Bill Text: IL HB5673 | 2019-2020 | 101st General Assembly | Introduced

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

Spectrum: Bipartisan Bill

Status: (Introduced - Dead) 2020-09-03 - Removed Co-Sponsor Rep. Anthony DeLuca [HB5673 Detail]

Download: Illinois-2019-HB5673-Introduced.html

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101ST GENERAL ASSEMBLY State of Illinois 2019 and 2020 HB5673 Introduced , by Rep. LaToya Greenwood SYNOPSIS AS INTRODUCED:
See Index
Amends the Illinois Power Agency Act. For electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers in this State: defines "energy efficiency"; in provisions concerning the renewable portfolio standards, specifies the goals for procurement of renewable energy credits and cost-effective renewable energy resources that shall be included in the long-term renewable resources procurement plan and makes other changes concerning these procurements; and provides for the calculation of the cost of equity for the purposes of recovering all reasonable and prudently incurred costs of energy efficiency measures from retail customers. Provides that savings of fuels other than electricity achieved by measures that educate about, incentivize, encourage or otherwise support the use of electricity to power vehicles shall count towards the applicable annual incremental goal and shall not be included in determining certain limits. Amends the Public Utilities Act. Provides that an electric utility that serves less than 3,000,000 retail customers but more than 500,000 customers in this State may plan for, construct, install, control, own, manage, or operate photovoltaic electricity production facilities and any energy storage facilities that are planned for, constructed, installed, controlled, owned, managed or operated in connection with photovoltaic electricity production facilities without obtaining a certificate of public convenience and necessity subject to specified terms and conditions. Defines "electric vehicle", "electric vehicle charging station", and "energy storage" for the purposes of the Electric Service Customer Choice and Rate Relief Law of 1997. Provides that, beginning in 2022, without obtaining any approvals from the Illinois Commerce Commission or any other agency, regardless of whether any such approval would otherwise be required, a participating utility that is a combination utility shall pay $1,000,000 per year for 10 years to the energy low-income and support program. Adds provisions authorizing certain utilities to plan for, construct, install, control, own, manage or operate electric vehicle charging infrastructure, including, but not limited to, electric vehicle charging stations within their service territories. Effective immediately.
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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 Utilities

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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
either an electric utility as defined in this Section, a

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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, including,
but not limited to, cars, trucks, buses, trains, trolleys,

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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
nameplate capacity in kilowatts AC.

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"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
Act, landfill gas produced in the State is considered a

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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
utility, an agreement between the owner of a clean coal

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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 electricity
usage.

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"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
would otherwise have had to acquire, reasonable estimates shall

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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
Interconnection, LLC or the Midcontinent Independent System

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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 their Illinois
jurisdictional load. This Section shall not apply to a small

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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,
engineering, risk management, or a related area of
study;

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(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
sector, including risk management experience;
(D) expertise in wholesale electricity market

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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:
(A) failure to satisfy qualification criteria;
(B) identification of a conflict of interest; or

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(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
Agency's selection, the Agency shall submit another
recommendation within 3 days based on the proposals

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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
June 1, 2017 (the effective date of Public Act 99-906). The
Agency shall review, and may revise on an expedited basis,

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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
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

HB5673 - 23 - LRB101 20817 JLS 70536 b
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
applicable portion of each utility's load for retail
customers who are not eligible retail customers, which

HB5673 - 24 - LRB101 20817 JLS 70536 b
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.
(C) Of the renewable energy credits procured under this
subsection (c), at least 75% shall come from wind and

HB5673 - 25 - LRB101 20817 JLS 70536 b
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
plan includes the procurement of more than
2,000,000 renewable energy credits from new

HB5673 - 26 - LRB101 20817 JLS 70536 b
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
photovoltaic projects; of that amount, to the
extent possible, the Agency shall procure: at

