Bill Text: IL SB2814 | 2015-2016 | 99th General Assembly | Chaptered

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Bill Title: Amends the Public Utilities Act. Provides that the Office of Retail Market Development shall: have the function and duties of promoting competition in the natural gas market for all classes of customers; work with all segments of the natural gas market to identify barriers to competition; and recommend to the Illinois Commerce Commission, the Governor, and the General Assembly programs or legislation needed to eliminate those barriers. Effective immediately.

Spectrum: Bipartisan Bill

Status: (Passed) 2016-12-07 - Public Act . . . . . . . . . 99-0906 [SB2814 Detail]

Download: Illinois-2015-SB2814-Chaptered.html

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Public Act 099-0906
SB2814 Enrolled LRB099 19990 EGJ 44389 b
AN ACT concerning regulation.
Be it enacted by the People of the State of Illinois,
represented in the General Assembly:
Section 1. Findings.
(a) In 2011, the General Assembly encouraged and enabled
the State's largest electric utilities to undertake
substantial investment to refurbish, rebuild, modernize, and
expand Illinois' century-old electric grid. Among those
investments were the deployment of a smart grid and advanced
metering infrastructure platform that would be accessible to
all retail customers through new, digital smart meters. This
investment, now well underway, not only allows utilities to
continue to provide safe, reliable, and affordable service to
the State's current and future utility customers, but also
empowers the citizens of this State to directly access and
participate in the rapidly emerging clean energy economy while
also presenting them with unprecedented choices in their source
of energy supply and pricing.
To ensure that the State and its citizens, including
low-income citizens, are equipped to enjoy the opportunities
and benefits of the smart grid and evolving clean energy
marketplace, the General Assembly finds and declares that
Illinois should continue in its efforts to build the grid of
the future using the smart grid and advanced metering

infrastructure platform, as well as maximize the impact of the
State's existing energy efficiency and renewable energy
portfolio standards. Specifically, the Generally Assembly
finds that:
(1) the State should encourage: the adoption and
deployment of cost-effective distributed energy resource
technologies and devices, such as photovoltaics, which can
encourage private investment in renewable energy
resources, stimulate economic growth, enhance the
continued diversification of Illinois' energy resource
mix, and protect the Illinois environment; investment in
renewable energy resources, including, but not limited to,
photovoltaic distributed generation, which should benefit
all citizens of the State, including low-income
households; and
(2) the State's existing energy efficiency standard
should be updated to ensure that customers continue to
realize increased value, to incorporate and optimize
measures enabled by the smart grid, including voltage
optimization measures, and to provide incentives for
electric utilities to achieve the energy savings goals.
(b) The General Assembly finds that low-income customers
should be included within the State's efforts to expand the use
of distributed generation technologies and devices.
Section 1.5. Zero emission standard legislative findings.

The General Assembly finds and declares:
(1) Reducing emissions of carbon dioxide and other air
pollutants, such as sulfur oxides, nitrogen oxides, and
particulate matter, is critical to improving air quality in
Illinois for Illinois residents.
(2) Sulfur oxides, nitrogen oxides, and particulate
emissions have significant adverse health effects on
persons exposed to them, and carbon dioxide emissions
result in climate change trends that could significantly
adversely impact Illinois.
(3) The existing renewable portfolio standard has been
successful in promoting the growth of renewable energy
generation to reduce air pollution in Illinois. However, to
achieve its environmental goals, Illinois must expand its
commitment to zero emission energy generation and value the
environmental attributes of zero emission generation that
currently falls outside the scope of the existing renewable
portfolio standard, including, but not limited to, nuclear
power.
(4) Preserving existing zero emission energy
generation and promoting new zero emission energy
generation is vital to placing the State on a glide path to
achieving its environmental goals and ensuring that air
quality in Illinois continues to improve.
(5) The Illinois Commerce Commission, the Illinois
Power Agency, the Illinois Environmental Protection

Agency, and the Department of Commerce and Economic
Opportunity issued a report dated January 5, 2015 titled
"Potential Nuclear Power Plant Closings in Illinois" (the
Report), which addressed the issues identified by Illinois
House Resolution 1146 of the 98th General Assembly, which,
among other things, urged the Illinois Environmental
Protection Agency to prepare a report showing how the
premature closure of existing nuclear power plants in
Illinois will affect the societal cost of increased
greenhouse gas emissions based upon the Environmental
Protection Agency's published societal cost of greenhouse
gases.
(6) The Report also included analysis from PJM
Interconnection, LLC, which identified significant adverse
consequences for electric reliability, including
significant voltage and thermal violations in the
interstate transmission network, in the event that
Illinois' existing nuclear facilities close prematurely.
The Report also found that nuclear power plants are among
the most reliable sources of energy, which means that
electricity from nuclear power plants is available on the
electric grid all hours of the day and when needed, thereby
always reducing carbon emissions.
(7) Illinois House Resolution 1146 further urged that
the Report make findings concerning potential market-based
solutions that will ensure that the premature closure of

these nuclear power plants does not occur and that the
associated dire consequences to the environment, electric
reliability, and the regional economy are averted.
(8) The Report identified potential market-based
solutions that will ensure that the premature closure of
these nuclear power plants does not occur and that the
associated dire consequences to the environment, electric
reliability, and the regional economy are averted.
The General Assembly further finds that the Social Cost of
Carbon is an appropriate valuation of the environmental
benefits provided by zero emission facilities, provided that
the valuation is subject to a price adjustment that can reduce
the price for zero emission credits below the Social Cost of
Carbon. This will ensure that the procurement of zero emission
credits remains affordable for retail customers even if energy
and capacity prices are projected to rise above 2016 levels
reflected in the baseline market price index.
The General Assembly therefore finds that it is necessary
to establish and implement a zero emission standard, which will
increase the State's reliance on zero emission energy through
the procurement of zero emission credits from zero emission
facilities, in order to achieve the State's environmental
objectives and reduce the adverse impact of emitted air
pollutants on the health and welfare of the State's citizens.
Section 3. The Illinois Administrative Procedure Act is

amended by changing Section 5-45 as follows:
(5 ILCS 100/5-45) (from Ch. 127, par. 1005-45)
Sec. 5-45. Emergency rulemaking.
(a) "Emergency" means the existence of any situation that
any agency finds reasonably constitutes a threat to the public
interest, safety, or welfare.
(b) If any agency finds that an emergency exists that
requires adoption of a rule upon fewer days than is required by
Section 5-40 and states in writing its reasons for that
finding, the agency may adopt an emergency rule without prior
notice or hearing upon filing a notice of emergency rulemaking
with the Secretary of State under Section 5-70. The notice
shall include the text of the emergency rule and shall be
published in the Illinois Register. Consent orders or other
court orders adopting settlements negotiated by an agency may
be adopted under this Section. Subject to applicable
constitutional or statutory provisions, an emergency rule
becomes effective immediately upon filing under Section 5-65 or
at a stated date less than 10 days thereafter. The agency's
finding and a statement of the specific reasons for the finding
shall be filed with the rule. The agency shall take reasonable
and appropriate measures to make emergency rules known to the
persons who may be affected by them.
(c) An emergency rule may be effective for a period of not
longer than 150 days, but the agency's authority to adopt an

identical rule under Section 5-40 is not precluded. No
emergency rule may be adopted more than once in any 24-month 24
month period, except that this limitation on the number of
emergency rules that may be adopted in a 24-month 24 month
period does not apply to (i) emergency rules that make
additions to and deletions from the Drug Manual under Section
5-5.16 of the Illinois Public Aid Code or the generic drug
formulary under Section 3.14 of the Illinois Food, Drug and
Cosmetic Act, (ii) emergency rules adopted by the Pollution
Control Board before July 1, 1997 to implement portions of the
Livestock Management Facilities Act, (iii) emergency rules
adopted by the Illinois Department of Public Health under
subsections (a) through (i) of Section 2 of the Department of
Public Health Act when necessary to protect the public's
health, (iv) emergency rules adopted pursuant to subsection (n)
of this Section, (v) emergency rules adopted pursuant to
subsection (o) of this Section, or (vi) emergency rules adopted
pursuant to subsection (c-5) of this Section. Two or more
emergency rules having substantially the same purpose and
effect shall be deemed to be a single rule for purposes of this
Section.
(c-5) To facilitate the maintenance of the program of group
health benefits provided to annuitants, survivors, and retired
employees under the State Employees Group Insurance Act of
1971, rules to alter the contributions to be paid by the State,
annuitants, survivors, retired employees, or any combination

