Bill Text: IL SB1485 | 2015-2016 | 99th General Assembly | Introduced

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Bill Title: Amends the Illinois Power Agency Act. Requires the Planning and Procurement Bureau to establish a long-term renewable resources procurement plan that includes all renewable energy credits necessary to meet specified goals (replacing the current renewable portfolio standards). Sets forth guidelines for what shall be included in the procurement plan. Makes changes to provisions concerning definitions, the powers of the Agency, the Illinois Power Agency Renewable Energy Resources Fund, and the duties of the Planning and Procurement Bureau. Amends the Public Utilities Act. Makes changes concerning nondiscrimination, energy efficiency and demand-response measures, natural gas efficiency programs, real-time pricing, infrastructure investment and modernization, the Illinois Smart Grid test bed, and on-bill financing programs for electric and gas utilities. Adds provisions related to renewable energy credit procurement. Amends the Environmental Protection Act. Provides that upon promulgation by the U.S. Environmental Protection Agency of a final rule regulating carbon dioxide emissions from existing electric generating units, the Illinois Environmental Protection Agency shall be authorized to implement a cap and invest program or similar market mechanism to regulate carbon dioxide emissions. Makes other changes. Effective immediately.

Spectrum: Partisan Bill (Democrat 31-0)

Status: (Introduced - Dead) 2016-10-20 - Added as Co-Sponsor Sen. Omar Aquino [SB1485 Detail]

Download: Illinois-2015-SB1485-Introduced.html

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99TH GENERAL ASSEMBLY State of Illinois 2015 and 2016 SB1485 Introduced 2/20/2015, by Sen. Don Harmon - David Koehler - Jacqueline Y. Collins SYNOPSIS AS INTRODUCED:
See Index
Amends the Illinois Power Agency Act. Requires the Planning and Procurement Bureau to establish a long-term renewable resources procurement plan that includes all renewable energy credits necessary to meet specified goals (replacing the current renewable portfolio standards). Sets forth guidelines for what shall be included in the procurement plan. Makes changes to provisions concerning definitions, the powers of the Agency, the Illinois Power Agency Renewable Energy Resources Fund, and the duties of the Planning and Procurement Bureau. Amends the Public Utilities Act. Makes changes concerning nondiscrimination, energy efficiency and demand-response measures, natural gas efficiency programs, real-time pricing, infrastructure investment and modernization, the Illinois Smart Grid test bed, and on-bill financing programs for electric and gas utilities. Adds provisions related to renewable energy credit procurement. Amends the Environmental Protection Act. Provides that upon promulgation by the U.S. Environmental Protection Agency of a final rule regulating carbon dioxide emissions from existing electric generating units, the Illinois Environmental Protection Agency shall be authorized to implement a cap and invest program or similar market mechanism to regulate carbon dioxide emissions. Makes other changes. Effective immediately.
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FISCAL NOTE ACT MAY APPLY
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 5. The Illinois Power Agency Act is amended by
changing Sections 1-5, 1-10, 1-20, 1-56, and 1-75 as follows:
(20 ILCS 3855/1-5)
Sec. 1-5. Legislative declarations and findings. The
General Assembly finds and declares:
(1) The health, welfare, and prosperity of all Illinois
citizens require the provision of adequate, reliable,
affordable, efficient, and environmentally sustainable
electric service at the lowest total cost over time, taking
into account any benefits of price stability.
(2) The transition to retail competition is not
complete. Some customers, especially residential and small
commercial customers, have failed to benefit from lower
electricity costs from retail and wholesale competition.
(3) Escalating prices for electricity in Illinois pose
a serious threat to the economic well-being, health, and
safety of the residents of and the commerce and industry of
the State.
(4) To protect against this threat to economic
well-being, health, and safety it is necessary to improve

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the process of procuring electricity to serve Illinois
residents, to promote investment in energy efficiency and
demand-response measures, and to support development of
clean coal technologies and renewable resources.
(5) Procuring a diverse electricity supply portfolio
will ensure the lowest total cost over time for adequate,
reliable, efficient, and environmentally sustainable
electric service.
(6) Including cost-effective renewable resources in
that portfolio will reduce long-term direct and indirect
costs to consumers by decreasing environmental impacts and
by avoiding or delaying the need for new generation,
transmission, and distribution infrastructure.
(7) Energy efficiency, demand-response measures, and
renewable energy are resources currently underused in
Illinois. These and other demand-side resources should be
used when cost-effective to reduce costs to consumers and
encourage job creation.
(8) The State should encourage the use of advanced
clean coal technologies that capture and sequester carbon
dioxide emissions to advance environmental protection
goals and to demonstrate the viability of coal and
coal-derived fuels in a carbon-constrained economy.
(9) The General Assembly enacted Public Act 96-0795 to
reform the State's purchasing processes, recognizing that
government procurement is susceptible to abuse if

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structural and procedural safeguards are not in place to
ensure independence, insulation, oversight, and
transparency.
(10) The principles that underlie the procurement
reform legislation apply also in the context of power
purchasing.
The General Assembly therefore finds that it is necessary
to create the Illinois Power Agency and that the goals and
objectives of that Agency are to accomplish each of the
following:
(A) Develop electricity procurement plans 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 electric utilities that on December
31, 2005 provided electric service to at least 100,000
customers in Illinois and for 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.
The procurement plan shall be updated on an annual basis
and shall include renewable energy resources sufficient to
achieve the standards specified in this Act.
(B) Conduct competitive procurement processes to
procure the supply resources identified in the procurement
plan.

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(C) Develop electric generation and co-generation
facilities that use indigenous coal or renewable
resources, or both, financed with bonds issued by the
Illinois Finance Authority.
(D) Supply electricity from the Agency's facilities at
cost to one or more of the following: municipal electric
systems, governmental aggregators, or rural electric
cooperatives in Illinois.
(E) Ensure that the process of power procurement is
conducted in an ethical and transparent fashion, immune
from improper influence.
(F) Continue to review its policies and practices to
determine how best to meet its mission of providing the
lowest cost power to the greatest number of people, at any
given point in time, in accordance with applicable law.
(G) Operate in a structurally insulated, independent,
and transparent fashion so that nothing impedes the
Agency's mission to secure power at the best prices the
market will bear, provided that the Agency meets all
applicable legal requirements.
(Source: P.A. 97-325, eff. 8-12-11; 97-618, eff. 10-26-11;
97-813, eff. 7-13-12.)
(20 ILCS 3855/1-10)
Sec. 1-10. Definitions.
"Agency" means the Illinois Power Agency.

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"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 solar project" means an electric generating
facility that:
(1) generates electricity using photovoltaic cells;
(2) is interconnected at the distribution system level
of either an electric utility as defined in this Section, a
municipal utility as defined in Section 3-105 of the Public
Utilities Act, or a rural electric cooperative as defined
in Section 3-119 of the Public Utilities Act; and
(3) is located on a site that is regulated by any of
the following entities under the following programs:
(i) the United States Environmental Protection
Agency under the federal Comprehensive Environmental
Response, Compensation, and Liability Act of 1980, as
amended;
(ii) the United States Environmental Protection
Agency under the Corrective Action Program of the
federal Resource Conservation and Recovery Act, as

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amended;
(iii) the Illinois Environmental Protection Agency
under the Illinois Site Remediation Program; or
(iv) 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,
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

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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.
"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

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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 solar project" means an electric generating
facility that:
(1) generates electricity using photovoltaic cells;
(2) is interconnected at the distribution system level
of an electric utility as defined in this Section;
(3) credits the value of electricity generated by the
facility to the subscribers of the facility; and
(4) is limited in nameplate capacity to no more than
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;

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(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
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 year beginning June 1 of the year
referenced 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

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periods.
"Distributed renewable energy generation device" means a
device that is:
(1) powered by wind, solar thermal energy,
photovoltaic cells and 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, an
alternative retail electric supplier as defined in Section
16-102 of the Public Utilities Act, a municipal utility as
defined in Section 3-105 of the Public Utilities Act, 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 no more than 2,000
kilowatts.
"Energy efficiency" means measures that reduce the amount
of electricity or natural gas required to achieve a given end
use. "Energy efficiency" also includes measures that reduce the
total Btus of electricity and natural gas needed to meet the
end use or uses.
"Electric utility" has the same definition as found in

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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.
"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.
"Nameplate capacity" means the aggregate inverter
nameplate capacity in kilowatts AC.
"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

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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 a
certain amount of energy produced from a renewable energy
generating facility 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, hydropower
that does not involve new construction or significant expansion
of hydropower dams, and other alternative sources of
environmentally preferable energy. For purposes of this Act,
landfill gas produced in the State is considered a renewable
energy resource. "Renewable energy resources" does not include
the incineration or burning of tires, garbage, general
household, institutional, and commercial waste, industrial
lunchroom or office waste, landscape waste other than tree
waste, railroad crossties, utility poles, or construction or
demolition debris, other than untreated and unadulterated
waste wood.
"Revenue bond" means any bond, note, or other evidence of

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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
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

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terms and conditions meeting the requirements of subsection
(h-1) of Section 9-220 of the Public Utilities Act.
"Standard wholesale product" means any type of product that
is routinely traded in a liquid regional wholesale market,
including, but not limited to, energy or demand-side resources.
"Subscriber" means any customer that takes delivery
service from an electric utility who owns one or more
subscriptions to a community solar project and who has
identified an individual billing meter within the same electric
utility service territory as the community solar project is
located to which each subscription shall be attributed. Each
subscriber to a single community solar project must have a
separate legal or corporate identity, and no subscriber's
subscriptions may total more than 40% of an individual
community solar project.
"Subscription" means a percentage interest in a community
solar project. Each subscription shall represent a percentage
of the community solar project's generating capacity, provided
that the subscription is intended to primarily offset part or
all of the subscriber's electricity usage.
"Substitute natural gas" or "SNG" means a gas manufactured
by gasification of hydrocarbon feedstock, which is
substantially interchangeable in use and distribution with
conventional natural gas.
"Total resource cost test" or "TRC test" means a standard
that is met if, for an investment in energy efficiency or

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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, including avoided
energy costs, avoided generating capacity costs, avoided
transmission and distribution system investments and price
suppression effects, as well as other quantifiable societal
benefits, including avoided natural gas utility costs, other
avoided energy costs, and reasonable estimates of non-energy
benefits, such as the health, safety, comfort, operation and
maintenance, business productivity, and financial security
benefits to low-income and moderate-income customers of
efficiency investments, 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
be included of financial costs likely to be imposed by future
regulations and legislation on emissions of greenhouse gases.

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In discounting future costs and benefits for the purpose of
computing net present values, a societal discount rate based on
real, long-term Treasury bond yields or other appropriate
indictors should be used.
(Source: P.A. 97-96, eff. 7-13-11; 97-239, eff. 8-2-11; 97-491,
eff. 8-22-11; 97-616, eff. 10-26-11; 97-813, eff. 7-13-12;
98-90, eff. 7-15-13.)
(20 ILCS 3855/1-20)
Sec. 1-20. General powers of the Agency.
(a) The Agency is authorized to do each of the following:
(1) Develop electricity procurement plans 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 electric utilities that on December
31, 2005 provided electric service to at least 100,000
customers in Illinois and for small multi-jurisdictional
electric utilities that (A) on December 31, 2005 served
less than 100,000 customers in Illinois and (B) request a
procurement plan for their Illinois jurisdictional load.
The electricity procurement plans shall be updated on an
annual basis and shall, until May 31, 2016, include
electricity generated from renewable resources sufficient
to achieve the standards specified in this Act and shall
include energy efficiency and demand response resources

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identified under Sections 16-108.5, 16-111.5, and
16-111.5B of the Public Utilities Act.
(1.5) Beginning with the planning process for the plan
or plans to be implemented in the 2016 delivery year,
develop a long-term renewable resources procurement plan
in accordance with subdivision (c) of Section 1-75 of this
Act for renewable energy credits in amounts sufficient to
achieve the standards specified in this Act for all
customers taking delivery service from an electric
utility.
(2) Conduct competitive procurement processes to
procure the supply resources identified in the electricity
procurement plan, pursuant to Section 16-111.5 of the
Public Utilities Act.
Beginning with the 2016 delivery year, conduct
competitive procurement processes and implement programs
to procure renewable energy credits identified in the
long-term renewable resources procurement plan developed
pursuant to subdivision (c) of Section 1-75 of this Act and
procured pursuant to Section 16-111.5C of the Public
Utilities Act.
(3) Develop electric generation and co-generation
facilities that use indigenous coal or renewable
resources, or both, financed with bonds issued by the
Illinois Finance Authority.
(4) Supply electricity from the Agency's facilities at

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cost to one or more of the following: municipal electric
systems, governmental aggregators, or rural electric
cooperatives in Illinois.
(b) Except as otherwise limited by this Act, the Agency has
all of the powers necessary or convenient to carry out the
purposes and provisions of this Act, including without
limitation, each of the following:
(1) To have a corporate seal, and to alter that seal at
pleasure, and to use it by causing it or a facsimile to be
affixed or impressed or reproduced in any other manner.
(2) To use the services of the Illinois Finance
Authority necessary to carry out the Agency's purposes.
(3) To negotiate and enter into loan agreements and
other agreements with the Illinois Finance Authority.
(4) To obtain and employ personnel and hire consultants
that are necessary to fulfill the Agency's purposes, and to
make expenditures for that purpose within the
appropriations for that purpose.
(5) To purchase, receive, take by grant, gift, devise,
bequest, or otherwise, lease, or otherwise acquire, own,
hold, improve, employ, use, and otherwise deal in and with,
real or personal property whether tangible or intangible,
or any interest therein, within the State.
(6) To acquire real or personal property, whether
tangible or intangible, including without limitation
property rights, interests in property, franchises,

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obligations, contracts, and debt and equity securities,
and to do so by the exercise of the power of eminent domain
in accordance with Section 1-21; except that any real
property acquired by the exercise of the power of eminent
domain must be located within the State.
(7) To sell, convey, lease, exchange, transfer,
abandon, or otherwise dispose of, or mortgage, pledge, or
create a security interest in, any of its assets,
properties, or any interest therein, wherever situated.
(8) To purchase, take, receive, subscribe for, or
otherwise acquire, hold, make a tender offer for, vote,
employ, sell, lend, lease, exchange, transfer, or
otherwise dispose of, mortgage, pledge, or grant a security
interest in, use, and otherwise deal in and with, bonds and
other obligations, shares, or other securities (or
interests therein) issued by others, whether engaged in a
similar or different business or activity.
(9) To make and execute agreements, contracts, and
other instruments necessary or convenient in the exercise
of the powers and functions of the Agency under this Act,
including contracts with any person, including personal
service contracts, or with any local government, State
agency, or other entity; and all State agencies and all
local governments are authorized to enter into and do all
things necessary to perform any such agreement, contract,
or other instrument with the Agency. No such agreement,

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contract, or other instrument shall exceed 40 years.
(10) To lend money, invest and reinvest its funds in
accordance with the Public Funds Investment Act, and take
and hold real and personal property as security for the
payment of funds loaned or invested.
(11) To borrow money at such rate or rates of interest
as the Agency may determine, issue its notes, bonds, or
other obligations to evidence that indebtedness, and
secure any of its obligations by mortgage or pledge of its
real or personal property, machinery, equipment,
structures, fixtures, inventories, revenues, grants, and
other funds as provided or any interest therein, wherever
situated.
(12) To enter into agreements with the Illinois Finance
Authority to issue bonds whether or not the income
therefrom is exempt from federal taxation.
(13) To procure insurance against any loss in
connection with its properties or operations in such amount
or amounts and from such insurers, including the federal
government, as it may deem necessary or desirable, and to
pay any premiums therefor.
(14) To negotiate and enter into agreements with
trustees or receivers appointed by United States
bankruptcy courts or federal district courts or in other
proceedings involving adjustment of debts and authorize
proceedings involving adjustment of debts and authorize

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legal counsel for the Agency to appear in any such
proceedings.
(15) To file a petition under Chapter 9 of Title 11 of
the United States Bankruptcy Code or take other similar
action for the adjustment of its debts.
(16) To enter into management agreements for the
operation of any of the property or facilities owned by the
Agency.
(17) To enter into an agreement to transfer and to
transfer any land, facilities, fixtures, or equipment of
the Agency to one or more municipal electric systems,
governmental aggregators, or rural electric agencies or
cooperatives, for such consideration and upon such terms as
the Agency may determine to be in the best interest of the
citizens of Illinois.
(18) To enter upon any lands and within any building
whenever in its judgment it may be necessary for the
purpose of making surveys and examinations to accomplish
any purpose authorized by this Act.
(19) To maintain an office or offices at such place or
places in the State as it may determine.
(20) To request information, and to make any inquiry,
investigation, survey, or study that the Agency may deem
necessary to enable it effectively to carry out the
provisions of this Act.
(21) To accept and expend appropriations.

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(22) To engage in any activity or operation that is
incidental to and in furtherance of efficient operation to
accomplish the Agency's purposes, including hiring
employees that the Director deems essential for the
operations of the Agency.
(23) To adopt, revise, amend, and repeal rules with
respect to its operations, properties, and facilities as
may be necessary or convenient to carry out the purposes of
this Act, subject to the provisions of the Illinois
Administrative Procedure Act and Sections 1-22 and 1-35 of
this Act.
(24) To establish and collect charges and fees as
described in this Act.
(25) To conduct competitive gasification feedstock
procurement processes to procure the feedstocks for the
clean coal SNG brownfield facility in accordance with the
requirements of Section 1-78 of this Act.
(26) To review, revise, and approve sourcing
agreements and mediate and resolve disputes between gas
utilities and the clean coal SNG brownfield facility
pursuant to subsection (h-1) of Section 9-220 of the Public
Utilities Act or to fulfill its responsibilities for
developing energy efficiency potential studies as required
under subsection (f) of Section 8-103 of the Public
Utilities Act.
(Source: P.A. 96-784, eff. 8-28-09; 96-1000, eff. 7-2-10;

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97-96, eff. 7-13-11; 97-325, eff. 8-12-11; 97-618, eff.
10-26-11; 97-813, eff. 7-13-12.)
(20 ILCS 3855/1-56)
Sec. 1-56. Illinois Power Agency Renewable Energy
Resources Fund.
(a) The Illinois Power Agency Renewable Energy Resources
Fund is created as a special fund in the State treasury.
(b) The Illinois Power Agency Renewable Energy Resources
Fund shall be administered by the Agency for the following
purposes:
(1) to purchase renewable energy credits according to
any approved procurement plan developed by the Agency prior
to June 1, 2016; and
(2) to purchase renewable energy credits and pay for
other applicable expenses as part of a low-income solar
program; the Agency shall create a low-income solar program
with the objective of bringing solar photovoltaics to
low-income communities in a manner that maximizes the
development of new renewable energy generating facilities,
provides workforce development opportunities within
low-income communities, creates a long-term, low-income
solar marketplace throughout Illinois, and minimizes
administrative costs; the Agency shall include the
low-income solar program as part of the long-term renewable
resources procurement plan authorized by subdivision (c)

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of Section 1-75 of this Act, and the program shall be
designed to grow the low-income solar market over at least
10 years; for this program, the Agency shall purchase
renewable energy credits from either (i) photovoltaic
distributed renewable energy generation devices or (ii)
community solar projects. The electricity generated by
each distributed generation device or community solar
project must primarily be used to offset the electricity
usage of (i) lower-income households, (ii) properties
where the majority of occupants are lower-income
households, (iii) public sector buildings that primarily
serve lower-income households, or (iv) not-for-profit
corporations that primarily serve lower-income households.
As used in this subsection (b), "lower-income households"
means persons and families whose income does not exceed 80% of
area median income, adjusted for family size and revised every
5 years.
Administrative costs associated with the low-income solar
program, including, but not limited to, the Agency's general
administrative expenses associated with developing and
operating the program, costs associated with the program
manager referenced in this Section, and costs related to the
evaluation of the low-income solar program, may be paid for
using the Illinois Power Agency Renewable Energy Resources
Fund, but the Agency and program manager shall strive to
minimize administrative expenses in the implementation of the

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program.
The Agency shall purchase renewable energy credits through
an upfront payment per kilowatt of installed nameplate capacity
paid once the device is energized. The payment shall be in
exchange for an assignment of all renewable energy credits
generated by the system during the first 15 years of operation
and shall be structured to overcome barriers to participation
in the solar market by the low-income community. The Agency
shall retire any renewable energy credits purchased from this
program and shall use the renewable energy credits to reduce
the obligation under subdivision (c) of Section 1-75 of this
Act for the electric utility to which the project is
interconnected.
The Agency shall establish the low-income solar program
terms, conditions, and requirements, including the initial
purchase price of renewable energy credits, through the
development, review, and approval of the Agency's long-term
renewable resources procurement plan described in subdivision
(c) of Section 1-75 of this Act. The Agency may review and
adjust the program terms, conditions, and requirements,
including the price offered to new systems, to ensure the
long-term viability and success of the program. The Commission
shall review and approve any modifications to the program
through the periodic plan revision process described in Section
16-111.5C of the Public Utilities Act.
The Agency shall issue a request for qualifications for a

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third-party program manager to administer the low-income solar
program. The third-party program manager may be a government
entity or a not-for-profit corporation and shall be chosen
through a competitive bid process based on selection criteria
and requirements developed by the Agency. In selecting a
program manager, the Agency shall consider a bidder's
experience in (i) administering low-income energy programs
with evidence of strong consumer protection, (ii) providing
low-income job training opportunities, and (iii) providing or
overseeing solar installation or energy efficiency services.
At least every 2 years, the Commission shall select an
independent evaluator to review and report on the low-income
solar program and the performance of the third-party program
manager of the low-income solar program. The report shall
include the number of projects installed, the total installed
capacity in kilowatts, the average cost per kilowatt of
installed capacity, the total number of jobs or job training
opportunities, and other economic, social and environmental
benefits created, and the total administrative costs expended
by the Agency and program manager to implement and evaluate the
program. The report shall be delivered to the Commission and
posted on the Agency's website and used, as needed, to revise
the low-income solar program.
The low-income solar program manager shall administer the
low-income solar program, which shall include the development
of standard contract forms, the development and implementation

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of a marketing and outreach program for eligible low-income
customers, and providing solar installation services,
including subcontractor solicitations when necessary. The
low-income solar program shall also include energy efficiency
referral and education services, solar job training and
workforce development opportunities, and consumer protection
provisions.
(b-5) Upon the submission of all payments required by
Section 16-115D of the Public Utilities Act, no funds shall be
deposited into the Illinois Power Agency Renewable Energy
Resources Fund unless directed by order of the Commission.
(b-10) Upon the balance of the Illinois Power Agency
Renewable Energy Resources Fund falling below $5,000, the Fund
shall be terminated, and any remaining funds shall be
transferred to the Low Income Home Energy Assistance Program,
as authorized by the Energy Assistance Act.
to procure renewable energy resources. Prior to June 1, 2011,
resources procured pursuant to this Section shall be procured
from facilities located in Illinois, provided the resources are
available from those facilities. If resources are not available
in Illinois, then they shall be procured in states that adjoin
Illinois. If resources are not available in Illinois or in
states that adjoin Illinois, then they may be purchased
elsewhere. Beginning June 1, 2011, resources procured pursuant
to this Section shall be procured from facilities located in
Illinois or states that adjoin Illinois. If resources are not

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available in Illinois or in states that adjoin Illinois, then
they may be procured elsewhere. To the extent available, at
least 75% of these renewable energy resources shall come from
wind generation. Of the renewable energy resources procured
pursuant to this Section at least the following specified
percentages shall come from photovoltaics on the following
schedule: 0.5% by June 1, 2012; 1.5% by June 1, 2013; 3% by
June 1, 2014; and 6% by June 1, 2015 and thereafter. Of the
renewable energy resources procured pursuant to this Section,
at least the following percentages shall come from distributed
renewable energy generation devices: 0.5% by June 1, 2013,
0.75% by June 1, 2014, and 1% by June 1, 2015 and thereafter.
To the extent available, half of the renewable energy resources
procured from distributed renewable energy generation shall
come from devices of less than 25 kilowatts in nameplate
capacity. Renewable energy resources procured from distributed
generation devices may also count towards the required
percentages for wind and solar photovoltaics. Procurement of
renewable energy resources from distributed renewable energy
generation devices shall be done on an annual basis through
multi-year contracts of no less than 5 years, and shall consist
solely of renewable energy credits.
The Agency shall create credit requirements for suppliers
of distributed renewable energy. In order to minimize the
administrative burden on contracting entities, the Agency
shall solicit the use of third-party organizations to aggregate

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distributed renewable energy into groups of no less than one
megawatt in installed capacity. These third-party
organizations shall administer contracts with individual
distributed renewable energy generation device owners. An
individual distributed renewable energy generation device
owner shall have the ability to measure the output of his or
her distributed renewable energy generation device.
(c) (Blank). The Agency shall procure renewable energy
resources at least once each year in conjunction with a
procurement event for electric utilities required to comply
with Section 1-75 of the Act and shall, whenever possible,
enter into long-term contracts on an annual basis for a portion
of the incremental requirement for the given procurement year.
(d) (Blank). The price paid to procure renewable energy
credits using monies from the Illinois Power Agency Renewable
Energy Resources Fund shall not exceed the winning bid prices
paid for like resources procured for electric utilities
required to comply with Section 1-75 of this Act.
(e) All renewable energy credits procured using monies from
the Illinois Power Agency Renewable Energy Resources Fund shall
be permanently retired.
(f) The selection of the third-party program manager, the
selection of the independent evaluator, and the procurement
process described in this Section are exempt from the
requirements of Section 20-10 of the Illinois Procurement Code.
The procurement process described in this Section is exempt

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from the requirements of the Illinois Procurement Code,
pursuant to Section 20-10 of that Code.
(g) All disbursements from the Illinois Power Agency
Renewable Energy Resources Fund shall be made only upon
warrants of the Comptroller drawn upon the Treasurer as
custodian of the Fund upon vouchers signed by the Director or
by the person or persons designated by the Director for that
purpose. The Comptroller is authorized to draw the warrant upon
vouchers so signed. The Treasurer shall accept all warrants so
signed and shall be released from liability for all payments
made on those warrants.
(h) The Illinois Power Agency Renewable Energy Resources
Fund shall not be subject to sweeps, administrative charges, or
chargebacks, including, but not limited to, those authorized
under Section 8h of the State Finance Act, that would in any
way result in the transfer of any funds from this Fund to any
other fund of this State or in having any such funds utilized
for any purpose other than the express purposes set forth in
this Section.
(i) Supplemental procurement process.
(1) Within 90 days after the effective date of this
amendatory Act of the 98th General Assembly, the Agency
shall develop a one-time supplemental procurement plan
limited to the procurement of renewable energy credits, if
available, from new or existing photovoltaics, including,
but not limited to, distributed photovoltaic generation.