HB5673 - 27 - LRB101 20817 JLS 70536 b
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
500,000 retail customers in this State and the
allocation of such procurement on behalf of

HB5673 - 28 - LRB101 20817 JLS 70536 b
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
resources procurement plan includes the
procurement of more than 4,000,000 renewable

HB5673 - 29 - LRB101 20817 JLS 70536 b
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.
"New photovoltaic projects" means photovoltaic
renewable energy facilities that are energized

HB5673 - 30 - LRB101 20817 JLS 70536 b
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
price benchmarks based on publicly available data on
regional technology costs and expected current and future
regional energy prices. The benchmarks in this Section

HB5673 - 31 - LRB101 20817 JLS 70536 b
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 for
supply, transmission, distribution, surcharges, and add-on
taxes.
Notwithstanding the requirements of this subsection

HB5673 - 32 - LRB101 20817 JLS 70536 b
(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 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

HB5673 - 33 - LRB101 20817 JLS 70536 b
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
subsection (c) regarding renewable energy credits in the
following order:
(i) renewable energy credits under existing
contractual obligations;

HB5673 - 34 - LRB101 20817 JLS 70536 b
(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
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

HB5673 - 35 - LRB101 20817 JLS 70536 b
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,
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

HB5673 - 36 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 37 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 38 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 39 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 40 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 41 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 42 - LRB101 20817 JLS 70536 b
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 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

HB5673 - 43 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 44 - LRB101 20817 JLS 70536 b
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
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)

HB5673 - 45 - LRB101 20817 JLS 70536 b
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, 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

HB5673 - 46 - LRB101 20817 JLS 70536 b
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 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

HB5673 - 47 - LRB101 20817 JLS 70536 b
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
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.

HB5673 - 48 - LRB101 20817 JLS 70536 b
(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
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

HB5673 - 49 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 50 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 51 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 52 - LRB101 20817 JLS 70536 b
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 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

HB5673 - 53 - LRB101 20817 JLS 70536 b
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.
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.

HB5673 - 54 - LRB101 20817 JLS 70536 b
(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
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

HB5673 - 55 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 56 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 57 - LRB101 20817 JLS 70536 b
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
female-owned business enterprises, and shall not,
consistent with State and federal law, discriminate based
on race or socioeconomic status.
(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 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

HB5673 - 58 - LRB101 20817 JLS 70536 b
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.
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

HB5673 - 59 - LRB101 20817 JLS 70536 b
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:
(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

HB5673 - 60 - LRB101 20817 JLS 70536 b
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 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

HB5673 - 61 - LRB101 20817 JLS 70536 b
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 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

HB5673 - 62 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 63 - LRB101 20817 JLS 70536 b
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
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)

HB5673 - 64 - LRB101 20817 JLS 70536 b
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 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

HB5673 - 65 - LRB101 20817 JLS 70536 b
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
(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;

HB5673 - 66 - LRB101 20817 JLS 70536 b
(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
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

HB5673 - 67 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 68 - LRB101 20817 JLS 70536 b
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)
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

HB5673 - 69 - LRB101 20817 JLS 70536 b
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 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

HB5673 - 70 - LRB101 20817 JLS 70536 b
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
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.

HB5673 - 71 - LRB101 20817 JLS 70536 b
(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
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

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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 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

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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
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

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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
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

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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
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

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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
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

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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
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

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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 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

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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 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,

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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
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

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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:
(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

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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 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

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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
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

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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 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

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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 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.

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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
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

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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
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%

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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, 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

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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)
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

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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
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

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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
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

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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
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

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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
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

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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.
(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

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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
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.

