration of a Smart Grid test
bed as described in subsection (c) of Section 16-108.8. The
plan need not allocate the work equally over the respective
periods, but should allocate material increments throughout
such periods commensurate with the work to be undertaken. No
later than April 1 of each subsequent year, the utility shall
submit to the Commission a report that includes any updates to
the plan, a schedule for the next calendar year, the
expenditures made for the prior calendar year and

SB0311 - 216 - LRB102 15398 SPS 20761 b
cumulatively, and the number of full-time equivalent jobs
created for the prior calendar year and cumulatively. If the
utility is materially deficient in satisfying a schedule or
staffing plan, then the report must also include a corrective
action plan to address the deficiency. The fact that the plan,
implementation of the plan, or a schedule changes shall not
imply the imprudence or unreasonableness of the infrastructure
investment program, plan, or schedule. Further, no later than
45 days following the last day of the first, second, and third
quarters of each year of the plan, a participating utility
shall submit to the Commission a verified quarterly report for
the prior quarter that includes (i) the total number of
full-time equivalent jobs created during the prior quarter,
(ii) the total number of employees as of the last day of the
prior quarter, (iii) the total number of full-time equivalent
hours in each job classification or job title, (iv) the total
number of incremental employees and contractors in support of
the investments undertaken pursuant to this subsection (b) for
the prior quarter, and (v) any other information that the
Commission may require by rule.
With respect to the participating utility's peak job
commitment, if, after considering the utility's corrective
action plan and compliance thereunder, the Commission enters
an order finding, after notice and hearing, that a
participating utility did not satisfy its peak job commitment
described in this subsection (b) for reasons that are

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reasonably within its control, then the Commission shall also
determine, after consideration of the evidence, including, but
not limited to, evidence submitted by the Department of
Commerce and Economic Opportunity and the utility, the
deficiency in the number of full-time equivalent jobs during
the peak program year due to such failure. The Commission
shall notify the Department of any proceeding that is
initiated pursuant to this paragraph. For each full-time
equivalent job deficiency during the peak program year that
the Commission finds as set forth in this paragraph, the
participating utility shall, within 30 days after the entry of
the Commission's order, pay $6,000 to a fund for training
grants administered under Section 605-800 of the Department of
Commerce and Economic Opportunity Law, which shall not be a
recoverable expense.
With respect to the participating utility's investment
amount commitments, if, after considering the utility's
corrective action plan and compliance thereunder, the
Commission enters an order finding, after notice and hearing,
that a participating utility is not satisfying its investment
amount commitments described in this subsection (b), then the
utility shall no longer be eligible to annually update the
performance-based formula rate tariff pursuant to subsection
(d) of this Section. In such event, the then current rates
shall remain in effect until such time as new rates are set
pursuant to Article IX of this Act, subject to retroactive

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adjustment, with interest, to reconcile rates charged with
actual costs.
If the Commission finds that a participating utility is no
longer eligible to update the performance-based formula rate
tariff pursuant to subsection (d) of this Section, or the
performance-based formula rate is otherwise terminated, then
the participating utility's voluntary commitments and
obligations under this subsection (b) shall immediately
terminate, except for the utility's obligation to pay an
amount already owed to the fund for training grants pursuant
to a Commission order.
In meeting the obligations of this subsection (b), to the
extent feasible and consistent with State and federal law, the
investments under the infrastructure investment program should
provide employment opportunities for all segments of the
population and workforce, including minority-owned and
woman-owned female-owned business enterprises, and shall not,
consistent with State and federal law, discriminate based on
race or socioeconomic status.
(b-5) Nothing in this Section shall prohibit the
Commission from investigating the prudence and reasonableness
of the expenditures made under the infrastructure investment
program during the annual review required by subsection (d) of
this Section and shall, as part of such investigation,
determine whether the utility's actual costs under the program
are prudent and reasonable. The fact that a participating

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utility invests more than the minimum amounts specified in
subsection (b) of this Section or its plan shall not imply
imprudence or unreasonableness.
If the participating utility finds that it is implementing
its plan for satisfying the infrastructure investment program
commitments described in subsection (b) of this Section at a
cost below the estimated amounts specified in subsection (b)
of this Section, then the utility may file a petition with the
Commission requesting that it be permitted to satisfy its
commitments by spending less than the estimated amounts
specified in subsection (b) of this Section. The Commission
shall, after notice and hearing, enter its order approving, or
approving as modified, or denying each such petition within
150 days after the filing of the petition.
In no event, absent General Assembly approval, shall the
capital investment costs incurred by a participating utility
other than a combination utility in satisfying its
infrastructure investment program commitments described in
subsection (b) of this Section exceed $3,000,000,000 or, for a
participating utility that is a combination utility,
$720,000,000. If the participating utility's updated cost
estimates for satisfying its infrastructure investment program
commitments described in subsection (b) of this Section exceed
the limitation imposed by this subsection (b-5), then it shall
submit a report to the Commission that identifies the
increased costs and explains the reason or reasons for the

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increased costs no later than the year in which the utility
estimates it will exceed the limitation. The Commission shall
review the report and shall, within 90 days after the
participating utility files the report, report to the General
Assembly its findings regarding the participating utility's
report. If the General Assembly does not amend the limitation
imposed by this subsection (b-5), then the utility may modify
its plan so as not to exceed the limitation imposed by this
subsection (b-5) and may propose corresponding changes to the
metrics established pursuant to subparagraphs (5) through (8)
of subsection (f) of this Section, and the Commission may
modify the metrics and incremental savings goals established
pursuant to subsection (f) of this Section accordingly.
(b-10) All participating utilities shall make
contributions for an energy low-income and support program in
accordance with this subsection. Beginning no later than 180
days after a participating utility files a performance-based
formula rate tariff pursuant to subsection (c) of this
Section, or beginning no later than January 1, 2012 if such
utility files such performance-based formula rate tariff
within 14 days of December 30, 2011 (the effective date of
Public Act 97-646), and without obtaining any approvals from
the Commission or any other agency other than as set forth in
this Section, regardless of whether any such approval would
otherwise be required, a participating utility other than a
combination utility shall pay $10,000,000 per year for 5 years

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and 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, which is intended to fund
customer assistance programs with the primary purpose being
avoidance of imminent disconnection. Such programs may
include:
(1) a residential hardship program that may partner
with community-based organizations, including senior
citizen organizations, and provides grants to low-income
residential customers, including low-income senior
citizens, who demonstrate a hardship;
(2) a program that provides grants and other bill
payment concessions to veterans with disabilities who
demonstrate a hardship and members of the armed services
or reserve forces of the United States or members of the
Illinois National Guard who are on active duty pursuant to
an executive order of the President of the United States,
an act of the Congress of the United States, or an order of
the Governor and who demonstrate a hardship;
(3) a budget assistance program that provides tools
and education to low-income senior citizens to assist them
with obtaining information regarding energy usage and
effective means of managing energy costs;
(4) a non-residential special hardship program that
provides grants to non-residential customers such as small
businesses and non-profit organizations that demonstrate a

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hardship, including those providing services to senior
citizen and low-income customers; and
(5) a performance-based assistance program that
provides grants to encourage residential customers to make
on-time payments by matching a portion of the customer's
payments or providing credits towards arrearages.
The payments made by a participating utility pursuant to
this subsection (b-10) shall not be a recoverable expense. A
participating utility may elect to fund either new or existing
customer assistance programs, including, but not limited to,
those that are administered by the utility.
Programs that use funds that are provided by a
participating utility to reduce utility bills may be
implemented through tariffs that are filed with and reviewed
by the Commission. If a utility elects to file tariffs with the
Commission to implement all or a portion of the programs,
those tariffs shall, regardless of the date actually filed, be
deemed accepted and approved, and shall become effective on
December 30, 2011 (the effective date of Public Act 97-646).
The participating utilities whose customers benefit from the
funds that are disbursed as contemplated in this Section shall
file annual reports documenting the disbursement of those
funds with the Commission. The Commission has the authority to
audit disbursement of the funds to ensure they were disbursed
consistently with this Section.
If the Commission finds that a participating utility is no

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longer eligible to update the performance-based formula rate
tariff pursuant to subsection (d) of this Section, or the
performance-based formula rate is otherwise terminated, then
the participating utility's voluntary commitments and
obligations under this subsection (b-10) shall immediately
terminate.
(b-15) Beginning in 2022, without obtaining any approvals
from the 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, which is intended to fund customer assistance
programs with the primary purpose of avoidance of imminent
disconnection and reconnecting customers who have been
disconnected for nonpayment. Such programs may include those
described in paragraphs (1) through (5) of subsection (b-10)
of this Section.
The payments made by a participating utility pursuant to
this subsection (b-15) is not a recoverable expense. A
participating utility may elect to fund either new or existing
customer assistance programs, including, but not limited to,
those that are administered by the utility.
Programs that use funds that are provided by a
participating utility to reduce utility bills may be
implemented through tariffs that are filed with and reviewed
by the Commission. If a utility elects to file tariffs with the

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Commission to implement all or a portion of the programs,
those tariffs shall, regardless of the date actually filed, be
deemed accepted and approved, and shall become effective on
the first business day after they are filed. The participating
utilities whose customers benefit from the funds that are
disbursed as contemplated in this subsection (b-15) shall file
annual reports documenting the disbursement of those funds
with the Commission. The Commission has the authority to audit
disbursement of the funds to ensure they were disbursed
consistently with this subsection (b-15).
If the Commission finds that a participating utility is no
longer eligible to update the performance-based formula rate
tariff pursuant to subsection (d) of this Section, or the
performance-based formula rate is otherwise terminated, then
the participating utility's voluntary commitments and
obligations under this subsection (b-15) shall immediately
terminate.
(c) A participating utility may elect to recover its
delivery services costs through a performance-based formula
rate approved by the Commission, which shall specify the cost
components that form the basis of the rate charged to
customers with sufficient specificity to operate in a
standardized manner and be updated annually with transparent
information that reflects the utility's actual costs to be
recovered during the applicable rate year, which is the period
beginning with the first billing day of January and extending

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through the last billing day of the following December. In the
event the utility recovers a portion of its costs through
automatic adjustment clause tariffs on October 26, 2011 (the
effective date of Public Act 97-616), the utility may elect to
continue to recover these costs through such tariffs, but then
these costs shall not be recovered through the
performance-based formula rate. In the event the participating
utility, prior to December 30, 2011 (the effective date of
Public Act 97-646), filed electric delivery services tariffs
with the Commission pursuant to Section 9-201 of this Act that
are related to the recovery of its electric delivery services
costs that are still pending on December 30, 2011 (the
effective date of Public Act 97-646), the participating
utility shall, at the time it files its performance-based
formula rate tariff with the Commission, also file a notice of
withdrawal with the Commission to withdraw the electric
delivery services tariffs previously filed pursuant to Section
9-201 of this Act. Upon receipt of such notice, the Commission
shall dismiss with prejudice any docket that had been
initiated to investigate the electric delivery services
tariffs filed pursuant to Section 9-201 of this Act, and such
tariffs and the record related thereto shall not be the
subject of any further hearing, investigation, or proceeding
of any kind related to rates for electric delivery services.
The performance-based formula rate shall be implemented
through a tariff filed with the Commission consistent with the

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provisions of this subsection (c) that shall be applicable to
all delivery services customers. The Commission shall initiate
and conduct an investigation of the tariff in a manner
consistent with the provisions of this subsection (c) and the
provisions of Article IX of this Act to the extent they do not
conflict with this subsection (c). Except in the case where
the Commission finds, after notice and hearing, that a
participating utility is not satisfying its investment amount
commitments under subsection (b) of this Section, the
performance-based formula rate shall remain in effect at the
discretion of the utility. The performance-based formula rate
approved by the Commission shall do the following:
(1) Provide for the recovery of the utility's actual
costs of delivery services that are prudently incurred and
reasonable in amount consistent with Commission practice
and law. The sole fact that a cost differs from that
incurred in a prior calendar year or that an investment is
different from that made in a prior calendar year shall
not imply the imprudence or unreasonableness of that cost
or investment.
(2) Reflect the utility's actual year-end capital
structure for the applicable calendar year, excluding
goodwill, subject to a determination of prudence and
reasonableness consistent with Commission practice and
law. To enable the financing of the incremental capital
expenditures, including regulatory assets, for electric

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utilities that serve less than 3,000,000 retail customers
but more than 500,000 retail customers in the State, a
participating electric utility's actual year-end capital
structure that includes a common equity ratio, excluding
goodwill, of up to and including 54% 50% of the total
capital structure shall be deemed reasonable and used to
set rates.
(3) Include a cost of equity, which in all years for a
participating utility that is not a combination utility,
and in each calendar year commencing before January 1,
2021 for a participating utility that is a combination
utility, shall be calculated as the sum of the following:
(A) the average for the applicable calendar year
of the monthly average yields of 30-year U.S. Treasury
bonds published by the Board of Governors of the
Federal Reserve System in its weekly H.15 Statistical
Release or successor publication; and
(B) 580 basis points.
For a participating utility that is a combination
utility, for each calendar year commencing after December
31, 2020, the cost of equity shall be equal to the national
average cost of equity as calculated under this paragraph
(3). For purposes of this paragraph (3), the national
average cost of equity for an applicable calendar year
shall be the simple average of the cost of equity
specified and approved in each order of a state regulatory

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commission, other than the Commission, issued during such
calendar year that is applicable to base rates for retail
electric service provided by an investor-owned public
utility company operating in the United States. No order
shall be excluded from the national average cost of equity
calculated under this paragraph (3) on the grounds that it
was arrived at by stipulation or agreement or is subject
to rehearing or appeal. In its final order in the
proceeding occurring pursuant to subsection (d) of this
Section during calendar year 2021, the Commission shall
set the cost of equity using the method applicable to
calendar years commencing prior to January 1, 2021. In its
final orders in the proceedings occurring pursuant to
subsection (d) of this Section in years subsequent to
calendar year 2021, including the reconciliation of the
2021 rate year, the Commission shall set the cost of
equity using the method applicable to calendar years
commencing after December 31, 2020. If, for any calendar
year, there are fewer than 15 applicable orders of state
regulatory commissions with which to compute the average
cost of equity, the Commission shall include in the
calculation of the national average the number of state
regulatory orders from the year or years immediately
preceding such calendar year necessary to reach a total of
15, beginning with the most recently issued and proceeding
in reverse chronological order.