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Nothing in this subsection (i) requires procurement of wind
generation through the supplemental procurement.
Renewable energy credits procured from new
photovoltaics, including, but not limited to, distributed
photovoltaic generation, under this subsection (i) must be
procured from devices installed by a qualified person. In
its supplemental procurement plan, the Agency shall
establish contractually enforceable mechanisms for
ensuring that the installation of new photovoltaics is
performed by a qualified person.
For the purposes of this paragraph (1), "qualified
person" means a person who performs installations of
photovoltaics, including, but not limited to, distributed
photovoltaic generation, and who: (A) has completed an
apprenticeship as a journeyman electrician from a United
States Department of Labor registered electrical
apprenticeship and training program and received a
certification of satisfactory completion; or (B) does not
currently meet the criteria under clause (A) of this
paragraph (1), but is enrolled in a United States
Department of Labor registered electrical apprenticeship
program, provided that the person is directly supervised by
a person who meets the criteria under clause (A) of this
paragraph (1); or (C) has obtained one of the following
credentials in addition to attesting to satisfactory
completion of at least 5 years or 8,000 hours of documented

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hands-on electrical experience: (i) a North American Board
of Certified Energy Practitioners (NABCEP) Installer
Certificate for Solar PV; (ii) an Underwriters
Laboratories (UL) PV Systems Installer Certificate; (iii)
an Electronics Technicians Association, International
(ETAI) Level 3 PV Installer Certificate; or (iv) an
Associate in Applied Science degree from an Illinois
Community College Board approved community college program
in renewable energy or a distributed generation
technology.
For the purposes of this paragraph (1), "directly
supervised" means that there is a qualified person who
meets the qualifications under clause (A) of this paragraph
(1) and who is available for supervision and consultation
regarding the work performed by persons under clause (B) of
this paragraph (1), including a final inspection of the
installation work that has been directly supervised to
ensure safety and conformity with applicable codes.
For the purposes of this paragraph (1), "install" means
the major activities and actions required to connect, in
accordance with applicable building and electrical codes,
the conductors, connectors, and all associated fittings,
devices, power outlets, or apparatuses mounted at the
premises that are directly involved in delivering energy to
the premises' electrical wiring from the photovoltaics,
including, but not limited to, to distributed photovoltaic

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generation.
The renewable energy credits procured pursuant to the
supplemental procurement plan shall be procured using up to
$30,000,000 from the Illinois Power Agency Renewable
Energy Resources Fund. The Agency shall not plan to use
funds from the Illinois Power Agency Renewable Energy
Resources Fund in excess of the monies on deposit in such
fund or projected to be deposited into such fund. The
supplemental procurement plan shall ensure adequate,
reliable, affordable, efficient, and environmentally
sustainable renewable energy resources (including credits)
at the lowest total cost over time, taking into account any
benefits of price stability.
To the extent available, 50% of the renewable energy
credits procured from distributed renewable energy
generation shall come from devices of less than 25
kilowatts in nameplate capacity. Procurement of renewable
energy credits from distributed renewable energy
generation devices shall be done through multi-year
contracts of no less than 5 years. The Agency shall create
credit requirements for counterparties. In order to
minimize the administrative burden on contracting
entities, the Agency shall solicit the use of third parties
to aggregate distributed renewable energy. These third
parties shall enter into and administer contracts with
individual distributed renewable energy generation device

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owners. An individual distributed renewable energy
generation device owner shall have the ability to measure
the output of his or her distributed renewable energy
generation device.
In developing the supplemental procurement plan, the
Agency shall hold at least one workshop open to the public
within 90 days after the effective date of this amendatory
Act of the 98th General Assembly and shall consider any
comments made by stakeholders or the public. Upon
development of the supplemental procurement plan within
this 90-day period, copies of the supplemental procurement
plan shall be posted and made publicly available on the
Agency's and Commission's websites. All interested parties
shall have 14 days following the date of posting to provide
comment to the Agency on the supplemental procurement plan.
All comments submitted to the Agency shall be specific,
supported by data or other detailed analyses, and, if
objecting to all or a portion of the supplemental
procurement plan, accompanied by specific alternative
wording or proposals. All comments shall be posted on the
Agency's and Commission's websites. Within 14 days
following the end of the 14-day review period, the Agency
shall revise the supplemental procurement plan as
necessary based on the comments received and file its
revised supplemental procurement plan with the Commission
for approval.

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(2) Within 5 days after the filing of the supplemental
procurement plan at the Commission, any person objecting to
the supplemental procurement plan shall file an objection
with the Commission. Within 10 days after the filing, the
Commission shall determine whether a hearing is necessary.
The Commission shall enter its order confirming or
modifying the supplemental procurement plan within 90 days
after the filing of the supplemental procurement plan by
the Agency.
(3) The Commission shall approve the supplemental
procurement plan of renewable energy credits to be procured
from new or existing photovoltaics, including, but not
limited to, distributed photovoltaic generation, if the
Commission determines that it will ensure adequate,
reliable, affordable, efficient, and environmentally
sustainable electric service in the form of renewable
energy credits at the lowest total cost over time, taking
into account any benefits of price stability.
(4) The supplemental procurement process under this
subsection (i) shall include each of the following
components:
(A) Procurement administrator. The Agency may
retain a procurement administrator in the manner set
forth in item (2) of subsection (a) of Section 1-75 of
this Act to conduct the supplemental procurement or may
elect to use the same procurement administrator

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administering the Agency's annual procurement under
Section 1-75.
(B) Procurement monitor. The procurement monitor
retained by the Commission pursuant to Section
16-111.5 of the Public Utilities Act shall:
(i) monitor interactions among the procurement
administrator and bidders and suppliers;
(ii) monitor and report to the Commission on
the progress of the supplemental procurement
process;
(iii) provide an independent confidential
report to the Commission regarding the results of
the procurement events;
(iv) assess compliance with the procurement
plan approved by the Commission for the
supplemental procurement process;
(v) preserve the confidentiality of supplier
and bidding information in a manner consistent
with all applicable laws, rules, regulations, and
tariffs;
(vi) provide expert advice to the Commission
and consult with the procurement administrator
regarding issues related to procurement process
design, rules, protocols, and policy-related
matters;
(vii) consult with the procurement

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administrator regarding the development and use of
benchmark criteria, standard form contracts,
credit policies, and bid documents; and
(viii) perform, with respect to the
supplemental procurement process, any other
procurement monitor duties specifically delineated
within subsection (i) of this Section.
(C) Solicitation, pre-qualification, and
registration of bidders. The procurement administrator
shall disseminate information to potential bidders to
promote a procurement event, notify potential bidders
that the procurement administrator may enter into a
post-bid price negotiation with bidders that meet the
applicable benchmarks, provide supply requirements,
and otherwise explain the competitive procurement
process. In addition to such other publication as the
procurement administrator determines is appropriate,
this information shall be posted on the Agency's and
the Commission's websites. The procurement
administrator shall also administer the
prequalification process, including evaluation of
credit worthiness, compliance with procurement rules,
and agreement to the standard form contract developed
pursuant to item (D) of this paragraph (4). The
procurement administrator shall then identify and
register bidders to participate in the procurement

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event.
(D) Standard contract forms and credit terms and
instruments. The procurement administrator, in
consultation with the Agency, the Commission, and
other interested parties and subject to Commission
oversight, shall develop and provide standard contract
forms for the supplier contracts that meet generally
accepted industry practices as well as include any
applicable State of Illinois terms and conditions that
are required for contracts entered into by an agency of
the State of Illinois. Standard credit terms and
instruments that meet generally accepted industry
practices shall be similarly developed. Contracts for
new photovoltaics shall include a provision attesting
that the supplier will use a qualified person for the
installation of the device pursuant to paragraph (1) of
subsection (i) of this Section. The procurement
administrator shall make available to the Commission
all written comments it receives on the contract forms,
credit terms, or instruments. If the procurement
administrator cannot reach agreement with the parties
as to the contract terms and conditions, the
procurement administrator must notify the Commission
of any disputed terms and the Commission shall resolve
the dispute. The terms of the contracts shall not be
subject to negotiation by winning bidders, and the

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bidders must agree to the terms of the contract in
advance so that winning bids are selected solely on the
basis of price.
(E) Requests for proposals; competitive
procurement process. The procurement administrator
shall design and issue requests for proposals to supply
renewable energy credits in accordance with the
supplemental procurement plan, as approved by the
Commission. The requests for proposals shall set forth
a procedure for sealed, binding commitment bidding
with pay-as-bid settlement, and provision for
selection of bids on the basis of price, provided,
however, that no bid shall be accepted if it exceeds
the benchmark developed pursuant to item (F) of this
paragraph (4).
(F) Benchmarks. Benchmarks for each product to be
procured shall be developed by the procurement
administrator in consultation with Commission staff,
the Agency, and the procurement monitor for use in this
supplemental procurement.
(G) A plan for implementing contingencies in the
event of supplier default, Commission rejection of
results, or any other cause.
(5) Within 2 business days after opening the sealed
bids, the procurement administrator shall submit a
confidential report to the Commission. The report shall

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contain the results of the bidding for each of the products
along with the procurement administrator's recommendation
for the acceptance and rejection of bids based on the price
benchmark criteria and other factors observed in the
process. The procurement monitor also shall submit a
confidential report to the Commission within 2 business
days after opening the sealed bids. The report shall
contain the procurement monitor's assessment of bidder
behavior in the process as well as an assessment of the
procurement administrator's compliance with the
procurement process and rules. The Commission shall review
the confidential reports submitted by the procurement
administrator and procurement monitor and shall accept or
reject the recommendations of the procurement
administrator within 2 business days after receipt of the
reports.
(6) Within 3 business days after the Commission
decision approving the results of a procurement event, the
Agency shall enter into binding contractual arrangements
with the winning suppliers using the standard form
contracts.
(7) The names of the successful bidders and the average
of the winning bid prices for each contract type and for
each contract term shall be made available to the public
within 2 days after the supplemental procurement event. The
Commission, the procurement monitor, the procurement

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administrator, the Agency, and all participants in the
procurement process shall maintain the confidentiality of
all other supplier and bidding information in a manner
consistent with all applicable laws, rules, regulations,
and tariffs. Confidential information, including the
confidential reports submitted by the procurement
administrator and procurement monitor pursuant to this
Section, shall not be made publicly available and shall not
be discoverable by any party in any proceeding, absent a
compelling demonstration of need, nor shall those reports
be admissible in any proceeding other than one for law
enforcement purposes.
(8) The supplemental procurement provided in this
subsection (i) shall not be subject to the requirements and
limitations of subsections (c) and (d) of this Section.
(9) Expenses incurred in connection with the
procurement process held pursuant to this Section,
including, but not limited to, the cost of developing the
supplemental procurement plan, the procurement
administrator, procurement monitor, and the cost of the
retirement of renewable energy credits purchased pursuant
to the supplemental procurement shall be paid for from the
Illinois Power Agency Renewable Energy Resources Fund. The
Agency shall enter into an interagency agreement with the
Commission to reimburse the Commission for its costs
associated with the procurement monitor for the

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supplemental procurement process.
(Source: P.A. 97-616, eff. 10-26-11; 98-672, eff. 6-30-14.)
(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. 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 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

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Section 16-111.5(a) of the Public Utilities Act.
Notwithstanding the requirements of this subdivision (a),
beginning with the planning process for the plan or plans to be
implemented in the 2016 delivery year, the Agency shall no
longer include the procurement of renewable energy resources in
the procurement plans required by this subdivision (a) and
shall instead develop a long-term renewable resources
procurement plan in accordance with subdivision (c) of this
Section.
(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;
(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

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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
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

SB1485 - 45 - LRB099 06216 AMC 30867 b
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
(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

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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
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

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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) The Planning and Procurement Bureau shall develop a
long-term renewable resources procurement plan that
includes all renewable energy credits necessary to meet the
goals set forth in this subdivision (c). The long-term
renewable resources procurement plan shall include
long-term programs and competitive procurement events
designed to meet the renewable resources goals in this
subdivision (c) from the date of the plan through the 2030
delivery year. The initial long-term renewable resources
procurement plan shall be released for comment no later
than 120 days after the effective date of this amendatory
Act of the 99th General Assembly. The Agency shall review
and revise the long-term renewable resources procurement

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plan at least every 2 years. The initial long-term
renewable resources procurement plan and each revised plan
shall be subject to review and approval by the Commission
pursuant to Section 16-111.5C of the Public Utilities Act.
(1.5) The Agency shall continue to implement all
procurements of renewable energy credits included in all
prior procurement plans filed with the Commission prior to
June 1, 2016. Any renewable energy credits procured as a
result of these prior procurements, including renewable
energy credits as part of bundled renewable energy
resources, shall be used to meet the goals set forth in
this subdivision (c) and shall be included as resources in
the long-term renewable resources plan required in
paragraph (1) of this subdivision (c). Any costs associated
with the procurement of renewable energy credits as a
result of these prior procurements, including the cost of
renewable energy credits included in the cost of bundled
renewable energy resources, but not including any
renewable energy credits procured as a result of
procurements authorized by subsection (i) of Section 1-56
of this Act or paid for using funds collected as a result
of paragraph (5) of this subdivision (c), shall be included
in the total cost of renewable energy credits procured
pursuant to the long-term procurement plan, as limited in
paragraph (1.15) of this subdivision (c).
As used in this subdivision (c):

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"Bundled renewable energy resources" means electricity
generated by a renewable energy system and its associated
renewable energy credit.
"Cost of renewable energy credits included in the cost
of bundled renewable energy resources" means the
difference between the contract price for the bundled
renewable energy resources and the day-ahead locational
marginal price at the load zone at which the contract is
settled multiplied by the megawatt hours of electricity
generated in each hour.
(1.10) The cost of any renewable energy credits
procured through a competitive procurement event pursuant
to an approved plan shall not exceed benchmarks established
by the procurement administrator, in consultation with the
Commission staff, Agency staff, and the procurement
monitor. The benchmarks shall be based on price data for
similar products for the same delivery period and same
utility delivery hub or other utility delivery hubs after
adjusting for that difference. The price benchmarks may
also be adjusted to take into account differences between
the information reflected in the underlying data sources
and the specific products and procurement process being
used to procure power for the Illinois utilities. The
benchmarks shall be confidential, but shall be provided to
the Commission and shall be subject to Commission review
and approval prior to a procurement event.

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(1.15) Notwithstanding the requirements of this
subdivision (c), the total amount of renewable energy
credits procured pursuant to the long-term renewable
resources procurement plan shall be reduced by an amount
necessary to limit the annual estimated average net
increase due to the costs of these credits included in the
amounts paid by all customers taking delivery service from
an electric utility to no more than 2.015% of the amount
paid per kilowatthour by eligible retail customers during
the year ending May 31, 2007. For purposes of this
subdivision (c), the amount paid per kilowatthour means the
total amount paid for electric service expressed on a per
kilowatthour basis, including without limitation amounts
paid for supply, transmission, distribution, surcharges,
and add-on taxes.
(1.20) The long-term renewable resources procurement
plan shall include the procurement of renewable energy
credits in amounts equal to at least the following
percentages measured as a percentage of the projected
amount of electricity in kilowatthours to be delivered by
the electric utilities to all customers taking delivery
service from an electric utility: 11.5% by the 2016
delivery year, and increasing by at least 1.5% each
delivery year thereafter to at least 25% by the 2025
delivery year; and increasing at least 2% each delivery
year thereafter to at least 35% by the 2030 delivery year,

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continuing at that percentage for each delivery year
thereafter.
(A) By the end of the 2020 delivery year:
(i) 75% of the total renewable energy credits
procured shall come from wind generation, of which
at least 25% shall come from new wind projects; and
(ii) 5% of the total renewable energy credits
procured or the equivalent amount of renewable
energy credits from 1,000 megawatts of solar
photovoltaic nameplate capacity, whichever is
larger, shall come from new photovoltaic projects;
of that amount, to the extent possible, the Agency
shall procure 75% from photovoltaic projects using
the program outlined in paragraph (1.25) of this
subdivision (c) from distributed renewable energy
devices or community solar projects and shall give
preference to brownfield solar projects that are
not community solar projects for the remaining
25%.
(B) By the end of the 2025 delivery year:
(i) 75% of the total renewable energy credits
procured shall come from wind generation, of which
at least 25% shall come from new wind projects; and
(ii) 6% of the total renewable energy credits
procured or the equivalent amount of renewable
energy credits from 1,500 megawatts of solar

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photovoltaic nameplate capacity, whichever is
larger, shall come from new photovoltaic projects;
of that amount, to the extent possible the Agency
shall procure 75% from photovoltaic projects using
the program outlined in paragraph (1.25) of this
subdivision (c) from distributed renewable energy
devices or community solar projects and shall give
preference to brownfield solar projects that are
not community solar projects for the remaining
25%.
(C) By the end of the 2030 delivery year:
(i) 75% of the total renewable energy credits
procured shall come from wind generation, of which
at least 25% shall come from new wind projects; and
(ii) 7% of the total renewable energy credits
procured or the equivalent amount of renewable
energy credits from 2,000 megawatts of solar
photovoltaic nameplate capacity, whichever is
larger, shall come from new photovoltaic projects;
of that amount, to the extent possible the Agency
shall procure 75% from photovoltaic projects using
the program outlined in paragraph (1.25) of this
subdivision (c) from distributed renewable energy
devices or community solar projects and shall give
preference to brownfield solar projects that are
not community solar projects for the remaining

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25%.
Renewable energy credits are eligible to be counted
toward the renewable energy requirements of this
subsection (c) if the renewable energy facility is located
in Illinois, if the facility has a generator
interconnection agreement with PJM or MISO, or if the
renewable energy facility is located in the United States
and the output of the facility is delivered to a
transmission asset that is controlled by PJM or MISO, where
"delivered" means the generated output of the facility has
been demonstrated to have a distribution factor of 25% or
greater on the transmission asset of PJM or MISO, and where
"distribution factor" means a measurement of the
sensitivity of the flow of electricity from a renewable
energy generator to a consuming load on a transmission
asset under the control of MISO or PJM. In procuring
renewable energy credits, the Agency may consider bid
selection criteria that include public interest factors,
such as the potential to increase fuel and resource
diversity in Illinois, enhance system reliability and
resiliency, and contribute to a cleaner and healthier
environment for the citizens of Illinois. In its long-term
plan, the Agency shall develop the method for incorporating
these public interest factors, in addition to bid price,
into its bid selection process. The Agency's method may
include, but may not be limited to, quantitatively scoring

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the evaluation of individual bids under public interest
criteria or the establishment of procurement minimums for
project categories informed by the public interest factors
described in this paragraph (1.15).
In the event that the rate impact cap in paragraph
(1.15) of this subdivision (c) prevents the Agency from
meeting all of the percentage goals in this subdivision
(c), the Agency shall prioritize compliance with the goals
for new wind and photovoltaic projects.
As used in this paragraph (1.20):
"New wind projects" means wind renewable energy
projects (i) that begin energy delivery no earlier than 3
years prior to the procurement date and (ii) for projects
located within Illinois, for which the owner of the project
has certified that not less than the prevailing wage was or
will be paid to employees who are engaged in construction
activities associated with the project.
"New photovoltaic projects" means photovoltaic
renewable energy projects (i) that are interconnected at
the distribution system level of either an electric
utility, a municipal utility as defined in Section 3-105 of
the Public Utilities Act, or a rural electric cooperative
as defined in Section 3-119 of the Public Utilities Act,
(ii) that are energized after January 1, 2016 for the first
procurement year or within one year of the procurement date
for subsequent procurement years, and (iii) for projects

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over 1,000 kilowatts in nameplate capacity, for which the
owner of the project has certified that not less than the
prevailing wage was or will be paid to employees who are
engaged in construction activities associated with the
project.
"Prevailing wage" has the same definition as in
subsection (F) of Section 5.5(a)(3) of the Enterprise Zone
Act.
(1.25) The long-term renewable resources procurement
plan developed by the Agency in accordance with this
subdivision (c) shall include a declining block program for
the procurement of renewable energy credits from
photovoltaic projects that are distributed renewable
energy generation devices or community solar projects. The
declining block program shall be designed to provide a
transparent schedule of prices and capacity to enable the
photovoltaic market to scale up and for renewable energy
credit prices to fall at a predictable, sustainable rate
over time. The declining block program shall include for
each category of eligible projects: (i) a schedule of
standard, declining block purchase prices to be offered,
(ii) a series of steps, with associated nameplate capacity
and purchase prices that decline from step to step, and
(iii) 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

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energized on or after January 1, 2016, shall be eligible
for the declining 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
paragraph (1.20) of this subdivision (c). The Agency may
periodically review the purchase prices and may
redistribute available funds as necessary and appropriate,
subject to Commission approval as part of the periodic plan
revision process described in Section 16-111.5C of the
Public Utilities Act.
The declining block program shall include at least the
following block groups, which may be adjusted upon review
by the Agency and approval of the Commission:
(A) Distributed renewable energy generation
devices with a nameplate capacity of no more than 10
kilowatts.
(B) Distributed renewable energy generation
devices with a nameplate capacity of more than 10
kilowatts and no more than 100 kilowatts.
(C) Distributed renewable energy generation
devices with a nameplate capacity of more than 100
kilowatts and no more than 500 kilowatts.
(D) Distributed renewable energy generation

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devices with a nameplate capacity of more than 500
kilowatts and no more than 2,000 kilowatts.
(E) Distributed renewable energy generation
devices with a nameplate capacity of no more than 2,000
kilowatts that are owned by a municipality, a school
district, a unit of local government, a public
university, or a not-for-profit corporation, and
primarily used to offset their own electricity load.
(F) Community solar projects.
For projects that qualify under paragraph (A) of this
paragraph (1.25), the renewable energy credit purchase
price shall be paid as an upfront payment per installed
kilowatt of nameplate capacity paid once the device is
energized. The electric utility shall receive all
renewable energy credits generated by the project for the
first 15 years of operation. For projects that qualify
under items (B) through (F) of this paragraph (1.25) and
any additional categories included in the long-term
renewable resources plan and approved by the Commission,
the renewable energy credit purchase price shall be in
exchange for an assignment of all renewable energy credits
generated by the project for the first 15 years of
operation. The Agency shall pay for those credits over the
first 5 years of operation of the system through a partial
payment made after the system is first energized and
additional payments over the first 4 years of operation

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based on actual energy produced. The electric utility shall
receive all renewable energy credits generated by the
project for the first 15 years of operation.
The Agency shall issue a request for qualifications for
a third-party program manager to administer the declining
block program. The third-party program manager shall be
chosen through a competitive bid process based on selection
criteria and requirements developed by the Agency,
including consideration of prior experience in
administering an incentive program for energy efficiency,
renewable energy, or other similar resources. The
third-party program manager shall be the counterparty to
the contract to purchase renewable energy credits from
individual systems. The utility shall transfer funds
needed to cover the cost of purchasing renewable energy
credits and administering the declining block program to
the third-party program manager at the order of the
Commission. The utility's obligation under this paragraph
(1.25) shall be considered met upon transfer of funds to
the third-party program manager and retirement of
associated renewable energy credits. At least every 2
years, the Agency shall select an independent evaluator to
review and report on the declining block program and the
performance of the declining block program manager. The
report should include the number of projects installed, the
total installed capacity in kilowatts, the average cost per

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kilowatt of installed capacity, the total number of jobs,
and other economic, social, and environmental benefits
created. The report shall be posted on the Agency's website
and used, as needed, to revise the declining block program.
Upon order of the Commission, the utility shall provide
payment for the independent evaluation of the declining
block program. Costs associated with evaluation of the
declining block program shall not be included in paragraph
(1.15) of this subdivision (c), however these costs shall
be recoverable as a utility cost of service under the
Public Utilities Act. The selection of the third-party
program manager, the selection of the independent
evaluator, and the procurement process described in this
paragraph (1.25) are exempt from the requirements of
Section 20-10 of the Illinois Procurement Code.
(1.30) The long-term renewable resources procurement
plan required by the subdivision (c) shall include a
Community Solar Program. The Agency shall develop the
Community Solar Program to purchase renewable energy
credits from community solar projects with a goal to expand
renewable energy generating facility access to a broader
group of energy consumers, including those who cannot
install renewable energy on their own properties, while
prioritizing those persons most sensitive to market
barriers.
The Agency shall establish the terms, conditions, and

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program requirements for community solar projects as part
of the long-term renewable resources plan required by this
Section. Any plan approved by the Commission must
reasonably allow for the creation, financing, and
accessibility of community solar projects and shall allow
subscriptions to community solar projects to be portable
and transferrable. Electric utilities shall establish a
tariff to provide bill credits to subscribers of community
solar projects, as specified in an approved long-term
renewable resources plan. The community solar bill credits
shall account for the fair value of the distributed solar
energy and its delivery, generation capacity, transmission
capacity, transmission and distribution line losses, and
environmental value. The Agency may provide an enhanced
bill credit for community solar projects that are located
within brownfield sites or within strategic zones
identified by the utility with approval by the Commission
to provide the greatest benefits to the electric
distribution system. If the electrical capacity of a
community solar project is not fully subscribed during the
first full year of operation, the electric utility shall
purchase the energy associated with the unsubscribed
capacity at the electric utility's avoided cost of
electricity supply over the month period or as otherwise
specified by the terms of a power purchase agreement
negotiated by the community solar owners or subscribers and