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(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
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

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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,
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 8-103B, 16-102, 16-107.6, 16-108.5, and 16-128A and by
adding Sections 8-218, 16-108.19 and 16-108.20 as follows:
(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

HB5673 - 98 - LRB101 20817 JLS 70536 b
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 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

HB5673 - 99 - LRB101 20817 JLS 70536 b
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
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;

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(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.
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

HB5673 - 101 - LRB101 20817 JLS 70536 b
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 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

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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
(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

HB5673 - 103 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 104 - LRB101 20817 JLS 70536 b
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
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;

HB5673 - 105 - LRB101 20817 JLS 70536 b
(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;
(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

HB5673 - 106 - LRB101 20817 JLS 70536 b
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
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;

HB5673 - 107 - LRB101 20817 JLS 70536 b
(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;
(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

HB5673 - 108 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 109 - LRB101 20817 JLS 70536 b
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,
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

HB5673 - 110 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 111 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 112 - LRB101 20817 JLS 70536 b
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 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
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

HB5673 - 113 - LRB101 20817 JLS 70536 b
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
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 50% of the total capital structure
shall be deemed reasonable and used to set rates.
(C) Include a cost of equity, which in all rate
years for electric utilities that serve 3,000,000 or
more retail customers in this State, and in each rate

HB5673 - 114 - LRB101 20817 JLS 70536 b
year commencing before December 1, 2019 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 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 the State, for each rate year
commencing after November 30, 2019, the cost of equity
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) 680 basis points;
however, if the cost of equity as calculated under this
subparagraph (C) of this paragraph (2) for each rate
year commencing after November 30, 2019, for electric
utilities that serve less than 3,000,000 retail
customers but more than 500,000 retail customers in

HB5673 - 115 - LRB101 20817 JLS 70536 b
this State is greater than the national average cost of
equity for the rate year by 50 basis points or more,
then the Illinois Commerce Commission shall include a
cost of equity at a rate equal to the national average
cost of equity as calculated under this subparagraph
(C) of this paragraph (2) plus 50 basis points. For
purposes of this subparagraph (C) of this paragraph
(2), the national average cost of equity for a rate
year shall be the simple average of the cost of equity
approved in each order of a state regulatory
commission, other than the Commission, issued during
that rate year that is applicable to 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 that it is subject to
rehearing or appeal. In the hearing during the first
rate year commencing after November 30, 2019, the
Commission shall set the cost of equity using the
method applicable to rate years commencing prior to
December 1, 2019. In the hearings in rate years
subsequent to such first rate year, the Commission
shall set the cost of equity using the method
applicable to rate years commencing after November 30,
2019, including the reconciliation of the first rate

HB5673 - 116 - LRB101 20817 JLS 70536 b
year commencing after November 30, 2019. If, for any
rate 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 prior year or years
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
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

HB5673 - 117 - LRB101 20817 JLS 70536 b
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;
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

HB5673 - 118 - LRB101 20817 JLS 70536 b
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 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,

HB5673 - 119 - LRB101 20817 JLS 70536 b
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,
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

HB5673 - 120 - LRB101 20817 JLS 70536 b
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
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

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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 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

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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
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

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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
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

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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 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

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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 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

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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
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,

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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 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

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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 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

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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 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

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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 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

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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 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.

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(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.
(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

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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
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

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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,
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

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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 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

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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
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

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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 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

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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 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

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(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 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

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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).
(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

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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
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

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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,
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

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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
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

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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 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

HB5673 - 145 - LRB101 20817 JLS 70536 b
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
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

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households that are not low-income households.
Commencing on the effective date of this amendatory Act of
the 101st 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 101st 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, shall be
evaluated using the following parameters:
(A) the evaluation shall use a factor of 1.50 lbs
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 101st 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 101st General
Assembly takes effect to reflect the annual increase of

HB5673 - 147 - LRB101 20817 JLS 70536 b
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
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 101st 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

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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 lbs of
carbon dioxide emitted per million Btu of fossil fuel
used for vehicle operation;
(F) the evaluation shall use a factor of 8.78 kg 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 paragraphs (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

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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 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

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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 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

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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
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,

HB5673 - 152 - LRB101 20817 JLS 70536 b
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 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 101st 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,