of those entities, for that program of group health benefits,
shall be adopted as emergency rules. The adoption of those
rules shall be considered an emergency and necessary for the
public interest, safety, and welfare.
(d) In order to provide for the expeditious and timely
implementation of the State's fiscal year 1999 budget,
emergency rules to implement any provision of Public Act 90-587
or 90-588 or any other budget initiative for fiscal year 1999
may be adopted in accordance with this Section by the agency
charged with administering that provision or initiative,
except that the 24-month limitation on the adoption of
emergency rules and the provisions of Sections 5-115 and 5-125
do not apply to rules adopted under this subsection (d). The
adoption of emergency rules authorized by this subsection (d)
shall be deemed to be necessary for the public interest,
safety, and welfare.
(e) In order to provide for the expeditious and timely
implementation of the State's fiscal year 2000 budget,
emergency rules to implement any provision of Public Act 91-24
or any other budget initiative for fiscal year 2000 may be
adopted in accordance with this Section by the agency charged
with administering that provision or initiative, except that
the 24-month limitation on the adoption of emergency rules and
the provisions of Sections 5-115 and 5-125 do not apply to
rules adopted under this subsection (e). The adoption of
emergency rules authorized by this subsection (e) shall be

deemed to be necessary for the public interest, safety, and
welfare.
(f) In order to provide for the expeditious and timely
implementation of the State's fiscal year 2001 budget,
emergency rules to implement any provision of Public Act 91-712
or any other budget initiative for fiscal year 2001 may be
adopted in accordance with this Section by the agency charged
with administering that provision or initiative, except that
the 24-month limitation on the adoption of emergency rules and
the provisions of Sections 5-115 and 5-125 do not apply to
rules adopted under this subsection (f). The adoption of
emergency rules authorized by this subsection (f) shall be
deemed to be necessary for the public interest, safety, and
welfare.
(g) In order to provide for the expeditious and timely
implementation of the State's fiscal year 2002 budget,
emergency rules to implement any provision of Public Act 92-10
or any other budget initiative for fiscal year 2002 may be
adopted in accordance with this Section by the agency charged
with administering that provision or initiative, except that
the 24-month limitation on the adoption of emergency rules and
the provisions of Sections 5-115 and 5-125 do not apply to
rules adopted under this subsection (g). The adoption of
emergency rules authorized by this subsection (g) shall be
deemed to be necessary for the public interest, safety, and
welfare.

(h) In order to provide for the expeditious and timely
implementation of the State's fiscal year 2003 budget,
emergency rules to implement any provision of Public Act 92-597
or any other budget initiative for fiscal year 2003 may be
adopted in accordance with this Section by the agency charged
with administering that provision or initiative, except that
the 24-month limitation on the adoption of emergency rules and
the provisions of Sections 5-115 and 5-125 do not apply to
rules adopted under this subsection (h). The adoption of
emergency rules authorized by this subsection (h) shall be
deemed to be necessary for the public interest, safety, and
welfare.
(i) In order to provide for the expeditious and timely
implementation of the State's fiscal year 2004 budget,
emergency rules to implement any provision of Public Act 93-20
or any other budget initiative for fiscal year 2004 may be
adopted in accordance with this Section by the agency charged
with administering that provision or initiative, except that
the 24-month limitation on the adoption of emergency rules and
the provisions of Sections 5-115 and 5-125 do not apply to
rules adopted under this subsection (i). The adoption of
emergency rules authorized by this subsection (i) shall be
deemed to be necessary for the public interest, safety, and
welfare.
(j) In order to provide for the expeditious and timely
implementation of the provisions of the State's fiscal year

2005 budget as provided under the Fiscal Year 2005 Budget
Implementation (Human Services) Act, emergency rules to
implement any provision of the Fiscal Year 2005 Budget
Implementation (Human Services) Act may be adopted in
accordance with this Section by the agency charged with
administering that provision, except that the 24-month
limitation on the adoption of emergency rules and the
provisions of Sections 5-115 and 5-125 do not apply to rules
adopted under this subsection (j). The Department of Public Aid
may also adopt rules under this subsection (j) necessary to
administer the Illinois Public Aid Code and the Children's
Health Insurance Program Act. The adoption of emergency rules
authorized by this subsection (j) shall be deemed to be
necessary for the public interest, safety, and welfare.
(k) In order to provide for the expeditious and timely
implementation of the provisions of the State's fiscal year
2006 budget, emergency rules to implement any provision of
Public Act 94-48 or any other budget initiative for fiscal year
2006 may be adopted in accordance with this Section by the
agency charged with administering that provision or
initiative, except that the 24-month limitation on the adoption
of emergency rules and the provisions of Sections 5-115 and
5-125 do not apply to rules adopted under this subsection (k).
The Department of Healthcare and Family Services may also adopt
rules under this subsection (k) necessary to administer the
Illinois Public Aid Code, the Senior Citizens and Persons with

Disabilities Property Tax Relief Act, the Senior Citizens and
Disabled Persons Prescription Drug Discount Program Act (now
the Illinois Prescription Drug Discount Program Act), and the
Children's Health Insurance Program Act. The adoption of
emergency rules authorized by this subsection (k) shall be
deemed to be necessary for the public interest, safety, and
welfare.
(l) In order to provide for the expeditious and timely
implementation of the provisions of the State's fiscal year
2007 budget, the Department of Healthcare and Family Services
may adopt emergency rules during fiscal year 2007, including
rules effective July 1, 2007, in accordance with this
subsection to the extent necessary to administer the
Department's responsibilities with respect to amendments to
the State plans and Illinois waivers approved by the federal
Centers for Medicare and Medicaid Services necessitated by the
requirements of Title XIX and Title XXI of the federal Social
Security Act. The adoption of emergency rules authorized by
this subsection (l) shall be deemed to be necessary for the
public interest, safety, and welfare.
(m) In order to provide for the expeditious and timely
implementation of the provisions of the State's fiscal year
2008 budget, the Department of Healthcare and Family Services
may adopt emergency rules during fiscal year 2008, including
rules effective July 1, 2008, in accordance with this
subsection to the extent necessary to administer the

Department's responsibilities with respect to amendments to
the State plans and Illinois waivers approved by the federal
Centers for Medicare and Medicaid Services necessitated by the
requirements of Title XIX and Title XXI of the federal Social
Security Act. The adoption of emergency rules authorized by
this subsection (m) shall be deemed to be necessary for the
public interest, safety, and welfare.
(n) In order to provide for the expeditious and timely
implementation of the provisions of the State's fiscal year
2010 budget, emergency rules to implement any provision of
Public Act 96-45 or any other budget initiative authorized by
the 96th General Assembly for fiscal year 2010 may be adopted
in accordance with this Section by the agency charged with
administering that provision or initiative. The adoption of
emergency rules authorized by this subsection (n) shall be
deemed to be necessary for the public interest, safety, and
welfare. The rulemaking authority granted in this subsection
(n) shall apply only to rules promulgated during Fiscal Year
2010.
(o) In order to provide for the expeditious and timely
implementation of the provisions of the State's fiscal year
2011 budget, emergency rules to implement any provision of
Public Act 96-958 or any other budget initiative authorized by
the 96th General Assembly for fiscal year 2011 may be adopted
in accordance with this Section by the agency charged with
administering that provision or initiative. The adoption of