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the electricity provider. After the first full year of
operation, if the electrical capacity of a community solar
project is not fully subscribed, the electric utility shall
purchase the energy associated with the unsubscribed
capacity at the electric utility's avoided cost of
electricity supply over the month period unless excess
capacity is otherwise provided for in a power purchase
agreement. The Agency shall purchase renewable energy
credits from subscribed shares of community solar projects
through the declining block program described in paragraph
(6) of this subdivision (c) or through the low income solar
program described in Section 1-56 of this Act. The owners
of and any subscribers to a community solar 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 solar project and shall not be required to
become an alternative retail electric supplier by
participating in a community solar project with a public
utility.
The procurement plans shall include cost-effective
renewable energy resources. A minimum percentage of each
utility's total supply to serve the load of eligible retail
customers, as defined in Section 16-111.5(a) of the Public
Utilities Act, procured for each of the following years
shall be generated from cost-effective renewable energy

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resources: at least 2% by June 1, 2008; at least 4% by June
1, 2009; at least 5% by June 1, 2010; at least 6% by June 1,
2011; at least 7% by June 1, 2012; at least 8% by June 1,
2013; at least 9% by June 1, 2014; at least 10% by June 1,
2015; and increasing by at least 1.5% each year thereafter
to at least 25% by June 1, 2025. To the extent that it is
available, at least 75% of the renewable energy resources
used to meet these standards shall come from wind
generation and, beginning on June 1, 2011, at least the
following percentages of the renewable energy resources
used to meet these standards shall come from photovoltaics
on the following schedule: 0.5% by June 1, 2012, 1.5% by
June 1, 2013; 3% by June 1, 2014; and 6% by June 1, 2015 and
thereafter. Of the renewable energy resources procured
pursuant to this Section, at least the following
percentages shall come from distributed renewable energy
generation devices: 0.5% by June 1, 2013, 0.75% by June 1,
2014, and 1% by June 1, 2015 and thereafter. To the extent
available, half of the renewable energy resources procured
from distributed renewable energy generation shall come
from devices of less than 25 kilowatts in nameplate
capacity. Renewable energy resources procured from
distributed generation devices may also count towards the
required percentages for wind and solar photovoltaics.
Procurement of renewable energy resources from distributed
renewable energy generation devices shall be done on an

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annual basis through multi-year contracts of no less than 5
years, and shall consist solely of renewable energy
credits.
The Agency shall create credit requirements for
suppliers of distributed renewable energy. In order to
minimize the administrative burden on contracting
entities, the Agency shall solicit the use of third-party
organizations to aggregate distributed renewable energy
into groups of no less than one megawatt in installed
capacity. These third-party organizations shall administer
contracts with individual distributed renewable energy
generation device owners. An individual distributed
renewable energy generation device owner shall have the
ability to measure the output of his or her distributed
renewable energy generation device.
For purposes of this subsection (c), "cost-effective"
means that the costs of procuring renewable energy
resources do not cause the limit stated in paragraph (2) of
this subsection (c) to be exceeded and do not exceed
benchmarks based on market prices for renewable energy
resources in the region, which 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.
(2) (Blank). For purposes of this subsection (c), the

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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) supplied by the electric utility to
eligible retail customers in the planning year ending
immediately prior to the procurement. 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
(c), the total of renewable energy resources procured
pursuant to the procurement plan for any single 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 2008, no more than 0.5% of the amount paid
per kilowatthour by those customers during the year
ending May 31, 2007;
(B) in 2009, the greater of an additional 0.5% of
the amount paid per kilowatthour by those customers
during the year ending May 31, 2008 or 1% of the amount
paid per kilowatthour by those customers during the

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year ending May 31, 2007;
(C) in 2010, the greater of an additional 0.5% of
the amount paid per kilowatthour by those customers
during the year ending May 31, 2009 or 1.5% of the
amount paid per kilowatthour by those customers during
the year ending May 31, 2007;
(D) 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 2% of the amount
paid per kilowatthour by those customers during the
year ending May 31, 2007; and
(E) thereafter, the amount of renewable energy
resources procured 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 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.
No later than June 30, 2011, the Commission shall
review the limitation on the amount of renewable energy
resources procured pursuant to this subsection (c) and
report to the General Assembly its findings as to

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whether that limitation unduly constrains the
procurement of cost-effective renewable energy
resources.
(3) (Blank). Through June 1, 2011, renewable energy
resources shall be counted for the purpose of meeting the
renewable energy standards set forth in paragraph (1) of
this subsection (c) only if they are generated from
facilities located in the State, provided that
cost-effective renewable energy resources are available
from those facilities. If those cost-effective resources
are not available in Illinois, they shall be procured in
states that adjoin Illinois and may be counted towards
compliance. If those cost-effective resources are not
available in Illinois or in states that adjoin Illinois,
they shall be purchased elsewhere and shall be counted
towards compliance. After June 1, 2011, cost-effective
renewable energy resources located in Illinois and in
states that adjoin Illinois may be counted towards
compliance with the standards set forth in paragraph (1) of
this subsection (c). If those cost-effective resources are
not available in Illinois or in states that adjoin
Illinois, they shall be purchased elsewhere and shall be
counted towards compliance.
(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

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after the 2016 delivery year year commencing June 1, 2010,
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 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. Beginning April 1, 2012, and
each year thereafter, the Agency shall prepare a public
report for the General Assembly and Illinois Commerce

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Commission that shall include, but not necessarily be
limited to:
(A) a comparison of the costs associated with the
Agency's procurement of renewable energy resources to
(1) the Agency's costs associated with electricity
generated by other types of generation facilities and
(2) the benefits associated with the Agency's
procurement of renewable energy resources; and
(B) an analysis of the rate impacts associated with
the Illinois Power Agency's procurement of renewable
resources, including, but not limited to, any
long-term contracts, on the eligible retail customers
of electric utilities.
The analysis shall include the Agency's estimate of the
total dollar impact that the Agency's procurement of
renewable resources has had on the annual electricity bills
of the customer classes that comprise each eligible retail
customer class taking service from an electric utility. The
Agency's report shall also analyze how the operation of the
alternative compliance payment mechanism, any long-term
contracts, or other aspects of the applicable renewable
portfolio standards impacts the rates of customers of
alternative retail electric suppliers.
(6) Costs of procuring renewable energy credits
pursuant to plans approved under Section 16-111.5C of the
Public Utilities Act and associated reasonable expenses

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for implementing the procurement programs, including the
costs of administering and evaluating the declining block
program, shall be recoverable as a utility cost of service
under the Public Utilities Act.
(7) In meeting the renewable energy requirements of
this subdivision (c), to the extent feasible and consistent
with State and federal law, the renewable energy credit
procurements, declining block solar program, and community
solar 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

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

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

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

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No later than June 30, 2015, the Commission shall
review the limitation on the total amount paid under
sourcing agreements, if any, with clean coal facilities
pursuant to this subsection (d) and report to the General
Assembly its findings as to whether that limitation unduly
constrains the amount of electricity generated by
cost-effective clean coal facilities that is covered by
sourcing agreements.
(3) Initial clean coal facility. In order to promote
development of clean coal facilities in Illinois, each
electric utility subject to this Section shall execute a
sourcing agreement to source electricity from a proposed
clean coal facility in Illinois (the "initial clean coal
facility") that will have a nameplate capacity of at least
500 MW when commercial operation commences, that has a
final Clean Air Act permit on the effective date of this
amendatory Act of the 95th General Assembly, 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

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

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pursuant to paragraph (3) of this subsection (d) or
item (5) of subsection (d) of Section 16-115 of the
Public Utilities Act, whether generated from the
synthesis gas derived from coal, from SNG, or from
natural gas, shall be credited against the revenue
requirement for this initial clean coal facility;
(B) power purchase provisions, which shall:
(i) provide that the utility party to such
sourcing agreement shall pay the contract price
for electricity delivered under such sourcing
agreement;
(ii) require delivery of electricity to the
regional transmission organization market of the
utility that is party to such sourcing agreement;
(iii) require the utility party to such
sourcing agreement to buy from the initial clean
coal facility in each hour an amount of energy
equal to all clean coal energy made available from
the initial clean coal facility during such hour
times a fraction, the numerator of which is such
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

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

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

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electricity determined pursuant to the preceding
clause (i); and
(iii) not require the utility to take physical
delivery of the electricity produced by the
facility;
(D) general provisions, which shall:
(i) specify a term of no more than 30 years,
commencing on the commercial operation date of the
facility;
(ii) provide that utilities shall maintain
adequate records documenting purchases under the
sourcing agreements entered into to comply with
this subsection (d) and shall file an accounting
with the load forecast that must be filed with the
Agency by July 15 of each year, in accordance with
subsection (d) of Section 16-111.5 of the Public
Utilities Act;
(iii) provide that all costs associated with
the initial clean coal facility will be
periodically reported to the Federal Energy
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

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otherwise on reasonable terms acceptable to the
Agency, if the Agency so requests no less than 3
years prior to the end of the stated contract term;
(v) require the owner of the initial clean coal
facility to provide documentation to the
Commission each year, starting in the facility's
first year of commercial operation, accurately
reporting the quantity of carbon emissions from
the facility that have been captured and
sequestered and report any quantities of carbon
released from the site or sites at which carbon
emissions were sequestered in prior years, based
on continuous monitoring of such sites. If, in any
year after the first year of commercial operation,
the owner of the facility fails to demonstrate that
the initial clean coal facility captured and
sequestered at least 50% of the total carbon
emissions that the facility would otherwise emit
or that sequestration of emissions from prior
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

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not recoverable shall not exceed $15 million in any
given year. No costs of any such purchases of
carbon offsets may be recovered from a utility or
its customers. All carbon offsets purchased for
this purpose and any carbon emission credits
associated with sequestration of carbon from the
facility must be permanently retired. The initial
clean coal facility shall not forfeit its
designation as a clean coal facility if the
facility fails to fully comply with the applicable
carbon sequestration requirements in any given
year, provided the requisite offsets are
purchased. However, the Attorney General, on
behalf of the People of the State of Illinois, may
specifically enforce the facility's sequestration
requirement and the other terms of this contract
provision. Compliance with the sequestration
requirements and offset purchase requirements
specified in paragraph (3) of this subsection (d)
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 wilfully fails to comply

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with the carbon capture and sequestration
requirements set forth in this item (v);
(vi) include limits on, and accordingly
provide for modification of, the amount the
utility is required to source under the sourcing
agreement consistent with paragraph (2) of this
subsection (d);
(vii) require Commission review: (1) to
determine the justness, reasonableness, and
prudence of the inputs to the formula referenced in
subparagraphs (A)(i) through (A)(iii) of paragraph
(3) of this subsection (d), prior to an adjustment
in those inputs including, without limitation, the
capital structure and return on equity, fuel
costs, and other operations and maintenance costs
and (2) to approve the costs to be passed through
to customers under the sourcing agreement by which
the utility satisfies its statutory obligations.
Commission review shall 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

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waives any right to assert federal pre-emption or
any other argument in response to a purported
disallowance of recovery costs;
(ix) limit the utility's or alternative retail
electric supplier's obligation to incur any
liability until such time as the facility is in
commercial operation and generating power and
energy and such power and energy is being delivered
to the facility busbar;
(x) provide that the owner or owners of the
initial clean coal facility, which is the
counterparty to such sourcing agreement, shall
have the right from time to time to elect whether
the obligations of the utility party thereto shall
be governed by the power purchase provisions or the
contract for differences provisions;
(xi) append documentation showing that the
formula rate and contract, insofar as they relate
to the power purchase provisions, have been
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

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

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consultation with the Agency, shall submit a report to
the General Assembly setting forth its analysis of the
facility cost report. Such report shall include, but
not be limited to, a comparison of the costs associated
with electricity generated by the initial clean coal
facility to the costs associated with electricity
generated by other types of generation facilities, an
analysis of the rate impacts on residential and small
business customers over the life of the sourcing
agreements, and an analysis of the likelihood that the
initial clean coal facility will commence commercial
operation by and be delivering power to the facility's
busbar by 2016. To assist in the preparation of its
report, the Commission, in consultation with the
Agency, may hire one or more experts or consultants,
the costs of which shall be paid for by the owner of
the initial clean coal facility. The Commission and
Agency may begin the process of selecting such experts
or consultants prior 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

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electricity generated by the initial clean coal
facility, (B) the projected impact on residential and
small business customers' bills over the life of the
sourcing agreements, and (C) the maximum allowable
return on equity for the project; and
(iv) Commission review. If the General Assembly
enacts authorizing legislation pursuant to
subparagraph (iii) approving a sourcing agreement, the
Commission shall, within 90 days of such enactment,
complete a review of such sourcing agreement. During
such time period, the Commission shall implement any
directive of the General Assembly, resolve any
disputes between the parties to the sourcing agreement
concerning the terms of such agreement, approve the
form of such agreement, and issue an order finding that
the sourcing agreement is prudent and reasonable.
The facility cost report shall be prepared as follows:
(A) The facility cost report shall be prepared by
duly licensed engineering and construction firms
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

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

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to permit quantification of major categories of
materials, commodities and labor hours, and receipt of
quotes from vendors of major equipment required to
construct and operate the clean coal facility.
(C) The facility cost report shall also include an
operating and maintenance cost quote that will provide
the estimated cost of delivered fuel, personnel,
maintenance contracts, chemicals, catalysts,
consumables, spares, and other fixed and variable
operations and maintenance costs. The delivered fuel
cost estimate will be provided by a recognized third
party expert or experts in the fuel and transportation
industries. The balance of the operating and
maintenance cost quote, excluding delivered fuel
costs, will be developed based on the inputs provided
by duly licensed engineering and construction firms
performing the construction cost quote, potential
vendors under long-term service agreements and plant
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

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

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subsection (d) of this Section and item (5) of subsection
(d) of Section 16-115 of the Public Utilities Act, covering
electricity generated by such facilities. In the case of
sourcing agreements that are power purchase agreements,
the contract price for electricity sales shall be
established on a cost of service basis. In the case of
sourcing agreements that are contracts for differences,
the contract price from which the reference price is
subtracted shall be established on a cost of service basis.
The Agency and the Commission may approve any such utility
sourcing agreements that do not exceed cost-based
benchmarks developed by the procurement administrator, in
consultation with the Commission staff, Agency staff and
the procurement monitor, subject to Commission review and
approval. The Commission shall have authority to inspect
all books and records associated with these clean coal
facilities during the term of any such contract.
(6) Costs incurred under this subsection (d) or
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.
(e) The draft procurement plans are subject to public
comment, as required by Section 16-111.5 of the Public
Utilities Act.

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(f) The Agency shall submit the final procurement plan to
the Commission. The Agency shall revise a procurement plan if
the Commission determines that it does not meet the standards
set forth in Section 16-111.5 of the Public Utilities Act.
(g) The Agency shall assess fees to each affected utility
to recover the costs incurred in preparation of the annual
procurement plan for the utility.
(h) The Agency shall assess fees to each bidder to recover
the costs incurred in connection with a competitive procurement
process.
(Source: P.A. 97-325, eff. 8-12-11; 97-616, eff. 10-26-11;
97-618, eff. 10-26-11; 97-658, eff. 1-13-12; 97-813, eff.
7-13-12; 98-463, eff. 8-16-13.)
Section 10. The Public Utilities Act is amended by changing
Sections 8-101, 8-103, 8-104, 16-107, 16-108.5, 16-108.8,
16-111.5, 16-111.5B, 16-111.7, 16-115D, and 19-140 and by
adding Section 16-111.5C as follows:
(220 ILCS 5/8-101) (from Ch. 111 2/3, par. 8-101)
Sec. 8-101. Duties of public utilities; nondiscrimination.
A public utility shall furnish, provide, and maintain such
service instrumentalities, equipment, and facilities as shall
promote the safety, health, comfort, and convenience of its
patrons, employees, and public and as shall be in all respects
adequate, efficient, just, and reasonable.

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All rules and regulations made by a public utility
affecting or pertaining to its charges or service to the public
shall be just and reasonable.
A public utility shall, upon reasonable notice, furnish to
all persons who may apply therefor and be reasonably entitled
thereto, suitable facilities and service, without
discrimination and without delay.
Nothing in this Section shall be construed to prevent a
public utility from accepting payment electronically or by the
use of a customer-preferred financially accredited credit or
debit methodology.
A public utility shall not discriminate against
technologies, regardless of generator, prime mover, or
inverter, when presented with an application for
interconnection of a distributed generation facility,
including without limitation a battery or energy storage
facility, that operates in parallel with the electric
distribution system.
(Source: P.A. 92-22, eff. 6-30-01.)
(220 ILCS 5/8-103)
Sec. 8-103. 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 delivery load. Requiring

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investment in cost-effective energy efficiency and
demand-response measures will reduce direct and indirect costs
to consumers by decreasing environmental impacts, by reducing
electricity prices in the regional power market, 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 expenses 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 (f)(4) 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" shall have the
meanings set forth in the Illinois Power Agency Act. For
purposes of this Section, the amount per kilowatthour means the
total amount paid for electric service expressed on a per
kilowatthour basis. For purposes of this Section, the total
amount paid for electric service includes without limitation
estimated amounts paid for supply, transmission, distribution,
surcharges, and add-on-taxes.
(b) Electric utilities shall implement cost-effective
energy efficiency measures to meet the following incremental
annual energy savings goals:
(1) 0.2% of energy delivered in the year commencing

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June 1, 2008;
(2) 0.4% of energy delivered in the year commencing
June 1, 2009;
(3) 0.6% of energy delivered in the year commencing
June 1, 2010;
(4) 0.8% of energy delivered in the year commencing
June 1, 2011;
(5) 1% of energy delivered in the year commencing June
1, 2012;
(6) 1.4% of energy delivered in the year commencing
June 1, 2013;
(7) 1.8% of energy delivered in the year commencing
June 1, 2014; and
(8) 2% of energy delivered in each the year commencing
June 1, 2015 and ending on December 31, 2017; and each year
thereafter.
(9) beginning in January 2018, an amount to be
determined by the Illinois Commerce Commission through the
process described in subsection (f) of this Section in
order to achieve a cumulative annual persisting reduction
in electric energy demand from efficiency measures
implemented as a result of utility programs from 2012
through 2025 of 20%, relative to average annual electricity
sales from 2014 through 2016, by the year ending December
31 2025; cumulative persisting annual reductions are the
reductions realized in a given year from measures installed

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in either the that year or in previous years that are still
operational and providing savings in that year because they
have not yet reached the end of their useful life; and
After 2025, the incremental annual energy goal shall be an
amount to be determined by the Illinois Commerce Commission in
order to fully capture the cost-effective potential for
electricity savings as assessed by the Illinois Power Agency
under subsection (j-10) of this Section.
Electric utilities may comply with this subsection (b) by
meeting the annual incremental savings goal in the applicable
year or by showing that the total cumulative annual savings
within a 3-year planning period associated with measures
implemented after May 31, 2014 was equal to the sum of each
annual incremental savings requirement from May 31, 2014
through the end of the applicable year. Beginning January 1,
2018, electric utilities may comply by showing that the total
cumulative annual savings persisting the last year of the
applicable 4-year planning period was equal to the cumulative
persisting annual savings required in that year by the Illinois
Commerce Commission pursuant to the plans approved under
subsection (f) of this Section. Annually, beginning on March 1,
2019, each participating utility shall file third-party
evaluations of the savings achieved in the preceding year.
Within 5 days after the filing, any person objecting to the
filing shall file an objection. Within 10 days after the
filing, the Commission shall determine whether a hearing is

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necessary. The Commission shall enter its order confirming or
modifying the savings estimates within 90 days after the filing
date.
(c) Electric utilities shall implement cost-effective
demand-response measures to reduce peak demand by 0.1% over the
prior year for its delivery customers 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 commences June
1, 2008 and continues for 10 years.
(d) Notwithstanding the requirements of subsections (b)
and (c) of this Section, an electric utility shall reduce the
amount of energy efficiency and demand-response measures
implemented over a 3-year planning period by an amount
necessary to limit the estimated average annual increase in the
amounts paid by retail customers in connection with electric
service due to the cost of those measures to:
(1) in 2008, no more than 0.5% of the amount paid per
kilowatthour by those customers during the year ending May
31, 2007;
(2) in 2009, the greater of an additional 0.5% of the
amount paid per kilowatthour by those customers during the
year ending May 31, 2008 or 1% of the amount paid per
kilowatthour by those customers during the year ending May
31, 2007;

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(3) in 2010, the greater of an additional 0.5% of the
amount paid per kilowatthour by those customers during the
year ending May 31, 2009 or 1.5% of the amount paid per
kilowatthour by those customers during the year ending May
31, 2007;
(4) 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 2% of the amount paid per
kilowatthour by those customers during the year ending May
31, 2007; and
(5) in 2012 and in each subsequent year through 2017
thereafter, the amount of energy efficiency and
demand-response measures implemented for any single year
shall be reduced by an amount necessary to limit the
estimated average net increase due to the cost of these
measures 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 measures in 2011.
No later than June 30, 2011, the Commission shall review
the limitation on the amount of energy efficiency and
demand-response measures implemented pursuant to this Section
and report to the General Assembly its findings as to whether
that limitation unduly constrains the procurement of energy

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efficiency and demand-response measures.
For utility efficiency programs offered on or after January
2018, the amount of savings shall be limited only to the extent
necessary to ensure that the measures installed will, in the
aggregate, result in net benefits to customers when the full
costs of the efficiency programs are compared with the full
benefits, as defined in the total resource cost test.
(e) Electric utilities shall be responsible for overseeing
the design, development, and filing of energy efficiency and
demand-response plans with the Commission. Electric utilities
shall implement 100% of the demand-response measures in the
plans. Electric utilities shall implement 75% of the energy
efficiency measures approved by the Commission, and may, as
part of that implementation, outsource various aspects of
program development and implementation. The remaining 25% of
those energy efficiency measures approved by the Commission
shall be implemented by the Department of Commerce and Economic
Opportunity, and must be designed in conjunction with the
utility and the filing process. The Department may outsource
development and implementation of energy efficiency measures.
A minimum of 10% of the entire portfolio of cost-effective
energy efficiency measures shall be procured from units of
local government, municipal corporations, school districts,
and community college districts. A minimum of 12.5% of the
entire portfolio of cost-effective energy efficiency measures
shall be allocated to programs that serve low-income

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residential customers. The Department shall coordinate the
implementation of these measures. As much as half of the
minimum low-income requirement may be met through energy
efficiency measures that result in savings related to fuels
other than electricity if necessary:
(1) to comprehensively capture treatment of efficiency
opportunities for low-income residential customers;
(2) to enable effective administration of low-income
programs; or
(3) to address limitations on availability of other
funding sources for efficiency measures to improve the
efficiency of use of natural gas, fuel oil, or other fuels
used by low-income residential customers.
The Department shall coordinate the implementation of these
measures.
The apportionment of the dollars to cover the costs to
implement the Department's share of the portfolio of energy
efficiency measures shall be made to the Department once the
Department has executed rebate agreements, grants, or
contracts for energy efficiency measures and provided
supporting documentation for those rebate agreements, grants,
and contracts to the utility. The Department is authorized to
adopt any rules necessary and prescribe procedures in order to
ensure compliance by applicants in carrying out the purposes of
rebate agreements for energy efficiency measures implemented
by the Department made under this Section.