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

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utility that is a combination utility or $10,000,000
for a participating utility that serves more than 3
million retail customers, then the full amount shall
be amortized consistent with subparagraph (F) of this
paragraph (4);
(D) investment return at a rate equal to the
utility's weighted average cost of long-term debt, on
the pension assets as, and in the amount, reported in
Account 186 (or in such other Account or Accounts as
such asset may subsequently be recorded) of the
utility's most recently filed FERC Form 1, net of
deferred tax benefits;
(E) recovery of the expenses related to the
Commission proceeding under this subsection (c) to
approve this performance-based formula rate and
initial rates or to subsequent proceedings related to
the formula, provided that the recovery shall be
amortized over a 3-year period; recovery of expenses
related to the annual Commission proceedings under
subsection (d) of this Section to review the inputs to
the performance-based formula rate shall be expensed
and recovered through the performance-based formula
rate;
(F) amortization over a 5-year period of the full
amount of each charge or credit that exceeds
$3,700,000 for a participating utility that is a

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combination utility or $10,000,000 for a participating
utility that serves more than 3 million retail
customers in the applicable calendar year and that
relates to a workforce reduction program's severance
costs, changes in accounting rules, changes in law,
compliance with any Commission-initiated audit, or a
single storm or other similar expense, provided that
any unamortized balance shall be reflected in rate
base. For purposes of this subparagraph (F), changes
in law includes any enactment, repeal, or amendment in
a law, ordinance, rule, regulation, interpretation,
permit, license, consent, or order, including those
relating to taxes, accounting, or to environmental
matters, or in the interpretation or application
thereof by any governmental authority occurring after
October 26, 2011 (the effective date of Public Act
97-616);
(G) recovery of existing regulatory assets over
the periods previously authorized by the Commission;
(H) historical weather normalized billing
determinants; and
(I) allocation methods for common costs.
(5) Provide that if the participating utility's earned
rate of return on common equity related to the provision
of delivery services for the prior rate year (calculated
using costs and capital structure approved by the

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

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the Commission as provided in subparagraph (2) of this
subsection (c), consistent with this Section, in
accordance with Commission rules and orders, including,
but not limited to, adjustments for goodwill, and after
any Commission-ordered disallowances and taxes) is more
than 50 basis points less than the return on common equity
calculated pursuant to paragraph (3) of this subsection
(c) (after adjusting for any adjustments penalties to the
rate of return on common equity applied pursuant to the
performance metrics provision of subsections subsection
(f), (f-5), (f-10), or (f-15) of this Section, as
applicable), then the participating utility shall apply a
charge through the performance-based formula rate that
reflects an amount equal to the value of that portion of
the earned rate of return on common equity that is more
than 50 basis points less than the rate of return on common
equity calculated pursuant to paragraph (3) of this
subsection (c) (after adjusting for any adjustments
penalties to the rate of return on common equity applied
pursuant to the performance metrics provision of
subsections subsection (f), (f-5), (f-10), or (f-15) of
this Section, as applicable) for the prior rate year,
adjusted for taxes.
(6) Provide for an annual reconciliation, as described
in subsection (d) of this Section, with interest, of the
revenue requirement reflected in rates for each calendar

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

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modified, the performance-based formula rate, including the
initial rates, as just and reasonable within 270 days after
the date on which the tariff was filed, or, if the tariff is
filed within 14 days after October 26, 2011 (the effective
date of Public Act 97-616), then by May 31, 2012. Such review
shall be based on the same evidentiary standards, including,
but not limited to, those concerning the prudence and
reasonableness of the costs incurred by the utility, the
Commission applies in a hearing to review a filing for a
general increase in rates under Article IX of this Act. The
initial rates shall take effect within 30 days after the
Commission's order approving the performance-based formula
rate tariff.
Until such time as the Commission approves a different
rate design and cost allocation pursuant to subsection (e) of
this Section, rate design and cost allocation across customer
classes shall be consistent with the Commission's most recent
order regarding the participating utility's request for a
general increase in its delivery services rates.
Subsequent changes to the performance-based formula rate
structure or protocols shall be made as set forth in Section
9-201 of this Act, but nothing in this subsection (c) is
intended to limit the Commission's authority under Article IX
and other provisions of this Act to initiate an investigation
of a participating utility's performance-based formula rate
tariff, provided that any such changes shall be consistent

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with paragraphs (1) through (6) of this subsection (c). Any
change ordered by the Commission shall be made at the same time
new rates take effect following the Commission's next order
pursuant to subsection (d) of this Section, provided that the
new rates take effect no less than 30 days after the date on
which the Commission issues an order adopting the change.
A participating utility that files a tariff pursuant to
this subsection (c) must submit a one-time $200,000 filing fee
at the time the Chief Clerk of the Commission accepts the
filing, which shall be a recoverable expense.
In the event the performance-based formula rate is
terminated, the then current rates shall remain in effect
until such time as new rates are set pursuant to Article IX of
this Act, subject to retroactive rate adjustment, with
interest, to reconcile rates charged with actual costs. At
such time that the performance-based formula rate is
terminated, the participating utility's voluntary commitments
and obligations under subsection (b) of this Section shall
immediately terminate, except for the utility's obligation to
pay an amount already owed to the fund for training grants
pursuant to a Commission order issued under subsection (b) of
this Section.
(c-5) Beginning in the first calendar year following the
year in which this reporting requirement becomes effective, a
participating utility that is a combination utility shall,
within 45 days after the close of each of the participating

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utility that is a combination utility's fiscal quarters,
submit to the Commission a report that summarizes the
additions to utility plant that were placed into service
during the prior quarter, which for purposes of the report
shall be the most recently closed fiscal quarter, as well as
what utility plant the participating utility that is a
combination utility projects will place into service through
the end of the calendar year in which the report is filed. The
quarterly report provided will be used for informational
purposes only, and any estimates therein shall not bind or
limit the participating utility that is a combination
utility's future decisions to invest in any utility plant or
other projects and may not be used in any Commission
proceeding to support any finding as to imprudence,
unreasonableness, or lack of use or usefulness of any
individual or aggregate level of utility plant or other
investment. Within 7 days of receiving a quarterly report, the
Commission shall make the report available to the public. Each
quarterly report shall include the following detail:
(1) the total dollar value of the additions to utility
plant placed in service during the prior quarter;
(2) a list of standing work orders for utility plant
placed in service during the prior quarter, including the
total dollar amount for the work reflected in each
standing work order as of the last day of the quarterly
reporting period and a summary description of the standing

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work order;
(3) a list of specific work orders for utility plant
placed in service during the prior quarter for utility
plant placed in service with a total dollar value as of the
last day of the quarterly reporting period that is equal
to or greater than $500,000, inclusive of the dollar
amount reflected in each specific work order and a summary
description of the specific work order;
(4) the estimated total dollar value of the additions
to utility plant projected to be placed in service through
the end of the calendar year in which the report is filed;
(5) a list of standing work orders for utility plant
projected to be placed in service through the end of the
calendar year in which the report is filed, including the
estimated dollar amount for the work reflected in each
standing work order and a summary description of the
standing work order; and
(6) a list of specific work orders for utility plant
projected to be placed in service through the end of the
calendar year in which the report is filed with an
estimated dollar value that is equal to or greater than
$500,000, inclusive of the estimated dollar amount for the
work reflected in each specific work order and a summary
description of the specific work order.
(d) Subsequent to the Commission's issuance of an order
approving the utility's performance-based formula rate

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structure and protocols, and initial rates under subsection
(c) of this Section, the utility shall file, on or before May 1
of each year, with the Chief Clerk of the Commission its
updated cost inputs to the performance-based formula rate for
the applicable rate year and the corresponding new charges.
Each such filing shall conform to the following requirements
and include the following information:
(1) The inputs to the performance-based formula rate
for the applicable rate year shall be based on final
historical data reflected in the utility's most recently
filed annual FERC Form 1 plus projected plant additions
and correspondingly updated depreciation reserve and
expense for the calendar year in which the inputs are
filed. The filing shall also include a reconciliation of
the revenue requirement that was in effect for the prior
rate year (as set by the cost inputs for the prior rate
year) with the actual revenue requirement for the prior
rate year (determined using a year-end rate base) that
uses amounts reflected in the applicable FERC Form 1 that
reports the actual costs for the prior rate year. Any
over-collection or under-collection indicated by such
reconciliation shall be reflected as a credit against, or
recovered as an additional charge to, respectively, with
interest calculated at a rate equal to the utility's
weighted average cost of capital approved by the
Commission for the prior rate year, the charges for the

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applicable rate year. Provided, however, that the first
such reconciliation shall be for the calendar year in
which the utility files its performance-based formula rate
tariff pursuant to subsection (c) of this Section and
shall reconcile (i) the revenue requirement or
requirements established by the rate order or orders in
effect from time to time during such calendar year
(weighted, as applicable) with (ii) the revenue
requirement determined using a year-end rate base for that
calendar year calculated pursuant to the performance-based
formula rate using (A) actual costs for that year as
reflected in the applicable FERC Form 1, and (B) for the
first such reconciliation only, the cost of equity, which
shall be calculated as the sum of 590 basis points plus the
average for the applicable calendar year of the monthly
average yields of 30-year U.S. Treasury bonds published by
the Board of Governors of the Federal Reserve System in
its weekly H.15 Statistical Release or successor
publication. The first such reconciliation is not intended
to provide for the recovery of costs previously excluded
from rates based on a prior Commission order finding of
imprudence or unreasonableness. Each reconciliation shall
be certified by the participating utility in the same
manner that FERC Form 1 is certified. The filing shall
also include the charge or credit, if any, resulting from
the calculation required by paragraph (6) of subsection

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(c) of this Section.
Notwithstanding anything that may be to the contrary,
the intent of the reconciliation is to ultimately
reconcile the revenue requirement reflected in rates for
each calendar year, beginning with the calendar year in
which the utility files its performance-based formula rate
tariff pursuant to subsection (c) of this Section, with
what the revenue requirement determined using a year-end
rate base for the applicable calendar year would have been
had the actual cost information for the applicable
calendar year been available at the filing date.
(2) The new charges shall take effect beginning on the
first billing day of the following January billing period
and remain in effect through the last billing day of the
next December billing period regardless of whether the
Commission enters upon a hearing pursuant to this
subsection (d).
(3) The filing shall include relevant and necessary
data and documentation for the applicable rate year that
is consistent with the Commission's rules applicable to a
filing for a general increase in rates or any rules
adopted by the Commission to implement this Section.
Normalization adjustments shall not be required.
Notwithstanding any other provision of this Section or Act
or any rule or other requirement adopted by the
Commission, a participating utility that is a combination

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utility with more than one rate zone shall not be required
to file a separate set of such data and documentation for
each rate zone and may combine such data and documentation
into a single set of schedules.
Within 45 days after the utility files its annual update
of cost inputs to the performance-based formula rate, the
Commission shall have the authority, either upon complaint or
its own initiative, but with reasonable notice, to enter upon
a hearing concerning the prudence and reasonableness of the
costs incurred by the utility to be recovered during the
applicable rate year that are reflected in the inputs to the
performance-based formula rate derived from the utility's FERC
Form 1. During the course of the hearing, each objection shall
be stated with particularity and evidence provided in support
thereof, after which the utility shall have the opportunity to
rebut the evidence. Discovery shall be allowed consistent with
the Commission's Rules of Practice, which Rules shall be
enforced by the Commission or the assigned administrative law
judge. The Commission shall apply the same evidentiary
standards, including, but not limited to, those concerning the
prudence and reasonableness of the costs incurred by the
utility, in the hearing as it would apply in a hearing to
review a filing for a general increase in rates under Article
IX of this Act. The Commission shall not, however, have the
authority in a proceeding under this subsection (d) to
consider or order any changes to the structure or protocols of

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the performance-based formula rate approved pursuant to
subsection (c) of this Section. In a proceeding under this
subsection (d), the Commission shall enter its order no later
than the earlier of 240 days after the utility's filing of its
annual update of cost inputs to the performance-based formula
rate or December 31. The Commission's determinations of the
prudence and reasonableness of the costs incurred for the
applicable calendar year shall be final upon entry of the
Commission's order and shall not be subject to reopening,
reexamination, or collateral attack in any other Commission
proceeding, case, docket, order, rule or regulation, provided,
however, that nothing in this subsection (d) shall prohibit a
party from petitioning the Commission to rehear or appeal to
the courts the order pursuant to the provisions of this Act.
In the event the Commission does not, either upon
complaint or its own initiative, enter upon a hearing within
45 days after the utility files the annual update of cost
inputs to its performance-based formula rate, then the costs
incurred for the applicable calendar year shall be deemed
prudent and reasonable, and the filed charges shall not be
subject to reopening, reexamination, or collateral attack in
any other proceeding, case, docket, order, rule, or
regulation.
A participating utility's first filing of the updated cost
inputs, and any Commission investigation of such inputs
pursuant to this subsection (d) shall proceed notwithstanding

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the fact that the Commission's investigation under subsection
(c) of this Section is still pending and notwithstanding any
other law, order, rule, or Commission practice to the
contrary.
(e) Nothing in subsections (c) or (d) of this Section
shall prohibit the Commission from investigating, or a
participating utility from filing, revenue-neutral tariff
changes related to rate design of a performance-based formula
rate that has been placed into effect for the utility.
Following approval of a participating utility's
performance-based formula rate tariff pursuant to subsection
(c) of this Section, the utility shall make a filing with the
Commission within one year after the effective date of the
performance-based formula rate tariff that proposes changes to
the tariff to incorporate the findings of any final rate
design orders of the Commission applicable to the
participating utility and entered subsequent to the
Commission's approval of the tariff. The Commission shall,
after notice and hearing, enter its order approving, or
approving with modification, the proposed changes to the
performance-based formula rate tariff within 240 days after
the utility's filing. Following such approval, the utility
shall make a filing with the Commission during each subsequent
3-year period that either proposes revenue-neutral tariff
changes or re-files the existing tariffs without change, which
shall present the Commission with an opportunity to suspend