emergency rules authorized by this subsection (o) is deemed to
be necessary for the public interest, safety, and welfare. The
rulemaking authority granted in this subsection (o) applies
only to rules promulgated on or after July 1, 2010 (the
effective date of Public Act 96-958) through June 30, 2011.
(p) In order to provide for the expeditious and timely
implementation of the provisions of Public Act 97-689,
emergency rules to implement any provision of Public Act 97-689
may be adopted in accordance with this subsection (p) by the
agency charged with administering that provision or
initiative. The 150-day limitation of the effective period of
emergency rules does not apply to rules adopted under this
subsection (p), and the effective period may continue through
June 30, 2013. The 24-month limitation on the adoption of
emergency rules does not apply to rules adopted under this
subsection (p). The adoption of emergency rules authorized by
this subsection (p) is deemed to be necessary for the public
interest, safety, and welfare.
(q) In order to provide for the expeditious and timely
implementation of the provisions of Articles 7, 8, 9, 11, and
12 of Public Act 98-104, emergency rules to implement any
provision of Articles 7, 8, 9, 11, and 12 of Public Act 98-104
may be adopted in accordance with this subsection (q) by the
agency charged with administering that provision or
initiative. The 24-month limitation on the adoption of
emergency rules does not apply to rules adopted under this

subsection (q). The adoption of emergency rules authorized by
this subsection (q) is deemed to be necessary for the public
interest, safety, and welfare.
(r) In order to provide for the expeditious and timely
implementation of the provisions of Public Act 98-651,
emergency rules to implement Public Act 98-651 may be adopted
in accordance with this subsection (r) by the Department of
Healthcare and Family Services. The 24-month limitation on the
adoption of emergency rules does not apply to rules adopted
under this subsection (r). The adoption of emergency rules
authorized by this subsection (r) is deemed to be necessary for
the public interest, safety, and welfare.
(s) In order to provide for the expeditious and timely
implementation of the provisions of Sections 5-5b.1 and 5A-2 of
the Illinois Public Aid Code, emergency rules to implement any
provision of Section 5-5b.1 or Section 5A-2 of the Illinois
Public Aid Code may be adopted in accordance with this
subsection (s) by the Department of Healthcare and Family
Services. The rulemaking authority granted in this subsection
(s) shall apply only to those rules adopted prior to July 1,
2015. Notwithstanding any other provision of this Section, any
emergency rule adopted under this subsection (s) shall only
apply to payments made for State fiscal year 2015. The adoption
of emergency rules authorized by this subsection (s) is deemed
to be necessary for the public interest, safety, and welfare.
(t) In order to provide for the expeditious and timely

implementation of the provisions of Article II of Public Act
99-6, emergency rules to implement the changes made by Article
II of Public Act 99-6 to the Emergency Telephone System Act may
be adopted in accordance with this subsection (t) by the
Department of State Police. The rulemaking authority granted in
this subsection (t) shall apply only to those rules adopted
prior to July 1, 2016. The 24-month limitation on the adoption
of emergency rules does not apply to rules adopted under this
subsection (t). The adoption of emergency rules authorized by
this subsection (t) is deemed to be necessary for the public
interest, safety, and welfare.
(u) In order to provide for the expeditious and timely
implementation of the provisions of the Burn Victims Relief
Act, emergency rules to implement any provision of the Act may
be adopted in accordance with this subsection (u) by the
Department of Insurance. The rulemaking authority granted in
this subsection (u) shall apply only to those rules adopted
prior to December 31, 2015. The adoption of emergency rules
authorized by this subsection (u) is deemed to be necessary for
the public interest, safety, and welfare.
(v) In order to provide for the expeditious and timely
implementation of the provisions of Public Act 99-516 this
amendatory Act of the 99th General Assembly, emergency rules to
implement Public Act 99-516 this amendatory Act of the 99th
General Assembly may be adopted in accordance with this
subsection (v) by the Department of Healthcare and Family

Services. The 24-month limitation on the adoption of emergency
rules does not apply to rules adopted under this subsection
(v). The adoption of emergency rules authorized by this
subsection (v) is deemed to be necessary for the public
interest, safety, and welfare.
(w) (v) In order to provide for the expeditious and timely
implementation of the provisions of Public Act 99-796 this
amendatory Act of the 99th General Assembly, emergency rules to
implement the changes made by Public Act 99-796 this amendatory
Act of the 99th General Assembly may be adopted in accordance
with this subsection (w) (v) by the Adjutant General. The
adoption of emergency rules authorized by this subsection (w)
(v) is deemed to be necessary for the public interest, safety,
and welfare.
(x) In order to provide for the expeditious and timely
implementation of the provisions of this amendatory Act of the
99th General Assembly, emergency rules to implement subsection
(i) of Section 16-115D, subsection (g) of Section 16-128A, and
subsection (a) of Section 16-128B of the Public Utilities Act
may be adopted in accordance with this subsection (x) by the
Illinois Commerce Commission. The rulemaking authority granted
in this subsection (x) shall apply only to those rules adopted
within 180 days after the effective date of this amendatory Act
of the 99th General Assembly. The adoption of emergency rules
authorized by this subsection (x) is deemed to be necessary for
the public interest, safety, and welfare.

(Source: P.A. 98-104, eff. 7-22-13; 98-463, eff. 8-16-13;
98-651, eff. 6-16-14; 99-2, eff. 3-26-15; 99-6, eff. 1-1-16;
99-143, eff. 7-27-15; 99-455, eff. 1-1-16; 99-516, eff.
6-30-16; 99-642, eff. 7-28-16; 99-796, eff. 1-1-17; revised
9-21-16.)
Section 5. The Illinois Power Agency Act is amended by
changing Sections 1-5, 1-10, 1-20, 1-25, 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) (Blank). 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) (Blank). 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) It To protect against this threat to economic
well-being, health, and safety it is necessary to improve
the process of procuring electricity to serve Illinois
residents, to promote investment in energy efficiency and
demand-response measures, and to maintain and support
development of clean coal technologies, generation
resources that operate at all hours of the day and under
all weather conditions, zero emission facilities, 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 and
zero emission credits from zero emission facilities 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. Developing
new renewable energy resources in Illinois, including
brownfield solar projects and community solar projects,
will help to diversify Illinois electricity supply, avoid
and reduce pollution, reduce peak demand, and enhance
public health and well-being of Illinois residents.
(7) Developing community solar projects in Illinois

will help to expand access to renewable energy resources to
more Illinois residents.
(8) Developing brownfield solar projects in Illinois
will help return blighted or contaminated land to
productive use while enhancing public health and the
well-being of Illinois residents.
(9) (7) Energy efficiency, demand-response measures,
zero emission energy, and renewable energy are resources
currently underused in Illinois. These resources should be
used, when cost effective, to reduce costs to consumers,
improve reliability, and improve environmental quality and
public health.
(10) (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.
(11) (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 structural and procedural safeguards are not in
place to ensure independence, insulation, oversight, and
transparency.
(12) (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 and,
beginning with the delivery year commencing June 1, 2017,
zero emission credits from zero emission facilities
sufficient to achieve the standards specified in this Act.
(B) Conduct the competitive procurement processes
identified in this Act to procure the supply resources
identified in the procurement plan.
(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.
(H) Implement renewable energy procurement and
training programs throughout the State to diversify
Illinois electricity supply, improve reliability, avoid
and reduce pollution, reduce peak demand, and enhance
public health and well-being of Illinois residents,
including low-income residents.
(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.
"Agency loan agreement" means any agreement pursuant to
which the Illinois Finance Authority agrees to loan the
proceeds of revenue bonds issued with respect to a project to
the Agency upon terms providing for loan repayment installments
at least sufficient to pay when due all principal of, interest
and premium, if any, on those revenue bonds, and providing for
maintenance, insurance, and other matters in respect of the
project.
"Authority" means the Illinois Finance Authority.
"Brownfield site photovoltaic project" means photovoltaics
that are:
(1) interconnected to an electric utility as defined in
this Section, a municipal utility as defined in this
Section, a public utility as defined in Section 3-105 of
the Public Utilities Act, or an electric cooperative, as
defined in Section 3-119 of the Public Utilities Act; and
(2) located at a site that is regulated by any of the
following entities under the following programs:
(A) the United States Environmental Protection
Agency under the federal Comprehensive Environmental
Response, Compensation, and Liability Act of 1980, as
amended;
(B) the United States Environmental Protection
Agency under the Corrective Action Program of the