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The details of the measures implemented by the Department
shall be submitted by the Department to the Commission in
connection with the utility's filing regarding the energy
efficiency and demand-response measures that the utility
implements.
A utility providing approved energy efficiency and
demand-response measures in the State before December 31, 2017
shall be permitted to recover costs of those measures 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. Beginning
January 1, 2018, a participating utility providing approved
energy efficiency and demand-response measures in the State
that has elected to be subject to Section 16-108.5 of the
Public Utilities Act may recover the costs of those measures as
part of its cost of service in its performance-based formula
rate as provided in paragraph (1) of subsection (c) of Section
16-108.5.
Each utility shall include, in its recovery of costs, the
costs estimated for both the utility's and the Department's
implementation of energy efficiency and demand-response
measures. Costs collected by the utility for measures
implemented by the Department shall be submitted to the

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Department pursuant to Section 605-323 of the Civil
Administrative Code of Illinois, shall be deposited into the
Energy Efficiency Portfolio Standards Fund, and shall be used
by the Department solely for the purpose of implementing these
measures. A utility shall not be required to advance any moneys
to the Department but only to forward such funds as it has
collected. The Department shall report to the Commission on an
annual basis regarding the costs actually incurred by the
Department in the implementation of the measures. Any changes
to the costs of energy efficiency measures as a result of plan
modifications shall be appropriately reflected in amounts
recovered by the utility and turned over to the Department.
The portfolio of measures, administered by both the
utilities and the Department, shall, in combination, be
designed to achieve the annual savings targets described in
subsections (b) and (c) of this Section, as modified by
subsection (d) of this Section.
The utility and the Department shall agree upon a
reasonable portfolio of measures and determine the measurable
corresponding percentage of the savings goals associated with
measures implemented by the utility or Department.
No utility shall be assessed a penalty under subsection (f)
of this Section for failure to make a timely filing if that
failure is the result of a lack of agreement with the
Department with respect to the allocation of responsibilities
or related costs or target assignments. In that case, the

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Department and the utility shall file their respective plans
with the Commission and the Commission shall determine an
appropriate division of measures and programs that meets the
requirements of this Section.
If the Department is unable to meet incremental annual
performance goals for the portion of the portfolio implemented
by the Department, then the utility and the Department shall
jointly submit a modified filing to the Commission explaining
the performance shortfall and recommending an appropriate
course going forward, including any program modifications that
may be appropriate in light of the evaluations conducted under
item (7) of subsection (f) of this Section. In this case, the
utility obligation to collect the Department's costs and turn
over those funds to the Department under this subsection (e)
shall continue only if the Commission approves the
modifications to the plan proposed by the Department.
(f) No later than November 15, 2007, each electric utility
shall file an energy efficiency and demand-response plan with
the Commission to meet the energy efficiency and
demand-response standards for 2008 through 2010. No later than
October 1, 2010, each electric utility shall file an energy
efficiency and demand-response plan with the Commission to meet
the energy efficiency and demand-response standards for 2011
through 2013. By September 1, 2013, each electric utility shall
file an energy efficiency and demand-response plan for 2014
through 2017. By January 1, 2016, the Illinois Power Agency

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shall publish a draft statewide energy efficiency potential
study that assesses the technical, economic, and maximum
cost-effective achievable potential for energy efficiency for
each electric utility service territory from 2018 through 2021
and from 2022 through 2025. The Agency shall seek input from
stakeholders in advance of conducting the study. After the
draft study is published, the Agency shall accept public
comments on the study through March 1, 2016 and shall transmit
a final proposed study to the Commission by April 15, 2017. The
Commission shall approve the study or approve with
modifications by June 1, 2016. By January 1, 2017, each
electric utility and the Department shall file an energy
efficiency plan for the period beginning January 1, 2018
through December 31, 2021 that seeks to achieve a cumulative
persisting annual reduction in electricity demand in 2021, from
efficiency measures installed as a result of its programs from
2012 through 2021, of at least 12% compared to average annual
electricity sales from 2014 through 2016, unless such levels
have been clearly shown by the Illinois Power Agency's
potential study to not be cost-effective or achievable, in
which case the plans should be designed to capture all of the
cost-effective potential for energy savings identified as
achievable in the potential study completed by the Illinois
Power Agency. By January 1, 2020 and every 4 years thereafter,
the Illinois Power Agency shall publish a second draft
statewide energy efficiency potential study updating its

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assessment of the cost-effective achievable potential for
energy efficiency for each electric utility service territory
from 2022 through 2025. The agency shall seek input from
stakeholders in advance of conducting the study. The agency
will accept public comments on the draft study through March 1,
2020 and shall transmit a final proposed study to the
Commission by April 15, 2020. The Commission shall approve the
study or approve with modifications by June 1, 2020. By January
1, 2021, each electric utility and the Department shall file an
energy efficiency plan for the period beginning January 1, 2022
through December 31, 2025 that seeks to achieve a cumulative
persisting annual reduction in electricity demand in 2025, from
efficiency measures installed as a result of its programs from
2012 through 2025, of at least 20% compared to average annual
electricity sales from 2014 through 2016, unless such levels
have been clearly shown by the Illinois Power Agency's study to
not be cost-effective or achievable, in which case the plans
should be designed to capture all of the cost-effective
potential for energy savings identified in the potential study
completed by the Illinois Power Agency. On January 1, 2024 and
every 4 years thereafter, each electric utility and the
Department shall file an energy efficiency plan covering a
4-year period beginning January 1 of the following year. Every
3 years thereafter, each electric utility shall file, no later
than September 1, an energy efficiency and demand-response plan
with the Commission. If a utility does not file such a plan by

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the deadlines described in this Section September 1 of an
applicable year, it shall face a penalty of $100,000 per day
until the plan is filed. Each utility's plan shall set forth
the utility's proposals to meet the utility's portion of the
energy efficiency standards identified in subsection (b) and
the demand-response standards identified in subsection (c) of
this Section as modified by subsections (d) and (e), taking
into account the unique circumstances of the utility's service
territory. The Commission shall seek public comment on the
utility's plan and shall issue an order approving or
disapproving each plan within 6 5 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. In submitting
proposed energy efficiency and demand-response plans and
funding levels to meet the savings goals adopted by this Act
the utility shall:
(1) Demonstrate that its proposed energy efficiency

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and demand-response measures will achieve the requirements
that are identified in subsections (b) and (c) of this
Section, as modified by subsections (d) and (e).
(2) Present specific proposals to implement new
building and appliance standards that have been placed into
effect.
(3) Present estimates of the total amount paid for
electric service expressed on a per kilowatthour basis
associated with the proposed portfolio of measures
designed to meet the requirements that are identified in
subsections (b) and (c) of this Section, as modified by
subsections (d) and (e).
(4) Coordinate with the Department to present a
portfolio of energy efficiency measures proportionate to
the share of total annual utility revenues in Illinois from
households at or below 150% of the poverty level. The
energy efficiency programs shall be targeted to households
with incomes at or below 80% of area median income.
(5) Demonstrate that its overall portfolio of energy
efficiency and demand-response measures, not including
programs covered by item (4) of this subsection (f), are
cost-effective using the total resource cost test and
represent a diverse cross-section of opportunities for
customers of all rate classes to participate in the
programs.
(5.5) Include meaningful opportunities for third-party

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energy efficiency businesses to deliver energy savings.
(5.10) Ensure that the portfolio as a whole, including
the portion administered by the Department of Commerce and
Economic Opportunity and programs offered by third-party
energy service providers, include opportunities for a
diverse set of building types, including both program
offering tailored to the needs of specific building types
and opportunities to source energy efficiency savings from
building, including, but not limited to, hospitals, health
care facilities, long-term care facilities, units of local
government, school districts, park districts, cultural
institutions, museums, facilities licensed under the Child
Care Act of 1969, preschools, churches and houses of
worship, public universities, private colleges, community
college districts, and wastewater and drinking water
treatment plant agencies and operators.
(5.15) Demonstrate that the utility consulted with
interested stakeholders, including customer groups,
environmental advocates, Commission staff, the Illinois
Commission on Environmental Justice, and other entities
who have participated in Commission proceedings to
consider the approval of past energy efficiency plans under
this Section and that those entities concerns and input
have been taken into consideration during the development
of the proposed plan.
(5.20) Ensure that the portfolio maximizes the use of

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cost-effective measures with measure lives of 10 years or
greater.
(6) Include a proposed cost-recovery tariff mechanism
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.
Beginning in 2018, a participating utility, as defined in
Section 16-108.5, providing approved energy efficiency and
demand-response measures in the State shall recover the
costs of those measures as part of its performance-based
formula rate as provided in paragraph (1) of subsection (c)
of Section 16-108.5.
(7) Provide for an annual independent evaluation of the
performance of the cost-effectiveness of the utility's
portfolio of measures and the Department's portfolio of
measures, as well as a full review of the full multi-year
portfolio 3-year 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. The resources dedicated to evaluation shall
not exceed 3% of portfolio resources in any given year. The
evaluations shall be performed by independent experts that
are retained for this purpose by the Illinois Commerce
Commission.
(g) No more than 3% of energy efficiency and
demand-response program revenue may be allocated for research,

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development, or pilot deployment of new equipment or measures
demonstration of breakthrough equipment and devices.
(h) This Section does not apply to an electric utility that
on December 31, 2005 provided electric service to fewer than
100,000 customers in Illinois.
(i) If, after 2 years, an electric utility fails to meet
the efficiency standard specified in subsection (b) of this
Section, as modified by subsections (d) and (e), it shall make
a contribution to the Low-Income Home Energy Assistance
Program. The combined total liability for failure to meet the
goal shall be $1,000,000, which shall be assessed as follows: a
large electric utility shall pay $665,000, and a medium
electric utility shall pay $335,000. If, after 3 years, an
electric utility fails to meet the efficiency standard
specified in subsection (b) of this Section, as modified by
subsections (d) and (e), it shall make a contribution to the
Low-Income Home Energy Assistance Program. The combined total
liability for failure to meet the goal shall be $1,000,000,
which shall be assessed as follows: a large electric utility
shall pay $665,000, and a medium electric utility shall pay
$335,000. In addition, the responsibility for implementing the
energy efficiency measures of the utility making the payment
shall be transferred to the Illinois Power Agency if, after 3
years, or in any subsequent 3-year period, the utility fails to
meet the efficiency standard specified in subsection (b) of
this Section, as modified by subsections (d) and (e). The

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Agency shall implement a competitive procurement program to
procure resources necessary to meet the standards specified in
this Section as modified by subsections (d) and (e), with costs
for those resources to be recovered in the same manner as
products purchased through the procurement plan as provided in
Section 16-111.5. The Director shall implement this
requirement in connection with the procurement plan as provided
in Section 16-111.5.
For purposes of this Section, (i) a "large electric
utility" is an electric utility that, on December 31, 2005,
served more than 2,000,000 electric customers in Illinois; (ii)
a "medium electric utility" is an electric utility that, on
December 31, 2005, served 2,000,000 or fewer but more than
100,000 electric customers in Illinois; and (iii) Illinois
electric utilities that are affiliated by virtue of a common
parent company are considered a single electric utility.
(j) If, after 3 years, or any subsequent 3-year period, the
Department fails to implement the Department's share of energy
efficiency measures required by the standards in subsection
(b), then the Illinois Power Agency may assume responsibility
for and control of the Department's share of the required
energy efficiency measures. The Agency shall implement a
competitive procurement program to procure resources necessary
to meet the standards specified in this Section, with the costs
of these resources to be recovered in the same manner as
provided for the Department in this Section.

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(j-5) By June 1, 2016 and every 4 years thereafter, the
Department of Commerce and Economic Opportunity shall perform
and make publicly available a study assessing the job creation
impact of implementation of energy efficiency programs and
policies in Illinois. The Department shall seek input from
stakeholders in advance of conducting the study.
(j-10) For the purposes of conducting the energy efficiency
potential studies required in subsection (f) of this Section,
the Illinois Power Agency shall:
(1) base estimates of the portion of economic potential
that could be achieved on document experience of the most
successful programs in other jurisdictions in each of the
specific efficiency markets being analyzed;
(2) include impacts from emergence of new technologies
that can reasonably be expected to emerge after the study
is conducted but during the period covered by the study;
(3) account for potential for measure costs to decline
as volumes of sales increase;
(4) account for economies that could be achieved
through joint electric-gas program delivery or
coordination;
(5) include estimates of potential from behavioral
changes and process improvements (in addition to
technologies);
(6) include estimates of impacts from fuel-switching
measures; and

SB1485 - 111 - LRB099 06216 AMC 30867 b
(7) include estimates of impacts from either
supporting adoption of stricter building codes or
equipment standards or better compliance with existing
codes and standards.
(j-15) The Commission shall issue an order extending the
programs approved under subsection (f) of this Section for the
period beginning June 1, 2014 and ending May 31, 2017 so that
these programs continue to be offered until December 31, 2017.
The savings goals and budgets associated with these approved
programs shall be modified to ensure that the programs will
continue to operate and acquire additional savings during this
period and under the same cost-effectiveness requirements
applicable when the programs were approved.
(k) No electric utility shall be deemed to have failed to
meet the energy efficiency standards to the extent any such
failure is due to a failure of the Department or the Agency.
(l) In meeting the energy efficiency requirements of this
Section, to the extent feasible and consistent with State and
federal law, the energy efficiency credit procurements,
declining block solar program, and community solar 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.
(Source: P.A. 97-616, eff. 10-26-11; 97-841, eff. 7-20-12;

SB1485 - 112 - LRB099 06216 AMC 30867 b
98-90, eff. 7-15-13.)
(220 ILCS 5/8-104)
Sec. 8-104. Natural gas energy efficiency programs.
(a) It is the policy of the State that natural gas
utilities and the Department of Commerce and Economic
Opportunity are required to use cost-effective energy
efficiency to reduce direct and indirect costs to consumers. It
serves the public interest to allow natural gas utilities to
recover costs for reasonably and prudently incurred expenses
for cost-effective energy efficiency measures.
(b) For purposes of this Section, "energy efficiency" means
measures that reduce the amount of energy required to achieve a
given end use. "Energy efficiency" also includes measures that
reduce the total Btus of electricity and natural gas needed to
meet the end use or uses. "Cost-effective" means that the
measures satisfy the total resource cost test, which, for
purposes of this Section, has the meaning given to that term in
Section 1-10 of the Illinois Power Agency Act. means a standard
that is met if, for an investment in energy efficiency, 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 measures to the net present value of the total costs as
calculated over the lifetime of the measures. The total
resource cost test compares the sum of avoided natural gas
utility costs, representing the benefits that accrue to the

SB1485 - 113 - LRB099 06216 AMC 30867 b
system and the participant in the delivery of those efficiency
measures, as well as other quantifiable societal benefits,
including avoided electric utility costs, to the sum of all
incremental costs of end use measures (including both utility
and participant contributions), plus costs to administer,
deliver, and evaluate each demand-side measure, to quantify the
net savings obtained by substituting demand-side measures for
supply resources. In calculating avoided costs, reasonable
estimates shall be included for financial costs likely to be
imposed by future regulation of emissions of greenhouse gases.
The low-income programs described in item (4) of subsection (f)
of this Section shall not be required to meet the total
resource cost test.
(c) Natural gas utilities shall implement cost-effective
energy efficiency measures to meet at least the following
natural gas savings requirements, which shall be based upon the
total amount of gas delivered to retail customers, other than
the customers described in subsection (m) of this Section,
during calendar year 2009 multiplied by the applicable
percentage. Natural gas utilities may comply with this Section
by meeting the annual incremental savings goal in the
applicable year or by showing that total cumulative annual
savings within a 3-year planning period associated with
measures implemented after May 31, 2011 were equal to the sum
of each annual incremental savings requirement from May 31,
2011 through the end of the applicable year:

SB1485 - 114 - LRB099 06216 AMC 30867 b
(1) 0.2% by May 31, 2012;
(2) an additional 0.4% by May 31, 2013, increasing
total savings to .6%;
(3) an additional 0.6% by May 31, 2014, increasing
total savings to 1.2%;
(4) an additional 0.8% by May 31, 2015, increasing
total savings to 2.0%;
(5) an additional 1% by May 31, 2016, increasing total
savings to 3.0%;
(6) an additional 1.2% by May 31, 2017, increasing
total savings to 4.2%;
(7) an additional 1.4% by May 31, 2018, increasing
total savings to 5.6%;
(8) an additional 1.5% by May 31, 2019, increasing
total savings to 7.1%; and
(9) an additional 1.5% in each 12-month period
thereafter.
(d) Notwithstanding the requirements of subsection (c) of
this Section, a natural gas utility shall limit the amount of
energy efficiency implemented in any 3-year reporting period
established by subsection (f) of Section 8-104 of this Act, by
an amount necessary to limit the estimated average increase in
the amounts paid by retail customers in connection with natural
gas service to no more than 2% in the applicable 3-year
reporting period. The energy savings requirements in
subsection (c) of this Section may be reduced by the Commission

SB1485 - 115 - LRB099 06216 AMC 30867 b
for the subject plan, if the utility demonstrates by
substantial evidence that it is highly unlikely that the
requirements could be achieved without exceeding the
applicable spending limits in any 3-year reporting period. No
later than September 1, 2013, the Commission shall review the
limitation on the amount of energy efficiency measures
implemented pursuant to this Section and report to the General
Assembly, in the report required by subsection (k) of this
Section, its findings as to whether that limitation unduly
constrains the procurement of energy efficiency measures.
(e) Natural gas utilities shall be responsible for
overseeing the design, development, and filing of their
efficiency plans with the Commission. The utility shall utilize
75% of the available funding associated with energy efficiency
programs approved by the Commission, and may outsource various
aspects of program development and implementation. The
remaining 25% of available funding shall be used by the
Department of Commerce and Economic Opportunity to implement
energy efficiency measures that achieve no less than 20% of the
requirements of subsection (c) of this Section. Such measures
shall be designed in conjunction with the utility and approved
by the Commission. The Department may outsource development and
implementation of energy efficiency measures. A minimum of 10%
of the entire portfolio of cost-effective energy efficiency
measures shall be procured from local government, municipal
corporations, school districts, and community college

SB1485 - 116 - LRB099 06216 AMC 30867 b
districts. Five percent of the entire portfolio of
cost-effective energy efficiency measures may be granted to
local government and municipal corporations for market
transformation initiatives. The Department shall coordinate
the implementation of these measures and shall integrate
delivery of natural gas efficiency programs with electric
efficiency programs delivered pursuant to Section 8-103 of this
Act, unless the Department can show that integration is not
feasible.
The apportionment of the dollars to cover the costs to
implement the Department's share of the portfolio of energy
efficiency measures shall be made to the Department once the
Department has executed rebate agreements, grants, or
contracts for energy efficiency measures and provided
supporting documentation for those rebate agreements, grants,
and contracts to the utility. The Department is authorized to
adopt any rules necessary and prescribe procedures in order to
ensure compliance by applicants in carrying out the purposes of
rebate agreements for energy efficiency measures implemented
by the Department made under this Section.
The details of the measures implemented by the Department
shall be submitted by the Department to the Commission in
connection with the utility's filing regarding the energy
efficiency measures that the utility implements.
A utility providing approved energy efficiency measures in
this State shall be permitted to recover costs of those

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measures 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 and
shall be applicable to the utility's customers other than the
customers described in subsection (m) of this Section. 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.
Each utility shall include, in its recovery of costs, the
costs estimated for both the utility's and the Department's
implementation of energy efficiency measures. Costs collected
by the utility for measures implemented by the Department shall
be submitted to the Department pursuant to Section 605-323 of
the Civil Administrative Code of Illinois, shall be deposited
into the Energy Efficiency Portfolio Standards Fund, and shall
be used by the Department solely for the purpose of
implementing these measures. A utility shall not be required to
advance any moneys to the Department but only to forward such
funds as it has collected. The Department shall report to the
Commission on an annual basis regarding the costs actually
incurred by the Department in the implementation of the
measures. Any changes to the costs of energy efficiency
measures as a result of plan modifications shall be
appropriately reflected in amounts recovered by the utility and
turned over to the Department.

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The portfolio of measures, administered by both the
utilities and the Department, shall, in combination, be
designed to achieve the annual energy savings requirements set
forth in subsection (c) of this Section, as modified by
subsection (d) of this Section.
The utility and the Department shall agree upon a
reasonable portfolio of measures and determine the measurable
corresponding percentage of the savings goals associated with
measures implemented by the Department.
No utility shall be assessed a penalty under subsection (f)
of this Section for failure to make a timely filing if that
failure is the result of a lack of agreement with the
Department with respect to the allocation of responsibilities
or related costs or target assignments. In that case, the
Department and the utility shall file their respective plans
with the Commission and the Commission shall determine an
appropriate division of measures and programs that meets the
requirements of this Section.
If the Department is unable to meet performance
requirements for the portion of the portfolio implemented by
the Department, then the utility and the Department shall
jointly submit a modified filing to the Commission explaining
the performance shortfall and recommending an appropriate
course going forward, including any program modifications that
may be appropriate in light of the evaluations conducted under
item (8) of subsection (f) of this Section. In this case, the

SB1485 - 119 - LRB099 06216 AMC 30867 b
utility obligation to collect the Department's costs and turn
over those funds to the Department under this subsection (e)
shall continue only if the Commission approves the
modifications to the plan proposed by the Department.
(f) No later than October 1, 2010, each gas utility shall
file an energy efficiency plan with the Commission to meet the
energy efficiency standards through May 31, 2014. Every 3 years
thereafter, each utility shall file, no later than October 1,
an energy efficiency plan with the Commission, except that for
plans covering 2018 through 2025, each gas utility shall file
plans on the same schedule as is required for the electric
utilities under subsection (f) of Section 8-103 of this Act. If
a utility does not file such a plan by the statutory deadline
described in this Section October 1 of the applicable year,
then it shall face a penalty of $100,000 per day until the plan
is filed. Each utility's plan shall set forth the utility's
proposals to meet the utility's portion of the energy
efficiency standards identified in subsection (c) of this
Section, as modified by subsection (d) of this Section, taking
into account the unique circumstances of the utility's service
territory. The Commission shall seek public comment on the
utility's plan and shall issue an order approving or
disapproving each plan. 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

SB1485 - 120 - LRB099 06216 AMC 30867 b
Commission's concerns satisfactorily. If the utility does not
refile with the Commission within 60 days after the
disapproval, 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
measures. Penalties shall be deposited into the Energy
Efficiency Trust Fund and the cost of any such penalties may
not be recovered from ratepayers. In submitting proposed energy
efficiency plans and funding levels to meet the savings goals
adopted by this Act the utility shall:
(1) Demonstrate that its proposed energy efficiency
measures will achieve the requirements that are identified
in subsection (c) of this Section, as modified by
subsection (d) of this Section.
(2) Present specific proposals to implement new
building and appliance standards that have been placed into
effect.
(3) Present estimates of the total amount paid for gas
service expressed on a per therm basis associated with the
proposed portfolio of measures designed to meet the
requirements that are identified in subsection (c) of this
Section, as modified by subsection (d) of this Section.
(4) Coordinate with the Department to present a
portfolio of energy efficiency measures proportionate to
the share of total annual utility revenues in Illinois from

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households at or below 150% of the poverty level. Such
programs shall be targeted to households with incomes at or
below 80% of area median income.
(5) Demonstrate that its overall portfolio of energy
efficiency measures, not including programs covered by
item (4) of this subsection (f), are cost-effective using
the total resource cost test and represent a diverse cross
section of opportunities for customers of all rate classes
to participate in the programs.
(6) Demonstrate that a gas utility affiliated with an
electric utility that is required to comply with Section
8-103 of this Act has integrated gas and electric
efficiency measures into a single program that reduces
program or participant costs and appropriately allocates
costs to gas and electric ratepayers. The Department shall
integrate all gas and electric programs it delivers in any
such utilities' service territories, unless the Department
can show that integration is not feasible or appropriate.
(7) Include a proposed cost recovery tariff mechanism
to fund the proposed energy efficiency measures and to
ensure the recovery of the prudently and reasonably
incurred costs of Commission-approved programs.
(8) Provide for quarterly status reports tracking
implementation of and expenditures for the utility's
portfolio of measures and the Department's portfolio of
measures, an annual independent review, and a full

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independent evaluation of the 3-year results of the
performance and the cost-effectiveness of the utility's
and Department's portfolios of measures and 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. The resources dedicated to
evaluation shall not exceed 3% of portfolio resources in
any given 3-year period.
(g) No more than 3% of expenditures on energy efficiency
measures may be allocated for demonstration of breakthrough
equipment and devices.
(h) Illinois natural gas utilities that are affiliated by
virtue of a common parent company may, at the utilities'
request, be considered a single natural gas utility for
purposes of complying with this Section.
(i) If, after 3 years, a gas utility fails to meet the
efficiency standard specified in subsection (c) of this Section
as modified by subsection (d), then it shall make a
contribution to the Low-Income Home Energy Assistance Program.
The total liability for failure to meet the goal shall be
assessed as follows:
(1) a large gas utility shall pay $600,000;
(2) a medium gas utility shall pay $400,000; and
(3) a small gas utility shall pay $200,000.
For purposes of this Section, (i) a "large gas utility" is
a gas utility that on December 31, 2008, served more than

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1,500,000 gas customers in Illinois; (ii) a "medium gas
utility" is a gas utility that on December 31, 2008, served
fewer than 1,500,000, but more than 500,000 gas customers in
Illinois; and (iii) a "small gas utility" is a gas utility that
on December 31, 2008, served fewer than 500,000 and more than
100,000 gas customers in Illinois. The costs of this
contribution may not be recovered from ratepayers.
If a gas utility fails to meet the efficiency standard
specified in subsection (c) of this Section, as modified by
subsection (d) of this Section, in any 2 consecutive 3-year
planning periods, then the responsibility for implementing the
utility's energy efficiency measures shall be transferred to an
independent program administrator selected by the Commission.
Reasonable and prudent costs incurred by the independent
program administrator to meet the efficiency standard
specified in subsection (c) of this Section, as modified by
subsection (d) of this Section, may be recovered from the
customers of the affected gas utilities, other than customers
described in subsection (m) of this Section. The utility shall
provide the independent program administrator with all
information and assistance necessary to perform the program
administrator's duties including but not limited to customer,
account, and energy usage data, and shall allow the program
administrator to include inserts in customer bills. The utility
may recover reasonable costs associated with any such
assistance.