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the tariffs and consider revenue-neutral tariff changes
related to rate design.
(f) Within 30 days after the filing of a tariff pursuant to
subsection (c) of this Section, each participating utility
shall develop and file with the Commission multi-year metrics
designed to achieve, ratably (i.e., in equal segments) over a
10-year period, improvement over baseline performance values
as follows:
(1) Twenty percent improvement in the System Average
Interruption Frequency Index, using a baseline of the
average of the data from 2001 through 2010.
(2) Fifteen percent improvement in the system Customer
Average Interruption Duration Index, using a baseline of
the average of the data from 2001 through 2010.
(3) For a participating utility other than a
combination utility, 20% improvement in the System Average
Interruption Frequency Index for its Southern Region,
using a baseline of the average of the data from 2001
through 2010. For purposes of this paragraph (3), Southern
Region shall have the meaning set forth in the
participating utility's most recent report filed pursuant
to Section 16-125 of this Act.
(3.5) For a participating utility other than a
combination utility, 20% improvement in the System Average
Interruption Frequency Index for its Northeastern Region,
using a baseline of the average of the data from 2001

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through 2010. For purposes of this paragraph (3.5),
Northeastern Region shall have the meaning set forth in
the participating utility's most recent report filed
pursuant to Section 16-125 of this Act.
(4) Seventy-five percent improvement in the total
number of customers who exceed the service reliability
targets as set forth in subparagraphs (A) through (C) of
paragraph (4) of subsection (b) of 83 Ill. Admin. Code
Part 411.140 as of May 1, 2011, using 2010 as the baseline
year.
(5) Reduction in issuance of estimated electric bills:
90% improvement for a participating utility other than a
combination utility, and 56% improvement for a
participating utility that is a combination utility, using
a baseline of the average number of estimated bills for
the years 2008 through 2010.
(6) Consumption on inactive meters: 90% improvement
for a participating utility other than a combination
utility, and 56% improvement for a participating utility
that is a combination utility, using a baseline of the
average unbilled kilowatthours for the years 2009 and
2010.
(7) Unaccounted for energy: 50% improvement for a
participating utility other than a combination utility
using a baseline of the non-technical line loss
unaccounted for energy kilowatthours for the year 2009.

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(8) Uncollectible expense: reduce uncollectible
expense by at least $30,000,000 for a participating
utility other than a combination utility and by at least
$3,500,000 for a participating utility that is a
combination utility, using a baseline of the average
uncollectible expense for the years 2008 through 2010.
(9) Opportunities for minority-owned and woman-owned
female-owned business enterprises: design a performance
metric regarding the creation of opportunities for
minority-owned and woman-owned female-owned business
enterprises consistent with State and federal law using a
base performance value of the percentage of the
participating utility's capital expenditures that were
paid to minority-owned and woman-owned female-owned
business enterprises in 2010.
The definitions set forth in 83 Ill. Admin. Code Part
411.20 as of May 1, 2011 shall be used for purposes of
calculating performance under paragraphs (1) through (3.5) of
this subsection (f), provided, however, that the participating
utility may exclude up to 9 extreme weather event days from
such calculation for each year, and provided further that the
participating utility shall exclude 9 extreme weather event
days when calculating each year of the baseline period to the
extent that there are 9 such days in a given year of the
baseline period. For purposes of this Section, an extreme
weather event day is a 24-hour calendar day (beginning at

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

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

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

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

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

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an identification of any extraordinary events that adversely
impacted the utility's performance. Whenever a participating
utility does not satisfy the metrics required pursuant to
subsection (f) of this Section, the Commission shall, after
notice and hearing, enter an order approving financial
penalties in accordance with this subsection (f-5). The
Commission-approved financial penalties shall be applied
beginning with the next rate year. Nothing in this Section
shall authorize the Commission to reduce or otherwise obviate
the imposition of financial penalties for failing to achieve
one or more of the metrics established pursuant to
subparagraph (1) through (4) of subsection (f) of this
Section.
(f-10) No later than December 31, 2021, a participating
utility that is a combination utility shall revise the tariff
it filed with the Commission pursuant to subsection (f) of
this Section to include multi-year metrics designed to achieve
ratably (in equal annual segments), where applicable, over the
10-year period beginning January 1, 2023 through December 31,
2032, maintenance or improvement over baseline performance
values as follows:
(1) Maintain the 20% improvement in the System Average
Interruption Frequency Index, using a baseline of the
average of the data from 2001 through 2010, achieved
during the initial 10-year performance period.
(2) Maintain the 15% improvement in the system

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Customer Average Interruption Duration Index, using a
baseline of the average of the data from 2001 through
2010, achieved during the initial 10-year performance
period.
(3) Increase the quantity of energy produced by solar
facilities owned and operated by the participating utility
to a level greater than or equal to 250,000 MWHs per year
by year 5 and 1,000,000 MWHs per year by year 10, using a
baseline of the data for the year end 2020.
(4) Increase the number of solar facilities owned and
operated by the participating utility, located, in whole
or part, within 5 miles of one or more of the 50 zip codes
in the participating utility's service territory that
include the largest percentage of households at or below
80% of area median income, to 10, by year 10, using a
baseline of year end 2020.
(5) Decrease the average driving distance between
publicly accessible Level III Fast DC charging locations
along major charging corridors (interstate and other major
travel routes) within the service territory of the
participating utility to 50 miles or less by year 5 using a
baseline of year end 2020.
(6) Increase the total number of publicly accessible
Level Two charging ports within the service territory of
the participating utility to 2,000 by year 5 using a
baseline of year end 2020.

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(7) Opportunities for minority-owned, woman-owned, and
veteran-owned business enterprises: design a performance
metric regarding the creation of opportunities for
minority-owned, woman-owned and veteran-owned business
enterprises consistent with State and federal law using a
base performance value of the percentage of the
participating utility's capital expenditures that were
paid to minority-owned, woman-owned and veteran-owned
business enterprises in the years 2018, 2019, and 2020.
The definitions set forth in 83 Ill. Adm. Code Part 411.20
as of May 1, 2011 shall be used for purposes of calculating
performance under paragraphs (1) and (2) of this subsection
(f-10), provided, however, that the participating utility may
exclude up to 9 extreme weather event days from such
calculation for each year, and provided further that the
participating utility shall exclude 9 extreme weather event
days when calculating each year of the baseline period to the
extent that there are 9 such days in a given year of the
baseline period. For purposes of this subsection (f-10), an
extreme weather event day is a 24-hour calendar day, beginning
at 12:00 a.m. and ending at 11:59 p.m., during which any
weather event, including but not limited to a storm or
tornado, caused interruptions for 3,500 or more of the
participating utility's customers for 3 hours or more. If
there are more than 9 extreme weather event days in a year,
then the utility may choose no more than 9 extreme weather

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event days to exclude, provided that the same extreme weather
event days are excluded from each of the calculations
performed under paragraphs (1) and (2) of this subsection
(f-10).
(f-15) The performance-based financial adjustments
applicable to the metrics described in subparagraphs (1)
through (6) of subsection (f-10) of this Section, as
applicable, shall be applied through an adjustment to the
participating utility's return on equity of no more than a
total of 40 basis points in each year of the 10-year
performance period:
(1) With respect to the incremental annual performance
goals established pursuant to paragraph (1) of subsection
(f-10) of this Section, for each year that a participating
utility does not achieve at least 95% of the annual goal,
the participating utility's return on equity shall be
reduced as follows: during years one through 5, by 8 basis
points; and during years 6 through 10, by 10 basis points;
for each year in which the participating utility achieves
105% or more of such goal, the participating utility's
return on equity shall be increased as follows: during
years one through 5, by 8 basis points; and during years 6
through 10, by 10 basis points.
(2) With respect to the incremental annual performance
goals established pursuant to paragraph (2) of subsection
(f-10) of this Section, for each year that a participating

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utility does not achieve at least 95% of the annual goal,
the participating utility's return on equity shall be
reduced as follows: during years one through 5, by 8 basis
points; and during years 6 through 10, by 10 basis points;
for each year in which the participating utility achieves
105% or more of such goal, the participating utility's
return on equity shall be increased as follows: during
years one through 5, by 8 basis points; and during years 6
through 10, by 10 basis points.
(3) With respect to the incremental annual performance
goals established pursuant to paragraph (3) of subsection
(f-10) of this Section, for each year that a participating
utility does not achieve at least 95% of the annual goal,
the participating utility's return on equity shall be
reduced as follows: during years one through 5, by 8 basis
points; and during years 6 through 10, by 10 basis points;
for each year in which the participating utility achieves
105% or more of such goal, the participating utility's
return on equity shall be increased as follows: during
years one through 5, by 8 basis points; and during years 6
through 10, by 10 basis points.
(4) With respect to the incremental annual performance
goals established pursuant to paragraph (4) of subsection
(f-10) of this Section, for each year that a participating
utility does not achieve at least 95% of the annual goal,
the participating utility's return on equity shall be

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reduced as follows: during years one through 5, by 8 basis
points; and during years 6 through 10, by 10 basis points;
for each year in which the participating utility achieves
105% or more of such goal, the participating utility's
return on equity shall be increased as follows: during
years one through 5, by 8 basis points; and during years 6
through 10, by 10 basis points.
(5) With respect to each of the incremental annual
performance goals established pursuant to paragraphs (5)
and (6) of subsection (f-10) of this Section, the
performance under each such goal shall be calculated in
terms of the percentage of the goal achieved. The
percentage of the goal achieved for each of the goals
shall be aggregated, and an average percentage value
calculated. For each year that a participating utility
does not achieve at least 95% of the annual goal, the
participating utility's return on equity shall be reduced
as follows: during years one through 5, by 8 basis points;
and during years 6 through 10, by no basis points; for each
year in which the participating utility achieves 105% or
more of such goal, the participating utility's return on
equity shall be increased as follows: during years one
through 5, by 8 basis points; and during years 6 through
10, by no basis points.
The financial adjustments shall be applied as described in
this subsection (f-15) for the 12-month period in which the

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performance occurred through a separate tariff mechanism,
which shall be filed by the utility together with its metrics.
In the event the performance based rate tariff established
pursuant to subsection (c) of this Section, terminates, the
utility's obligations under subsection (f), (f-5), (f-10), and
this subparagraph (f-15) shall also terminate, provided,
however, that the tariff mechanism established pursuant to
subsection (f-10) and this subsection (f-15) shall remain in
effect until the remaining balance of any financial
adjustments at the time of such termination is fully
amortized.
(g) On or before July 31, 2014, each participating utility
shall file a report with the Commission that sets forth the
average annual increase in the average amount paid per
kilowatthour for residential eligible retail customers,
exclusive of the effects of energy efficiency programs,
comparing the 12-month period ending May 31, 2012; the
12-month period ending May 31, 2013; and the 12-month period
ending May 31, 2014. For a participating utility that is a
combination utility with more than one rate zone, the weighted
average aggregate increase shall be provided. The report shall
be filed together with a statement from an independent auditor
attesting to the accuracy of the report. The cost of the
independent auditor shall be borne by the participating
utility and shall not be a recoverable expense. "The average
amount paid per kilowatthour" shall be based on the

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participating utility's tariffed rates actually in effect and
shall not be calculated using any hypothetical rate or
adjustments to actual charges (other than as specified for
energy efficiency) as an input.
In the event that the average annual increase exceeds 2.5%
as calculated pursuant to this subsection (g), then Sections
16-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act, other
than this subsection, shall be inoperative as they relate to
the utility and its service area as of the date of the report
due to be submitted pursuant to this subsection and the
utility shall no longer be eligible to annually update the
performance-based formula rate tariff pursuant to subsection
(d) of this Section. In such event, the then current rates
shall remain in effect until such time as new rates are set
pursuant to Article IX of this Act, subject to retroactive
adjustment, with interest, to reconcile rates charged with
actual costs, and the participating utility's voluntary
commitments and obligations under subsection (b) of this
Section shall immediately terminate, except for the utility's
obligation to pay an amount already owed to the fund for
training grants pursuant to a Commission order issued under
subsection (b) of this Section.
In the event that the average annual increase is 2.5% or
less as calculated pursuant to this subsection (g), then the
performance-based formula rate shall remain in effect as set
forth in this Section.

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For purposes of this Section, the amount per kilowatthour
means the total amount paid for electric service expressed on
a per kilowatthour basis, and the total amount paid for
electric service includes without limitation amounts paid for
supply, transmission, distribution, surcharges, and add-on
taxes exclusive of any increases in taxes or new taxes imposed
after October 26, 2011 (the effective date of Public Act
97-616). For purposes of this Section, "eligible retail
customers" shall have the meaning set forth in Section
16-111.5 of this Act.
The fact that this Section becomes inoperative as set
forth in this subsection shall not be construed to mean that
the Commission may reexamine or otherwise reopen prudence or
reasonableness determinations already made.
(h) By December 31, 2017, the Commission shall prepare and
file with the General Assembly a report on the infrastructure
program and the performance-based formula rate. The report
shall include the change in the average amount per
kilowatthour paid by residential customers between June 1,
2011 and May 31, 2017. If the change in the total average rate
paid exceeds 2.5% compounded annually, the Commission shall
include in the report an analysis that shows the portion of the
change due to the delivery services component and the portion
of the change due to the supply component of the rate. The
report shall include separate sections for each participating
utility.