federal Resource Conservation and Recovery Act, as
amended;
(C) the Illinois Environmental Protection Agency
under the Illinois Site Remediation Program; or
(D) the Illinois Environmental Protection Agency
under the Illinois Solid Waste Program.
"Clean coal facility" means an electric generating
facility that uses primarily coal as a feedstock and that
captures and sequesters carbon dioxide emissions at the
following levels: at least 50% of the total carbon dioxide
emissions that the facility would otherwise emit if, at the
time construction commences, the facility is scheduled to
commence operation before 2016, at least 70% of the total
carbon dioxide emissions that the facility would otherwise emit
if, at the time construction commences, the facility is
scheduled to commence operation during 2016 or 2017, and at
least 90% of the total carbon dioxide emissions that the
facility would otherwise emit if, at the time construction
commences, the facility is scheduled to commence operation
after 2017. The power block of the clean coal facility shall
not exceed allowable emission rates for sulfur dioxide,
nitrogen oxides, carbon monoxide, particulates and mercury for
a natural gas-fired combined-cycle facility the same size as
and in the same location as the clean coal facility at the time
the clean coal facility obtains an approved air permit. All
coal used by a clean coal facility shall have high volatile

bituminous rank and greater than 1.7 pounds of sulfur per
million btu content, unless the clean coal facility does not
use gasification technology and was operating as a conventional
coal-fired electric generating facility on June 1, 2009 (the
effective date of Public Act 95-1027).
"Clean coal SNG brownfield facility" means a facility that
(1) has commenced construction by July 1, 2015 on an urban
brownfield site in a municipality with at least 1,000,000
residents; (2) uses a gasification process to produce
substitute natural gas; (3) uses coal as at least 50% of the
total feedstock over the term of any sourcing agreement with a
utility and the remainder of the feedstock may be either
petroleum coke or coal, with all such coal having a high
bituminous rank and greater than 1.7 pounds of sulfur per
million Btu content unless the facility reasonably determines
that it is necessary to use additional petroleum coke to
deliver additional consumer savings, in which case the facility
shall use coal for at least 35% of the total feedstock over the
term of any sourcing agreement; and (4) captures and sequesters
at least 85% of the total carbon dioxide emissions that the
facility would otherwise emit.
"Clean coal SNG facility" means a facility that uses a
gasification process to produce substitute natural gas, that
sequesters at least 90% of the total carbon dioxide emissions
that the facility would otherwise emit, that uses at least 90%
coal as a feedstock, with all such coal having a high

bituminous rank and greater than 1.7 pounds of sulfur per
million btu content, and that has a valid and effective permit
to construct emission sources and air pollution control
equipment and approval with respect to the federal regulations
for Prevention of Significant Deterioration of Air Quality
(PSD) for the plant pursuant to the federal Clean Air Act;
provided, however, a clean coal SNG brownfield facility shall
not be a clean coal SNG facility.
"Commission" means the Illinois Commerce Commission.
"Community renewable generation project" means an electric
generating facility that:
(1) is powered by wind, solar thermal energy,
photovoltaic cells or panels, biodiesel, crops and
untreated and unadulterated organic waste biomass, tree
waste, and hydropower that does not involve new
construction or significant expansion of hydropower dams;
(2) is interconnected at the distribution system level
of an electric utility as defined in this Section, a
municipal utility as defined in this Section that owns or
operates electric distribution facilities, a public
utility as defined in Section 3-105 of the Public Utilities
Act, or an electric cooperative, as defined in Section
3-119 of the Public Utilities Act;
(3) credits the value of electricity generated by the
facility to the subscribers of the facility; and
(4) is limited in nameplate capacity to less than or

equal to 2,000 kilowatts.
"Costs incurred in connection with the development and
construction of a facility" means:
(1) the cost of acquisition of all real property,
fixtures, and improvements in connection therewith and
equipment, personal property, and other property, rights,
and easements acquired that are deemed necessary for the
operation and maintenance of the facility;
(2) financing costs with respect to bonds, notes, and
other evidences of indebtedness of the Agency;
(3) all origination, commitment, utilization,
facility, placement, underwriting, syndication, credit
enhancement, and rating agency fees;
(4) engineering, design, procurement, consulting,
legal, accounting, title insurance, survey, appraisal,
escrow, trustee, collateral agency, interest rate hedging,
interest rate swap, capitalized interest, contingency, as
required by lenders, and other financing costs, and other
expenses for professional services; and
(5) the costs of plans, specifications, site study and
investigation, installation, surveys, other Agency costs
and estimates of costs, and other expenses necessary or
incidental to determining the feasibility of any project,
together with such other expenses as may be necessary or
incidental to the financing, insuring, acquisition, and
construction of a specific project and starting up,

commissioning, and placing that project in operation.
"Delivery services" has the same definition as found in
Section 16-102 of the Public Utilities Act.
"Delivery year" means the consecutive 12-month period
beginning June 1 of a given year and ending May 31 of the
following year.
"Department" means the Department of Commerce and Economic
Opportunity.
"Director" means the Director of the Illinois Power Agency.
"Demand-response" means measures that decrease peak
electricity demand or shift demand from peak to off-peak
periods.
"Distributed renewable energy generation device" means a
device that is:
(1) powered by wind, solar thermal energy,
photovoltaic cells or 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 this Section that owns or operates electric
distribution facilities 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 less than or equal
to no more than 2,000 kilowatts.
"Energy efficiency" means measures that reduce the amount
of electricity or natural gas consumed in order required to
achieve a given end use. "Energy efficiency" includes voltage
optimization measures that optimize the voltage at points on
the electric distribution voltage system and thereby reduce
electricity consumption by electric customers' end use
devices. "Energy efficiency" also includes measures that
reduce the total Btus of electricity, and natural gas, and
other fuels needed to meet the end use or uses.
"Electric utility" has the same definition as found in
Section 16-102 of the Public Utilities Act.
"Facility" means an electric generating unit or a
co-generating unit that produces electricity along with
related equipment necessary to connect the facility to an
electric transmission or distribution system.
"Governmental aggregator" means one or more units of local
government that individually or collectively procure
electricity to serve residential retail electrical loads
located within its or their jurisdiction.
"Local government" means a unit of local government as

defined in Section 1 of Article VII of the Illinois
Constitution.
"Municipality" means a city, village, or incorporated
town.
"Municipal utility" means a public utility owned and
operated by any subdivision or municipal corporation of this
State.
"Nameplate capacity" means the aggregate inverter
nameplate capacity in kilowatts AC.
"Person" means any natural person, firm, partnership,
corporation, either domestic or foreign, company, association,
limited liability company, joint stock company, or association
and includes any trustee, receiver, assignee, or personal
representative thereof.
"Project" means the planning, bidding, and construction of
a facility.
"Public utility" has the same definition as found in
Section 3-105 of the Public Utilities Act.
"Real property" means any interest in land together with
all structures, fixtures, and improvements thereon, including
lands under water and riparian rights, any easements,
covenants, licenses, leases, rights-of-way, uses, and other
interests, together with any liens, judgments, mortgages, or
other claims or security interests related to real property.
"Renewable energy credit" means a tradable credit that
represents the environmental attributes of one megawatt hour a

certain amount of energy produced from a renewable energy
resource.
"Renewable energy resources" includes energy and its
associated renewable energy credit or renewable energy credits
from wind, solar thermal energy, photovoltaic cells and panels,
biodiesel, anaerobic digestion, crops and untreated and
unadulterated organic waste biomass, tree waste, and
hydropower that does not involve new construction or
significant expansion of hydropower dams, 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.
"Retail customer" has the same definition as found in
Section 16-102 of the Public Utilities Act.
"Revenue bond" means any bond, note, or other evidence of
indebtedness issued by the Authority, the principal and
interest of which is payable solely from revenues or income
derived from any project or activity of the Agency.
"Sequester" means permanent storage of carbon dioxide by
injecting it into a saline aquifer, a depleted gas reservoir,