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(j) No utility shall be deemed to have failed to meet the
energy efficiency standards to the extent any such failure is
due to a failure of the Department.
(k) Not later than January 1, 2012, the Commission shall
develop and solicit public comment on a plan to foster
statewide coordination and consistency between statutorily
mandated natural gas and electric energy efficiency programs to
reduce program or participant costs or to improve program
performance. Not later than September 1, 2013, the Commission
shall issue a report to the General Assembly containing its
findings and recommendations.
(l) This Section does not apply to a gas utility that on
January 1, 2009, provided gas service to fewer than 100,000
customers in Illinois.
(m) Subsections (a) through (k) of this Section do not
apply to customers of a natural gas utility that have a North
American Industry Classification System code number that is
22111 or any such code number beginning with the digits 31, 32,
or 33 and (i) annual usage in the aggregate of 4 million therms
or more within the service territory of the affected gas
utility or with aggregate usage of 8 million therms or more in
this State and complying with the provisions of item (l) of
this subsection (m); or (ii) using natural gas as feedstock and
meeting the usage requirements described in item (i) of this
subsection (m), to the extent such annual feedstock usage is
greater than 60% of the customer's total annual usage of

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natural gas.
(1) Customers described in this subsection (m) of this
Section shall apply, on a form approved on or before
October 1, 2009 by the Department, to the Department to be
designated as a self-directing customer ("SDC") or as an
exempt customer using natural gas as a feedstock from which
other products are made, including, but not limited to,
feedstock for a hydrogen plant, on or before the 1st day of
February, 2010. Thereafter, application may be made not
less than 6 months before the filing date of the gas
utility energy efficiency plan described in subsection (f)
of this Section; however, a new customer that commences
taking service from a natural gas utility after February 1,
2010 may apply to become a SDC or exempt customer up to 30
days after beginning service. Customers described in this
subsection (m) that have not already been approved by the
Department may apply to be designated a self-directing
customer or exempt customer, on a form approved by the
Department, between September 1, 2013 and September 30,
2013. Customer applications that are approved by the
Department under this amendatory Act of the 98th General
Assembly shall be considered to be a self-directing
customer or exempt customer, as applicable, for the current
3-year planning period effective December 1, 2013. Such
application shall contain the following:
(A) the customer's certification that, at the time

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of its application, it qualifies to be a SDC or exempt
customer described in this subsection (m) of this
Section;
(B) in the case of a SDC, the customer's
certification that it has established or will
establish by the beginning of the utility's 3-year
planning period commencing subsequent to the
application, and will maintain for accounting
purposes, an energy efficiency reserve account and
that the customer will accrue funds in said account to
be held for the purpose of funding, in whole or in
part, energy efficiency measures of the customer's
choosing, which may include, but are not limited to,
projects involving combined heat and power systems
that use the same energy source both for the generation
of electrical or mechanical power and the production of
steam or another form of useful thermal energy or the
use of combustible gas produced from biomass, or both;
(C) in the case of a SDC, the customer's
certification that annual funding levels for the
energy efficiency reserve account will be equal to 2%
of the customer's cost of natural gas, composed of the
customer's commodity cost and the delivery service
charges paid to the gas utility, or $150,000, whichever
is less;
(D) in the case of a SDC, the customer's

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certification that the required reserve account
balance will be capped at 3 years' worth of accruals
and that the customer may, at its option, make further
deposits to the account to the extent such deposit
would increase the reserve account balance above the
designated cap level;
(E) in the case of a SDC, the customer's
certification that by October 1 of each year, beginning
no sooner than October 1, 2012, the customer will
report to the Department information, for the 12-month
period ending May 31 of the same year, on all deposits
and reductions, if any, to the reserve account during
the reporting year, and to the extent deposits to the
reserve account in any year are in an amount less than
$150,000, the basis for such reduced deposits; reserve
account balances by month; a description of energy
efficiency measures undertaken by the customer and
paid for in whole or in part with funds from the
reserve account; an estimate of the energy saved, or to
be saved, by the measure; and that the report shall
include a verification by an officer or plant manager
of the customer or by a registered professional
engineer or certified energy efficiency trade
professional that the funds withdrawn from the reserve
account were used for the energy efficiency measures;
(F) in the case of an exempt customer, the

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customer's certification of the level of gas usage as
feedstock in the customer's operation in a typical year
and that it will provide information establishing this
level, upon request of the Department;
(G) in the case of either an exempt customer or a
SDC, the customer's certification that it has provided
the gas utility or utilities serving the customer with
a copy of the application as filed with the Department;
(H) in the case of either an exempt customer or a
SDC, certification of the natural gas utility or
utilities serving the customer in Illinois including
the natural gas utility accounts that are the subject
of the application; and
(I) in the case of either an exempt customer or a
SDC, a verification signed by a plant manager or an
authorized corporate officer attesting to the
truthfulness and accuracy of the information contained
in the application.
(2) The Department shall review the application to
determine that it contains the information described in
provisions (A) through (I) of item (1) of this subsection
(m), as applicable. The review shall be completed within 30
days after the date the application is filed with the
Department. Absent a determination by the Department
within the 30-day period, the applicant shall be considered
to be a SDC or exempt customer, as applicable, for all

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subsequent 3-year planning periods, as of the date of
filing the application described in this subsection (m). If
the Department determines that the application does not
contain the applicable information described in provisions
(A) through (I) of item (1) of this subsection (m), it
shall notify the customer, in writing, of its determination
that the application does not contain the required
information and identify the information that is missing,
and the customer shall provide the missing information
within 15 working days after the date of receipt of the
Department's notification.
(3) The Department shall have the right to audit the
information provided in the customer's application and
annual reports to ensure continued compliance with the
requirements of this subsection. Based on the audit, if the
Department determines the customer is no longer in
compliance with the requirements of items (A) through (I)
of item (1) of this subsection (m), as applicable, the
Department shall notify the customer in writing of the
noncompliance. The customer shall have 30 days to establish
its compliance, and failing to do so, may have its status
as a SDC or exempt customer revoked by the Department. The
Department shall treat all information provided by any
customer seeking SDC status or exemption from the
provisions of this Section as strictly confidential.
(4) Upon request, or on its own motion, the Commission

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may open an investigation, no more than once every 3 years
and not before October 1, 2014, to evaluate the
effectiveness of the self-directing program described in
this subsection (m).
Customers described in this subsection (m) that applied to
the Department on January 3, 2013, were approved by the
Department on February 13, 2013 to be a self-directing customer
or exempt customer, and receive natural gas from a utility that
provides gas service to at least 500,000 retail customers in
Illinois and electric service to at least 1,000,000 retail
customers in Illinois shall be considered to be a
self-directing customer or exempt customer, as applicable, for
the current 3-year planning period effective December 1, 2013.
(n) The applicability of this Section to customers
described in subsection (m) of this Section is conditioned on
the existence of the SDC program. In no event will any
provision of this Section apply to such customers after January
1, 2020.
(Source: P.A. 97-813, eff. 7-13-12; 97-841, eff. 7-20-12;
98-90, eff. 7-15-13; 98-225, eff. 8-9-13; 98-604, eff.
12-17-13.)
(220 ILCS 5/16-107)
Sec. 16-107. Real-time pricing.
(a) Each electric utility shall file, on or before May 1,
1998, a tariff or tariffs which allow nonresidential retail

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customers in the electric utility's service area to elect
real-time pricing beginning October 1, 1998.
(b) Each electric utility shall file, on or before May 1,
2000, a tariff or tariffs which allow residential retail
customers in the electric utility's service area to elect
real-time pricing beginning October 1, 2000.
(b-5) Each electric utility shall file a tariff or tariffs
allowing residential retail customers in the electric
utility's service area to elect real-time pricing beginning
January 2, 2007. A customer who elects real-time pricing shall
remain on such rate for a minimum of 12 months. The Commission
may, after notice and hearing, approve the tariff or tariffs,
provided that the Commission finds that the potential for
demand reductions will result in net economic benefits to all
residential customers of the electric utility. In examining
economic benefits from demand reductions, the Commission
shall, at a minimum, consider the following: improvements to
system reliability and power quality, reduction in wholesale
market prices and price volatility, electric utility cost
avoidance and reductions, market power mitigation, and other
benefits of demand reductions, but only to the extent that the
effects of reduced demand can be demonstrated to lower the cost
of electricity delivered to residential customers. A tariff or
tariffs approved pursuant to this subsection (b-5) shall, at a
minimum, describe (i) the methodology for determining the
market price of energy to be reflected in the real-time rate

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and (ii) the manner in which customers who elect real-time
pricing will be provided with ready access to hourly market
prices, including, but not limited to, day-ahead hourly energy
prices.
A proceeding under this subsection (b-5) may not exceed 120
days in length.
(b-10) Each electric utility providing real-time pricing
pursuant to subsection (b-5) shall install a meter capable of
recording hourly interval energy use at the service location of
each customer that elects real-time pricing pursuant to this
subsection.
(b-15) If the Commission issues an order pursuant to
subsection (b-5), the affected electric utility shall contract
with an entity not affiliated with the electric utility to
serve as a program administrator to develop and implement a
program to provide consumer outreach, enrollment, and
education concerning real-time pricing and to establish and
administer an information system and technical and other
customer assistance that is necessary to enable customers to
manage electricity use. The program administrator: (i) shall be
selected and compensated by the electric utility, subject to
Commission approval; (ii) shall have demonstrated technical
and managerial competence in the development and
administration of demand management programs; and (iii) may
develop and implement risk management, energy efficiency, and
other services related to energy use management for which the

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program administrator shall be compensated by participants in
the program receiving such services. The electric utility shall
provide the program administrator with all information and
assistance necessary to perform the program administrator's
duties, including, but not limited to, customer, account, and
energy use data. The electric utility shall permit the program
administrator to include inserts in residential customer bills
2 times per year to assist with customer outreach and
enrollment.
The program administrator shall submit an annual report to
the electric utility no later than April 1 of each year
describing the operation and results of the program, including
information concerning the number and types of customers using
real-time pricing, changes in customers' energy use patterns,
an assessment of the value of the program to both participants
and non-participants, and recommendations concerning
modification of the program and the tariff or tariffs filed
under subsection (b-5). This report shall be filed by the
electric utility with the Commission within 30 days of receipt
and shall be available to the public on the Commission's web
site.
(b-20) The Commission shall monitor the performance of
programs established pursuant to subsection (b-15) and shall
order the termination or modification of a program if it
determines that the program is not, after a reasonable period
of time for development not to exceed 4 years, resulting in net

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benefits to the residential customers of the electric utility.
(b-25) An electric utility shall be entitled to recover
reasonable costs incurred in complying with this Section,
provided that recovery of the costs is fairly apportioned among
its residential customers as provided in this subsection
(b-25). The electric utility may apportion greater costs on the
residential customers who elect real-time pricing, but may also
impose some of the costs of real-time pricing on customers who
do not elect real-time pricing, provided that the Commission
determines that the cost savings resulting from real-time
pricing will exceed the costs imposed on customers for
maintaining the program.
(c) The electric utility's tariff or tariffs filed pursuant
to this Section shall be subject to Article IX.
(d) This Section does not apply to any electric utility
providing service to 100,000 or fewer customers.
(Source: P.A. 94-977, eff. 6-30-06.)
(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

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

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and a labor union that existed on the effective date of this
amendatory Act of the 97th General Assembly 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 the effective date of
this amendatory Act of the 97th General Assembly. 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 the
effective date of this amendatory Act of the 97th General
Assembly, 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

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totaling an estimated $1,000,000,000, including
underground residential distribution cable
injection and replacement and mainline cable
system refurbishment and replacement projects;
(ii) training facility construction or upgrade
projects totaling an estimated $10,000,000,
provided that, at a minimum, one such facility
shall be located in a municipality having a
population of more than 2 million residents and one
such facility shall be located in a municipality
having a population of more than 150,000 residents
but fewer than 170,000 residents; any such new
facility located in a municipality having a
population of more than 2 million residents must be
designed for the purpose of obtaining, and the
owner of the facility shall apply for,
certification under the United States Green
Building Council's Leadership in Energy Efficiency
Design Green Building Rating System;
(iii) wood pole inspection, treatment, and
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,

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

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January 1, 2012 if such utility files such
performance-based formula rate tariff within 14 days of the
effective date of this amendatory Act of the 97th General
Assembly, the participating utility shall, except as
provided in subsection (b-5):
(A) over a 10-year period, invest an estimated
$265,000,000 in electric system upgrades,
modernization projects, and training facilities,
including, but not limited to:
(i) distribution infrastructure improvements
totaling an estimated $245,000,000, which may
include bulk supply substations, transformers,
reconductoring, and rebuilding overhead
distribution and sub-transmission lines,
underground residential distribution cable
injection and replacement and mainline cable
system refurbishment and replacement projects;
(ii) training facility construction or upgrade
projects totaling an estimated $1,000,000; any
such new facility must be designed for the purpose
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

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replacement programs; and
(B) over a 10-year period, invest an estimated
$360,000,000 to upgrade and modernize its transmission
and distribution infrastructure and in Smart Grid
electric system upgrades, including, but not limited
to:
(i) additional smart meters;
(ii) distribution automation;
(iii) associated cyber secure data
communication network; and
(iv) substation micro-processor relay
upgrades.
For purposes of this Section, "Smart Grid electric system
upgrades" shall have the meaning set forth in subsection (a) of
Section 16-108.6 of this Act.
The investments in the infrastructure investment program
described in this subsection (b) shall be incremental to the
participating utility's annual capital investment program, as
defined by, for purposes of this subsection (b), the
participating utility's average capital spend for calendar
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

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reasonable construction ramp-up and ramp-down time to the
investment periods specified in this subsection (b). For each
such investment period, the ramp-up and ramp-down time shall
not exceed a total of 6 months.
Within 60 days after filing a tariff under subsection (c)
of this Section, a participating utility shall submit to the
Commission its plan, including scope, schedule, and staffing,
for satisfying its infrastructure investment program
commitments pursuant to this subsection (b). The submitted plan
shall include a schedule and staffing plan for the next
calendar year. The plan shall also include a plan for the
creation, operation, and administration of a Smart Grid test
bed as described in subsection (c) of Section 16-108.8. The
plan need not allocate the work equally over the respective
periods, but should allocate material increments throughout
such periods commensurate with the work to be undertaken. No
later than April 1 of each subsequent year, the utility shall
submit to the Commission a report that includes any updates to
the plan, a schedule for the next calendar year, the
expenditures made for the prior calendar year and 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

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

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

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obligations under this subsection (b) shall immediately
terminate, except for the utility's obligation to pay an amount
already owed to the fund for training grants pursuant to a
Commission order.
In meeting the obligations of this subsection (b), to the
extent feasible and consistent with State and federal law, the
investments under the infrastructure investment program should
provide employment opportunities for all segments of the
population and workforce, including minority-owned and
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

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this Section, then the utility may file a petition with the
Commission requesting that it be permitted to satisfy its
commitments by spending less than the estimated amounts
specified in subsection (b) of this Section. The Commission
shall, after notice and hearing, enter its order approving, or
approving as modified, or denying each such petition within 150
days after the filing of the petition.
In no event, absent General Assembly approval, shall the
capital investment costs incurred by a participating utility
other than a combination utility in satisfying its
infrastructure investment program commitments described in
subsection (b) of this Section exceed $3,000,000,000 or, for a
participating utility that is a combination utility,
$720,000,000. If the participating utility's updated cost
estimates for satisfying its infrastructure investment program
commitments described in subsection (b) of this Section exceed
the limitation imposed by this subsection (b-5), then it shall
submit a report to the Commission that identifies the increased
costs and explains the reason or reasons for the 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

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not to exceed the limitation imposed by this subsection (b-5)
and may propose corresponding changes to the metrics
established pursuant to subparagraphs (5) through (8) of
subsection (f) of this Section, and the Commission may modify
the metrics and incremental savings goals established pursuant
to subsection (f) of this Section accordingly.
(b-10) All participating utilities shall make
contributions for an energy low-income and support program in
accordance with this subsection. Beginning no later than 180
days after a participating utility files a performance-based
formula rate tariff pursuant to subsection (c) of this Section,
or beginning no later than January 1, 2012 if such utility
files such performance-based formula rate tariff within 14 days
of the effective date of this amendatory Act of the 97th
General Assembly, 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

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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 disabled veterans who demonstrate a
hardship and members of the armed services or reserve
forces of the United States or members of the Illinois
National Guard who are on active duty pursuant to an
executive order of the President of the United States, an
act of the Congress of the United States, or an order of
the Governor and who demonstrate a hardship;
(3) a budget assistance program that provides tools and
education to low-income senior citizens to assist them with
obtaining information regarding energy usage and effective
means of managing energy costs;
(4) a non-residential special hardship program that
provides grants to non-residential customers such as small
businesses and non-profit organizations that demonstrate a
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

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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 shall 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
effective date of this amendatory Act of the 97th General
Assembly. 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.
(c) A participating utility shall may elect to recover its
delivery services costs through a performance-based formula

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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 the effective date of this amendatory Act of
the 97th General Assembly, 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 the
effective date of this amendatory Act of the 97th General
Assembly, 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 the effective date of this amendatory
Act of the 97th General Assembly, the participating utility
shall, at the time it files its performance-based formula rate
tariff with the Commission, also file a notice of withdrawal
with the Commission to withdraw the electric delivery services
tariffs previously filed pursuant to Section 9-201 of this Act.
Upon receipt of such notice, the Commission shall dismiss with
prejudice any docket that had been initiated to investigate the

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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
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

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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.
(3) Include a cost of equity, which shall be calculated
as the sum of the following:
(A) the average for the applicable calendar year of
the monthly average yields of 30-year U.S. Treasury
bonds published by the Board of Governors of the
Federal Reserve System in its weekly H.15 Statistical
Release or successor publication; and
(B) 580 basis points.
At such time as the Board of Governors of the Federal
Reserve System ceases to include the monthly average yields
of 30-year U.S. Treasury bonds in its weekly H.15
Statistical Release or successor publication, the monthly
average yields of the U.S. Treasury bonds then having the
longest duration published by the Board of Governors in its
weekly H.15 Statistical Release or successor publication
shall instead be used for purposes of this paragraph (3).
(4) Permit and set forth protocols, subject to a
determination of prudence and reasonableness consistent
with Commission practice and law, for the following:
(A) recovery of incentive compensation expense

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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
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

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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
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

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interpretation or application thereof by any
governmental authority occurring after the effective
date of this amendatory Act of the 97th General
Assembly;
(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
adjusting for any penalties to the rate of return on common
equity applied pursuant to the performance metrics
provision of subsection (f) of this Section), 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

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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) of this Section) 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
provision of subsection (f) of this Section), 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

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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) of this Section) 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
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

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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 the effective date of this amendatory Act
of the 97th General Assembly, then by May 31, 2012. Such review
shall be based on the same evidentiary standards, including,
but not limited to, those concerning the prudence and
reasonableness of the costs incurred by the utility, the
Commission applies in a hearing to review a filing for a
general increase in rates under Article IX of this Act. The
initial rates shall take effect within 30 days after the
Commission's order approving the performance-based formula
rate tariff.
Until such time as the Commission approves a different rate
design and cost allocation pursuant to subsection (e) of this
Section, rate design and cost allocation across customer
classes shall be consistent with the Commission's most recent
order regarding the participating utility's request for a
general increase in its delivery services rates.
Subsequent changes to the performance-based formula rate

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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
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

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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
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

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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
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

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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).
(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

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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
enforced by the Commission or the assigned hearing examiner.
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

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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
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

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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
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

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

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

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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.
(10) Achieving cost-effective energy efficiency
savings consistent with Section 8-103 of this Act. By
January 1, 2018, each participating utility shall file with
the Commission a proposed set of performance metrics
designed to align financial rewards with the utility's
performance relative to the goal provided in Section 8-103
of this Act.
(11) Improve load shape by achieving a 20% reduction in
peak load by January 1, 2025 as compared to the baseline
year of 2009 through annual incremental reductions.
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

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such calculation for each year, and provided further that the
participating utility shall exclude 9 extreme weather event
days when calculating each year of the baseline period to the
extent that there are 9 such days in a given year of the
baseline period. For purposes of this Section, an extreme
weather event day is a 24-hour calendar day (beginning at 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

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date on which the Commission enters its order approving the
utility's Advanced Metering Infrastructure Deployment Plan
pursuant to subsection (c) of Section 16-108.6 of this Act.
The metrics and performance goals set forth in
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

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subsection (f) of this Section,
(A) for each year that a participating utility
other than a combination utility does not achieve the
annual goal, the participating utility's return on
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

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that a participating utility other than a combination
utility does not achieve both such goals, the participating
utility's return on equity shall be reduced as follows:
during years 1 through 3, by 5 basis points; 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

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implementation of the Advanced Metering Infrastructure
Deployment Plan, as defined in Section 16-108.6 of this
Act, the performance under each such goal shall be
calculated in terms of the percentage of the goal 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)

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of this Section. On June 1 of each subsequent year, each
participating utility shall file a report with the Commission
that includes, among other things, a description of how the
participating utility performed under each metric and 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.
(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

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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
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.

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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
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
the effective date of this amendatory Act of the 97th General
Assembly. 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) Sections 16-108.5, 16-108.6, 16-108.7, and 16-108.8 of
this Act, other than this subsection, are inoperative after
December 31, 2017 for every participating utility, after which
time a participating 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

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to retroactive adjustment, with interest, to reconcile rates
charged with actual costs.
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.
In the event Sections 16-108.5, 16-108.6, 16-108.7, and
16-108.8 of this Act do not become inoperative after December
31, 2017, then these Sections are inoperative after December
31, 2022 for every participating utility, after which time a
participating utility shall no longer be eligible to annually
update the performance-based formula rate tariff pursuant to
subsection (d) of this Section. At such time, the then current
rates shall remain in effect until such time as new rates are
set pursuant to Article IX of this Act, subject to retroactive
adjustment, with interest, to reconcile rates charged with
actual costs.
The fact that this Section becomes inoperative as set forth
in this subsection shall not be construed to mean that the

SB1485 - 177 - LRB099 06216 AMC 30867 b
Commission may reexamine or otherwise reopen prudence or
reasonableness determinations already made. The fact that this
Section becomes inoperative, as set forth in this Section,
shall not eliminate a utility's obligations under Section 8-103
of this Act.
(i) While a participating utility may use, develop, and
maintain broadband systems and the delivery of broadband
services, voice-over-internet-protocol services,
telecommunications services, and cable and video programming
services for use in providing delivery services and Smart Grid
functionality or application to its retail customers,
including, but not limited to, the installation,
implementation and maintenance of Smart Grid electric system
upgrades as defined in Section 16-108.6 of this Act, a
participating utility is prohibited from offering to its retail
customers broadband services or the delivery of broadband
services, voice-over-internet-protocol services,
telecommunications services, or cable or video programming
services, unless they are part of a service directly related to
delivery services or Smart Grid functionality or applications
as defined in Section 16-108.6 of this Act, and from recovering
the costs of such offerings from retail customers.
(j) Nothing in this Section is intended to legislatively
overturn the opinion issued in Commonwealth Edison Co. v. Ill.
Commerce Comm'n, Nos. 2-08-0959, 2-08-1037, 2-08-1137,
1-08-3008, 1-08-3030, 1-08-3054, 1-08-3313 cons. (Ill. App.

SB1485 - 178 - LRB099 06216 AMC 30867 b
Ct. 2d Dist. Sept. 30, 2010). This amendatory Act of the 97th
General Assembly 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 this amendatory Act of the 98th General Assembly are
intended to be a restatement and clarification of existing law,
and intended to give binding effect to the provisions of House
Resolution 1157 adopted by the House of Representatives of the
97th General Assembly and Senate Resolution 821 adopted by the
Senate of the 97th General Assembly that are reflected in
paragraph (3) of this subsection. In addition, this amendatory
Act of the 98th General Assembly 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 the effective
date of this amendatory Act of the 98th General Assembly,
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 this amendatory
Act of the 98th General Assembly 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

SB1485 - 179 - LRB099 06216 AMC 30867 b
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
this amendatory Act of the 98th General Assembly. 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 this
amendatory Act of the 98th General Assembly: paragraph (2)

SB1485 - 180 - LRB099 06216 AMC 30867 b
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
this amendatory Act of the 98th General Assembly.
(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
the effective date of this amendatory Act of the 98th General
Assembly. 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

SB1485 - 181 - LRB099 06216 AMC 30867 b
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:
(1) if this amendatory Act of the 98th General Assembly
takes effect on or before June 15, 2013, 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 the effective date of this
amendatory Act of the 98th General Assembly, then the
order entered in such proceeding shall, after notice
and hearing, accelerate the commencement of the meter
deployment schedule approved in the final Commission
order on rehearing entered in Docket No. 12-0298;
(B) if the Commission has entered an order pursuant
to subsection (e) of Section 16-108.6 of this Act prior
to the effective date of this amendatory Act of the
98th General Assembly 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

SB1485 - 182 - LRB099 06216 AMC 30867 b
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 the effective date of
this amendatory Act of the 98th General Assembly, then
the utility shall file with the Commission, within 45
days after such effective date, a plan for accelerating
the commencement of the utility's meter deployment
schedule approved in the final Commission order on
rehearing entered in Docket No. 12-0298 and the
Commission shall, after notice and hearing, approve or
approve as modified such plan within 90 days after the
utility's filing;
(2) if this amendatory Act of the 98th General Assembly
takes effect after June 15, 2013, then each participating
utility other than a combination 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

SB1485 - 183 - LRB099 06216 AMC 30867 b
Commission shall reopen the most recent proceeding in which
it entered an order pursuant to subsection (e) of Section
16-108.6 of this Act and within 90 days after the utility's
filing shall, after notice and hearing, enter an amendatory
order that approves or approves as modified such
accelerated plan, provided that if there was no such prior
proceeding the Commission shall open a new proceeding and
within 90 days after the utility's filing shall, after
notice and hearing, enter an order that approves or
approves as modified such accelerated plan.
Any schedule for meter deployment approved by the
Commission pursuant to subparagraphs (1) or (2) of this
subsection (l) shall take into consideration procurement times
for meters and other equipment and operational issues. Nothing
in this amendatory Act of the 98th General Assembly 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 this amendatory Act of the 98th
General Assembly are severable under Section 1.31 of the
Statute on Statutes.
(Source: P.A. 97-616, eff. 10-26-11; 97-646, eff. 12-30-11;
98-15, eff. 5-22-13.)