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This Section, other than this subsection (h), and Sections
16-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act, other
than this subsection (h), are inoperative after December 31,
2022 for every participating utility other than a combination
utility, after which time a participating utility other than a
combination utility shall no longer be eligible to annually
update the performance-based formula rate tariff pursuant to
subsection (d) of this Section. At such time, the then current
rates shall remain in effect until such time as new rates are
set pursuant to Article IX of this Act, subject to retroactive
adjustment, with interest, to reconcile rates charged with
actual costs.
This Section, other than this subsection (h), and Sections
16-108.6, 16-108.7, and 16-108.8 of this Act are inoperative
after December 31, 2032 for every participating utility that
is a combination utility, after which time a participating
utility that is a combination utility shall no longer be
eligible to annually update the performance-based formula rate
tariff pursuant to subsection (d) of this Section. At such
time, the then current rates shall remain in effect until such
time as new rates are set pursuant to Article IX of this Act,
subject to retroactive adjustment, with interest, to reconcile
rates charged with actual costs.
The fact that this Section becomes inoperative as set
forth in this subsection shall not be construed to mean that
the Commission may reexamine or otherwise reopen prudence or

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reasonableness determinations already made.
(i) While a participating utility may use, develop, and
maintain broadband systems and the delivery of broadband
services, voice-over-internet-protocol services,
telecommunications services, and cable and video programming
services for use in providing delivery services and Smart Grid
functionality or application to its retail customers,
including, but not limited to, the installation,
implementation and maintenance of Smart Grid electric system
upgrades as defined in Section 16-108.6 of this Act, a
participating utility is prohibited from offering to its
retail customers broadband services or the delivery of
broadband services, voice-over-internet-protocol services,
telecommunications services, or cable or video programming
services, unless they are part of a service directly related
to delivery services or Smart Grid functionality or
applications as defined in Section 16-108.6 of this Act, and
from recovering the costs of such offerings from retail
customers.
(j) Nothing in this Section is intended to legislatively
overturn the opinion issued in Commonwealth Edison Co. v. Ill.
Commerce Comm'n, Nos. 2-08-0959, 2-08-1037, 2-08-1137,
1-08-3008, 1-08-3030, 1-08-3054, 1-08-3313 cons. (Ill. App.
Ct. 2d Dist. Sept. 30, 2010). Public Act 97-616 shall not be
construed as creating a contract between the General Assembly
and the participating utility, and shall not establish a

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property right in the participating utility.
(k) The changes made in subsections (c) and (d) of this
Section by Public Act 98-15 are intended to be a restatement
and clarification of existing law, and intended to give
binding effect to the provisions of House Resolution 1157
adopted by the House of Representatives of the 97th General
Assembly and Senate Resolution 821 adopted by the Senate of
the 97th General Assembly that are reflected in paragraph (3)
of this subsection. In addition, Public Act 98-15 preempts and
supersedes any final Commission orders entered in Docket Nos.
11-0721, 12-0001, 12-0293, and 12-0321 to the extent
inconsistent with the amendatory language added to subsections
(c) and (d).
(1) No earlier than 5 business days after May 22, 2013
(the effective date of Public Act 98-15), each
participating utility shall file any tariff changes
necessary to implement the amendatory language set forth
in subsections (c) and (d) of this Section by Public Act
98-15 and a revised revenue requirement under the
participating utility's performance-based formula rate.
The Commission shall enter a final order approving such
tariff changes and revised revenue requirement within 21
days after the participating utility's filing.
(2) Notwithstanding anything that may be to the
contrary, a participating utility may file a tariff to
retroactively recover its previously unrecovered actual

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costs of delivery service that are no longer subject to
recovery through a reconciliation adjustment under
subsection (d) of this Section. This retroactive recovery
shall include any derivative adjustments resulting from
the changes to subsections (c) and (d) of this Section by
Public Act 98-15. Such tariff shall allow the utility to
assess, on current customer bills over a period of 12
monthly billing periods, a charge or credit related to
those unrecovered costs with interest at the utility's
weighted average cost of capital during the period in
which those costs were unrecovered. A participating
utility may file a tariff that implements a retroactive
charge or credit as described in this paragraph for
amounts not otherwise included in the tariff filing
provided for in paragraph (1) of this subsection (k). The
Commission shall enter a final order approving such tariff
within 21 days after the participating utility's filing.
(3) The tariff changes described in paragraphs (1) and
(2) of this subsection (k) shall relate only to, and be
consistent with, the following provisions of Public Act
98-15: paragraph (2) of subsection (c) regarding year-end
capital structure, subparagraph (D) of paragraph (4) of
subsection (c) regarding pension assets, and subsection
(d) regarding the reconciliation components related to
year-end rate base and interest calculated at a rate equal
to the utility's weighted average cost of capital.

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(4) Nothing in this subsection is intended to effect a
dismissal of or otherwise affect an appeal from any final
Commission orders entered in Docket Nos. 11-0721, 12-0001,
12-0293, and 12-0321 other than to the extent of the
amendatory language contained in subsections (c) and (d)
of this Section of Public Act 98-15.
(l) Each participating utility shall be deemed to have
been in full compliance with all requirements of subsection
(b) of this Section, subsection (c) of this Section, Section
16-108.6 of this Act, and all Commission orders entered
pursuant to Sections 16-108.5 and 16-108.6 of this Act, up to
and including May 22, 2013 (the effective date of Public Act
98-15). The Commission shall not undertake any investigation
of such compliance and no penalty shall be assessed or adverse
action taken against a participating utility for noncompliance
with Commission orders associated with subsection (b) of this
Section, subsection (c) of this Section, and Section 16-108.6
of this Act prior to such date. Each participating utility
other than a combination utility shall be permitted, without
penalty, a period of 12 months after such effective date to
take actions required to ensure its infrastructure investment
program is in compliance with subsection (b) of this Section
and with Section 16-108.6 of this Act. Provided further, the
following subparagraphs shall apply to a participating utility
other than a combination utility:
(A) if the Commission has initiated a proceeding

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pursuant to subsection (e) of Section 16-108.6 of this Act
that is pending as of May 22, 2013 (the effective date of
Public Act 98-15), then the order entered in such
proceeding shall, after notice and hearing, accelerate the
commencement of the meter deployment schedule approved in
the final Commission order on rehearing entered in Docket
No. 12-0298;
(B) if the Commission has entered an order pursuant to
subsection (e) of Section 16-108.6 of this Act prior to
May 22, 2013 (the effective date of Public Act 98-15) that
does not accelerate the commencement of the meter
deployment schedule approved in the final Commission order
on rehearing entered in Docket No. 12-0298, then the
utility shall file with the Commission, within 45 days
after such effective date, a plan for accelerating the
commencement of the utility's meter deployment schedule
approved in the final Commission order on rehearing
entered in Docket No. 12-0298; the Commission shall reopen
the proceeding in which it entered its order pursuant to
subsection (e) of Section 16-108.6 of this Act and shall,
after notice and hearing, enter an amendatory order that
approves or approves as modified such accelerated plan
within 90 days after the utility's filing; or
(C) if the Commission has not initiated a proceeding
pursuant to subsection (e) of Section 16-108.6 of this Act
prior to May 22, 2013 (the effective date of Public Act

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98-15), then the utility shall file with the Commission,
within 45 days after such effective date, a plan for
accelerating the commencement of the utility's meter
deployment schedule approved in the final Commission order
on rehearing entered in Docket No. 12-0298 and the
Commission shall, after notice and hearing, approve or
approve as modified such plan within 90 days after the
utility's filing.
Any schedule for meter deployment approved by the
Commission pursuant to this subsection (l) shall take into
consideration procurement times for meters and other equipment
and operational issues. Nothing in Public Act 98-15 shall
shorten or extend the end dates for the 5-year or 10-year
periods set forth in subsection (b) of this Section or Section
16-108.6 of this Act. Nothing in this subsection is intended
to address whether a participating utility has, or has not,
satisfied any or all of the metrics and performance goals
established pursuant to subsection (f) of this Section.
(m) The provisions of Public Act 98-15 are severable under
Section 1.31 of the Statute on Statutes.
(Source: P.A. 99-143, eff. 7-27-15; 99-642, eff. 7-28-16;
99-906, eff. 6-1-17; 100-840, eff. 8-13-18.)
(220 ILCS 5/16-108.19 new)
Sec. 16-108.19. Electric vehicle charging station
infrastructure.

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(a) Notwithstanding any other provisions of this Act and
without obtaining any approvals from the Commission or any
other agency, including, but not limited to, approvals
otherwise required under Section 8-406 of this Act, regardless
of whether any such approval would otherwise be required,
electric utilities that serve less than 3,000,000 retail
customers but more than 500,000 retail customers in this State
are authorized to, but are not required 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. Electric utilities that serve less than 3,000,000
retail customers but more than 500,000 retail customers in
this State may construct electric vehicle charging
infrastructure on private property or publicly owned property;
however, the Commission may not authorize an electric utility
under Section 8-509 of this Act to acquire property rights by
eminent domain for the construction of any electric vehicle
charging station. Electric utilities that serve less than
3,000,000 retail customers but more than 500,000 retail
customers in this State shall be allowed to recover all
reasonable and prudent costs associated with investment in the
electric vehicle charging infrastructure, including, but not
limited to, costs to plan for, construct, install, control,
own, manage, or operate under this Section through the
applicable provisions of this Article XVI or Article IX of

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this Act.
(b) Electric utilities that serve less than 3,000,000
retail customers but more than 500,000 retail customers in
this State may file with the Commission an electric vehicle
charging infrastructure deployment and charging facility
rebate plan, the purpose of which shall be to encourage the
adoption of electric vehicles in this State, including in the
service territory of the electric utilities subject to this
Section. The plan filed by an electric utility subject to this
Section shall identify a system of publicly accessible
electric vehicle charging stations and a schedule of rebates
that would be available to: (1) retail customers taking
electric service from the electric utility at an address in
the electric utility's service territory; and (2) any third
party that would construct, own, or operate a publicly
accessible electric vehicle charging station as authorized by
this Section. The Commission shall review the plan for
compliance with the provisions of this Section 16-108.19 and
issue an order either approving or modifying the plan within
180 days after the initial filing. If the Commission finds
that the plan filed pursuant to this subsection (b) complies
with the requirements of subsections (c) and (d) of this
Section, the Commission shall approve the plan and the
electric utility shall implement it in accordance with the
Commission approval. If the Commission modifies the plan, the
electric utility shall notify the Commission in writing within

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90 days after service of the Commission's order modifying the
plan as to whether the electric utility accepts the
Commission's modifications. If the electric utility notifies
the Commission in writing that it does not accept the
Commission's modifications, the electric utility shall have no
further obligations with respect to the plan, including any
obligation to implement the plan as modified and may, at its
discretion, file a new plan with the Commission in the future.
Upon approval by the Commission and acceptance by the electric
utility of a plan filed under this subsection (b), no further
approvals by the Commission other than those approvals set
forth in this Section shall be necessary and the electric
utility shall implement the approved plan in accordance with
the Commission's approval.
(c) A plan filed under subsection (b) of this Section
shall include, at a minimum, the following categories of
information regarding the proposed deployment of electric
vehicle charging stations:
(1) Identification of existing publicly accessible
electric vehicle charging station infrastructure installed
in the electric utility's service territory.
(2) Sufficient detail to identify the proposed general
location and type of electric vehicle charging station
infrastructure that could be installed on private or
publicly owned land along proposed electric vehicle
charging corridors or other public spaces within the

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electric utility's service territory, including the
general identification of any proposed location and type
of electric vehicle charging station infrastructure that
the electric utility proposes to be part of the
third-party request for proposals process set forth in
paragraph (3) of this subsection (c);
(3) A proposed request for proposals process to be
managed by the electric utility, which shall request
proposals from third parties to compete for utility
rebates for the construction, ownership, and operation of
the electric vehicle charging stations within the electric
utility's service territory. The request for proposals
process shall address at least the following information
for the proposed electric vehicle charging infrastructure:
(A) requirements for electric vehicle charging
station infrastructure owners and operators regarding
construction, installation, operation, and maintenance
for each proposed general location;
(B) criteria by which the bids will be reviewed
and assessed; however, bids shall address the proposed
ownership and ongoing operation of the electric
vehicle charging station and the bids may be
contingent on securing State or federal funds,
including any tax incentives, available for electric
vehicle charging station development or deployment;
(C) provisions for how rebates will be made

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available to electric vehicle charging station winning
bidders, which shall be designed to encourage
participation in the request for proposals process and
actual construction, installation, ownership, and
operation of the electric vehicle charging station at
each proposed location; and
(D) a proposal that provides the electric utility
the option to plan for, construct, install, control,
own, manage, or operate any electric vehicle charging
infrastructure at any location identified for
inclusion in the request for proposals, but for which
no third-party bid was received or awarded under the
criteria identified pursuant to this paragraph (3).
(d) In addition to the information set forth in subsection
(c) of this Section, a plan filed under subsection (b) of this
Section shall also include the following categories of
information:
(1) The proposed rebates offered by the electric
utility to customers taking service from the electric
utility at an address within its service territory for
electric vehicle charging infrastructure or facilities,
which should include, but not be limited to, the following
information:
(A) identification of available rebates for
electric utility residential customers who purchase
electric vehicles and install home electric vehicle

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charging facilities subsequent to the effective date
of this amendatory Act of the 102nd General Assembly;
(B) identification of available rebates for
multi-family residential buildings and non-residential
customers that, subsequent to the effective date of
this amendatory Act of the 102nd General Assembly,
install and provide access to electric vehicle
charging facilities located in a common area generally
available to residents or the public;
(C) identification of available rebates designed
to promote the use of electric vehicles serving
low-income or moderate-income communities, including,
but not limited to, any rebates available to shared
electric vehicles, ride share electric vehicles, and
public transportation fleets or school districts using
electric vehicles; and
(D) the manner and timing of the payment of the
proposed rebates; however, the rebates identified
pursuant to this paragraph (1) may be paid through a
monthly bill credit spread fairly and reasonably
across a 12-month period, and provided any customer
receiving a rebate must sign up for and remain on a
3-part delivery service rate, if available.
(2) An estimated budget for the electric utility to
develop and implement an education and engagement strategy
that encourages the adoption of electric vehicles in the