HB5673 - 153 - LRB101 20817 JLS 70536 b
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. 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. Admin. 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

HB5673 - 154 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 155 - LRB101 20817 JLS 70536 b
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 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

HB5673 - 156 - LRB101 20817 JLS 70536 b
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
1-75 of the Illinois Power Agency Act; and
(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 101st 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.
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
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

HB5673 - 157 - LRB101 20817 JLS 70536 b
subparagraph (E) of paragraph (1) of subsection (c) of Section
1-75 of the Illinois Power Agency Act.
(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,
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

HB5673 - 158 - LRB101 20817 JLS 70536 b
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 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

HB5673 - 159 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 160 - LRB101 20817 JLS 70536 b
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 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

HB5673 - 161 - LRB101 20817 JLS 70536 b
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 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

HB5673 - 162 - LRB101 20817 JLS 70536 b
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.
"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

HB5673 - 163 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 164 - LRB101 20817 JLS 70536 b
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 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

HB5673 - 165 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 166 - LRB101 20817 JLS 70536 b
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
(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:

HB5673 - 167 - LRB101 20817 JLS 70536 b
"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.
"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

HB5673 - 168 - LRB101 20817 JLS 70536 b
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
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

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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 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

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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
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

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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
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

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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 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.

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(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 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

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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
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
rate years for electric utilities that serve more than
3,000,000 retail customers in this State, and in each rate
year commencing before December 1, 2019 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

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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 rate year commencing
after November 30, 2019, the cost of equity 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) 680
basis points; however, if the cost of equity as calculated
under this paragraph (1) for each rate year commencing
after November 30, 2019, for electric utilities that serve
less than 3,000,000 retail customers but more than 500,000
retail customers in this State is greater than the national
average cost of equity for the rate year by 50 basis points
or more, then the Illinois Commerce Commission shall
include a cost of equity at a rate equal to the national
average cost of equity as calculated under this paragraph
(1) plus 50 basis points. For purposes of this paragraph
(1), the national average cost of equity for a rate year
shall be the simple average of the cost of equity approved
in each order of a state regulatory commission, other than

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the Commission, issued during that rate year that is
applicable to 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 is subject to rehearing or appeal.
In the hearing during the first rate year commencing after
November 30, 2019, the Commission shall set the cost of
equity using the method applicable to rate years commencing
prior to December 1, 2019. In the hearings in rate years
subsequent to such first rate year, the Commission shall
set the cost of equity using the method applicable to rate
years commencing after November 30, 2019, including the
reconciliation of the first rate year commencing after
November 30, 2019. If, for any rate 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
prior year or years 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

HB5673 - 177 - LRB101 20817 JLS 70536 b
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 equity ratio,
excluding goodwill, of up to and including 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

HB5673 - 178 - LRB101 20817 JLS 70536 b
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 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

HB5673 - 179 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 180 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 181 - LRB101 20817 JLS 70536 b
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 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

HB5673 - 182 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 183 - LRB101 20817 JLS 70536 b
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
(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):

HB5673 - 184 - LRB101 20817 JLS 70536 b
(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
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

HB5673 - 185 - LRB101 20817 JLS 70536 b
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
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)

HB5673 - 186 - LRB101 20817 JLS 70536 b
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 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

HB5673 - 187 - LRB101 20817 JLS 70536 b
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 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

HB5673 - 188 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 189 - LRB101 20817 JLS 70536 b
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
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 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

HB5673 - 190 - LRB101 20817 JLS 70536 b
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 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

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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 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

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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
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

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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
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

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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
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

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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 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

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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
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

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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
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 50% of the total capital
structure shall be deemed reasonable and used to set rates.
(3) Include a cost of equity, which in all rate years
for a participating utility that is not a combination
utility, and in each rate year commencing before December
1, 2019 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