SB1485 - 184 - LRB099 06216 AMC 30867 b
(220 ILCS 5/16-108.8)
Sec. 16-108.8. Illinois Smart Grid test bed.
(a) Within 180 days after the effective date of this
amendatory Act of the 97th General Assembly, each participating
utility, as defined by Section 16-108.5 of this Act, shall
create or otherwise designate a Smart Grid test bed, which may
be located at one or more places within the utility's system,
for the purposes of allowing for the testing of Smart Grid
technologies. The objectives of this test bed shall be to:
(1) provide an open, unbiased opportunity for testing
programs, technologies, business models, and other Smart
Grid-related activities;
(2) provide on-grid locations for the testing of
potentially innovative Smart Grid-related technologies and
services, including but not limited to those funded by the
trust or foundation established pursuant to Section
16-108.7 of this Act;
(3) facilitate testing of business models or services
that help integrate Smart Grid-related technologies into
the electric grid, especially those business models that
may help promote new products and services for retail
customers;
(4) offer opportunities to test and showcase Smart Grid
technologies and services, especially those likely to
support the economic development goals of the State of

SB1485 - 185 - LRB099 06216 AMC 30867 b
Illinois.
(b) The test bed shall reside in one or more locations on
the participating utility's network. Such locations shall be
chosen by the utility to maximize the opportunity for real-time
and real-world testing of Smart Grid technologies and services
taking into account the safety and security of the
participating utility's grid and grid operations.
(c) The participating utility, with input from the Smart
Grid Advisory Council established pursuant to Section 16-108.6
of this Act, shall, as part of its filing under subsection (b)
of Section 16-108.5, include a plan for the creation,
operation, and administration of the test bed. This plan shall
address the following:
(1) how the utility proposes to comply with each of the
objectives set forth in subsection (a) of this Section;
(2) the proposed location or locations of the test bed;
(3) the process by which the utility will receive,
review, and qualify proposals to use the test bed;
(4) the criteria by which the utility proposes to
qualify proposals to use the test bed, including, but not
limited to, safety, reliability, security, customer data
security, privacy, and economic development
considerations;
(5) the engineering and operations support that the
utility will provide to test bed users, including provision
of customer data; and

SB1485 - 186 - LRB099 06216 AMC 30867 b
(6) the estimated costs to establish, administer and
promote the availability of the test bed.
(d) The test bed should be open to all qualified entities
wishing to test programs, technologies, business models, and
other Smart Grid-related activities, provided that the utility
retains control of its grid and operations and may reject any
programs, technologies, business models, and other Smart
Grid-related activities that threaten the reliability, safety,
security, or operations of its network, or that would threaten
the security of customer-identifiable data in the judgment of
the utility. The number of technologies and entities
participating in the test bed at any time may be limited by the
utility based on its determination of its ability to maintain a
secure, safe, and reliable grid.
(e) At a minimum, the test bed shall have the ability to
receive live signals from PJM Interconnection LLC or other
applicable regional transmission organization, the ability to
test new applications in a utility scale environment (to
include ramp rate regulations for distributed wind and solar
resources), critical peak price response, and market-based
power dispatch.
(f) At the end of the fourth year of operation the test bed
shall be subject to an independent evaluation to determine if
the test bed is meeting the objectives of this Section or is
likely to meet the objectives in the future. The evaluation
shall include the performance of the utility as test bed

SB1485 - 187 - LRB099 06216 AMC 30867 b
operator. Subject to the findings, the utility and the trust or
foundation established pursuant to Section 16-108.7 of this Act
may choose to continue operating the test bed.
(g) The utility shall be entitled to recover all prudently
incurred and reasonable costs associated with evaluation of
proposals, engineering, construction, operation, and
administration of the test bed through the performance-based
formula rate tariff established pursuant to Section 16-108.5 of
this Act.
(h) The utility is authorized to charge fees to users of
the test bed that shall recover the costs associated with the
incremental direct costs to the utility associated with
administration of the test bed, provided, however, that any
such fees collected by the utility shall be used to offset the
costs to be recovered pursuant to subsection (g) of this
Section.
(i) On a quarterly basis, the utility shall provide the
trust or foundation established pursuant to Section 16-108.7 of
this Act with a report summarizing test bed activities,
customers, discoveries, and other information as shall be
mutually deemed relevant.
(j) To the extent practicable, the utility and trust or
foundation established pursuant to Section 16-108.7 of this Act
shall jointly pursue resources that enhance the capabilities
and capacity of the test bed.
(k) If Section 16-108.5 of this Act becomes inoperative

SB1485 - 188 - LRB099 06216 AMC 30867 b
with respect to one or more participating utilities as set
forth in subsection (g) or (h) of that Section, then Sections
16-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act shall
become inoperative as to each affected utility and its service
area on the same date as Section 16-108.5 become inoperative.
(Source: P.A. 97-616, eff. 10-26-11.)
(220 ILCS 5/16-111.5)
Sec. 16-111.5. Provisions relating to electricity
procurement.
(a) An electric utility that on December 31, 2005 served at
least 100,000 customers in Illinois shall procure power and
energy for its eligible retail customers in accordance with the
applicable provisions set forth in Section 1-75 of the Illinois
Power Agency Act and this Section. A small multi-jurisdictional
electric utility that on December 31, 2005 served less than
100,000 customers in Illinois may elect to procure power and
energy for all or a portion of its eligible Illinois retail
customers in accordance with the applicable provisions set
forth in this Section and Section 1-75 of the Illinois Power
Agency Act. This Section shall not apply to a small
multi-jurisdictional utility until such time as a small
multi-jurisdictional utility requests the Illinois Power
Agency to prepare an electricity a procurement plan for its
eligible retail customers. "Eligible retail customers" for the
purposes of this Section means those retail customers that

SB1485 - 189 - LRB099 06216 AMC 30867 b
purchase power and energy from the electric utility under
fixed-price bundled service tariffs, other than those retail
customers whose service is declared or deemed competitive under
Section 16-113 and those other customer groups specified in
this Section, including self-generating customers, customers
electing hourly pricing, or those customers who are otherwise
ineligible for fixed-price bundled tariff service. Those
customers that are excluded from the definition of "eligible
retail customers" shall not be included in the electricity
procurement plan load requirements, and the utility shall
procure any supply requirements, including capacity, ancillary
services, and hourly priced energy, in the applicable markets
as needed to serve those customers, provided that the utility
may include in its electricity procurement plan load
requirements for the load that is associated with those retail
customers whose service has been declared or deemed competitive
pursuant to Section 16-113 of this Act to the extent that those
customers are purchasing power and energy during one of the
transition periods identified in subsection (b) of Section
16-113 of this Act.
(b) An electricity A procurement plan shall be prepared for
each electric utility consistent with the applicable
requirements of the Illinois Power Agency Act and this Section.
For purposes of this Section, Illinois electric utilities that
are affiliated by virtue of a common parent company are
considered to be a single electric utility. Small

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

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

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

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

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(4) Proposed procedures for balancing loads. The
electricity procurement plan shall include, for load
requirements included in the electricity procurement plan,
the process for (i) hourly balancing of supply and demand
and (ii) the criteria for portfolio re-balancing in the
event of significant shifts in load.
(c) The procurement process set forth in Section 1-75 of
the Illinois Power Agency Act and subsection (e) of this
Section shall be administered by a procurement administrator
and monitored by a procurement monitor.
(1) The procurement administrator shall:
(i) design the final procurement process in
accordance with Section 1-75 of the Illinois Power
Agency Act and subsection (e) of this Section following
Commission approval of the electricity procurement
plan;
(ii) develop benchmarks in accordance with
subsection (e)(3) to be used to evaluate bids; these
benchmarks shall be submitted to the Commission for
review and approval on a confidential basis prior to
the procurement event;
(iii) serve as the interface between the electric
utility and suppliers;
(iv) manage the bidder pre-qualification and
registration process;
(v) obtain the electric utilities' agreement to

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the final form of all supply contracts and credit
collateral agreements;
(vi) administer the request for proposals process;
(vii) have the discretion to negotiate to
determine whether bidders are willing to lower the
price of bids that meet the benchmarks approved by the
Commission; any post-bid negotiations with bidders
shall be limited to price only and shall be completed
within 24 hours after opening the sealed bids and shall
be conducted in a fair and unbiased manner; in
conducting the negotiations, there shall be no
disclosure of any information derived from proposals
submitted by competing bidders; if information is
disclosed to any bidder, it shall be provided to all
competing bidders;
(viii) maintain confidentiality of supplier and
bidding information in a manner consistent with all
applicable laws, rules, regulations, and tariffs;
(ix) submit a confidential report to the
Commission recommending acceptance or rejection of
bids;
(x) notify the utility of contract counterparties
and contract specifics; and
(xi) administer related contingency procurement
events.
(2) The procurement monitor, who shall be retained by

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the Commission, shall:
(i) monitor interactions among the procurement
administrator, suppliers, and utility;
(ii) monitor and report to the Commission on the
progress of the procurement process;
(iii) provide an independent confidential report
to the Commission regarding the results of the
procurement event;
(iv) assess compliance with the electricity
procurement plans approved by the Commission for each
utility that on December 31, 2005 provided electric
service to a least 100,000 customers in Illinois and
for each small multi-jurisdictional utility that on
December 31, 2005 served less than 100,000 customers in
Illinois;
(v) preserve the confidentiality of supplier and
bidding information in a manner consistent with all
applicable laws, rules, regulations, and tariffs;
(vi) provide expert advice to the Commission and
consult with the procurement administrator regarding
issues related to procurement process design, rules,
protocols, and policy-related matters; and
(vii) consult with the procurement administrator
regarding the development and use of benchmark
criteria, standard form contracts, credit policies,
and bid documents.

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(d) Except as provided in subsection (j), the planning
process shall be conducted as follows:
(1) Beginning in 2008, each Illinois utility procuring
power pursuant to this Section shall annually provide a
range of load forecasts to the Illinois Power Agency by
July 15 of each year, or such other date as may be required
by the Commission or Agency. The load forecasts shall cover
the 5-year electricity procurement planning period for the
next electricity procurement plan and shall include hourly
data representing a high-load, low-load and expected-load
scenario for the load of the eligible retail customers. The
utility shall provide supporting data and assumptions for
each of the scenarios.
(2) Beginning in 2008, the Illinois Power Agency shall
prepare an electricity a procurement plan by August 15th of
each year, or such other date as may be required by the
Commission. The electricity procurement plan shall
identify the portfolio of demand-response and power and
energy products to be procured. Cost-effective
demand-response measures shall be procured as set forth in
item (iii) of subsection (b) of this Section. Copies of the
electricity procurement plan shall be posted and made
publicly available on the Agency's and Commission's
websites, and copies shall also be provided to each
affected electric utility. An affected utility shall have
30 days following the date of posting to provide comment to

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the Agency on the electricity procurement plan. Other
interested entities also may comment on the electricity
procurement plan. All comments submitted to the Agency
shall be specific, supported by data or other detailed
analyses, and, if objecting to all or a portion of the
electricity procurement plan, accompanied by specific
alternative wording or proposals. All comments shall be
posted on the Agency's and Commission's websites. During
this 30-day comment period, the Agency shall hold at least
one public hearing within each utility's service area for
the purpose of receiving public comment on the electricity
procurement plan. Within 14 days following the end of the
30-day review period, the Agency shall revise the
electricity procurement plan as necessary based on the
comments received and file the electricity procurement
plan with the Commission and post the electricity
procurement plan on the websites.
(3) Within 5 days after the filing of the electricity
procurement plan, any person objecting to the electricity
procurement plan shall file an objection with the
Commission. Within 10 days after the filing, the Commission
shall determine whether a hearing is necessary. The
Commission shall enter its order confirming or modifying
the electricity procurement plan within 90 days after the
filing of the electricity procurement plan by the Illinois
Power Agency.

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(4) The Commission shall approve the electricity
procurement plan, including expressly the forecast used in
the electricity procurement plan, if the Commission
determines that it will ensure adequate, reliable,
affordable, efficient, and environmentally sustainable
electric service at the lowest total cost over time, taking
into account any benefits of price stability.
(e) The procurement process shall include each of the
following components:
(1) Solicitation, pre-qualification, and registration
of bidders. The procurement administrator shall
disseminate information to potential bidders to promote a
procurement event, notify potential bidders that the
procurement administrator may enter into a post-bid price
negotiation with bidders that meet the applicable
benchmarks, provide supply requirements, and otherwise
explain the competitive procurement process. In addition
to such other publication as the procurement administrator
determines is appropriate, this information shall be
posted on the Illinois Power Agency's and the Commission's
websites. The procurement administrator shall also
administer the prequalification process, including
evaluation of credit worthiness, compliance with
procurement rules, and agreement to the standard form
contract developed pursuant to paragraph (2) of this
subsection (e). The procurement administrator shall then

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

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

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

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

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including ancillary services, capacity, and day-ahead
or real time energy or both; provided, however, that if
a needed product is not available through the regional
transmission organization market it shall be purchased
from the wholesale market.
(6) The procurement process described in this
subsection is exempt from the requirements of the Illinois
Procurement Code, pursuant to Section 20-10 of that Code.
(f) Within 2 business days after opening the sealed bids,
the procurement administrator shall submit a confidential
report to the Commission. The report shall contain the results
of the bidding for each of the products along with the
procurement administrator's recommendation for the acceptance
and rejection of bids based on the price benchmark criteria and
other factors observed in the process. The procurement monitor
also shall submit a confidential report to the Commission
within 2 business days after opening the sealed bids. The
report shall contain the procurement monitor's assessment of
bidder behavior in the process as well as an assessment of the
procurement administrator's compliance with the procurement
process and rules. The Commission shall review the confidential
reports submitted by the procurement administrator and
procurement monitor, and shall accept or reject the
recommendations of the procurement administrator within 2
business days after receipt of the reports.
(g) Within 3 business days after the Commission decision

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

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as may be required by the Commission from time to time, the
utility shall file for informational purposes with the
Commission its actual or estimated retail supply charges, as
applicable, by customer supply group reflecting the costs
associated with the procurement and computed in accordance with
the tariffs filed pursuant to subsection (l) of this Section
and approved by the Commission.
(j) Within 60 days following the effective date of this
amendatory Act, each electric utility that on December 31, 2005
provided electric service to at least 100,000 customers in
Illinois shall prepare and file with the Commission an initial
electricity procurement plan, which shall conform in all
material respects to the requirements of the electricity
procurement plan set forth in subsection (b); provided,
however, that the Illinois Power Agency Act shall not apply to
the initial electricity procurement plan prepared pursuant to
this subsection. The initial electricity procurement plan
shall identify the portfolio of power and energy products to be
procured and delivered for the period June 2008 through May
2009, and shall identify the proposed procurement
administrator, who shall have the same experience and expertise
as is required of a procurement administrator hired pursuant to
Section 1-75 of the Illinois Power Agency Act. Copies of the
electricity procurement plan shall be posted and made publicly
available on the Commission's website. The initial electricity
procurement plan may include contracts for renewable resources

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

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into account any benefits of price stability.
(k) In order to promote price stability for residential and
small commercial customers during the transition to
competition in Illinois, and notwithstanding any other
provision of this Act, each electric utility subject to this
Section shall enter into one or more multi-year financial swap
contracts that become effective on the effective date of this
amendatory Act. These contracts may be executed with generators
and power marketers, including affiliated interests of the
electric utility. These contracts shall be for a term of no
more than 5 years and shall, for each respective utility or for
any Illinois electric utilities that are affiliated by virtue
of a common parent company and that are thereby considered a
single electric utility for purposes of this subsection (k),
not exceed in the aggregate 3,000 megawatts for any hour of the
year. The contracts shall be financial contracts and not energy
sales contracts. The contracts shall be executed as
transactions under a negotiated master agreement based on the
form of master agreement for financial swap contracts sponsored
by the International Swaps and Derivatives Association, Inc.
and shall be considered pre-existing contracts in the
utilities' electricity procurement plans for residential and
small commercial customers. Costs incurred pursuant to a
contract authorized by this subsection (k) shall be deemed
prudently incurred and reasonable in amount and the electric
utility shall be entitled to full cost recovery pursuant to the

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tariffs filed with the Commission.
(k-5) In order to promote price stability for residential
and small commercial customers during the infrastructure
investment program described in subsection (b) of Section
16-108.5 of this Act, and notwithstanding any other provision
of this Act or the Illinois Power Agency Act, for each electric
utility that serves more than one million retail customers in
Illinois, the Illinois Power Agency shall conduct a procurement
event within 120 days after October 26, 2011 (the effective
date of Public Act 97-616) and may procure contracts for energy
and renewable energy credits for the period June 1, 2013
through December 31, 2017 that satisfy the requirements of this
subsection (k-5), including the benchmarks described in this
subsection. These contracts shall be entered into as the result
of a competitive procurement event, and, to the extent that any
provisions of this Section or the Illinois Power Agency Act do
not conflict with this subsection (k-5), such provisions shall
apply to the procurement event. The energy contracts shall be
for 24 hour by 7 day supply over a term that runs from the first
delivery year through December 31, 2017. For a utility that
serves over 2 million customers, the energy contracts shall be
multi-year with pricing escalating at 2.5% per annum. The
energy contracts may be designed as financial swaps or may
require physical delivery.
Within 30 days of October 26, 2011 (the effective date of
Public Act 97-616), each such utility shall submit to the

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Agency updated load forecasts for the period June 1, 2013
through December 31, 2017. The megawatt volume of the contracts
shall be based on the updated load forecasts of the minimum
monthly on-peak or off-peak average load requirements shown in
the forecasts, taking into account any existing energy
contracts in effect as well as the expected migration of the
utility's customers to alternative retail electric suppliers.
The renewable energy credit volume shall be based on the number
of credits that would satisfy the requirements of subsection
(c) of Section 1-75 of the Illinois Power Agency Act, subject
to the rate impact caps and other provisions of subsection (c)
of Section 1-75 of the Illinois Power Agency Act. The
evaluation of contract bids in the competitive procurement
events for energy and for renewable energy credits shall
incorporate price benchmarks set collaboratively by the
Agency, the procurement administrator, the staff of the
Commission, and the procurement monitor. If the contracts are
swap contracts, then they shall be executed as transactions
under a negotiated master agreement based on the form of master
agreement for financial swap contracts sponsored by the
International Swaps and Derivatives Association, Inc. Costs
incurred pursuant to a contract authorized by this subsection
(k-5) 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.
The cost of administering the procurement event described

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in this subsection (k-5) shall be paid by the winning supplier
or suppliers to the procurement administrator through a
supplier fee. In the event that there is no winning supplier
for a particular utility, such utility will pay the procurement
administrator for the costs associated with the procurement
event, and those costs shall not be a recoverable expense.
Nothing in this subsection (k-5) is intended to alter the
recovery of costs for any other procurement event.
(l) An electric utility shall recover its costs incurred
under this Section, including, but not limited to, the costs of
procuring power and energy demand-response resources under
this Section. The utility shall file with the initial
electricity procurement plan its proposed tariffs through
which its costs of procuring power that are incurred pursuant
to a Commission-approved electricity procurement plan and
those other costs identified in this subsection (l), will be
recovered. The tariffs shall include a formula rate or charge
designed to pass through both the costs incurred by the utility
in procuring a supply of electric power and energy for the
applicable customer classes with no mark-up or return on the
price paid by the utility for that supply, plus any just and
reasonable costs that the utility incurs in arranging and
providing for the supply of electric power and energy. The
formula rate or charge shall also contain provisions that
ensure that its application does not result in over or under
recovery due to changes in customer usage and demand patterns,

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and that provide for the correction, on at least an annual
basis, of any accounting errors that may occur. A utility shall
recover through the tariff all reasonable costs incurred to
implement or comply with any electricity procurement plan that
is developed and put into effect pursuant to Section 1-75 of
the Illinois Power Agency Act and this Section, including any
fees assessed by the Illinois Power Agency, costs associated
with load balancing, and contingency plan costs. The electric
utility shall also recover its full costs of procuring electric
supply for which it contracted before the effective date of
this Section in conjunction with the provision of full
requirements service under fixed-price bundled service tariffs
subsequent to December 31, 2006. All such costs shall be deemed
to have been prudently incurred. The pass-through tariffs that
are filed and approved pursuant to this Section shall not be
subject to review under, or in any way limited by, Section
16-111(i) of this Act.
(m) The Commission has the authority to adopt rules to
carry out the provisions of this Section. For the public
interest, safety, and welfare, the Commission also has
authority to adopt rules to carry out the provisions of this
Section on an emergency basis immediately following the
effective date of this amendatory Act.
(n) Notwithstanding any other provision of this Act, any
affiliated electric utilities that submit a single electricity
procurement plan covering their combined needs may procure for

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those combined needs in conjunction with that plan, and may
enter jointly into power supply contracts, purchases, and other
procurement arrangements, and allocate capacity and energy and
cost responsibility therefor among themselves in proportion to
their requirements.
(o) On or before June 1 of each year, the Commission shall
hold an informal hearing for the purpose of receiving comments
on the prior year's procurement process and any recommendations
for change.
(p) An electric utility subject to this Section may propose
to invest, lease, own, or operate an electric generation
facility as part of its electricity procurement plan, provided
the utility demonstrates that such facility is the least-cost
option to provide electric service to eligible retail
customers. If the facility is shown to be the least-cost option
and is included in an electricity a procurement plan prepared
in accordance with Section 1-75 of the Illinois Power Agency
Act and this Section, then the electric utility shall make a
filing pursuant to Section 8-406 of this Act, and may request
of the Commission any statutory relief required thereunder. If
the Commission grants all of the necessary approvals for the
proposed facility, such supply shall thereafter be considered
as a pre-existing contract under subsection (b) of this
Section. The Commission shall in any order approving a proposal
under this subsection specify how the utility will recover the
prudently incurred costs of investing in, leasing, owning, or

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operating such generation facility through just and reasonable
rates charged to eligible retail customers. Cost recovery for
facilities included in the utility's electricity procurement
plan pursuant to this subsection shall not be subject to review
under or in any way limited by the provisions of Section
16-111(i) of this Act. Nothing in this Section is intended to
prohibit a utility from filing for a fuel adjustment clause as
is otherwise permitted under Section 9-220 of this Act.
(q) Notwithstanding any other provisions of this Section,
beginning with the 2016 delivery year, the procurement of
renewable energy credits in accordance with subdivision (c) of
Section 1-75 of the Illinois Power Agency Act shall not be
subject to this Section. For the purposes of this Section,
"delivery year" has the same meaning as in Section 1-10 of the
Illinois Power Agency Act.
(Source: P.A. 97-325, eff. 8-12-11; 97-616, eff. 10-26-11;
97-813, eff. 7-13-12.)
(220 ILCS 5/16-111.5B)
Sec. 16-111.5B. Provisions relating to energy efficiency
procurement.
(a) Beginning in 2012, procurement plans prepared pursuant
to Section 16-111.5 of this Act shall be subject to the
following additional requirements, except that beginning in
2018, any utility that has achieved the performance metrics
under paragraph (10) of subsection (f) of Section 16-108.5 of

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this Act shall be exempt from this Section:
(1) The analysis included pursuant to paragraph (2) of
subsection (b) of Section 16-111.5 shall also include the
impact of energy efficiency building codes or appliance
standards, both current and projected.
(2) The procurement plan components described in
subsection (b) of Section 16-111.5 shall also include an
assessment of opportunities to expand the programs
promoting energy efficiency measures that have been
offered under plans approved pursuant to Section 8-103 of
this Act or to implement additional cost-effective energy
efficiency programs or measures.
(3) In addition to the information provided pursuant to
paragraph (1) of subsection (d) of Section 16-111.5 of this
Act, each Illinois utility procuring power pursuant to that
Section shall annually provide to the Illinois Power Agency
by July 15 of each year, or such other date as may be
required by the Commission or Agency, an assessment of
cost-effective energy efficiency programs or measures that
could be included in the procurement plan. The assessment
shall include the following:
(A) A comprehensive energy efficiency potential
study for the utility's service territory that was
completed within the past 3 years.
(B) Beginning in 2014, the most recent analysis
submitted pursuant to Section 8-103A of this Act and

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approved by the Commission under subsection (f) of
Section 8-103 of this Act.
(C) Identification of new or expanded
cost-effective energy efficiency programs or measures
that are incremental to those included in energy
efficiency and demand-response plans approved by the
Commission pursuant to Section 8-103 of this Act and
that would be offered to all retail customers whose
electric service has not been declared competitive
under Section 16-113 of this Act and who are eligible
to purchase power and energy from the utility under
fixed-price bundled service tariffs, regardless of
whether such customers actually do purchase such power
and energy from the utility.
(D) Analysis showing that the new or expanded
cost-effective energy efficiency programs or measures
would lead to a reduction in the overall cost of
electric service.
(E) Analysis of how the cost of procuring
additional cost-effective energy efficiency measures
compares over the life of the measures to the
prevailing cost of comparable supply.
(F) An energy savings goal, expressed in
megawatt-hours, for the year in which the measures will
be implemented.
(G) For each expanded or new program, the estimated

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amount that the program may reduce the agency's need to
procure supply.
In preparing such assessments, a utility shall conduct
an annual solicitation process for purposes of requesting
proposals from third-party vendors, the results of which
shall be provided to the Agency as part of the assessment,
including documentation of all bids received. The utility
shall develop requests for proposals consistent with the
manner in which it develops requests for proposals under
plans approved pursuant to Section 8-103 of this Act, which
considers input from the Agency and interested
stakeholders.
(4) The Illinois Power Agency shall include in the
procurement plan prepared pursuant to paragraph (2) of
subsection (d) of Section 16-111.5 of this Act energy
efficiency programs and measures it determines are
cost-effective and the associated annual energy savings
goal included in the annual solicitation process and
assessment submitted pursuant to paragraph (3) of this
subsection (a).
(5) Pursuant to paragraph (4) of subsection (d) of
Section 16-111.5 of this Act, the Commission shall also
approve the energy efficiency programs and measures
included in the procurement plan, including the annual
energy savings goal, if the Commission determines they
fully capture the potential for all achievable

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cost-effective savings, to the extent practicable, and
otherwise satisfy the requirements of Section 8-103 of this
Act.
In the event the Commission approves the procurement of
additional energy efficiency, it shall reduce the amount of
power to be procured under the procurement plan to reflect
the additional energy efficiency and shall direct the
utility to undertake the procurement of such energy
efficiency, which shall not be subject to the requirements
of subsection (e) of Section 16-111.5 of this Act. The
utility shall consider input from the Agency and interested
stakeholders on the procurement and administration
process.
(6) An electric utility shall recover its costs
incurred under this Section related to the implementation
of energy efficiency programs and measures approved by the
Commission in its order approving the procurement plan
under Section 16-111.5 of this Act, including, but not
limited to, all costs associated with complying with this
Section and all start-up and administrative costs and the
costs for any evaluation, measurement, and verification of
the measures, from all retail customers whose electric
service has not been declared competitive under Section
16-113 of this Act and who are eligible to purchase power
and energy from the utility under fixed-price bundled
service tariffs, regardless of whether such customers

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actually do purchase such power and energy from the utility
through the automatic adjustment clause tariff established
pursuant to Section 8-103 of this Act, provided, however,
that the limitations described in subsection (d) of that
Section shall not apply to the costs incurred pursuant to
this Section or Section 16-111.7 of this Act.
(b) For purposes of this Section, the term "energy
efficiency" shall have the meaning set forth in Section 1-10 of
the Illinois Power Agency Act, and the term "cost-effective"
shall have the meaning set forth in subsection (a) of Section
8-103 of this Act.
(Source: P.A. 97-616, eff. 10-26-11; 97-824, eff. 7-18-12.)
(220 ILCS 5/16-111.5C new)
Sec. 16-111.5C. Provisions related to renewable energy
credit procurement.
(a) Beginning with the planning process to develop a plan
or plans for implementation starting in the 2016 delivery year,
a long-term renewable resources procurement plan for the
procurement of renewable energy credits shall be prepared
consistent with the applicable requirements of the Illinois
Power Agency Act and this Section. The long-term renewable
resources procurement plan and all subsequent revisions shall
be subject to review and approval by the Commission according
to the provisions set forth in this Section. For the purposes
of this Section, "delivery year" has the same meaning as in