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electric utility's service territory, including, but not
limited to, programs to be delivered to entities that
educate and promote the adoption of electric vehicles,
including, but not limited to, car dealerships and
elementary, middle, and high schools.
(e) An electric utility implementing a plan approved
pursuant to subsection (b) of this Section, may update its
plan at any time by filing such update with the Commission in
the same docket in which the Commission originally approved
the plan. Any updated filing made pursuant to this subsection
(e) must identify the updates to be implemented and any
updates shall be deemed approved as reasonable 45 days after
the filing unless the Commission initiates an investigation
into the updated actions. Any final order regarding the
investigation initiated pursuant to this subsection (e) must
be issued within 180 days of the initiating order.
(f) Notwithstanding any other provision of law to the
contrary, electric utilities that serve less than 3,000,000
retail customers but more than 500,000 retail customers in
this State shall be permitted to recover all reasonable and
prudently incurred costs incurred under this Section,
including, but not limited to, any costs incurred to make any
location identified pursuant to subsections (b) and (c) of
this Section ready for installation and connection of an
electric vehicle charging station to the distribution system;
the costs incurred to provide the rebates identified pursuant

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to subsections (b), (c), and (d) of this Section; the costs
incurred to undertake the education and engagement activities
authorized under this Section; and other costs incurred by the
utility to comply with and implement the requirements of this
Section, including any amounts that reasonably exceed any
estimates provided as part of the plan filed pursuant to
subsection (b) of this Section. Electric utilities that serve
less than 3,000,000 retail customers but more than 500,000
retail customers in this State are authorized to recover any
costs identified in this subsection (f) by way of a tariff or
tariffs approved by the Illinois Commerce Commission,
consistent with the following provisions:
(1) An electric utility subject to this Section shall
be permitted to recover all reasonable and prudently
incurred costs incurred to make any location identified
pursuant to subsections (b) and (c) of this Section ready
for installation and connection of an electric vehicle
charging station to the distribution system through its
delivery service rates, as authorized by the applicable
provisions of Article IX or this Article XVI. For any
electric vehicle infrastructure identified in any plan
filed pursuant to subsections (b) and (c) of this Section,
distribution extension free allowances up to and including
$1,500 per kilowatt of connected electric vehicle charging
station equipment shall be deemed reasonable and shall not
limit the use of alternate extension provisions

SB0311 - 277 - LRB102 15398 SPS 20761 b
demonstrated to be more favorable and approved by the
Illinois Commerce Commission.
(2) Beginning on the effective date of this amendatory
Act of the 102nd General Assembly, an electric utility
subject to this Section shall have authority to defer up
to the full amount of its costs incurred under this
Section, other than those costs being recovered pursuant
to paragraph (1) of this subsection (f), as a regulatory
asset, to be amortized over a 15-year period. The
unamortized balance shall be recognized as of December 31
for a given year. The utility shall also earn a return on
the total of the unamortized balance of the regulatory
asset authorized under this Section, less any deferred
taxes related to the unamortized balance, at an annual
rate equal to the utility's weighted average cost of
capital that includes, based on a year-end capital
structure, the utility's actual cost of debt for the
applicable calendar year and a cost of equity, which shall
be equal to the national average cost of equity as
calculated under this paragraph (2). For purposes of this
paragraph (2), the national average cost of equity for a
calendar year shall be the simple average of the cost of
equity specified and approved in each order of a state
regulatory commission, other than the Commission, issued
during such calendar year that is applicable to base rates
for retail electric service provided by an investor-owned

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public utility company operating in the United States. No
order shall be excluded from the national average cost of
equity calculated under this paragraph (2) on the grounds
that it was arrived at by stipulation or agreement or is
subject to rehearing or appeal. If, for any calendar year,
there are fewer than 15 applicable orders of state
regulatory commissions with which to compute the average
cost of equity, the Commission shall include in the
calculation of the national average the number of state
regulatory orders from the year or years immediately
preceding such calendar year necessary to reach a total of
15, beginning with the most recently issued and proceeding
in reverse chronological order.
(3) When an electric utility subject to this Section
creates a regulatory asset under the provisions of this
Section, the costs shall be recovered over a period during
which customers also receive a benefit, which is in the
public interest. Accordingly, it is the intent of the
General Assembly that an electric utility that elects to
create a regulatory asset under the provisions of this
Section shall recover all of the associated costs,
including, but not limited to, its cost of capital as set
forth in this Section. After the Commission has approved,
as set forth in this Section, the prudence and
reasonableness of the costs that comprise the regulatory
asset, the electric utility shall be permitted to recover

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all such costs, and the value and recoverability through
rates of the associated regulatory asset shall not be
limited, altered, impaired, or reduced. To enable the
financing of the incremental capital expenditures,
including regulatory assets, for electric utilities
subject to this Section, the utility's actual year-end
capital structure that includes a common equity ratio,
excluding goodwill, of up to and including 54% of the
total capital structure shall be deemed reasonable and
used to set rates.
(4) Notwithstanding paragraph (1) of this subsection
(f), an electric utility subject to this Section may, at
its election, recover some or all of the costs it incurs
under this Section as part of a filing for a general
increase in rates under Article IX of this Act, as part of
an annual filing to update a performance-based formula
rate under subsection (d) of Section 16-108.5 of this Act
or subsection (d) of Section 8-103B, or through an
automatic adjustment clause tariff; provided that nothing
in this paragraph (4) of this subsection (f) permits the
double recovery of such costs from customers. Such costs
shall be allocated across all classes of retail customers
in proportion to delivery service revenue requirement
attributed to a class. If the electric utility elects to
recover the costs it incurs under this Section through an
automatic adjustment clause tariff, the utility may file

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its proposed tariff together with the plan it files under
subsection (b) of this Section or at a later time. The
proposed tariff shall provide for an annual
reconciliation, less any deferred taxes related to the
reconciliation, with interest at an annual rate of return
equal to the utility's weighted average cost of capital as
calculated under paragraph (2) of this subsection (f),
including a revenue conversion factor calculated to
recover or refund all additional income taxes that may be
payable or receivable as a result of that return, of the
revenue requirement reflected in rates for each calendar
year, beginning with the calendar year in which the
utility files its automatic adjustment clause tariff under
this subsection (f), with what the revenue requirement
would have been had the actual cost information for the
applicable calendar year been available at the filing
date. The tariff may permit recovery of costs through a
single cents per kilowatt-hour charge applicable to each
retail class. The Commission shall review the proposed
tariff and may make changes to the tariff that are
consistent with this Section and with the Commission's
authority under Article IX of this Act, subject to notice
and hearing, as required. Following notice and hearing, as
required, the Commission shall issue an order approving,
or approving with modification, such tariff no later than
240 days after the electric utility files its tariff.

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(g) Any electric vehicle charging infrastructure,
including, but not limited to, an electric vehicle charging
station, constructed, installed, controlled, owned, managed,
or operated by an electric utility pursuant to this Section
shall be treated as jurisdictional distribution plant assets
for ratemaking purposes. The investment in, and the costs to
construct, install, control, own, manage, or operate electric
vehicle charging infrastructure owned by the electric utility
shall be fully recovered in delivery service rates. The
electric utility shall charge, pursuant to a tariff on file
with the Commission, market rates for electricity sold through
every such electric vehicle charging station, and all revenue
from such sales shall be credited to distribution customers in
the applicable ratemaking process.
(h) In addition to the plan authorized in subsection (b),
electric utilities that serve less than 3,000,000 retail
customers but more than 500,000 retail customers in this State
shall be permitted to administer programs designed to
encourage or incentivize the adoption of electric vehicles by
Illinois electric consumers, and such programs shall not be
prohibited by the Commission as promotional practices under
any rules or policies of the Commission, including, but not
limited to, 83 Ill. Adm. Code Part 275.
(220 ILCS 5/16-108.20 new)
Sec. 16-108.20. Electric energy storage.

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(a) An electric utility may plan for, construct, install,
control, own, manage, or operate energy storage as part of its
distribution system when such electric utility has reasonably
and prudently assessed and determined that such energy storage
will preserve, maintain, or improve stability and reliability
of the electric utility's distribution system.
(b) Notwithstanding any other provision of law to the
contrary, an electric utility subject to this Section shall be
permitted to recover all reasonable and prudently incurred
costs incurred under this Section, including, but not limited
to, the costs incurred to plan for, construct, control, own,
manage, or operate the infrastructure and undertake activities
identified in this Section in a reasonable and prudent manner
pursuant to Article IX or this Article XVI, as applicable, and
for purposes of cost recovery the energy storage facilities
shall be treated as distribution assets; provided that: (1)
the Commission shall have the authority to determine the
reasonableness of the costs of the facilities; and (2) any
monetary value of power and energy from the facilities shall
be credited against the delivery services revenue requirement.
An electric utility subject to this Section shall operate
storage for the primary purpose of facilitating stable and
reliable delivery service, and any loss incidental to the
operation of storage facilities shall also be recoverable to
the extent such losses were prudently incurred as a result of
the operation of the facility.

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(220 ILCS 5/16-111.5)
Sec. 16-111.5. Provisions relating to procurement.
(a) An electric utility that on December 31, 2005 served
at least 100,000 customers in Illinois shall procure power and
energy for its eligible retail customers in accordance with
the applicable provisions set forth in Section 1-75 of the
Illinois Power Agency Act and this Section. Beginning with the
delivery year commencing on June 1, 2017, such electric
utility shall also procure zero emission credits from zero
emission facilities in accordance with the applicable
provisions set forth in Section 1-75 of the Illinois Power
Agency Act, and, for years beginning on or after June 1, 2017,
the utility shall procure renewable energy resources in
accordance with the applicable provisions set forth in Section
1-75 of the Illinois Power Agency Act and this Section. A small
multi-jurisdictional electric utility that on December 31,
2005 served less than 100,000 customers in Illinois may elect
to procure power and energy for all or a portion of its
eligible Illinois retail customers in accordance with the
applicable provisions set forth in this Section and Section
1-75 of the Illinois Power Agency Act. This Section shall not
apply to a small multi-jurisdictional utility until such time
as a small multi-jurisdictional utility requests the Illinois
Power Agency to prepare a procurement plan for its eligible
retail customers. "Eligible retail customers" for the purposes

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of this Section means those retail customers that purchase
power and energy from the electric utility under fixed-price
bundled service tariffs, other than those retail customers
whose service is declared or deemed competitive under Section
16-113 and those other customer groups specified in this
Section, including self-generating customers, customers
electing hourly pricing, or those customers who are otherwise
ineligible for fixed-price bundled tariff service. For those
customers that are excluded from the procurement plan's
electric supply service requirements, and the utility shall
procure any supply requirements, including capacity, ancillary
services, and hourly priced energy, in the applicable markets
as needed to serve those customers, provided that the utility
may include in its procurement plan load requirements for the
load that is associated with those retail customers whose
service has been declared or deemed competitive pursuant to
Section 16-113 of this Act to the extent that those customers
are purchasing power and energy during one of the transition
periods identified in subsection (b) of Section 16-113 of this
Act.
(b) A procurement plan shall be prepared for each electric
utility consistent with the applicable requirements of the
Illinois Power Agency Act and this Section. For purposes of
this Section, Illinois electric utilities that are affiliated
by virtue of a common parent company are considered to be a
single electric utility. Small multi-jurisdictional utilities

SB0311 - 285 - LRB102 15398 SPS 20761 b
may request a procurement plan for a portion of or all of its
Illinois load. Each procurement plan shall analyze the
projected balance of supply and demand for those retail
customers to be included in the plan's electric supply service
requirements over a 5-year period, with the first planning
year beginning on June 1 of the year following the year in
which the plan is filed. The plan shall specifically identify
the wholesale products to be procured following plan approval,
and shall follow all the requirements set forth in the Public
Utilities Act and all applicable State and federal laws,
statutes, rules, or regulations, as well as Commission orders.
Nothing in this Section precludes consideration of contracts
longer than 5 years and related forecast data. Unless
specified otherwise in this Section, in the procurement plan
or in the implementing tariff, any procurement occurring in
accordance with this plan shall be competitively bid through a
request for proposals process. Approval and implementation of
the procurement plan shall be subject to review and approval
by the Commission according to the provisions set forth in
this Section. A procurement plan shall include each of the
following components:
(1) Hourly load analysis. This analysis shall include:
(i) multi-year historical analysis of hourly
loads;
(ii) switching trends and competitive retail
market analysis;

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(iii) known or projected changes to future loads;
and
(iv) growth forecasts by customer class.
(2) Analysis of the impact of any demand side and
renewable energy initiatives. This analysis shall include:
(i) the impact of demand response programs and
energy efficiency programs, both current and
projected; for small multi-jurisdictional utilities,
the impact of demand response and energy efficiency
programs approved pursuant to Section 8-408 of this
Act, both current and projected; and
(ii) supply side needs that are projected to be
offset by purchases of renewable energy resources, if
any.
(3) A plan for meeting the expected load requirements
that will not be met through preexisting contracts. This
plan shall include:
(i) definitions of the different Illinois retail
customer classes for which supply is being purchased;
(ii) the proposed mix of demand-response products
for which contracts will be executed during the next
year. For small multi-jurisdictional electric
utilities that on December 31, 2005 served fewer than
100,000 customers in Illinois, these shall be defined
as demand-response products offered in an energy
efficiency plan approved pursuant to Section 8-408 of

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this Act. The cost-effective demand-response measures
shall be procured whenever the cost is lower than
procuring comparable capacity products, provided that
such products shall:
(A) be procured by a demand-response provider
from those retail customers included in the plan's
electric supply service requirements;
(B) at least satisfy the demand-response
requirements of the regional transmission
organization market in which the utility's service
territory is located, including, but not limited
to, any applicable capacity or dispatch
requirements;
(C) provide for customers' participation in
the stream of benefits produced by the
demand-response products;
(D) provide for reimbursement by the
demand-response provider of the utility for any
costs incurred as a result of the failure of the
supplier of such products to perform its
obligations thereunder; and
(E) meet the same credit requirements as apply
to suppliers of capacity, in the applicable
regional transmission organization market;
(iii) monthly forecasted system supply
requirements, including expected minimum, maximum, and

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average values for the planning period;
(iv) the proposed mix and selection of standard
wholesale products for which contracts will be
executed during the next year, separately or in
combination, to meet that portion of its load
requirements not met through pre-existing contracts,
including but not limited to monthly 5 x 16 peak period
block energy, monthly off-peak wrap energy, monthly 7
x 24 energy, annual 5 x 16 energy, annual off-peak wrap
energy, annual 7 x 24 energy, monthly capacity, annual
capacity, peak load capacity obligations, capacity
purchase plan, and ancillary services;
(v) proposed term structures for each wholesale
product type included in the proposed procurement plan
portfolio of products; and
(vi) an assessment of the price risk, load
uncertainty, and other factors that are associated
with the proposed procurement plan; this assessment,
to the extent possible, shall include an analysis of
the following factors: contract terms, time frames for
securing products or services, fuel costs, weather
patterns, transmission costs, market conditions, and
the governmental regulatory environment; the proposed
procurement plan shall also identify alternatives for
those portfolio measures that are identified as having
significant price risk.