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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 rate year commencing after November 30,
2019, the cost of equity 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) 680 basis points; however,
if the cost of equity as calculated under this paragraph
(3) for each rate year commencing after November 30, 2019,
for electric utilities that serve less than 3,000,000
retail customers but more than 500,000 retail customers in
this State is greater than the national average cost of
equity for the rate year by 50 basis points or more, then
the Illinois Commerce Commission shall include a cost of
equity at a rate equal to the national average cost of
equity as calculated under this paragraph (3) plus 50 basis
points. For purposes of this paragraph (3), the national
average cost of equity for a rate year shall be the simple
average of the cost of equity approved in each order of a
state regulatory commission, other than the Commission,
issued during that rate year that is applicable to retail

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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
is subject to rehearing or appeal. In the hearing during
the first rate year commencing after November 30, 2019, the
Commission shall set the cost of equity using the method
applicable to rate years commencing prior to December 1,
2019. In the hearings in rate years subsequent to such
first rate year, the Commission shall set the cost of
equity using the method applicable to rate years commencing
after November 30, 2019, including the reconciliation of
the first rate year commencing after November 30, 2019. If,
for any rate 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 prior year or
years 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 weekly H.15
Statistical Release or successor publication, the monthly
average yields of the U.S. Treasury bonds then having the

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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
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

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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 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

HB5673 - 202 - LRB101 20817 JLS 70536 b
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 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

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adjusting for any penalties to the rate of return on common
equity applied pursuant to the performance metrics
provision of subsection (f), (f-5), or (f-10) 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 penalties to
the rate of return on common equity applied pursuant to the
performance metrics provision of subsection (f), (f-5), or
(f-10) 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
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 penalties to the rate of return on
common equity applied pursuant to the performance metrics

HB5673 - 204 - LRB101 20817 JLS 70536 b
provision of subsection (f), (f-5), or (f-10) 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 penalties to
the rate of return on common equity applied pursuant to the
performance metrics provision of subsection (f), (f-5), or
(f-10) 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
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

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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
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.

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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 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

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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.
(d) Subsequent to the Commission's issuance of an order
approving the utility's performance-based formula 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 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

HB5673 - 208 - LRB101 20817 JLS 70536 b
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.
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

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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 (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).

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(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 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

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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 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

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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
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

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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 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

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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
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.

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(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.
(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 female-owned
business enterprises: design a performance metric
regarding the creation of opportunities for minority-owned
and 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
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

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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 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.

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The metrics and performance goals set forth in
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

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annual 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; 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:

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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.
(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

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calculated in terms of the percentage of the goal 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

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participating utility performed under each metric and 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) Each applicable 10-year period previously approved
by the Commission pursuant to subsections (f) and (f-5) of this
Section for a participating utility that is a combination
utility shall be extended for an additional 10-year period that
commences immediately after the termination of the previous
10-year period. The performance goals and financial penalties
applicable to each year of an additional 10-year period shall
be fixed at, and the same as, the performance goals applicable
to year 10 that were previously approved by the Commission
pursuant to subsections (f) and (f-5) of this Section and the
financial penalties applicable to year 10 set forth in
subsection (f-5) of this Section. The total amount of financial
penalties applicable in any given year shall not exceed 38

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basis points. During the additional 10-year period, each
participating utility shall continue to file the annual reports
required by subsection (f-5) of this Section, and the
requirements of subsection (f-5) related to Commission
approval of any financial penalties shall continue to apply.
The tariff or tariffs approved under subsection (f-5) of this
Section for each participating utility that is a combination
utility shall remain in effect during the additional 10-year
period, and each participating utility that is a combination
utility is authorized to submit a compliance filing after the
effective date of this amendatory Act of the 101st General
Assembly conforming its tariff or tariffs to the provisions of
this subsection (f-10). In the event the formula rate tariff
established pursuant to subsection (c) of this Section
terminates, the utility's obligations under this subsection
(f-10) shall also terminate; however, the tariff mechanism
established pursuant to subsections (f) and (f-5) of this
Section, and extended under this subsection (f-10), shall
remain in effect until any penalties due and owing at the time
of such termination are applied.
The metrics and performance goals set forth in paragraphs
(5) through (8) of subsection (f) of this Section and extended
under this subsection (f-10), are based on the assumption 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