or an oil reservoir, directly or through an enhanced oil
recovery process that may involve intermediate storage,
regardless of whether these activities are conducted by a clean
coal facility, a clean coal SNG facility, a clean coal SNG
brownfield facility, or a party with which a clean coal
facility, clean coal SNG facility, or clean coal SNG brownfield
facility has contracted for such purposes.
"Service area" has the same definition as found in Section
16-102 of the Public Utilities Act.
"Sourcing agreement" means (i) in the case of an electric
utility, an agreement between the owner of a clean coal
facility and such electric utility, which agreement shall have
terms and conditions meeting the requirements of paragraph (3)
of subsection (d) of Section 1-75, (ii) in the case of an
alternative retail electric supplier, an agreement between the
owner of a clean coal facility and such alternative retail
electric supplier, which agreement shall have terms and
conditions meeting the requirements of Section 16-115(d)(5) of
the Public Utilities Act, and (iii) in case of a gas utility,
an agreement between the owner of a clean coal SNG brownfield
facility and the gas utility, which agreement shall have the
terms and conditions meeting the requirements of subsection
(h-1) of Section 9-220 of the Public Utilities Act.
"Subscriber" means a person who (i) takes delivery service
from an electric utility, and (ii) has a subscription of no
less than 200 watts to a community renewable generation project

that is located in the electric utility's service area. No
subscriber's subscriptions may total more than 40% of the
nameplate capacity of an individual community renewable
generation project. Entities that are affiliated by virtue of a
common parent shall not represent multiple subscriptions that
total more than 40% of the nameplate capacity of an individual
community renewable generation project.
"Subscription" means an interest in a community renewable
generation project expressed in kilowatts, which is sized
primarily to offset part or all of the subscriber's electricity
usage.
"Substitute natural gas" or "SNG" means a gas manufactured
by gasification of hydrocarbon feedstock, which is
substantially interchangeable in use and distribution with
conventional natural gas.
"Total resource cost test" or "TRC test" means a standard
that is met if, for an investment in energy efficiency or
demand-response measures, the benefit-cost ratio is greater
than one. The benefit-cost ratio is the ratio of the net
present value of the total benefits of the program to the net
present value of the total costs as calculated over the
lifetime of the measures. A total resource cost test compares
the sum of avoided electric utility costs, representing the
benefits that accrue to the system and the participant in the
delivery of those efficiency measures and including avoided
costs associated with reduced use of natural gas or other

fuels, avoided costs associated with reduced water
consumption, and avoided costs associated with reduced
operation and maintenance costs, as well as other quantifiable
societal benefits, including avoided natural gas utility
costs, 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. In discounting
future societal costs and benefits for the purpose of
calculating net present values, a societal discount rate based
on actual, long-term Treasury bond yields should be used.
Notwithstanding anything to the contrary, the TRC test shall
not include or take into account a calculation of market price
suppression effects or demand reduction induced price effects.
"Utility-scale solar project" means an electric generating
facility that:
(1) generates electricity using photovoltaic cells;
and
(2) has a nameplate capacity that is greater than 2,000
kilowatts.

"Utility-scale wind project" means an electric generating
facility that:
(1) generates electricity using wind; and
(2) has a nameplate capacity that is greater than 2,000
kilowatts.
"Zero emission credit" means a tradable credit that
represents the environmental attributes of one megawatt hour of
energy produced from a zero emission facility.
"Zero emission facility" means a facility that: (1) is
fueled by nuclear power; and (2) is interconnected with PJM
Interconnection, LLC or the Midcontinent Independent System
Operator, Inc., or their successors.
(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.
Except as provided in paragraph (1.5) of this subsection
(a), the electricity The procurement plans shall be updated
on an annual basis and shall include electricity generated
from renewable resources sufficient to achieve the
standards specified in this Act. Beginning with the
delivery year commencing June 1, 2017, develop procurement
plans to include zero emission credits generated from zero
emission facilities sufficient to achieve the standards
specified in this Act.
(1.5) Develop a long-term renewable resources
procurement plan in accordance with subsection (c) of
Section 1-75 of this Act for renewable energy credits in
amounts sufficient to achieve the standards specified in
this Act for delivery years commencing June 1, 2017 and for
the programs and renewable energy credits specified in
Section 1-56 of this Act. Electricity procurement plans for
delivery years commencing after May 31, 2017, shall not
include procurement of renewable energy resources.
(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, and, for the delivery year commencing
June 1, 2017, conduct procurement processes to procure zero

emission credits from zero emission facilities, under
subsection (d-5) of Section 1-75 of this Act.
(2.5) Beginning with the procurement for the 2017
delivery year, conduct competitive procurement processes
and implement programs to procure renewable energy credits
identified in the long-term renewable resources
procurement plan developed and approved under subsection
(c) of Section 1-75 of this Act and Section 16-111.5 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
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,
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,
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
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.
(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.
(27) To request, review and accept proposals, execute
contracts, purchase renewable energy credits and otherwise
dedicate funds from the Illinois Power Agency Renewable
Energy Resources Fund to create and carry out the
objectives of the Illinois Solar for All program in
accordance with Section 1-56 of this Act.
(Source: P.A. 96-784, eff. 8-28-09; 96-1000, eff. 7-2-10;
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 3855/1-25)
Sec. 1-25. Agency subject to other laws. Unless otherwise
stated, the Agency is subject to the provisions of all
applicable laws, including but not limited to, each of the
following:
(1) The State Records Act.

(2) The Illinois Procurement Code, except that the
Illinois Procurement Code does not apply to the hiring or
payment of procurement administrators, or procurement
planning consultants, third-party program managers, or
other persons who will implement the programs described in
Sections 1-56 and pursuant to Section 1-75 of the Illinois
Power Agency Act.
(3) The Freedom of Information Act.
(4) The State Property Control Act.
(5) (Blank).
(6) The State Officials and Employees Ethics Act.
(Source: P.A. 97-618, eff. 10-26-11.)
(20 ILCS 3855/1-56)
Sec. 1-56. Illinois Power Agency Renewable Energy
Resources Fund; Illinois Solar for All Program.
(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 as described in this
subsection (b), provided that the changes to this subsection
(b) made by this amendatory Act of the 99th General Assembly
shall not interfere with existing contracts under this Section.
(1) The Illinois Power Agency Renewable Energy
Resources Fund shall be used to purchase renewable energy
credits according to any approved procurement plan

developed by the Agency prior to June 1, 2017.
(2) The Illinois Power Agency Renewable Energy
Resources Fund shall also be used to create the Illinois
Solar for All Program, which shall include incentives for
low-income distributed generation and community solar
projects, and other associated approved expenditures. The
objectives of the Illinois Solar for All Program are to
bring photovoltaics to low-income communities in this
State in a manner that maximizes the development of new
photovoltaic generating facilities, to create a long-term,
low-income solar marketplace throughout this State, to
integrate, through interaction with stakeholders, with
existing energy efficiency initiatives, and to minimize
administrative costs. The Agency shall include a
description of its proposed approach to the design,
administration, implementation and evaluation of the
Illinois Solar for All Program, as part of the long-term
renewable resources procurement plan authorized by
subsection (c) of Section 1-75 of this Act, and the program
shall be designed to grow the low-income solar market. The
Agency or utility, as applicable, shall purchase renewable
energy credits from the (i) photovoltaic distributed
renewable energy generation projects and (ii) community
solar projects that are procured under procurement
processes authorized by the long-term renewable resources
procurement plans approved by the Commission.