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(4) Proposed procedures for balancing loads. The
procurement plan shall include, for load requirements
included in the procurement plan, the process for (i)
hourly balancing of supply and demand and (ii) the
criteria for portfolio re-balancing in the event of
significant shifts in load.
(5) Long-Term Renewable Resources Procurement Plan.
The Agency shall prepare a long-term renewable resources
procurement plan for the procurement of renewable energy
credits under Sections 1-56 and 1-75 of the Illinois Power
Agency Act for delivery beginning in the 2017 delivery
year.
(i) The initial long-term renewable resources
procurement plan and all subsequent revisions shall be
subject to review and approval by the Commission. For
the purposes of this Section, "delivery year" has the
same meaning as in Section 1-10 of the Illinois Power
Agency Act. For purposes of this Section, "Agency"
shall mean the Illinois Power Agency.
(ii) The long-term renewable resources planning
process shall be conducted as follows:
(A) Electric utilities shall provide a range
of load forecasts to the Illinois Power Agency
within 45 days of the Agency's request for
forecasts, which request shall specify the length
and conditions for the forecasts including, but

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not limited to, the quantity of distributed
generation expected to be interconnected for each
year.
(B) The Agency shall publish for comment the
initial long-term renewable resources procurement
plan no later than 120 days after the effective
date of this amendatory Act of the 99th General
Assembly and shall review, and may revise, the
plan at least every 2 years thereafter. To the
extent practicable, the Agency shall review and
propose any revisions to the long-term renewable
energy resources procurement plan in conjunction
with the Agency's other planning and approval
processes conducted under this Section. The
initial long-term renewable resources procurement
plan shall:
(aa) Identify the procurement programs and
competitive procurement events consistent with
the applicable requirements of the Illinois
Power Agency Act and shall be designed to
achieve the goals set forth in subsection (c)
of Section 1-75 of that Act.
(bb) Include a schedule for procurements
for renewable energy credits from
utility-scale wind projects, utility-scale
solar projects, and brownfield site

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photovoltaic projects consistent with
subparagraph (G) of paragraph (1) of
subsection (c) of Section 1-75 of the Illinois
Power Agency Act.
(cc) Identify the process whereby the
Agency will submit to the Commission for
review and approval the proposed contracts to
implement the programs required by such plan.
Copies of the initial long-term renewable
resources procurement plan and all subsequent
revisions shall be posted and made publicly
available on the Agency's and Commission's
websites, and copies shall also be provided to
each affected electric utility. As part of any
renewable resources procurement plan, the Agency
will compile and publish a list of any sellers of
renewable energy resources procured by the Agency
that are not, as of January 1 of the calendar year
in which the procurement plan will be filed for
approval with the Commission, in compliance with
the reporting obligations of Section 5-117 of the
Public Utilities Act, and the Agency shall not
procure any renewable energy resources from any
entity not in compliance with the reporting
obligations of Section 5-117 of the Public
Utilities Act in the procurement plan. An affected

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utility and other interested parties shall have 45
days following the date of posting to provide
comment to the Agency on the initial long-term
renewable resources procurement plan and all
subsequent revisions. All comments submitted to
the Agency shall be specific, supported by data or
other detailed analyses, and, if objecting to all
or a portion of the procurement plan, accompanied
by specific alternative wording or proposals. All
comments shall be posted on the Agency's and
Commission's websites. During this 45-day comment
period, the Agency shall hold at least one public
hearing within each utility's service area that is
subject to the requirements of this paragraph (5)
for the purpose of receiving public comment.
Within 21 days following the end of the 45-day
review period, the Agency may revise the long-term
renewable resources procurement plan based on the
comments received and shall file the plan with the
Commission for review and approval.
(C) Within 14 days after the filing of the
initial long-term renewable resources procurement
plan or any subsequent revisions, any person
objecting to the plan may file an objection with
the Commission. Within 21 days after the filing of
the plan, the Commission shall determine whether a

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hearing is necessary. The Commission shall enter
its order confirming or modifying the initial
long-term renewable resources procurement plan or
any subsequent revisions within 120 days after the
filing of the plan by the Illinois Power Agency.
(D) The Commission shall approve the initial
long-term renewable resources procurement plan and
any subsequent revisions, including expressly the
forecast used in the plan and taking into account
that funding will be limited to the amount of
revenues actually collected by the utilities, if
the Commission determines that the plan will
reasonably and prudently accomplish the
requirements of Section 1-56 and subsection (c) of
Section 1-75 of the Illinois Power Agency Act. The
Commission shall also approve the process for the
submission, review, and approval of the proposed
contracts to procure renewable energy credits or
implement the programs authorized by the
Commission pursuant to a long-term renewable
resources procurement plan approved under this
Section.
(iii) The Agency or third parties contracted by
the Agency shall implement all programs authorized by
the Commission in an approved long-term renewable
resources procurement plan without further review and

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approval by the Commission. Third parties shall not
begin implementing any programs or receive any payment
under this Section until the Commission has approved
the contract or contracts under the process authorized
by the Commission in item (D) of subparagraph (ii) of
paragraph (5) of this subsection (b) and the third
party and the Agency or utility, as applicable, have
executed the contract. For those renewable energy
credits subject to procurement through a competitive
bid process under the plan or under the initial
forward procurements for wind and solar resources
described in subparagraph (G) of paragraph (1) of
subsection (c) of Section 1-75 of the Illinois Power
Agency Act, the Agency shall follow the procurement
process specified in the provisions relating to
electricity procurement in subsections (e) through (i)
of this Section.
(iv) An electric utility shall recover its costs
associated with the procurement of renewable energy
credits under this Section through an automatic
adjustment clause tariff under subsection (k) of
Section 16-108 of this Act. A utility shall not be
required to advance any payment or pay any amounts
under this Section that exceed the actual amount of
revenues collected by the utility under paragraph (6)
of subsection (c) of Section 1-75 of the Illinois

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Power Agency Act and subsection (k) of Section 16-108
of this Act, and contracts executed under this Section
shall expressly incorporate this limitation.
(v) For the public interest, safety, and welfare,
the Agency and the Commission may adopt rules to carry
out the provisions of this Section on an emergency
basis immediately following the effective date of this
amendatory Act of the 99th General Assembly.
(vi) On or before July 1 of each year, the
Commission shall hold an informal hearing for the
purpose of receiving comments on the prior year's
procurement process and any recommendations for
change.
(c) The procurement process set forth in Section 1-75 of
the Illinois Power Agency Act and subsection (e) of this
Section shall be administered by a procurement administrator
and monitored by a procurement monitor.
(1) The procurement administrator shall:
(i) design the final procurement process in
accordance with Section 1-75 of the Illinois Power
Agency Act and subsection (e) of this Section
following Commission approval of the procurement plan;
(ii) develop benchmarks in accordance with
subsection (e)(3) to be used to evaluate bids; these
benchmarks shall be submitted to the Commission for
review and approval on a confidential basis prior to

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

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bids;
(x) notify the utility of contract counterparties
and contract specifics; and
(xi) administer related contingency procurement
events.
(2) The procurement monitor, who shall be retained by
the Commission, shall:
(i) monitor interactions among the procurement
administrator, suppliers, and utility;
(ii) monitor and report to the Commission on the
progress of the procurement process;
(iii) provide an independent confidential report
to the Commission regarding the results of the
procurement event;
(iv) assess compliance with the procurement plans
approved by the Commission for each utility that on
December 31, 2005 provided electric service to at
least 100,000 customers in Illinois and for each small
multi-jurisdictional utility that on December 31, 2005
served less than 100,000 customers in Illinois;
(v) preserve the confidentiality of supplier and
bidding information in a manner consistent with all
applicable laws, rules, regulations, and tariffs;
(vi) provide expert advice to the Commission and
consult with the procurement administrator regarding
issues related to procurement process design, rules,

SB0311 - 298 - LRB102 15398 SPS 20761 b
protocols, and policy-related matters; and
(vii) consult with the procurement administrator
regarding the development and use of benchmark
criteria, standard form contracts, credit policies,
and bid documents.
(d) Except as provided in subsection (j), the planning
process shall be conducted as follows:
(1) Beginning in 2008, each Illinois utility procuring
power pursuant to this Section shall annually provide a
range of load forecasts to the Illinois Power Agency by
July 15 of each year, or such other date as may be required
by the Commission or Agency. The load forecasts shall
cover the 5-year procurement planning period for the next
procurement plan and shall include hourly data
representing a high-load, low-load, and expected-load
scenario for the load of those retail customers included
in the plan's electric supply service requirements. The
utility shall provide supporting data and assumptions for
each of the scenarios.
(2) Beginning in 2008, the Illinois Power Agency shall
prepare a procurement plan by August 15th of each year, or
such other date as may be required by the Commission. The
procurement plan shall identify the portfolio of
demand-response and power and energy products to be
procured. Cost-effective demand-response measures shall be
procured as set forth in item (iii) of subsection (b) of

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this Section. Copies of the procurement plan shall be
posted and made publicly available on the Agency's and
Commission's websites, and copies shall also be provided
to each affected electric utility. An affected utility
shall have 30 days following the date of posting to
provide comment to the Agency on the procurement plan.
Other interested entities also may comment on the
procurement plan. All comments submitted to the Agency
shall be specific, supported by data or other detailed
analyses, and, if objecting to all or a portion of the
procurement plan, accompanied by specific alternative
wording or proposals. All comments shall be posted on the
Agency's and Commission's websites. During this 30-day
comment period, the Agency shall hold at least one public
hearing within each utility's service area for the purpose
of receiving public comment on the procurement plan.
Within 14 days following the end of the 30-day review
period, the Agency shall revise the procurement plan as
necessary based on the comments received and file the
procurement plan with the Commission and post the
procurement plan on the websites.
(3) Within 5 days after the filing of the procurement
plan, any person objecting to the procurement plan shall
file an objection with the Commission. Within 10 days
after the filing, the Commission shall determine whether a
hearing is necessary. The Commission shall enter its order

SB0311 - 300 - LRB102 15398 SPS 20761 b
confirming or modifying the procurement plan within 90
days after the filing of the procurement plan by the
Illinois Power Agency.
(4) The Commission shall approve the procurement plan,
including expressly the forecast used in the procurement
plan, if the Commission determines that it will ensure
adequate, reliable, affordable, efficient, and
environmentally sustainable electric service at the lowest
total cost over time, taking into account any benefits of
price stability.
(e) The procurement process shall include each of the
following components:
(1) Solicitation, pre-qualification, and registration
of bidders. The procurement administrator shall
disseminate information to potential bidders to promote a
procurement event, notify potential bidders that the
procurement administrator may enter into a post-bid price
negotiation with bidders that meet the applicable
benchmarks, provide supply requirements, and otherwise
explain the competitive procurement process. In addition
to such other publication as the procurement administrator
determines is appropriate, this information shall be
posted on the Illinois Power Agency's and the Commission's
websites. The procurement administrator shall also
administer the prequalification process, including
evaluation of credit worthiness, compliance with

SB0311 - 301 - LRB102 15398 SPS 20761 b
procurement rules, and agreement to the standard form
contract developed pursuant to paragraph (2) of this
subsection (e). The procurement administrator shall then
identify and register bidders to participate in the
procurement event.
(2) Standard contract forms and credit terms and
instruments. The procurement administrator, in
consultation with the utilities, the Commission, and other
interested parties and subject to Commission oversight,
shall develop and provide standard contract forms for the
supplier contracts that meet generally accepted industry
practices. Standard credit terms and instruments that meet
generally accepted industry practices shall be similarly
developed. The procurement administrator shall make
available to the Commission all written comments it
receives on the contract forms, credit terms, or
instruments. If the procurement administrator cannot reach
agreement with the applicable electric utility as to the
contract terms and conditions, the procurement
administrator must notify the Commission of any disputed
terms and the Commission shall resolve the dispute. The
terms of the contracts shall not be subject to negotiation
by winning bidders, and the bidders must agree to the
terms of the contract in advance so that winning bids are
selected solely on the basis of price.
(3) Establishment of a market-based price benchmark.