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Section 1-10 of the Illinois Power Agency Act.
(b) The long-term renewable resources planning process
shall be conducted as follows:
(1) Electric utilities shall provide a range of load
forecasts to the Illinois Power Agency within 30 days after
the effective date of this amendatory Act of the 99th
General Assembly and on July 15 of each year thereafter or
upon such other date as may be required by the Commission
or Agency. The load forecasts shall cover the procurement
planning period through the 2030 delivery year and beyond
and shall include a high-load, low-load, and expected-load
scenario for the load of all customers taking delivery
service from the electric utility. The utility shall
provide supporting data and assumptions for each of the
scenarios.
(2) The Illinois Power Agency shall publish for comment
the initial long-term renewable resources plan no later
than 120 days after the effective date of this amendatory
Act of the 99th General Assembly and shall make revisions
to the plan at least every 2 years thereafter. The
long-term renewable resources procurement plan shall
identify the procurement programs and competitive
procurement events consistent with the applicable
requirements of the Illinois Power Agency Act and designed
to achieve the goals set forth in subdivision (c) of
Section 1-75 of that Act. Copies of the long-term renewable

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resources procurement plan shall be posted and made
publicly available on the Agency's and Commission's
websites, and copies shall also be provided to each
affected electric utility. An affected utility and other
interested parties shall have 30 days following the date of
posting to provide comment to the Agency on the procurement
plan. All comments submitted to the Agency shall be
specific, supported by data or other detailed analyses,
and, if objecting to all or a portion of the procurement
plan, accompanied by specific alternative wording or
proposals. All comments shall be posted on the Agency's and
Commission's websites. During this 30-day comment period,
the Agency shall hold at least one public hearing within
each utility's service area for the purpose of receiving
public comment on the long-term renewable resources
procurement plan. Within 14 days following the end of the
30-day review period, the Agency shall revise the long-term
renewable resources procurement plan as necessary based on
the comments received and file the plan with the Commission
for review and approval.
(3) Within 14 days after the filing of the long-term
renewable resources procurement plan, any person objecting
to the plan shall file an objection with the Commission.
Within 21 days after the filing, the Commission shall
determine whether a hearing is necessary. The Commission
shall enter its order confirming or modifying the

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procurement plan within 120 days after the filing of the
procurement plan by the Illinois Power Agency.
(4) The Commission shall approve the long-term
renewable resources procurement plan if the Commission
determines that the plan will reasonably and prudently
fulfill the relevant requirements of Section 1-56 and
subdivision (c) of Section 1-75 of the Illinois Power
Agency Act.
(c) The Agency or third parties contracted by the Agency
shall implement all programs authorized by the Commission in an
approved long-term renewable resources procurement plan. For
those renewable energy credits subject to procurement through a
competitive bid process under the plan, the Agency shall follow
the procurement process specified in the provisions relating to
electricity procurement in subsections (e) through (i) of
Section 16-111.5 of this Act.
(d) An electric utility shall recover its costs incurred
under this Section, including, but not limited to, the costs of
procuring renewable energy credits under this Section, as a
utility cost of service under the Illinois Public Utilities
Act.
(e) The Commission has the authority to adopt rules to
carry out the provisions of this Section. For the public
interest, safety, and welfare, the Commission also has
authority to adopt rules to carry out the provisions of this
Section on an emergency basis immediately following the

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effective date of this amendatory Act of the 99th General
Assembly.
(f) On or before July 1 of each year, the Commission shall
hold an informal hearing for the purpose of receiving comments
on the prior year's procurement process and any recommendations
for change.
(220 ILCS 5/16-111.7)
Sec. 16-111.7. On-bill financing program; electric
utilities.
(a) The Illinois General Assembly finds that Illinois homes
and businesses have the potential to save energy through
conservation and cost-effective energy efficiency measures.
Programs created pursuant to this Section will allow utility
customers to purchase cost-effective energy efficiency
measures, including measures set forth in a
Commission-approved energy efficiency and demand-response plan
under Section 8-103 of this Act, with no required initial
upfront payment, and to pay the cost of those products and
services over time on their utility bill.
(a-5) As used in this Section:
"Eligible electric energy efficiency measure" or "measure"
means a product or service for which one or more of the
following is true:
(1) a building energy assessment, performed by an
energy auditor who is certified by the Building Performance

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Institute or who holds a similar certification, has
recommended the product or service as likely to be
cost-effective over the course of its installed life for
the building in which the measure is to be installed;
(2) the projected electricity savings (determined by
rates in effect at the time of purchase) are sufficient to
cover the costs of implementing the measures, including
finance charges and any program fees not recovered pursuant
to subsection (g) of this Section;
(3) the product or service is included in a
Commission-approved energy efficiency and demand-response
plan under Section 8-103 of this Act and is cost-effective
as that term is defined by that Section; or
(4) the product or service is necessary to safely or
correctly install to code or industry standard an
efficiency measure, including, but not limited to,
installation work; changes needed to plumbing or
electrical connections; upgrades to wiring or fixtures;
removal of hazardous materials; correction of leaks;
changes to thermostats, controls or similar devices; and
changes to venting or exhaust necessitated by the measure.
"Small commercial customer" means, for an electric utility
serving more than 3,000,000 retail customers, those customers
having peak demand of less than 100 kilowatts, and, for an
electric utility serving less than 3,000,000 retail customers,
those customers having peak demand of less than 150 kilowatts;

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provided, however, that in the event the Commission, after
August 27, 2013 (the effective date of Public Act 98-586),
approves changes to a utility's tariffs that reflect new or
revised demand criteria for the utility's customer rate
classifications, then the utility may file a petition with the
Commission to revise the applicable definition of a small
commercial customer to reflect the new or revised demand
criteria for the purposes of this Section. After notice and
hearing, the Commission shall enter an order approving, or
approving with modification, the revised definition within 60
days after the utility files the petition.
(b) Notwithstanding any other provision of this Act, an
electric utility serving more than 100,000 customers on January
1, 2009 shall offer a Commission-approved on-bill financing
program ("program") that allows its eligible retail customers,
as that term is defined in Section 16-111.5 of this Act, who
own a residential single family home, duplex, or other
residential building with 4 or less units, or condominium at
which the electric service is being provided (i) to borrow
funds from a third party lender in order to purchase electric
energy efficiency measures approved under the program for
installation in such home or condominium without any required
upfront payment and (ii) to pay back such funds over time
through the electric utility's bill. Based upon the process
described in subsection (b-5) of this Section, small commercial
customers who own the premises at which electric service is

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being provided may be included in such program. After receiving
a request from an electric utility for approval of a proposed
program and tariffs pursuant to this Section, the Commission
shall render its decision within 120 days. If no decision is
rendered within 120 days, then the request shall be deemed to
be approved.
Beginning no later than December 31, 2013, an electric
utility subject to this subsection (b) shall also offer its
program to eligible retail customers that own multifamily
residential or mixed-use buildings with no more than 50
residential units, provided, however, that such customers must
either be a residential customer or small commercial customer
and may not use the program in such a way that repayment of the
cost of energy efficiency measures is made through tenants'
utility bills. An electric utility may impose a per site loan
limit not to exceed $150,000. The program, and loans issued
thereunder, shall only be offered to customers of the utility
that meet the requirements of this Section and that also have
an electric service account at the premises where the energy
efficiency measures being financed shall be installed.
Beginning no later than December 31, 2015, an electric
utility subject to this subsection (b) shall also offer its
program to eligible retail customers that are Unit Owners'
Associations, as defined in subsection (o) of Section 2 of the
Condominium Property Act, or Master Associations, as defined in
subsection (u) of Section 2 of the Condominium Property Act;

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however, such customers must either be residential customers or
small commercial customers and may not use the program in such
a way that repayment of the cost of energy efficiency measures
is made through unit owners' utility bills. The program and
loans issued under the program shall only be offered to
customers of the utility that meet the requirements of this
Section and that also have an electric service account at the
premises where the energy efficiency measures being financed
shall be installed.
For purposes of this Section, "small commercial customer"
means, for an electric utility serving more than 3,000,000
retail customers, those customers having peak demand of less
than 100 kilowatts, and, for an electric utility serving less
than 3,000,000 retail customers, those customers having peak
demand of less than 150 kilowatts; provided, however, that in
the event the Commission, after the effective date of this
amendatory Act of the 98th General Assembly, approves changes
to a utility's tariffs that reflects new or revised demand
criteria for the utility's customer rate classifications, then
the utility may file a petition with the Commission to revise
the applicable definition of a small commercial customer to
reflect the new or revised demand criteria for the purposes of
this Section. After notice and hearing, the Commission shall
enter an order approving, or approving with modification, the
revised definition within 60 days after the utility files the
petition.

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(b-5) Within 30 days after the effective date of this
amendatory Act of the 96th General Assembly, the Commission
shall convene a workshop process during which interested
participants may discuss issues related to the program,
including program design, eligible electric energy efficiency
measures, vendor qualifications, and a methodology for
ensuring ongoing compliance with such qualifications,
financing, sample documents such as request for proposals,
contracts and agreements, dispute resolution, pre-installment
and post-installment verification, and evaluation. The
workshop process shall be completed within 150 days after the
effective date of this amendatory Act of the 96th General
Assembly.
(c) Not later than 60 days following completion of the
workshop process described in subsection (b-5) of this Section,
each electric utility subject to subsection (b) of this Section
shall submit a proposed program to the Commission that contains
the following components:
(1) A description of how the program will determine if
measures to be financed are eligible electric energy
efficiency measures, as defined in subsection (b) of this
Section. A list of recommended electric energy efficiency
measures that will be eligible for on-bill financing. An
eligible electric energy efficiency measure ("measure")
shall be a product or service for which one or more of the
following is true:

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(A) (blank);
(B) the projected electricity savings (determined
by rates in effect at the time of purchase) are
sufficient to cover the costs of implementing the
measures, including finance charges and any program
fees not recovered pursuant to subsection (f) of this
Section; or
(C) the product or service is included in a
Commission-approved energy efficiency and
demand-response plan under Section 8-103 of this Act.
(2) The electric utility shall issue a request for
proposals ("RFP") to lenders for purposes of providing
financing to participants to pay for approved measures.
Lenders may be for-profit or not-for-profit institutions
which can accept, manage, and lend utility funds consistent
with applicable financial regulations. The RFP criteria
shall include, but not be limited to, the interest rate,
origination fees, and credit terms. The utility shall
select the winning bidders based on its evaluation of these
criteria, with a preference for those bids containing the
rates, fees, and terms most favorable to participants;
(3) The utility shall work with the lenders selected
pursuant to the RFP process, and with vendors, to establish
the terms and processes pursuant to which a participant can
purchase eligible electric energy efficiency measures
using the financing obtained from the lender. The vendor

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shall explain and offer the approved financing packaging to
those customers identified in subsection (b) of this
Section and shall assist customers in applying for
financing. As part of the process, vendors shall also
provide to participants information about any other
incentives that may be available for the measures.
(4) The lender shall determine loan eligibility by
first examining customer utility bill payment history,
unless untimely to do so, and then by conducting conduct
credit checks or undertaking undertake other appropriate
measures to limit credit risk, and shall review and approve
or deny financing applications submitted by customers
identified in subsection (b) of this Section. If a customer
is not approved for financing as a result of a credit
check, the lender shall determine whether to approve or
deny financing by considering the customer's utility bill
repayment history and the bill reductions likely from the
energy efficiency measures to be financed and other
appropriate measures. Following the lender's approval of
financing and the participant's purchase of the measure or
measures, the lender shall forward payment information to
the electric utility, and the utility shall add as a
separate line item on the participant's utility bill a
charge showing the amount due under the program each month.
(5) A loan issued to a participant pursuant to the
program shall be the sole responsibility of the

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participant, and any dispute that may arise concerning the
loan's terms, conditions, or charges shall be resolved
between the participant and lender. Upon transfer of the
property title for the premises at which the participant
receives electric service from the utility or the
participant's request to terminate service at such
premises, the participant shall pay in full its electric
utility bill, including all amounts due under the program,
provided that this obligation may be modified as provided
in subsection (g) of this Section. Amounts due under the
program shall be deemed amounts owed for residential and,
as appropriate, small commercial electric service.
(6) The electric utility shall remit payment in full to
the lender each month on behalf of the participant. In the
event a participant defaults on payment of its electric
utility bill, the electric utility shall continue to remit
all payments due under the program to the lender, up to the
larger of $10,000,000 or 50% of the total allowable
outstanding amount financed under paragraph (7) of this
subsection (c), and the utility shall be entitled to
recover all costs related to a participant's nonpayment, up
to the larger of $10,000,000 or 50% of the total allowable
outstanding amount financed under paragraph (7) of this
subsection (c), through the automatic adjustment clause
tariff established pursuant to Section 16-111.8 of this
Act. In addition, the electric utility shall retain a

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security interest in the measure or measures purchased
under the program, and the utility retains its right to
disconnect a participant that defaults on the payment of
its utility bill.
(7) The total annual outstanding amount financed under
the program in this subsection and subsection (c-5) of this
Section shall not exceed $20,000,000 $2.5 million for an
electric utility or electric utilities under a single
holding company, provided that the electric utility or
electric utilities may petition the Commission for an
increase in such amount. A utility may meet the annual
obligation using funds repaid through this program or
through additional contributions.
(c-5) Within 120 days after the effective date of this
amendatory Act of the 98th General Assembly, each electric
utility subject to the requirements of this Section shall
submit an informational filing to the Commission that describes
its plan for implementing the provisions of this amendatory Act
of the 98th General Assembly on or before December 31, 2013.
Such filing shall also describe how the electric utility shall
coordinate its program with any gas utility or utilities that
provide gas service to buildings within the electric utility's
service territory so that it is practical and feasible for the
owner of a multifamily building to make a single application to
access loans for both gas and electric energy efficiency
measures in any individual building.

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Within 60 days after the effective date of this amendatory
Act of the 99th General Assembly, each electric utility subject
to the requirements of this Section shall submit a filing to
the Commission that describes its plan for implementing the
provisions of this amendatory Act of the 99th General Assembly
on or before December 31, 2015. The Commission shall seek
public comment on the utility's plan and shall issue an order
approving or disapproving each plan within 120 days of 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.
(d) A program approved by the Commission shall also include
the following criteria and guidelines for such program:
(1) guidelines for financing of measures installed
under a program, including, but not limited to, RFP
criteria and limits on both individual loan amounts and the
duration of the loans;
(2) criteria and standards for identifying and
approving measures;
(3) qualifications of vendors that will market or
install measures, as well as a methodology for ensuring
ongoing compliance with such qualifications;
(4) sample contracts and agreements necessary to
implement the measures and program; and

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(5) the types of data and information that utilities
and vendors participating in the program shall collect for
purposes of preparing the reports required under
subsection (g) of this Section.
(e) The proposed program submitted by each electric utility
shall be consistent with the provisions of this Section that
define operational, financial and billing arrangements between
and among program participants, vendors, lenders, and the
electric utility.
(f) An electric utility shall recover all of the prudently
incurred costs of offering a program approved by the Commission
pursuant to this Section, including, but not limited to, all
start-up and administrative costs and the costs for program
evaluation. All prudently incurred costs under this Section
shall be recovered from the residential and small commercial
retail customer classes eligible to participate in the program
through the automatic adjustment clause tariff established
pursuant to Section 8-103 of this Act.
(g) An independent evaluation of a program shall be
conducted after 3 years of the program's operation. The
electric utility shall retain an independent evaluator who
shall evaluate the effects of the measures installed under the
program and the overall operation of the program, including,
but not limited to, customer eligibility criteria and whether
the payment obligation for permanent electric energy
efficiency measures that will continue to provide benefits of

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energy savings should attach to the meter location. As part of
the evaluation process, the evaluator shall also solicit
feedback from participants and interested stakeholders. The
evaluator shall issue a report to the Commission on its
findings no later than 4 years after the date on which the
program commenced, and the Commission shall issue a report to
the Governor and General Assembly including a summary of the
information described in this Section as well as its
recommendations as to whether the program should be
discontinued, continued with modification or modifications or
continued without modification, provided that any recommended
modifications shall only apply prospectively and to measures
not yet installed or financed. The Commission's report shall
discuss changes to the program that were not considered in the
independent evaluation, if any.
(h) An electric utility offering a Commission-approved
program pursuant to this Section shall not be required to
comply with any other statute, order, rule, or regulation of
this State that may relate to the offering of such program,
provided that nothing in this Section is intended to limit the
electric utility's obligation to comply with this Act and the
Commission's orders, rules, and regulations, including Part
280 of Title 83 of the Illinois Administrative Code.
(i) The source of a utility customer's electric supply
shall not disqualify a customer from participation in the
utility's on-bill financing program. Customers of alternative

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retail electric suppliers may participate in the program under
the same terms and conditions applicable to the utility's
supply customers.
(Source: P.A. 97-616, eff. 10-26-11; 98-586, eff. 8-27-13.)
(220 ILCS 5/16-115D)
Sec. 16-115D. Renewable portfolio standard for alternative
retail electric suppliers and electric utilities operating
outside their service territories.
(a) In conjunction with energy deliveries under contracts
with customers for the period through May 31, 2016, an An
alternative retail electric supplier shall be responsible for
procuring cost-effective renewable energy resources as
required under item (5) of subsection (d) of Section 16-115 of
this Act as outlined herein:
(1) The definition of renewable energy resources
contained in Section 1-10 of the Illinois Power Agency Act
applies to all renewable energy resources required to be
procured by alternative retail electric suppliers.
(2) The quantity of renewable energy resources shall be
measured as a percentage of the actual amount of metered
electricity (megawatt-hours) delivered by the alternative
retail electric supplier to Illinois retail customers
during the 12-month period June 1 through May 31,
commencing June 1, 2009, and the comparable 12-month period
in each year thereafter except as provided in item (6) of

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this subsection (a).
(3) The quantity of renewable energy resources shall be
in amounts at least equal to the annual percentages set
forth in item (1) of subsection (c) of Section 1-75 of the
Illinois Power Agency Act. At least 60% of the renewable
energy resources procured pursuant to items (1) through (3)
of subsection (b) of this Section shall come from wind
generation and, starting June 1, 2015, at least 6% of the
renewable energy resources procured pursuant to items (1)
through (3) of subsection (b) of this Section shall come
from solar photovoltaics. If, in any given year, an
alternative retail electric supplier does not purchase at
least these levels of renewable energy resources, then the
alternative retail electric supplier shall make
alternative compliance payments, as described in
subsection (d) of this Section.
(4) The quantity and source of renewable energy
resources shall be independently verified through the PJM
Environmental Information System Generation Attribute
Tracking System (PJM-GATS) or the Midwest Renewable Energy
Tracking System (M-RETS), which shall document the
location of generation, resource type, month, and year of
generation for all qualifying renewable energy resources
that an alternative retail electric supplier uses to comply
with this Section. No later than June 1, 2009, the Illinois
Power Agency shall provide PJM-GATS, M-RETS, and

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alternative retail electric suppliers with all information
necessary to identify resources located in Illinois,
within states that adjoin Illinois or within portions of
the PJM and MISO footprint in the United States that
qualify under the definition of renewable energy resources
in Section 1-10 of the Illinois Power Agency Act for
compliance with this Section 16-115D. Alternative retail
electric suppliers shall not be subject to the requirements
in item (3) of subsection (c) of Section 1-75 of the
Illinois Power Agency Act.
(5) All renewable energy credits used to comply with
this Section shall be permanently retired.
(6) The required procurement of renewable energy
resources by an alternative retail electric supplier shall
apply to all metered electricity delivered to Illinois
retail customers by the alternative retail electric
supplier pursuant to contracts executed or extended after
March 15, 2009.
(b) For deliveries to customers through May 31, 2016, an An
alternative retail electric supplier shall comply with the
renewable energy portfolio standards by making an alternative
compliance payment, as described in subsection (d) of this
Section, to cover at least one-half of the alternative retail
electric supplier's compliance obligation and any one or
combination of the following means to cover the remainder of
the alternative retail electric supplier's compliance

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obligation:
(1) Generating electricity using renewable energy
resources identified pursuant to item (4) of subsection (a)
of this Section.
(2) Purchasing electricity generated using renewable
energy resources identified pursuant to item (4) of
subsection (a) of this Section through an energy contract.
(3) Purchasing renewable energy credits from renewable
energy resources identified pursuant to item (4) of
subsection (a) of this Section.
(4) Making an alternative compliance payment as
described in subsection (d) of this Section.
(c) Use of renewable energy credits.
(1) Renewable energy credits that are not used by an
alternative retail electric supplier to comply with a
renewable portfolio standard in a compliance year may be
banked and carried forward up to 2 12-month compliance
periods after the compliance period in which the credit was
generated for the purpose of complying with a renewable
portfolio standard in those 2 subsequent compliance
periods. For the 2009-2010 and 2010-2011 compliance
periods, an alternative retail electric supplier may use
renewable credits generated after December 31, 2008 and
before June 1, 2009 to comply with this Section.
(2) An alternative retail electric supplier is
responsible for demonstrating that a renewable energy

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credit used to comply with a renewable portfolio standard
is derived from a renewable energy resource and that the
alternative retail electric supplier has not used, traded,
sold, or otherwise transferred the credit.
(3) The same renewable energy credit may be used by an
alternative retail electric supplier to comply with a
federal renewable portfolio standard and a renewable
portfolio standard established under this Act. An
alternative retail electric supplier that uses a renewable
energy credit to comply with a renewable portfolio standard
imposed by any other state may not use the same credit to
comply with a renewable portfolio standard established
under this Act.
(d) Alternative compliance payments.
(1) The Commission shall establish and post on its
website, within 5 business days after entering an order
approving a procurement plan pursuant to Section 1-75 of
the Illinois Power Agency Act, maximum alternative
compliance payment rates, expressed on a per kilowatt-hour
basis, that will be applicable in the first compliance
period following the plan approval. A separate maximum
alternative compliance payment rate shall be established
for the service territory of each electric utility that is
subject to subsection (c) of Section 1-75 of the Illinois
Power Agency Act. Each maximum alternative compliance
payment rate shall be equal to the maximum allowable annual

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estimated average net increase due to the costs of the
utility's purchase of renewable energy resources included
in the amounts paid by eligible retail customers in
connection with electric service, as described in item (2)
of subsection (c) of Section 1-75 of the Illinois Power
Agency Act for the compliance period, and as established in
the approved procurement plan. Following each procurement
event through which renewable energy resources are
purchased for one or more of these utilities for the
compliance period, the Commission shall establish and post
on its website estimates of the alternative compliance
payment rates, expressed on a per kilowatt-hour basis, that
shall apply for that compliance period. Posting of the
estimates shall occur no later than 10 business days
following the procurement event, however, the Commission
shall not be required to establish and post such estimates
more often than once per calendar month. By July 1 of each
year, the Commission shall establish and post on its
website the actual alternative compliance payment rates
for the preceding compliance year. For compliance years
beginning prior to June 1, 2014, each alternative
compliance payment rate shall be equal to the total amount
of dollars that the utility contracted to spend on
renewable resources, excepting the additional incremental
cost attributable to solar resources, for the compliance
period divided by the forecasted load of eligible retail

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customers, at the customers' meters, as previously
established in the Commission-approved procurement plan
for that compliance year. For compliance years commencing
on or after June 1, 2014, each alternative compliance
payment rate shall be equal to the total amount of dollars
that the utility contracted to spend on all renewable
resources for the compliance period divided by the
forecasted load of eligible retail customers, at the
customers' meters, as previously established in the
Commission-approved procurement plan for that compliance
year. The actual alternative compliance payment rates may
not exceed the maximum alternative compliance payment
rates established for the compliance period. For purposes
of this subsection (d), the term "eligible retail
customers" has the same meaning as found in Section
16-111.5 of this Act.
(2) In any given compliance year, an alternative retail
electric supplier may elect to use alternative compliance
payments to comply with all or a part of the applicable
renewable portfolio standard. In the event that an
alternative retail electric supplier elects to make
alternative compliance payments to comply with all or a
part of the applicable renewable portfolio standard, such
payments shall be made by September 1, 2010 for the period
of June 1, 2009 to May 1, 2010 and by September 1 of each
year thereafter for the subsequent compliance period, in

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the manner and form as determined by the Commission. Any
election by an alternative retail electric supplier to use
alternative compliance payments is subject to review by the
Commission under subsection (e) of this Section.
(3) An alternative retail electric supplier's
alternative compliance payments shall be computed
separately for each electric utility's service territory
within which the alternative retail electric supplier
provided retail service during the compliance period,
provided that the electric utility was subject to
subsection (c) of Section 1-75 of the Illinois Power Agency
Act. For each service territory, the alternative retail
electric supplier's alternative compliance payment shall
be equal to (i) the actual alternative compliance payment
rate established in item (1) of this subsection (d),
multiplied by (ii) the actual amount of metered electricity
delivered by the alternative retail electric supplier to
retail customers within the service territory during the
compliance period, multiplied by (iii) the result of one
minus the ratios of the quantity of renewable energy
resources used by the alternative retail electric supplier
to comply with the requirements of this Section within the
service territory to the product of the percentage of
renewable energy resources required under item (3) of
subsection (a) of this Section and the actual amount of
metered electricity delivered by the alternative retail

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electric supplier to retail customers within the service
territory during the compliance period.
(4) All alternative compliance payments by alternative
retail electric suppliers shall be deposited in the
Illinois Power Agency Renewable Energy Resources Fund and
used to purchase renewable energy credits, in accordance
with Section 1-56 of the Illinois Power Agency Act.
Beginning April 1, 2012 and by April 1 of each year
thereafter, the Illinois Power Agency shall submit an
annual report to the General Assembly, the Commission, and
alternative retail electric suppliers that shall include,
but not be limited to:
(A) the total amount of alternative compliance
payments received in aggregate from alternative retail
electric suppliers by planning year for all previous
planning years in which the alternative compliance
payment was in effect;
(B) the amount of those payments utilized to
purchased renewable energy credits itemized by the
date of each procurement in which the payments were
utilized; and
(C) the unused and remaining balance in the Agency
Renewable Energy Resources Fund attributable to those
payments.
(5) The Commission, in consultation with the Illinois
Power Agency, shall establish a process or proceeding to

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consider the impact of a federal renewable portfolio
standard, if enacted, on the operation of the alternative
compliance mechanism, which shall include, but not be
limited to, developing, to the extent permitted by the
applicable federal statute, an appropriate methodology to
apportion renewable energy credits retired as a result of
alternative compliance payments made in accordance with
this Section. The Commission shall commence any such
process or proceeding within 35 days after enactment of a
federal renewable portfolio standard.
(e) Each alternative retail electric supplier shall, by
September 1, 2010 and by September 1 of each year thereafter,
prepare and submit to the Commission a report, in a format to
be specified by the Commission on or before December 31, 2009,
that provides information certifying compliance by the
alternative retail electric supplier with this Section,
including copies of all PJM-GATS and M-RETS reports, and
documentation relating to banking, retiring renewable energy
credits, and any other information that the Commission
determines necessary to ensure compliance with this Section. An
alternative retail electric supplier may file commercially or
financially sensitive information or trade secrets with the
Commission as provided under the rules of the Commission. To be
filed confidentially, the information shall be accompanied by
an affidavit that sets forth both the reasons for the
confidentiality and a public synopsis of the information.