The Illinois Solar for All Program shall include the
program offerings described in subparagraphs (A) through
(D) of this paragraph (2), which the Agency shall implement
through contracts with third-party providers and, subject
to appropriation, pay the approximate amounts identified
using monies available in the Illinois Power Agency
Renewable Energy Resources Fund. Each contract that
provides for the installation of solar facilities shall
provide that the solar facilities will produce energy and
economic benefits, at a level determined by the Agency to
be reasonable, for the participating low income customers.
The monies available in the Illinois Power Agency Renewable
Energy Resources Fund and not otherwise committed to
contracts executed under subsection (i) of this Section
shall be allocated among the programs described in this
paragraph (2), as follows: 22.5% of these funds shall be
allocated to programs described in subparagraph (A) of this
paragraph (2), 37.5% of these funds shall be allocated to
programs described in subparagraph (B) of this paragraph
(2), 15% of these funds shall be allocated to programs
described in subparagraph (C) of this paragraph (2), and
25% of these funds, but in no event more than $50,000,000,
shall be allocated to programs described in subparagraph
(D) of this paragraph (2). The allocation of funds among
subparagraphs (A), (B), or (C) of this paragraph (2) may be
changed if the Agency or administrator, through delegated

authority, determines incentives in subparagraphs (A),
(B), or (C) of this paragraph (2) have not been adequately
subscribed to fully utilize the Illinois Power Agency
Renewable Energy Resources Fund. The determination shall
include input through a stakeholder process. The program
offerings described in subparagraphs (A) through (D) of
this paragraph (2) shall also be implemented through
contracts funded from such additional amounts as are
allocated to one or more of the programs in the long-term
renewable resources procurement plans as specified in
subsection (c) of Section 1-75 of this Act and subparagraph
(O) of paragraph (1) of such subsection (c).
Contracts that will be paid with funds in the Illinois
Power Agency Renewable Energy Resources Fund shall be
executed by the Agency. Contracts that will be paid with
funds collected by an electric utility shall be executed by
the electric utility.
Contracts under the Illinois Solar for All Program
shall include an approach, as set forth in the long-term
renewable resources procurement plans, to ensure the
wholesale market value of the energy is credited to
participating low-income customers or organizations and to
ensure tangible economic benefits flow directly to program
participants, except in the case of low-income
multi-family housing where the low-income customer does
not directly pay for energy. Priority shall be given to

projects that demonstrate meaningful involvement of
low-income community members in designing the initial
proposals. Acceptable proposals to implement projects must
demonstrate the applicant's ability to conduct initial
community outreach, education, and recruitment of
low-income participants in the community. Projects must
include job training opportunities if available, and shall
endeavor to coordinate with the job training programs
described in paragraph (1) of subsection (a) of Section
16-108.12 of the Public Utilities Act.
(A) Low-income distributed generation incentive.
This program will provide incentives to low-income
customers, either directly or through solar providers,
to increase the participation of low-income households
in photovoltaic on-site distributed generation.
Companies participating in this program that install
solar panels shall commit to hiring job trainees for a
portion of their low-income installations, and an
administrator shall facilitate partnering the
companies that install solar panels with entities that
provide solar panel installation job training. It is a
goal of this program that a minimum of 25% of the
incentives for this program be allocated to projects
located within environmental justice communities.
Contracts entered into under this paragraph may be
entered into with an entity that will develop and

administer the program and shall also include
contracts for renewable energy credits from the
photovoltaic distributed generation that is the
subject of the program, as set forth in the long-term
renewable resources procurement plan.
(B) Low-Income Community Solar Project Initiative.
Incentives shall be offered to low-income customers,
either directly or through developers, to increase the
participation of low-income subscribers of community
solar projects. The developer of each project shall
identify its partnership with community stakeholders
regarding the location, development, and participation
in the project, provided that nothing shall preclude a
project from including an anchor tenant that does not
qualify as low-income. Incentives should also be
offered to community solar projects that are 100%
low-income subscriber owned, which includes low-income
households, not-for-profit organizations, and
affordable housing owners. It is a goal of this program
that a minimum of 25% of the incentives for this
program be allocated to community photovoltaic
projects in environmental justice communities.
Contracts entered into under this paragraph may be
entered into with developers and shall also include
contracts for renewable energy credits related to the
program.

(C) Incentives for non-profits and public
facilities. Under this program funds shall be used to
support on-site photovoltaic distributed renewable
energy generation devices to serve the load associated
with not-for-profit customers and to support
photovoltaic distributed renewable energy generation
that uses photovoltaic technology to serve the load
associated with public sector customers taking service
at public buildings. It is a goal of this program that
at least 25% of the incentives for this program be
allocated to projects located in environmental justice
communities. Contracts entered into under this
paragraph may be entered into with an entity that will
develop and administer the program or with developers
and shall also include contracts for renewable energy
credits related to the program.
(D) Low-Income Community Solar Pilot Projects.
Under this program, persons, including, but not
limited to, electric utilities, shall propose pilot
community solar projects. Community solar projects
proposed under this subparagraph (D) may exceed 2,000
kilowatts in nameplate capacity, but the amount paid
per project under this program may not exceed
$20,000,000. Pilot projects must result in economic
benefits for the members of the community in which the
project will be located. The proposed pilot project

must include a partnership with at least one
community-based organization. Approved pilot projects
shall be competitively bid by the Agency, subject to
fair and equitable guidelines developed by the Agency.
Funding available under this subparagraph (D) may not
be distributed solely to a utility, and at least some
funds under this subparagraph (D) must include a
project partnership that includes community ownership
by the project subscribers. Contracts entered into
under this paragraph may be entered into with an entity
that will develop and administer the program or with
developers and shall also include contracts for
renewable energy credits related to the program. A
project proposed by a utility that is implemented under
this subparagraph (D) shall not be included in the
utility's ratebase.
The requirement that a qualified person, as defined in
paragraph (1) of subsection (i) of this Section, install
photovoltaic devices does not apply to the Illinois Solar
for All Program described in this subsection (b).
(3) Costs associated with the Illinois Solar for All
Program and its components described in paragraph (2) of
this subsection (b), including, but not limited to, costs
associated with procuring experts, consultants, and the
program administrator referenced in this subsection (b)
and related incremental costs, and costs related to the

evaluation of the Illinois Solar for All Program, may be
paid for using monies in the Illinois Power Agency
Renewable Energy Resources Fund, but the Agency or program
administrator shall strive to minimize costs in the
implementation of the program. The Agency shall purchase
renewable energy credits from generation that is the
subject of a contract under subparagraphs (A) through (D)
of this paragraph (2) of this subsection (b), and may pay
for such renewable energy credits through an upfront
payment per installed kilowatt of nameplate capacity paid
once the device is interconnected at the distribution
system level of the utility and 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 incentives provided for in this
Section may be implemented through the pricing of renewable
energy credits where the prices paid for the credits are
higher than the prices from programs offered under
subsection (c) of Section 1-75 of this Act to account for
the incentives. The Agency shall ensure collaboration with
community agencies, and allocate up to 5% of the funds
available under the Illinois Solar for All Program to
community-based groups to assist in grassroots education
efforts related to the Illinois Solar for All Program. The

Agency shall retire any renewable energy credits purchased
from this program and the credits shall count towards the
obligation under subsection (c) of Section 1-75 of this Act
for the electric utility to which the project is
interconnected.
(4) The Agency shall, consistent with the requirements
of this subsection (b), propose the Illinois Solar for All
Program terms, conditions, and requirements, including the
prices to be paid for renewable energy credits, and which
prices may be determined through a formula, through the
development, review, and approval of the Agency's
long-term renewable resources procurement plan described
in subsection (c) of Section 1-75 of this Act and Section
16-111.5 of the Public Utilities Act. In the course of the
Commission proceeding initiated to review and approve the
plan, including the Illinois Solar for All Program proposed
by the Agency, a party may propose an additional low-income
solar or solar incentive program, or modifications to the
programs proposed by the Agency, and the Commission may
approve an additional program, or modifications to the
Agency's proposed program, if the additional or modified
program more effectively maximizes the benefits to
low-income customers after taking into account all
relevant factors, including, but not limited to, the extent
to which a competitive market for low-income solar has
developed. Following the Commission's approval of the