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As part of the development of the procurement process, the
procurement administrator, in consultation with the
Commission staff, Agency staff, and the procurement
monitor, shall establish benchmarks for evaluating the
final prices in the contracts for each of the products
that will be procured through the procurement process. The
benchmarks shall be based on price data for similar
products for the same delivery period and same delivery
hub, or other delivery hubs after adjusting for that
difference. The price benchmarks may also be adjusted to
take into account differences between the information
reflected in the underlying data sources and the specific
products and procurement process being used to procure
power for the Illinois utilities. The benchmarks shall be
confidential but shall be provided to, and will be subject
to Commission review and approval, prior to a procurement
event.
(4) Request for proposals competitive procurement
process. The procurement administrator shall design and
issue a request for proposals to supply electricity in
accordance with each utility's procurement plan, as
approved by the Commission. The request for proposals
shall set forth a procedure for sealed, binding commitment
bidding with pay-as-bid settlement, and provision for
selection of bids on the basis of price.
(5) A plan for implementing contingencies in the event

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of supplier default or failure of the procurement process
to fully meet the expected load requirement due to
insufficient supplier participation, Commission rejection
of results, or any other cause.
(i) Event of supplier default: In the event of
supplier default, the utility shall review the
contract of the defaulting supplier to determine if
the amount of supply is 200 megawatts or greater, and
if there are more than 60 days remaining of the
contract term. If both of these conditions are met,
and the default results in termination of the
contract, the utility shall immediately notify the
Illinois Power Agency that a request for proposals
must be issued to procure replacement power, and the
procurement administrator shall run an additional
procurement event. If the contracted supply of the
defaulting supplier is less than 200 megawatts or
there are less than 60 days remaining of the contract
term, the utility shall procure power and energy from
the applicable regional transmission organization
market, including ancillary services, capacity, and
day-ahead or real time energy, or both, for the
duration of the contract term to replace the
contracted supply; provided, however, that if a needed
product is not available through the regional
transmission organization market it shall be purchased

SB0311 - 304 - LRB102 15398 SPS 20761 b
from the wholesale market.
(ii) Failure of the procurement process to fully
meet the expected load requirement: If the procurement
process fails to fully meet the expected load
requirement due to insufficient supplier participation
or due to a Commission rejection of the procurement
results, the procurement administrator, the
procurement monitor, and the Commission staff shall
meet within 10 days to analyze potential causes of low
supplier interest or causes for the Commission
decision. If changes are identified that would likely
result in increased supplier participation, or that
would address concerns causing the Commission to
reject the results of the prior procurement event, the
procurement administrator may implement those changes
and rerun the request for proposals process according
to a schedule determined by those parties and
consistent with Section 1-75 of the Illinois Power
Agency Act and this subsection. In any event, a new
request for proposals process shall be implemented by
the procurement administrator within 90 days after the
determination that the procurement process has failed
to fully meet the expected load requirement.
(iii) In all cases where there is insufficient
supply provided under contracts awarded through the
procurement process to fully meet the electric

SB0311 - 305 - LRB102 15398 SPS 20761 b
utility's load requirement, the utility shall meet the
load requirement by procuring power and energy from
the applicable regional transmission organization
market, including ancillary services, capacity, and
day-ahead or real time energy, or both; provided,
however, that if a needed product is not available
through the regional transmission organization market
it shall be purchased from the wholesale market.
(6) The procurement process described in this
subsection is exempt from the requirements of the Illinois
Procurement Code, pursuant to Section 20-10 of that Code.
(f) Within 2 business days after opening the sealed bids,
the procurement administrator shall submit a confidential
report to the Commission. The report shall contain the results
of the bidding for each of the products along with the
procurement administrator's recommendation for the acceptance
and rejection of bids based on the price benchmark criteria
and other factors observed in the process. The procurement
monitor also shall submit a confidential report to the
Commission within 2 business days after opening the sealed
bids. The report shall contain the procurement monitor's
assessment of bidder behavior in the process as well as an
assessment of the procurement administrator's compliance with
the procurement process and rules. The Commission shall review
the confidential reports submitted by the procurement
administrator and procurement monitor, and shall accept or

SB0311 - 306 - LRB102 15398 SPS 20761 b
reject the recommendations of the procurement administrator
within 2 business days after receipt of the reports.
(g) Within 3 business days after the Commission decision
approving the results of a procurement event, the utility
shall enter into binding contractual arrangements with the
winning suppliers using the standard form contracts; except
that the utility shall not be required either directly or
indirectly to execute the contracts if a tariff that is
consistent with subsection (l) of this Section has not been
approved and placed into effect for that utility.
(h) The names of the successful bidders and the load
weighted average of the winning bid prices for each contract
type and for each contract term shall be made available to the
public at the time of Commission approval of a procurement
event. The Commission, the procurement monitor, the
procurement administrator, the Illinois Power Agency, and all
participants in the procurement process shall maintain the
confidentiality of all other supplier and bidding information
in a manner consistent with all applicable laws, rules,
regulations, and tariffs. Confidential information, including
the confidential reports submitted by the procurement
administrator and procurement monitor pursuant to subsection
(f) of this Section, shall not be made publicly available and
shall not be discoverable by any party in any proceeding,
absent a compelling demonstration of need, nor shall those
reports be admissible in any proceeding other than one for law

SB0311 - 307 - LRB102 15398 SPS 20761 b
enforcement purposes.
(i) Within 2 business days after a Commission decision
approving the results of a procurement event or such other
date as may be required by the Commission from time to time,
the utility shall file for informational purposes with the
Commission its actual or estimated retail supply charges, as
applicable, by customer supply group reflecting the costs
associated with the procurement and computed in accordance
with the tariffs filed pursuant to subsection (l) of this
Section and approved by the Commission.
(j) Within 60 days following August 28, 2007 (the
effective date of Public Act 95-481), each electric utility
that on December 31, 2005 provided electric service to at
least 100,000 customers in Illinois shall prepare and file
with the Commission an initial procurement plan, which shall
conform in all material respects to the requirements of the
procurement plan set forth in subsection (b); provided,
however, that the Illinois Power Agency Act shall not apply to
the initial procurement plan prepared pursuant to this
subsection. The initial procurement plan shall identify the
portfolio of power and energy products to be procured and
delivered for the period June 2008 through May 2009, and shall
identify the proposed procurement administrator, who shall
have the same experience and expertise as is required of a
procurement administrator hired pursuant to Section 1-75 of
the Illinois Power Agency Act. Copies of the procurement plan

SB0311 - 308 - LRB102 15398 SPS 20761 b
shall be posted and made publicly available on the
Commission's website. The initial procurement plan may include
contracts for renewable resources that extend beyond May 2009.
(i) Within 14 days following filing of the initial
procurement plan, any person may file a detailed objection
with the Commission contesting the procurement plan
submitted by the electric utility. All objections to the
electric utility's plan shall be specific, supported by
data or other detailed analyses. The electric utility may
file a response to any objections to its procurement plan
within 7 days after the date objections are due to be
filed. Within 7 days after the date the utility's response
is due, the Commission shall determine whether a hearing
is necessary. If it determines that a hearing is
necessary, it shall require the hearing to be completed
and issue an order on the procurement plan within 60 days
after the filing of the procurement plan by the electric
utility.
(ii) The order shall approve or modify the procurement
plan, approve an independent procurement administrator,
and approve or modify the electric utility's tariffs that
are proposed with the initial procurement plan. The
Commission shall approve the procurement plan if the
Commission determines that it will ensure adequate,
reliable, affordable, efficient, and environmentally
sustainable electric service at the lowest total cost over

SB0311 - 309 - LRB102 15398 SPS 20761 b
time, taking into account any benefits of price stability.
(k) (Blank).
(k-5) (Blank).
(l) An electric utility shall recover its costs incurred
under this Section, including, but not limited to, the costs
of procuring power and energy demand-response resources under
this Section. The utility shall file with the initial
procurement plan its proposed tariffs through which its costs
of procuring power that are incurred pursuant to a
Commission-approved procurement plan and those other costs
identified in this subsection (l), will be recovered. The
tariffs shall include a formula rate or charge designed to
pass through both the costs incurred by the utility in
procuring a supply of electric power and energy for the
applicable customer classes with no mark-up or return on the
price paid by the utility for that supply, plus any just and
reasonable costs that the utility incurs in arranging and
providing for the supply of electric power and energy. The
formula rate or charge shall also contain provisions that
ensure that its application does not result in over or under
recovery due to changes in customer usage and demand patterns,
and that provide for the correction, on at least an annual
basis, of any accounting errors that may occur. A utility
shall recover through the tariff all reasonable costs incurred
to implement or comply with any procurement plan that is
developed and put into effect pursuant to Section 1-75 of the

SB0311 - 310 - LRB102 15398 SPS 20761 b
Illinois Power Agency Act and this Section, including any fees
assessed by the Illinois Power Agency, costs associated with
load balancing, and contingency plan costs. The electric
utility shall also recover its full costs of procuring
electric supply for which it contracted before the effective
date of this Section in conjunction with the provision of full
requirements service under fixed-price bundled service tariffs
subsequent to December 31, 2006. All such costs shall be
deemed to have been prudently incurred. The pass-through
tariffs that are filed and approved pursuant to this Section
shall not be subject to review under, or in any way limited by,
Section 16-111(i) of this Act. All of the costs incurred by the
electric utility associated with the purchase of zero emission
credits in accordance with subsection (d-5) of Section 1-75 of
the Illinois Power Agency Act and, beginning June 1, 2017, all
of the costs incurred by the electric utility associated with
the purchase of renewable energy resources in accordance with
Sections 1-56 and 1-75 of the Illinois Power Agency Act, shall
be recovered through the electric utility's tariffed charges
applicable to all of its retail customers, as specified in
subsection (k) of Section 16-108 of this Act, and shall not be
recovered through the electric utility's tariffed charges for
electric power and energy supply to its eligible retail
customers.
(m) The Commission has the authority to adopt rules to
carry out the provisions of this Section. For the public

SB0311 - 311 - LRB102 15398 SPS 20761 b
interest, safety, and welfare, the Commission also has
authority to adopt rules to carry out the provisions of this
Section on an emergency basis immediately following August 28,
2007 (the effective date of Public Act 95-481).
(n) Notwithstanding any other provision of this Act, any
affiliated electric utilities that submit a single procurement
plan covering their combined needs may procure for those
combined needs in conjunction with that plan, and may enter
jointly into power supply contracts, purchases, and other
procurement arrangements, and allocate capacity and energy and
cost responsibility therefor among themselves in proportion to
their requirements.
(o) On or before June 1 of each year, the Commission shall
hold an informal hearing for the purpose of receiving comments
on the prior year's procurement process and any
recommendations for change.
(p) An electric utility subject to this Section may
propose to invest, lease, own, or operate an electric
generation facility as part of its procurement plan, provided
the utility demonstrates that such facility is the least-cost
option to provide electric service to those retail customers
included in the plan's electric supply service requirements.
If the facility is shown to be the least-cost option and is
included in a procurement plan prepared in accordance with
Section 1-75 of the Illinois Power Agency Act and this
Section, then the electric utility shall make a filing

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pursuant to Section 8-406 of this Act, and may request of the
Commission any statutory relief required thereunder. If the
Commission grants all of the necessary approvals for the
proposed facility, such supply shall thereafter be considered
as a pre-existing contract under subsection (b) of this
Section. The Commission shall in any order approving a
proposal under this subsection specify how the utility will
recover the prudently incurred costs of investing in, leasing,
owning, or operating such generation facility through just and
reasonable rates charged to those retail customers included in
the plan's electric supply service requirements. Cost recovery
for facilities included in the utility's procurement plan
pursuant to this subsection shall not be subject to review
under or in any way limited by the provisions of Section
16-111(i) of this Act. Nothing in this Section is intended to
prohibit a utility from filing for a fuel adjustment clause as
is otherwise permitted under Section 9-220 of this Act.
(q) If the Illinois Power Agency filed with the
Commission, under Section 16-111.5 of this Act, its proposed
procurement plan for the period commencing June 1, 2017, and
the Commission has not yet entered its final order approving
the plan on or before the effective date of this amendatory Act
of the 99th General Assembly, then the Illinois Power Agency
shall file a notice of withdrawal with the Commission, after
the effective date of this amendatory Act of the 99th General
Assembly, to withdraw the proposed procurement of renewable

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energy resources to be approved under the plan, other than the
procurement of renewable energy credits from distributed
renewable energy generation devices using funds previously
collected from electric utilities' retail customers that take
service pursuant to electric utilities' hourly pricing tariff
or tariffs and, for an electric utility that serves less than
100,000 retail customers in the State, other than the
procurement of renewable energy credits from distributed
renewable energy generation devices. Upon receipt of the
notice, the Commission shall enter an order that approves the
withdrawal of the proposed procurement of renewable energy
resources from the plan. The initially proposed procurement of
renewable energy resources shall not be approved or be the
subject of any further hearing, investigation, proceeding, or
order of any kind.
This amendatory Act of the 99th General Assembly preempts
and supersedes any order entered by the Commission that
approved the Illinois Power Agency's procurement plan for the
period commencing June 1, 2017, to the extent it is
inconsistent with the provisions of this amendatory Act of the
99th General Assembly. To the extent any previously entered
order approved the procurement of renewable energy resources,
the portion of that order approving the procurement shall be
void, other than the procurement of renewable energy credits
from distributed renewable energy generation devices using
funds previously collected from electric utilities' retail

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customers that take service under electric utilities' hourly
pricing tariff or tariffs and, for an electric utility that
serves less than 100,000 retail customers in the State, other
than the procurement of renewable energy credits for
distributed renewable energy generation devices.
(Source: P.A. 99-906, eff. 6-1-17.)
(220 ILCS 5/16-128A)
Sec. 16-128A. Certification of installers, maintainers, or
repairers.
(a) Within 18 months of the effective date of this
amendatory Act of the 97th General Assembly, the Commission
shall adopt rules, including emergency rules, establishing
certification requirements ensuring that entities installing
distributed generation facilities are in compliance with the
requirements of subsection (a) of Section 16-128 of this Act.
For purposes of this Section, the phrase "entities
installing distributed generation facilities" shall include,
but not be limited to, all entities that are exempt from the
definition of "alternative retail electric supplier" under
item (v) of Section 16-102 of this Act. For purposes of this
Section, the phrase "self-installer" means an individual who
(i) leases or purchases a cogeneration facility for his or her
own personal use and (ii) installs such cogeneration or
self-generation facility on his or her own premises without
the assistance of any other person.