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(f) The Commission may initiate a contested case to review
allegations that the alternative retail electric supplier has
violated this Section, including an order issued or rule
promulgated under this Section. In any such proceeding, the
alternative retail electric supplier shall have the burden of
proof. If the Commission finds, after notice and hearing, that
an alternative retail electric supplier has violated this
Section, then the Commission shall issue an order requiring the
alternative retail electric supplier to:
(1) immediately comply with this Section; and
(2) if the violation involves a failure to procure the
requisite quantity of renewable energy resources or pay the
applicable alternative compliance payment by the annual
deadline, the Commission shall require the alternative
retail electric supplier to double the applicable
alternative compliance payment that would otherwise be
required to bring the alternative retail electric supplier
into compliance with this Section.
If an alternative retail electric supplier fails to comply
with the renewable energy resource portfolio requirement in
this Section more than once in a 5-year period, then the
Commission shall revoke the alternative electric supplier's
certificate of service authority. The Commission shall not
accept an application for a certificate of service authority
from an alternative retail electric supplier that has lost
certification under this subsection (f), or any corporate

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affiliate thereof, for at least one year after the date of
revocation.
(g) All of the provisions of this Section apply to electric
utilities operating outside their service area except under
item (2) of subsection (a) of this Section the quantity of
renewable energy resources shall be measured as a percentage of
the actual amount of electricity (megawatt-hours) supplied in
the State outside of the utility's service territory during the
12-month period June 1 through May 31, commencing June 1, 2009,
and the comparable 12-month period in each year thereafter
except as provided in item (6) of subsection (a) of this
Section.
If any such utility fails to procure the requisite quantity
of renewable energy resources by the annual deadline, then the
Commission shall require the utility to double the alternative
compliance payment that would otherwise be required to bring
the utility into compliance with this Section.
If any such utility fails to comply with the renewable
energy resource portfolio requirement in this Section more than
once in a 5-year period, then the Commission shall order the
utility to cease all sales outside of the utility's service
territory for a period of at least one year.
(h) The provisions of this Section and the provisions of
subsection (d) of Section 16-115 of this Act relating to
procurement of renewable energy resources shall not apply to an
alternative retail electric supplier that operates a combined

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heat and power system in this State or that has a corporate
affiliate that operates such a combined heat and power system
in this State that supplies electricity primarily to or for the
benefit of: (i) facilities owned by the supplier, its
subsidiary, or other corporate affiliate; (ii) facilities
electrically integrated with the electrical system of
facilities owned by the supplier, its subsidiary, or other
corporate affiliate; or (iii) facilities that are adjacent to
the site on which the combined heat and power system is
located.
(i) The obligations specified in this Section of
alternative retail electric suppliers and electric utilities
operating outside their service territories to procure
renewable energy resources, make alternative compliance
payments, and file annual reports, and the obligations of the
Commission to determine and post alternative compliance
payment rates, shall terminate effective with the filing of
reports and full payments made by alternative retail electric
suppliers for energy deliveries to customers for the period
ending May 31, 2016, provided that alternative retail electric
suppliers and electric utilities operating outside their
service territories shall be obligated to make all alternative
compliance payments that they were obligated to pay for periods
through and including May 31, 2016 but were not paid as of that
date and to file all required reports for periods prior to June
1, 2016. The Commission shall continue to enforce the payment

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of unpaid alternative compliance payments after May 31, 2016 in
accordance with subsections (f) and (g) of this Section. All
alternative compliance payments made after May 31, 2016 shall
be deposited in the Illinois Power Agency Renewable Energy
Resources Fund and used to purchase renewable energy credits in
accordance with Section 1-56 of the Illinois Power Agency Act.
(Source: P.A. 96-33, eff. 7-10-09; 96-159, eff. 8-10-09;
96-1437, eff. 8-17-10; 97-658, eff. 1-13-12.)
(220 ILCS 5/19-140)
Sec. 19-140. On-bill financing program; gas utilities.
(a) The Illinois General Assembly finds that Illinois homes
and businesses have the potential to save energy through
conservation and cost-effective energy efficiency measures.
Programs created pursuant to this Section will allow utility
customers to purchase cost-effective energy efficiency
measures, including measures set forth in a
Commission-approved energy efficiency plan under Section 8-104
of this Act, with no required initial upfront payment, and to
pay the cost of those products and services over time on their
utility bill.
(a-5) As used in this Section:
"Eligible gas energy efficiency measure" or "measure"
means a product or service for which one or more of the
following is true:
(1) a building energy assessment, performed by an

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energy auditor who is certified by the Building Performance
Institute or who holds a similar certification, has
recommended the product or service as likely to be
cost-effective over the course of its installed life for
the building in which the measure is to be installed;
(2) the projected gas savings (determined by rates in
effect at the time of purchase) are sufficient to cover the
costs of implementing the measures, including finance
charges and any program fees not recovered pursuant to
subsection (f) of this Section;
(3) the product or service is included in a
Commission-approved energy efficiency and demand-response
plan under Section 8-104 of this Act and is cost-effective
as that term is defined by that Section; or
(4) the product or service is necessary to safely or
correctly install to code or industry standard an
efficiency measure, including, but not limited to
installation work, changes needed to plumbing or
electrical connections, upgrades to wiring or fixtures,
removal of hazardous materials, correction of leaks,
changes to thermostats, controls, or similar devices, and
changes to venting or exhaust necessitated by the measure.
"Small commercial customer" for a gas utility shall be
defined in that gas utility's filing that is made under
subsection (c-5) of this Section.
(b) Notwithstanding any other provision of this Act, a gas

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utility serving more than 100,000 customers on January 1, 2009
shall offer a Commission-approved on-bill financing program
("program") that allows its retail customers who own a
residential single family home, duplex, or other residential
building with 4 or less units, or condominium at which the gas
service is being provided (i) to borrow funds from a third
party lender in order to purchase gas energy efficiency
measures approved under the program for installation in such
home or condominium without any required upfront payment and
(ii) to pay back such funds over time through the gas utility's
bill. Based upon the process described in subsection (b-5) of
this Section, small commercial customers who own the premises
at which gas service is being provided may be included in such
program. After receiving a request from a gas utility for
approval of a proposed program and tariffs pursuant to this
Section, the Commission shall render its decision within 120
days. If no decision is rendered within 120 days, then the
request shall be deemed to be approved. Beginning no later than
December 31, 2013, a gas utility subject to this subsection (b)
shall also offer its program to eligible retail customers that
own a multifamily residential or mixed-use building with no
more than 50 residential units, provided, however, that such
customer must either be a residential customer or small
commercial customer and may not use the program in such a way
that repayment of the cost of energy efficiency measures is
made through tenants' utility bills. A gas utility may impose a

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per site loan limit not to exceed $150,000. The program, and
loans issued thereunder, shall only be offered to customers of
the utility that meet the requirements of this Section and that
also have a gas service account at the premises where the
energy efficiency measures being financed shall be installed.
Beginning no later than December 31, 2015, a gas utility
subject to this subsection (b) shall also offer its program to
eligible retail customers that are Unit Owners' Associations,
as defined in subsection (o) of Section 2 of the Condominium
Property Act, or Master Associations, as defined in subsection
(u) of Section 2 of the Condominium Property Act; however, such
customers must either be a residential customer or small
commercial customer and may not use the program in such a way
that repayment of the cost of energy efficiency measures is
made through unit owners' utility bills. The program and loans
issued under the program shall only be offered to customers of
the utility that meet the requirements of this Section and that
also have a gas service account at the premises where the
energy efficiency measures being financed shall be installed.
For purposes of this Section, a small commercial customer
for a gas utility shall be defined in that gas utility's
informational filing that is made under subsection (c-5) of
this Section.
(b-5) Within 30 days after the effective date of this
amendatory Act of the 96th General Assembly, the Commission
shall convene a workshop process during which interested

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participants may discuss issues related to the program,
including program design, eligible gas energy efficiency
measures, vendor qualifications, and a methodology for
ensuring ongoing compliance with such qualifications,
financing, sample documents such as request for proposals,
contracts and agreements, dispute resolution, pre-installment
and post-installment verification, and evaluation. The
workshop process shall be completed within 150 days after the
effective date of this amendatory Act of the 96th General
Assembly.
(c) Not later than 60 days following completion of the
workshop process described in subsection (b-5) of this Section,
each gas utility subject to subsection (b) of this Section
shall submit a proposed program to the Commission that contains
the following components:
(1) A description of how the program will determine if
measures to be financed are eligible electric energy
efficiency measures, as defined in subsection (a-5) of this
Section. A list of recommended gas energy efficiency
measures that will be eligible for on-bill financing. An
eligible gas energy efficiency measure ("measure") shall
be a product or service for which one or more of the
following is true:
(A) (blank);
(B) the projected gas savings (determined by rates
in effect at the time of purchase) are sufficient to

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cover the costs of implementing the measures,
including finance charges and any program fees not
recovered pursuant to subsection (f) of this Section;
or
(C) the product or service is included in a
Commission-approved energy efficiency plan under
Section 8-104 of this Act.
(2) The gas utility shall issue a request for proposals
("RFP") to lenders for purposes of providing financing to
participants to pay for approved measures. The RFP criteria
shall include, but not be limited to, the interest rate,
origination fees, and credit terms. The utility shall
select the winning bidders based on its evaluation of these
criteria, with a preference for those bids containing the
rates, fees, and terms most favorable to participants.
(3) The utility shall work with the lenders selected
pursuant to the RFP process, and with vendors, to establish
the terms and processes pursuant to which a participant can
purchase eligible gas energy efficiency measures using the
financing obtained from the lender. The vendor shall
explain and offer the approved financing packaging to those
customers identified in subsection (b) of this Section and
shall assist customers in applying for financing. As part
of such process, vendors shall also provide to participants
information about any other incentives that may be
available for the measures.

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(4) The lender shall conduct credit checks or undertake
other appropriate measures to limit credit risk, and shall
review and approve or deny financing applications
submitted by customers identified in subsection (b) of this
Section. If a customer is not approved for financing as a
result of a credit check, the lender shall determine
whether to approve or deny financing by considering the
customer's utility bill repayment history and the bill
reductions likely from the energy efficiency measures to be
financed and other appropriate measures. Following the
lender's approval of financing and the participant's
purchase of the measure or measures, the lender shall
forward payment information to the gas utility, and the
utility shall add as a separate line item on the
participant's utility bill a charge showing the amount due
under the program each month.
(5) A loan issued to a participant pursuant to the
program shall be the sole responsibility of the
participant, and any dispute that may arise concerning the
loan's terms, conditions, or charges shall be resolved
between the participant and lender. Upon transfer of the
property title for the premises at which the participant
receives gas service from the utility or the participant's
request to terminate service at such premises, the
participant shall pay in full its gas utility bill,
including all amounts due under the program, provided that

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this obligation may be modified as provided in subsection
(g) of this Section. Amounts due under the program shall be
deemed amounts owed for residential and, as appropriate,
small commercial gas service.
(6) The gas utility shall remit payment in full to the
lender each month on behalf of the participant. In the
event a participant defaults on payment of its gas utility
bill, the gas utility shall continue to remit all payments
due under the program to the lender, up to the larger of
$10,000,000 or 50% of the total allowable outstanding
amount financed under paragraph (7) of this subsection (c),
and the utility shall be entitled to recover all costs
related to a participant's nonpayment, up to the larger of
$10,000,000 or 50% of the total allowable outstanding
amount financed under paragraph (7) of this subsection (c),
through the automatic adjustment clause tariff established
pursuant to Section 19-145 of this Act. In addition, the
gas utility shall retain a security interest in the measure
or measures purchased under the program, and the utility
retains its right to disconnect a participant that defaults
on the payment of its utility bill.
(7) The total outstanding amount financed under the
program in this subsection and subsection (c-5) of this
Section shall not exceed $20,000,000 $2.5 million for a gas
utility or gas utilities under a single holding company,
provided that the gas utility or gas utilities may petition

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the Commission for an increase in such amount.
(c-5) Within 120 days after the effective date of this
amendatory Act of the 98th General Assembly, each covered gas
utility shall submit an informational filing to the Commission
that describes its plan for implementing the provisions of this
amendatory Act of the 98th General Assembly on or before
December 31, 2013. A gas utility subject to this Section shall
cooperate with any electric utility that provides electric
service to buildings within the gas utility's service territory
so that it is practical and feasible for the owner of a
multifamily building to make a single application to access
loans for both gas and electric energy efficiency measures in
any individual building.
Within 60 days after the effective date of this amendatory
Act of the 99th General Assembly, each electric utility subject
to the requirements of this Section shall submit a filing to
the Commission that describes its plan for implementing the
provisions of this amendatory Act of the 99th General Assembly
on or before December 31, 2015. The Commission shall seek
public comment on the utility's plan and shall issue an order
approving or disapproving each plan within 120 days of 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.

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(d) A program approved by the Commission shall also include
the following criteria and guidelines for such program:
(1) guidelines for financing of measures installed
under a program, including, but not limited to, RFP
criteria and limits on both individual loan amounts and the
duration of the loans;
(2) criteria and standards for identifying and
approving measures;
(3) qualifications of vendors that will market or
install measures, as well as a methodology for ensuring
ongoing compliance with such qualifications;
(4) sample contracts and agreements necessary to
implement the measures and program; and
(5) the types of data and information that utilities
and vendors participating in the program shall collect for
purposes of preparing the reports required under
subsection (g) of this Section.
(e) The proposed program submitted by each gas utility
shall be consistent with the provisions of this Section that
define operational, financial, and billing arrangements
between and among program participants, vendors, lenders, and
the gas utility.
(f) A gas utility shall recover all of the prudently
incurred costs of offering a program approved by the Commission
pursuant to this Section, including, but not limited to, all
start-up and administrative costs and the costs for program

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evaluation. All prudently incurred costs under this Section
shall be recovered from the residential and small commercial
retail customer classes eligible to participate in the program
through the automatic adjustment clause tariff established
pursuant to Section 8-104 of this Act.
(g) An independent evaluation of a program shall be
conducted after 3 years of the program's operation. The gas
utility shall retain an independent evaluator who shall
evaluate the effects of the measures installed under the
program and the overall operation of the program, including,
but not limited to, customer eligibility criteria and whether
the payment obligation for permanent gas energy efficiency
measures that will continue to provide benefits of energy
savings should attach to the meter location. As part of the
evaluation process, the evaluator shall also solicit feedback
from participants and interested stakeholders. The evaluator
shall issue a report to the Commission on its findings no later
than 4 years after the date on which the program commenced, and
the Commission shall issue a report to the Governor and General
Assembly including a summary of the information described in
this Section as well as its recommendations as to whether the
program should be discontinued, continued with modification or
modifications or continued without modification, provided that
any recommended modifications shall only apply prospectively
and to measures not yet installed or financed. The Commission's
report shall discuss changes to the program that were not

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considered in the independent evaluation, if any.
(h) A gas utility offering a Commission-approved program
pursuant to this Section shall not be required to comply with
any other statute, order, rule, or regulation of this State
that may relate to the offering of such program, provided that
nothing in this Section is intended to limit the gas utility's
obligation to comply with this Act and the Commission's orders,
rules, and regulations, including Part 280 of Title 83 of the
Illinois Administrative Code.
(i) The source of a utility customer's gas supply shall not
disqualify a customer from participation in the utility's
on-bill financing program. Customers of alternative gas
suppliers may participate in the program under the same terms
and conditions applicable to the utility's supply customers.
(Source: P.A. 98-586, eff. 8-27-13.)
Section 15. The Environmental Protection Act is amended by
changing Section 9.1 as follows:
(415 ILCS 5/9.1) (from Ch. 111 1/2, par. 1009.1)
Sec. 9.1. (a) The General Assembly finds that the federal
Clean Air Act, as amended, and regulations adopted pursuant
thereto establish complex and detailed provisions for
State-federal cooperation in the field of air pollution
control, provide for a Prevention of Significant Deterioration
program to regulate the issuance of preconstruction permits to

SB1485 - 261 - LRB099 06216 AMC 30867 b
insure that economic growth will occur in a manner consistent
with the preservation of existing clean air resources, and also
provide for plan requirements for nonattainment areas to
regulate the construction, modification and operation of
sources of air pollution to insure that economic growth will
occur in a manner consistent with the goal of achieving the
national ambient air quality standards, and that the General
Assembly cannot conveniently or advantageously set forth in
this Act all the requirements of such federal Act or all
regulations which may be established thereunder.
It is the purpose of this Section to avoid the existence of
duplicative, overlapping or conflicting State and federal
regulatory systems.
(b) The provisions of Section 111 of the federal Clean Air
Act (42 USC 7411), as amended, relating to standards of
performance for new stationary sources, and Section 112 of the
federal Clean Air Act (42 USC 7412), as amended, relating to
the establishment of national emission standards for hazardous
air pollutants are applicable in this State and are enforceable
under this Act. Any such enforcement shall be stayed consistent
with any stay granted in any federal judicial action to review
such standards. Enforcement shall be consistent with the
results of any such judicial review.
(b-5) (1) Upon the promulgation by the U.S. Environmental
Protection Agency (USEPA) of a final rule regulating carbon
dioxide emissions from existing electric generating units

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under 42 U.S.C. 7411(d) that allows for mass-based compliance
and maintains state flexibility to achieve compliance using
market-based tools (USEPA Rule), the Illinois Environmental
Protection Agency shall develop a state implementation plan
(Plan) to comply with the requirements of the USEPA rule by
creating a market-based system to reduce carbon dioxide and
create a revenue stream to be used by the State of Illinois
consistent with paragraphs (2) through (4) of this subsection
(b-5).
(2) The Illinois Environmental Protection Agency (Agency)
is authorized to create and implement a cap and invest program
or similar market mechanism (Program) to comply with the USEPA
rule, after undertaking a robust and open stakeholder process
and a comprehensive analysis and modeling of the impact of such
a program on Illinois' energy system, ratepayers, and
communities.
(A) The Illinois Environmental Protection Agency shall
adopt rules to implement the Program consistent with this
Act.
(B) A comprehensive market-based program shall, at a
minimum, achieve the carbon emissions reductions required
to meet Illinois' mass-based goal under its Plan and create
a mechanism to achieve additional emissions reductions
from the power sector when implemented in conjunction with
other State policies, including Illinois' Renewable Energy
Standard and Energy Efficiency Resource Standard.

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(C) The Illinois Environmental Protection Agency is
authorized to evaluate, establish, implement, and manage
an annual cap on CO2 emissions and administer an auction
program to sell power sector CO2 allowances in a
market-based program consistent with this Act and the USEPA
rule. The Program shall include a minimum emissions
allowance price calibrated to ensure compliance with the
State's obligations under the USEPA rule.
(D) The Agency shall make every effort to participate
in a regional program and regional allowance auctions with
other states if it results in greater carbon dioxide
emission reductions at a lower cost for Illinois' residents
over time. The Agency may conduct Illinois-only auctions if
such auctions are found to be in the best interests of
Illinois ratepayers, as determined by the Agency, and after
consultation with the Illinois Commerce Commission, taking
into account the impact on the State's goals under the
USEPA rule, State residents' health, and ratepayers.
Participation in a regional program does not relieve the
Agency of its obligations to comply with the provisions of
this Act.
(E) The Agency shall perform an environmental justice
analysis of its Plan to ensure compliance with the USEPA
rule and Federal Executive Order No. 12898, including a
cumulative impacts assessment as part of its environmental
impact assessment of the Program, following existing USEPA

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methodologies.
(F) The Agency shall develop, in coordination with the
Illinois Environmental Justice Commission, through an open
and inclusive stakeholder process, a list of Environmental
Justice Communities, defined as distinct geographic areas
of low-income and minority communities that are
disproportionately impacted by power plant pollution and
co-pollutant emissions.
(G) Any Program shall address and mitigate the
displacement of Illinois carbon dioxide emissions to other
states as well as establish appropriate spatial
restrictions on allowance trading to avoid the creation of
co-pollutant hotspots or areas with high concentrations of
co-pollutants, defined in terms of cumulative impacts.
(H) After a Program is in place, the Agency shall
require existing electric generating units located in
low-income and minority communities to install and
maintain monitors that provide detailed information on
co-pollutant emissions tied to the purchase of allowances
under the program. Information on these trading
transactions and reports on emission levels shall be
available to the public.
(I) The authority in this subsection (b-5) is
restricted to verifiable carbon dioxide emissions
allowances and credits within the power sector and does not
permit inclusion of carbon emissions allowances, credits,

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or offsets from other sectors of the economy.
(3) The Illinois Environmental Protection Agency is
authorized to invest the auction proceeds under this Act in
strategies to meet the State's goal under the USEPA rule,
create jobs in the State's renewable energy and energy
efficiency industries (as defined in the Illinois Power Agency
Act), enable workers' transition to renewable energy jobs, and
mitigate adverse health and economic impacts of fossil
fuel-fired power plants on minority and low-income
communities, in a manner consistent with this Act.
(A) A minimum of 65% of the revenue the Agency receives
from the Program (Revenue) shall be directed to the
Illinois Power Agency to spend on new energy efficiency and
renewable energy investments anywhere in the State. At
least 20% of this portion must be invested to support
energy efficiency and renewable energy investments in
low-income communities and low-income households, where
preference shall be given to investments in communities
designated as Environmental Justice Communities, followed
by investments in communities where power plants are or
have been located. A portion of these funds shall support
energy efficiency and renewable energy projects designed
to assist public institutions, including, but not limited
to, hospitals, health care facilities, long-term care
facilities, schools, preschools, daycare facilities, and
wastewater and drinking water treatment plant operators,

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with reducing their operating costs.
(B) A minimum of 5% of the Revenue shall be directed to
the Low Income Home Energy Assistance Program for bill
assistance.
(C) A minimum of 5% of the Revenue shall be directed to
assist workers in the fossil fuel-fired power plant
industry to transition to renewable energy and energy
efficiency jobs.
(D) A minimum of 10% of the Revenue shall be directed
to communities in which power plants are or have been
located to mitigate the adverse health and economic impacts
of power plants on those communities. Priority shall be
given to areas that are designated non-attainment for any
criteria pollutant under the Clean Air Act.
(E) A maximum of 5% of the Revenue shall be reserved
for program administration, pollutant and co-pollutant
monitoring as required under item (H) of paragraph (2) of
this subsection (b-5), to invest in innovative strategies
to reduce carbon emissions in the power sector, mitigate
the impacts of climate change, and to increase public
awareness of the impacts of climate change.
(4) In the development and operation of the Program, the
Illinois Environmental Protection Agency is prohibited from
doing the following:
(A) Implementing any program that leads to the
degradation of air quality, or significantly hindering the

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attainment of other air quality standards under this Act.
(B) Allocating CO2 allowances to sources covered under
the Program for free.
(C) Approving of any CO2 credits for emission
reductions, allowances, or offsets from outside the scope
of the Program.
(c) The Board may adopt regulations establishing permit
programs meeting the requirements of Sections 165 and 173 of
the Clean Air Act (42 USC 7475 and 42 USC 7503) as amended. The
Agency may adopt procedures for the administration of such
programs.
(d) No person shall:
(1) violate any provisions of Sections 111, 112, 165 or
173 of the Clean Air Act, as now or hereafter amended, or
federal regulations adopted pursuant thereto; or
(2) construct, install, modify or operate any
equipment, building, facility, source or installation
which is subject to regulation under Sections 111, 112, 165
or 173 of the Clean Air Act, as now or hereafter amended,
except in compliance with the requirements of such Sections
and federal regulations adopted pursuant thereto, and no
such action shall be undertaken (A) without a permit
granted by the Agency whenever a permit is required
pursuant to (i) this Act or Board regulations or (ii)
Section 111, 112, 165, or 173 of the Clean Air Act or
federal regulations adopted pursuant thereto or (B) in

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violation of any conditions imposed by such permit. Any
denial of such a permit or any conditions imposed in such a
permit shall be reviewable by the Board in accordance with
Section 40 of this Act.
(e) The Board shall exempt from regulation under the State
Implementation Plan for ozone the volatile organic compounds
which have been determined by the U.S. Environmental Protection
Agency to be exempt from regulation under state implementation
plans for ozone due to negligible photochemical reactivity. In
accordance with subsection (b) of Section 7.2, the Board shall
adopt regulations identical in substance to the U.S.
Environmental Protection Agency exemptions or deletion of
exemptions published in policy statements on the control of
volatile organic compounds in the Federal Register by amending
the list of exemptions to the Board's definition of volatile
organic material found at 35 Ill. Adm. Code Part 211. The
provisions and requirements of Title VII of this Act shall not
apply to regulations adopted under this subsection. Section
5-35 of the Illinois Administrative Procedure Act, relating to
procedures for rulemaking, does not apply to regulations
adopted under this subsection. However, the Board shall provide
for notice, a hearing if required by the U.S. Environmental
Protection Agency, and public comment before adopted rules are
filed with the Secretary of State. The Board may consolidate
into a single rulemaking under this subsection all such federal
policy statements published in the Federal Register within a

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period of time not to exceed 6 months.
(f) (Blank).
(Source: P.A. 97-95, eff. 7-12-11; 98-284, eff. 8-9-13.)
Section 99. Effective date. This Act takes effect upon
becoming law.
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INDEX
Statutes amended in order of appearance