Illinois Solar for All Program, the Agency or a party may
propose adjustments to 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 plan revision
process described in Section 16-111.5 of the Public
Utilities Act.
(5) The Agency shall issue a request for qualifications
for a third-party program administrator or administrators
to administer all or a portion of the Illinois Solar for
All Program. The third-party program administrator shall
be chosen through a competitive bid process based on
selection criteria and requirements developed by the
Agency, including, but not limited to, experience in
administering low-income energy programs and overseeing
statewide clean energy or energy efficiency services. If
the Agency retains a program administrator or
administrators to implement all or a portion of the
Illinois Solar for All Program, each administrator shall
periodically submit reports to the Agency and Commission
for each program that it administers, at appropriate
intervals to be identified by the Agency in its long-term
renewable resources procurement plan, provided that the
reporting interval is at least quarterly.
(6) The long-term renewable resources procurement plan

shall also provide for an independent evaluation of the
Illinois Solar for All Program. At least every 2 years, the
Agency shall select an independent evaluator to review and
report on the Illinois Solar for All Program and the
performance of the third-party program administrator of
the Illinois Solar for All Program. The evaluation shall be
based on objective criteria developed through a public
stakeholder process. The process shall include feedback
and participation from Illinois Solar for All Program
stakeholders, including participants and organizations in
environmental justice and historically underserved
communities. The report shall include a summary of the
evaluation of the Illinois Solar for All Program based on
the stakeholder developed objective criteria. The report
shall include the number of projects installed; the total
installed capacity in kilowatts; the average cost per
kilowatt of installed capacity to the extent reasonably
obtainable by the Agency; the number of jobs or job
opportunities created; economic, social, and environmental
benefits created; and the total administrative costs
expended by the Agency and program administrator to
implement and evaluate the program. The report shall be
delivered to the Commission and posted on the Agency's
website, and shall be used, as needed, to revise the
Illinois Solar for All Program. The Commission shall also
consider the results of the evaluation as part of its

review of the long-term renewable resources procurement
plan under subsection (c) of Section 1-75 of this Act.
(7) If additional funding for the programs described in
this subsection (b) is available under subsection (k) of
Section 16-108 of the Public Utilities Act, then the Agency
shall submit a procurement plan to the Commission no later
than September 1, 2018, that proposes how the Agency will
procure programs on behalf of the applicable utility. After
notice and hearing, the Commission shall approve, or
approve with modification, the plan no later than November
1, 2018.
As used in this subsection (b), "low-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.
For the purposes of this subsection (b), the Agency shall
define "environmental justice community" as part of long-term
renewable resources procurement plan development, to ensure,
to the extent practicable, compatibility with other agencies'
definitions and may, for guidance, look to the definitions used
by federal, state, or local governments.
(b-5) After the receipt of all payments required by Section
16-115D of the Public Utilities Act, no additional funds shall
be deposited into the Illinois Power Agency Renewable Energy
Resources Fund unless directed by order of the Commission.
(b-10) After the receipt of all payments required by

Section 16-115D of the Public Utilities Act and payment in full
of all contracts executed by the Agency under subsections (b)
and (i) of this Section, if the balance of the Illinois Power
Agency Renewable Energy Resources Fund is under $5,000, then
the Fund shall be inoperative and any remaining funds and any
funds submitted to the Fund after that date, shall be
transferred to the Supplemental Low-Income Energy Assistance
Fund for use in 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
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
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 one or more third-party program
managers or administrators, the selection of the independent
evaluator, and the procurement processes described in this
Section are exempt from the requirements of the Illinois
Procurement Code, under Section 20-10 of that Code. The
procurement process described in this Section is exempt 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.
(h-5) The Agency may assess fees to each bidder to recover
the costs incurred in connection with a procurement process
held under this Section. Fees collected from bidders shall be
deposited into the Renewable Energy Resources Fund.
(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.
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
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
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
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.
(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
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
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
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
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
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
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
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. Beginning with the delivery year
commencing on June 1, 2017, the Planning and Procurement Bureau
shall develop plans and processes for the procurement of zero
emission credits from zero emission facilities in accordance
with the requirements of subsection (d-5) of this Section. The
Planning and Procurement Bureau shall also develop procurement
plans and conduct competitive procurement processes in
accordance with the requirements of Section 16-111.5 of the
Public Utilities Act for the eligible retail customers of small
multi-jurisdictional electric utilities that (i) on December
31, 2005 served less than 100,000 customers in Illinois and
(ii) request a procurement plan for their Illinois
jurisdictional load. This Section shall not apply to a small
multi-jurisdictional utility until such time as a small
multi-jurisdictional utility requests the Agency to prepare a

procurement plan for their Illinois jurisdictional load. For
the purposes of this Section, the term "eligible retail
customers" has the same definition as found in Section
16-111.5(a) of the Public Utilities Act.
Beginning with the plan or plans to be implemented in the
2017 delivery year, the Agency shall no longer include the
procurement of renewable energy resources in the annual
procurement plans required by this subsection (a), except as
provided in subsection (q) of Section 16-111.5 of the Public
Utilities Act, and shall instead develop a long-term renewable
resources procurement plan in accordance with subsection (c) of
this Section and Section 16-111.5 of the Public Utilities Act.
(1) The Agency shall each year, beginning in 2008, as
needed, issue a request for qualifications for experts or
expert consulting firms to develop the procurement plans in
accordance with Section 16-111.5 of the Public Utilities
Act. In order to qualify an expert or expert consulting
firm must have:
(A) direct previous experience assembling
large-scale power supply plans or portfolios for
end-use customers;
(B) an advanced degree in economics, mathematics,
engineering, risk management, or a related area of
study;
(C) 10 years of experience in the electricity
sector, including managing supply risk;

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

organizations;
(E) expertise in credit and contract protocols;
(F) adequate resources to perform and fulfill the
required functions and responsibilities; and
(G) the absence of a conflict of interest and
inappropriate bias for or against potential bidders or
the affected electric utilities.
(3) The Agency shall provide affected utilities and
other interested parties with the lists of qualified
experts or expert consulting firms identified through the
request for qualifications processes that are under
consideration to develop the procurement plans and to serve
as the procurement administrator. The Agency shall also
provide each qualified expert's or expert consulting
firm's response to the request for qualifications. All
information provided under this subparagraph shall also be
provided to the Commission. The Agency may provide by rule
for fees associated with supplying the information to
utilities and other interested parties. These parties
shall, within 5 business days, notify the Agency in writing
if they object to any experts or expert consulting firms on
the lists. Objections shall be based on:
(A) failure to satisfy qualification criteria;
(B) identification of a conflict of interest; or
(C) evidence of inappropriate bias for or against
potential bidders or the affected utilities.

The Agency shall remove experts or expert consulting
firms from the lists within 10 days if there is a
reasonable basis for an objection and provide the updated
lists to the affected utilities and other interested
parties. If the Agency fails to remove an expert or expert
consulting firm from a list, an objecting party may seek
review by the Commission within 5 days thereafter by filing
a petition, and the Commission shall render a ruling on the
petition within 10 days. There is no right of appeal of the
Commission's ruling.
(4) The Agency shall issue requests for proposals to
the qualified experts or expert consulting firms to develop
a procurement plan for the affected utilities and to serve
as procurement administrator.
(5) The Agency shall select an expert or expert
consulting firm to develop procurement plans based on the
proposals submitted and shall award contracts of up to 5
years to those selected.
(6) The Agency shall select an expert or expert
consulting firm, with approval of the Commission, to serve
as procurement administrator based on the proposals
submitted. If the Commission rejects, within 5 days, the
Agency's selection, the Agency shall submit another
recommendation within 3 days based on the proposals
submitted. The Agency shall award a 5-year contract to the
expert or expert consulting firm so selected with