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(b) In addition to any authority granted to the Commission
under this Act, the Commission is also authorized to: (1)
determine which entities are subject to certification under
this Section; (2) impose reasonable certification fees and
penalties; (3) adopt disciplinary procedures; (4) investigate
any and all activities subject to this Section, including
violations thereof; (5) adopt procedures to issue or renew, or
to refuse to issue or renew, a certification or to revoke,
suspend, place on probation, reprimand, or otherwise
discipline a certified entity under this Act or take other
enforcement action against an entity subject to this Section;
and (6) prescribe forms to be issued for the administration
and enforcement of this Section.
(c) No electric utility shall provide a retail customer
with net metering service related to interconnection of that
customer's distributed generation facility unless the customer
provides the electric utility with (i) a certification that
the customer installing the distributed generation facility
was a self-installer or (ii) evidence that the distributed
generation facility was installed by an entity certified under
this Section that is also in good standing with the
Commission. For purposes of this subsection, a retail customer
includes that customer's employees, officers, and agents. An
electric utility shall file a tariff or tariffs with the
Commission setting forth the documentation, as specified by
Commission rule, that a retail customer must provide to an

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electric utility. The provisions of this subsection (c) shall
apply on or after the effective date of the Commission's rules
prescribed pursuant to subsection (a) of this Section.
(d) Within 180 days after the effective date of this
amendatory Act of the 97th General Assembly, the Commission
shall initiate a rulemaking proceeding to establish
certification requirements that shall be applicable to persons
or entities that install, maintain, or repair electric vehicle
charging stations. The notification and certification
requirements of this Section shall only be applicable to
individuals or entities that perform work on or within an
electric vehicle charging station, including, but not limited
to, connection of power to an electric vehicle charging
station.
For the purposes of this Section "electric vehicle
charging station" means any facility or equipment that is used
to charge a battery or other energy storage device of an
electric vehicle.
Rules regulating the installation, maintenance, or repair
of electric vehicle charging stations, in which the Commission
may establish separate requirements based upon the
characteristics of electric vehicle charging stations, so long
as it is in accordance with the requirements of subsection (a)
of Section 16-128 and Section 16-128A of this Act, shall:
(1) establish a certification process for persons or
entities that install, maintain, or repair of electric

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vehicle charging stations;
(2) require persons or entities that install,
maintain, or repair electric vehicle stations to be
certified to do business and to be bonded in the State;
(3) ensure that persons or entities that install,
maintain, or repair electric vehicle charging stations
have the requisite knowledge, skills, training,
experience, and competence to perform functions in a safe
and reliable manner as required under subsection (a) of
Section 16-128 of this Act;
(4) impose reasonable certification fees and penalties
on persons or entities that install, maintain, or repair
of electric vehicle charging stations for noncompliance of
the rules adopted under this subsection;
(5) ensure that all persons or entities that install,
maintain, or repair electric vehicle charging stations
conform to applicable building and electrical codes;
(6) ensure that all electric vehicle charging stations
meet recognized industry standards as the Commission deems
appropriate, such as the National Electric Code (NEC) and
standards developed or created by the Institute of
Electrical and Electronics Engineers (IEEE), the Electric
Power Research Institute (EPRI), the Detroit Edison
Institute (DTE), the Underwriters Laboratory (UL), the
Society of Automotive Engineers (SAE), and the National
Institute of Standards and Technology (NIST);

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(7) include any additional requirements that the
Commission deems reasonable to ensure that persons or
entities that install, maintain, or repair electric
vehicle charging stations meet adequate training,
financial, and competency requirements;
(8) ensure that the obligations required under this
Section and subsection (a) of Section 16-128 of this Act
are met prior to the interconnection of any electric
vehicle charging station;
(9) ensure electric vehicle charging stations
installed by a self-installer are not used for any
commercial purpose;
(10) establish an inspection procedure for the
conversion of electric vehicle charging stations installed
by a self-installer if it is determined that the
self-installed electric vehicle charging station is being
used for commercial purposes;
(11) establish the requirement that all persons or
entities that install electric vehicle charging stations
shall notify the servicing electric utility in writing of
plans to install an electric vehicle charging station and
shall notify the servicing electric utility in writing
when installation is complete;
(12) ensure that all persons or entities that install,
maintain, or repair electric vehicle charging stations
obtain certificates of insurance in sufficient amounts and

SB0311 - 319 - LRB102 15398 SPS 20761 b
coverages that the Commission so determines and, if
necessary as determined by the Commission, names the
affected public utility as an additional insured; and
(13) identify and determine the training or other
programs by which persons or entities may obtain the
requisite training, skills, or experience necessary to
achieve and maintain compliance with the requirements set
forth in this subsection and subsection (a) of Section
16-128 to install, maintain, or repair electric vehicle
charging stations.
Within 18 months after the effective date of this
amendatory Act of the 97th General Assembly, the Commission
shall adopt rules, and may, if it deems necessary, adopt
emergency rules, for the installation, maintenance, or repair
of electric vehicle charging stations.
All retail customers who own, maintain, or repair an
electric vehicle charging station shall provide the servicing
electric utility (i) a certification that the customer
installing the electric vehicle charging station was a
self-installer or (ii) evidence that the electric vehicle
charging station was installed by an entity certified under
this subsection (d) that is also in good standing with the
Commission. For purposes of this subsection (d), a retail
customer includes that retail customer's employees, officers,
and agents. If the electric vehicle charging station was not
installed by a self-installer, then the person or entity that

SB0311 - 320 - LRB102 15398 SPS 20761 b
plans to install the electric vehicle charging station shall
provide notice to the servicing electric utility prior to
installation and when installation is complete and provide any
other information required by the Commission's rules
established under subsection (d) of this Section. An electric
utility shall file a tariff or tariffs with the Commission
setting forth the documentation, as specified by Commission
rule, that a retail customer who owns, uses, operates, or
maintains an electric vehicle charging station must provide to
an electric utility.
For the purposes of this subsection, an electric vehicle
charging station shall constitute a distribution facility or
equipment as that term is used in subsection (a) of Section
16-128 of this Act. The phrase "self-installer" means an
individual who (i) leases or purchases an electric vehicle
charging station for his or her own personal use and (ii)
installs an electric vehicle charging station on his or her
own premises without the assistance of any other person.
(e) Fees and penalties collected under this Section shall
be deposited into the Public Utility Fund and used to fund the
Commission's compliance with the obligations imposed by this
Section.
(f) The rules established under subsection (d) of this
Section shall specify the initial dates for compliance with
the rules.
(g) Within 18 months of the effective date of this

SB0311 - 321 - LRB102 15398 SPS 20761 b
amendatory Act of the 99th General Assembly, the Commission
shall adopt rules, including emergency rules, establishing a
process for entities installing a new utility-scale solar
project to certify compliance with the requirements of this
Section. For purposes of this Section, the phrase "entities
installing a new utility-scale solar project" shall include,
but is not limited to, any entity installing new photovoltaic
projects as such terms are defined in subsection (c) of
Section 1-75 of the Illinois Power Agency Act.
The process shall include an option to complete the
certification electronically by completing forms on-line. An
entity installing a new utility-scale solar project shall be
permitted to complete certification after the subject work has
been completed. The Commission shall maintain on its website a
list of entities installing new utility-scale solar projects
measures that have successfully completed the certification
process.
(h) In addition to any authority granted to the Commission
under this Act, the Commission is also authorized to: (1)
determine which entities are subject to certification under
subsection (g) of this Section; (2) impose reasonable
certification fees and penalties; (3) adopt disciplinary
procedures; (4) investigate any and all activities subject to
subsection (g) or this subsection (h) of this Section,
including violations thereof; (5) adopt procedures to issue or
renew, or to refuse to issue or renew, a certification or to

SB0311 - 322 - LRB102 15398 SPS 20761 b
revoke, suspend, place on probation, reprimand, or otherwise
discipline a certified entity under subsection (g) of this
Section or take other enforcement action against an entity
subject to subsection (g) or this subsection (h) of this
Section; (6) prescribe forms to be issued for the
administration and enforcement of subsection (g) and this
subsection (h) of this Section; and (7) establish requirements
to ensure that entities installing a new photovoltaic project
have the requisite knowledge, skills, training, experience,
and competence to perform in a safe and reliable manner as
required by subsection (a) of Section 16-128 of this Act.
(i) The certification of persons or entities that install,
maintain, or repair new photovoltaic projects, distributed
generation facilities, and electric vehicle charging stations
as set forth in this Section is an exclusive power and function
of the State. A home rule unit or other units of local
government authority may subject persons or entities that
install, maintain, or repair new photovoltaic projects,
distributed generation facilities, or electric vehicle
charging stations as set forth in this Section to any
applicable local licensing, siting, and permitting
requirements otherwise permitted under law so long as only
Commission-certified persons or entities are authorized to
install, maintain, or repair new photovoltaic projects,
distributed generation facilities, or electric vehicle
charging stations. This Section is a limitation under

SB0311 - 323 - LRB102 15398 SPS 20761 b
subsection (h) of Section 6 of Article VII of the Illinois
Constitution on the exercise by home rule units of powers and
functions exclusively exercised by the State.
(Source: P.A. 99-906, eff. 6-1-17; 100-16, eff. 6-30-17.)
Section 15. The Prevailing Wage Act is amended by changing
Section 2 as follows:
(820 ILCS 130/2) (from Ch. 48, par. 39s-2)
Sec. 2. This Act applies to the wages of laborers,
mechanics and other workers employed in any public works, as
hereinafter defined, by any public body and to anyone under
contracts for public works. This includes any maintenance,
repair, assembly, or disassembly work performed on equipment
whether owned, leased, or rented.
As used in this Act, unless the context indicates
otherwise:
"Public works" means all fixed works constructed or
demolished by any public body, or paid for wholly or in part
out of public funds. "Public works" as defined herein includes
all projects financed in whole or in part with bonds, grants,
loans, or other funds made available by or through the State or
any of its political subdivisions, including but not limited
to: bonds issued under the Industrial Project Revenue Bond Act
(Article 11, Division 74 of the Illinois Municipal Code), the
Industrial Building Revenue Bond Act, the Illinois Finance

SB0311 - 324 - LRB102 15398 SPS 20761 b
Authority Act, the Illinois Sports Facilities Authority Act,
or the Build Illinois Bond Act; loans or other funds made
available pursuant to the Build Illinois Act; loans or other
funds made available pursuant to the Riverfront Development
Fund under Section 10-15 of the River Edge Redevelopment Zone
Act; or funds from the Fund for Illinois' Future under Section
6z-47 of the State Finance Act, funds for school construction
under Section 5 of the General Obligation Bond Act, funds
authorized under Section 3 of the School Construction Bond
Act, funds for school infrastructure under Section 6z-45 of
the State Finance Act, and funds for transportation purposes
under Section 4 of the General Obligation Bond Act. "Public
works" also includes (i) all projects financed in whole or in
part with funds from the Department of Commerce and Economic
Opportunity under the Illinois Renewable Fuels Development
Program Act for which there is no project labor agreement;
(ii) all work performed pursuant to a public private agreement
under the Public Private Agreements for the Illiana Expressway
Act or the Public-Private Agreements for the South Suburban
Airport Act; and (iii) all projects undertaken under a
public-private agreement under the Public-Private Partnerships
for Transportation Act. "Public works" also includes all
projects at leased facility property used for airport purposes
under Section 35 of the Local Government Facility Lease Act.
"Public works" also includes the construction of a new wind
power facility by a business designated as a High Impact

SB0311 - 325 - LRB102 15398 SPS 20761 b
Business under Section 5.5(a)(3)(E) of the Illinois Enterprise
Zone Act. "Public works" also includes any facility financed
in whole or in part with renewable energy resources procured
pursuant to Section 1-75 of the Illinois Power Agency Act and
any photovoltaic electric production facility constructed
pursuant to Section 8-218 of the Public Utilities Act. "Public
works" does not include work done directly by any public
utility company, whether or not done under public supervision
or direction, or paid for wholly or in part out of public
funds. "Public works" also includes any corrective action
performed pursuant to Title XVI of the Environmental
Protection Act for which payment from the Underground Storage
Tank Fund is requested. "Public works" does not include
projects undertaken by the owner at an owner-occupied
single-family residence or at an owner-occupied unit of a
multi-family residence. "Public works" does not include work
performed for soil and water conservation purposes on
agricultural lands, whether or not done under public
supervision or paid for wholly or in part out of public funds,
done directly by an owner or person who has legal control of
those lands.
"Construction" means all work on public works involving
laborers, workers or mechanics. This includes any maintenance,
repair, assembly, or disassembly work performed on equipment
whether owned, leased, or rented.
"Locality" means the county where the physical work upon

SB0311 - 326 - LRB102 15398 SPS 20761 b
public works is performed, except (1) that if there is not
available in the county a sufficient number of competent
skilled laborers, workers and mechanics to construct the
public works efficiently and properly, "locality" includes any
other county nearest the one in which the work or construction
is to be performed and from which such persons may be obtained
in sufficient numbers to perform the work and (2) that, with
respect to contracts for highway work with the Department of
Transportation of this State, "locality" may at the discretion
of the Secretary of the Department of Transportation be
construed to include two or more adjacent counties from which
workers may be accessible for work on such construction.
"Public body" means the State or any officer, board or
commission of the State or any political subdivision or
department thereof, or any institution supported in whole or
in part by public funds, and includes every county, city,
town, village, township, school district, irrigation, utility,
reclamation improvement or other district and every other
political subdivision, district or municipality of the state
whether such political subdivision, municipality or district
operates under a special charter or not.
"Labor organization" means an organization that is the
exclusive representative of an employer's employees recognized
or certified pursuant to the National Labor Relations Act.
The terms "general prevailing rate of hourly wages",
"general prevailing rate of wages" or "prevailing rate of

SB0311 - 327 - LRB102 15398 SPS 20761 b
wages" when used in this Act mean the hourly cash wages plus
annualized fringe benefits for training and apprenticeship
programs approved by the U.S. Department of Labor, Bureau of
Apprenticeship and Training, health and welfare, insurance,
vacations and pensions paid generally, in the locality in
which the work is being performed, to employees engaged in
work of a similar character on public works.
(Source: P.A. 100-1177, eff. 6-1-19.)
Section 97. Severability. The provisions of this Act are
severable under Section 1.31 of the Statute on Statutes.
Section 99. Effective date. This Act takes effect upon
becoming law.
SB0311 - 328 - LRB102 15398 SPS 20761 b
INDEX
Statutes amended in order of appearance