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there is no requirement for personal on-site notification. If
the utility is unable to meet the metrics and performance goals
applicable to paragraphs (5) through (8) of subsection (f) of
this Section for such reasons during the additional 10-year
period, as those metrics and goals are set by this subsection
(f-10), 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.
(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 participating utility's
tariffed rates actually in effect and shall not be calculated

HB5673 - 224 - LRB101 20817 JLS 70536 b
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.
For purposes of this Section, the amount per kilowatthour
means the total amount paid for electric service expressed on a

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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.
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

HB5673 - 226 - LRB101 20817 JLS 70536 b
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 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.
(i) While a participating utility may use, develop, and
maintain broadband systems and the delivery of broadband
services, voice-over-internet-protocol services,

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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
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

HB5673 - 228 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 229 - LRB101 20817 JLS 70536 b
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.
(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

HB5673 - 230 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 231 - LRB101 20817 JLS 70536 b
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
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

HB5673 - 232 - LRB101 20817 JLS 70536 b
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.
(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,

HB5673 - 233 - LRB101 20817 JLS 70536 b
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 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

HB5673 - 234 - LRB101 20817 JLS 70536 b
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) of this Section 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 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

HB5673 - 235 - LRB101 20817 JLS 70536 b
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) of this Section, 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
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

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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
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

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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
charging facilities subsequent to the effective date
of this amendatory Act of the 101st 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 101st General Assembly,
install and provide access to electric vehicle

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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
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

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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 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

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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 electric vehicle charging station
expected peak demand shall be deemed reasonable and shall
not limit the use of alternate extension provisions
demonstrated to be more favorable and approved by the
Illinois Commerce Commission.
(2) Beginning on the effective date of this amendatory
Act of the 101st General Assembly Act, 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 not being recovered pursuant to

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paragraph (1) of this subsection (f) of this Section, 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 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) 680 basis
points; however, if the cost of equity as calculated under
this paragraph (2) is greater than the national average
cost of equity for the rate year by 50 basis points or
more, then the Illinois Commerce Commission shall include a
cost of equity at a rate equal to the national average cost
of equity as calculated under this paragraph (2) plus 50
basis points. For purposes of this paragraph (2), the
national average cost of equity for a rate year shall be
the simple average of the cost of equity approved in each
order of a state regulatory commission, other than the

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Commission, issued during that rate year that is applicable
to 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 (2) on the grounds
that it is subject to rehearing or appeal. If, for any rate
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 prior year or years 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 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).
(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

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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
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 50% 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

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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 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
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

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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.
(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

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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.
(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

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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.
(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

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self-generation facility on his or her own premises without the
assistance of any other person.
(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

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setting forth the documentation, as specified by Commission
rule, that a retail customer must provide to an 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:

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(1) establish a certification process for persons or
entities that install, maintain, or repair of electric
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

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Society of Automotive Engineers (SAE), and the National
Institute of Standards and Technology (NIST);
(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,

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maintain, or repair electric vehicle charging stations
obtain certificates of insurance in sufficient amounts and
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,

HB5673 - 253 - LRB101 20817 JLS 70536 b
and agents. If the electric vehicle charging station was not
installed by a self-installer, then the person or entity that
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

HB5673 - 254 - LRB101 20817 JLS 70536 b
rules.
(g) Within 18 months of the effective date of this
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,

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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 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,

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distributed generation facilities, or electric vehicle
charging stations. This Section is a limitation under
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 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.
HB5673 - 257 - LRB101 20817 JLS 70536 b
INDEX
Statutes amended in order of appearance