Commission approval.
(b) The experts or expert consulting firms retained by the
Agency shall, as appropriate, prepare procurement plans, and
conduct a competitive procurement process as prescribed in
Section 16-111.5 of the Public Utilities Act, to ensure
adequate, reliable, affordable, efficient, and environmentally
sustainable electric service at the lowest total cost over
time, taking into account any benefits of price stability, for
eligible retail customers of electric utilities that on
December 31, 2005 provided electric service to at least 100,000
customers in the State of Illinois, and for eligible Illinois
retail customers of small multi-jurisdictional electric
utilities that (i) on December 31, 2005 served less than
100,000 customers in Illinois and (ii) request a procurement
plan for their Illinois jurisdictional load.
(c) Renewable portfolio standard.
(1)(A) The Agency shall develop a long-term renewable
resources procurement plan that shall include procurement
programs and competitive procurement events necessary to
meet the goals set forth in this subsection (c). The
initial long-term renewable resources procurement plan
shall be released for comment no later than 160 days after
the effective date of this amendatory Act of the 99th
General Assembly. The Agency shall review, and may revise
on an expedited basis, the long-term renewable resources
procurement plan at least every 2 years, which shall be

conducted in conjunction with the procurement plan under
Section 16-111.5 of the Public Utilities Act to the extent
practicable to minimize administrative expense. The
long-term renewable resources procurement plans shall be
subject to review and approval by the Commission under
Section 16-111.5 of the Public Utilities Act.
(B) Subject to subparagraph (F) of this paragraph (1),
the long-term renewable resources procurement plan shall
include the goals for procurement of renewable energy
credits to meet at least the following overall percentages:
13% by the 2017 delivery year; increasing by at least 1.5%
each delivery year thereafter to at least 25% by the 2025
delivery year; and continuing at no less than 25% for each
delivery year thereafter. In the event of a conflict
between these goals and the new wind and new photovoltaic
procurement requirements described in items (i) through
(iii) of subparagraph (C) of this paragraph (1), the
long-term plan shall prioritize compliance with the new
wind and new photovoltaic procurement requirements
described in items (i) through (iii) of subparagraph (C) of
this paragraph (1) over the annual percentage targets
described in this subparagraph (B).
For the delivery year beginning June 1, 2017, the
procurement plan shall include cost-effective renewable energy
resources equal to at least 13% of each utility's load for
eligible retail customers and 13% of the applicable portion of

each utility's load for retail customers who are not eligible
retail customers, which applicable portion shall equal 50% of
the utility's load for retail customers who are not eligible
retail customers on February 28, 2017.
For the delivery year beginning June 1, 2018, the
procurement plan shall include cost-effective renewable energy
resources equal to at least 14.5% of each utility's load for
eligible retail customers and 14.5% of the applicable portion
of each utility's load for retail customers who are not
eligible retail customers, which applicable portion shall
equal 75% of the utility's load for retail customers who are
not eligible retail customers on February 28, 2017.
For the delivery year beginning June 1, 2019, and for each
year thereafter, the procurement plans shall include
cost-effective renewable energy resources equal to a minimum
percentage of each utility's load for all retail customers as
follows: 16% by June 1, 2019; increasing by 1.5% each year
thereafter to 25% by June 1, 2025; and 25% by June 1, 2026 and
each year thereafter.
For each delivery year, the Agency shall first
recognize each utility's obligations for that delivery
year under existing contracts. Any renewable energy
credits under existing contracts, including renewable
energy credits as part of renewable energy resources, shall
be used to meet the goals set forth in this subsection (c)
for the delivery year.

(C) Of the renewable energy credits procured under this
subsection (c), at least 75% shall come from wind and
photovoltaic projects. The long-term renewable resources
procurement plan described in subparagraph (A) of this
paragraph (1) shall include the procurement of renewable
energy credits in amounts equal to at least the following:
(i) By the end of the 2020 delivery year:
At least 2,000,000 renewable energy credits
for each delivery year shall come from new wind
projects; and
At least 2,000,000 renewable energy credits
for each delivery year shall come from new
photovoltaic projects; of that amount, to the
extent possible, the Agency shall procure: at
least 50% from solar photovoltaic projects using
the program outlined in subparagraph (K) of this
paragraph (1) from distributed renewable energy
generation devices or community renewable
generation projects; at least 40% from
utility-scale solar projects; at least 2% from
brownfield site photovoltaic projects that are not
community renewable generation projects; and the
remainder shall be determined through the
long-term planning process described in
subparagraph (A) of this paragraph (1).
(ii) By the end of the 2025 delivery year:

At least 3,000,000 renewable energy credits
for each delivery year shall come from new wind
projects; and
At least 3,000,000 renewable energy credits
for each delivery year shall come from new
photovoltaic projects; of that amount, to the
extent possible, the Agency shall procure: at
least 50% from solar photovoltaic projects using
the program outlined in subparagraph (K) of this
paragraph (1) from distributed renewable energy
devices or community renewable generation
projects; at least 40% from utility-scale solar
projects; at least 2% from brownfield site
photovoltaic projects that are not community
renewable generation projects; and the remainder
shall be determined through the long-term planning
process described in subparagraph (A) of this
paragraph (1).
(iii) By the end of the 2030 delivery year:
At least 4,000,000 renewable energy credits
for each delivery year shall come from new wind
projects; and
At least 4,000,000 renewable energy credits
for each delivery year shall come from new
photovoltaic projects; of that amount, to the
extent possible, the Agency shall procure: at

least 50% from solar photovoltaic projects using
the program outlined in subparagraph (K) of this
paragraph (1) from distributed renewable energy
devices or community renewable generation
projects; at least 40% from utility-scale solar
projects; at least 2% from brownfield site
photovoltaic projects that are not community
renewable generation projects; and the remainder
shall be determined through the long-term planning
process described in subparagraph (A) of this
paragraph (1).
For purposes of this Section:
"New wind projects" means wind renewable
energy facilities that are energized after June 1,
2017 for the delivery year commencing June 1, 2017
or within 3 years after the date the Commission
approves contracts for subsequent delivery years.
"New photovoltaic projects" means photovoltaic
renewable energy facilities that are energized
after June 1, 2017. Photovoltaic projects
developed under Section 1-56 of this Act shall not
apply towards the new photovoltaic project
requirements in this subparagraph (C).
(D) Renewable energy credits shall be cost effective.
For purposes of this subsection (c), "cost effective" means
that the costs of procuring renewable energy resources do

not cause the limit stated in subparagraph (E) of this
paragraph (1) to be exceeded and, for renewable energy
credits procured through a competitive procurement event,
do not exceed benchmarks based on market prices for like
products in the region. For purposes of this subsection
(c), "like products" means contracts for renewable energy
credits from the same or substantially similar technology,
same or substantially similar vintage (new or existing),
the same or substantially similar quantity, and the same or
substantially similar contract length and structure.
Benchmarks shall be developed by the procurement
administrator, in consultation with the Commission staff,
Agency staff, and the procurement monitor and shall be
subject to Commission review and approval. If price
benchmarks for like products in the region are not
available, the procurement administrator shall establish
price benchmarks based on publicly available data on
regional technology costs and expected current and future
regional energy prices. The benchmarks in this Section
shall not be used to curtail or otherwise reduce
contractual obligations entered into by or through the
Agency prior to the effective date of this amendatory Act
of the 99th General Assembly.
(E) For purposes of this subsection (c), the required
procurement of cost-effective renewable energy resources
for a particular year commencing prior to June 1, 2017

shall be measured as a percentage of the actual amount of
electricity (megawatt-hours) supplied by the electric
utility to eligible retail customers in the delivery year
ending immediately prior to the procurement, and, for
delivery years commencing on and after June 1, 2017, the
required procurement of cost-effective renewable energy
resources for a particular year shall be measured as a
percentage of the actual amount of electricity
(megawatt-hours) delivered by the electric utility in the
delivery year ending immediately prior to the procurement,
to all retail customers in its service territory. For
purposes of this subsection (c), the amount paid per
kilowatthour means the total amount paid for electric
service expressed on a per kilowatthour basis. For purposes
of this subsection (c), the total amount paid for electric
service includes without limitation amounts paid for
supply, transmission, distribution, surcharges, and add-on
taxes.
Notwithstanding the requirements of this subsection
(c), the total of renewable energy resources procured under
the procurement plan for any single year shall be subject
to the limitations of this subparagraph (E). Such
procurement shall be reduced for all retail customers based
on the amount necessary to limit the annual estimated
average net increase due to the costs of these resources
included in the amounts paid by eligible retail customers

in connection with electric service to no more than the
greater of 2.015% of the amount paid per kilowatthour by
those customers during the year ending May 31, 2007 or the
incremental amount per kilowatthour paid for these
resources in 2011. To arrive at a maximum dollar amount of
renewable energy resources to be procured for the
particular delivery year, the resulting per kilowatthour
amount shall be applied to the actual amount of
kilowatthours of electricity delivered, or applicable
portion of such amount as specified in paragraph (1) of
this subsection (c), as applicable, by the electric utility
in the delivery year immediately prior to the procurement
to all retail customers in its service territory. The
calculations required by this subparagraph (E) shall be
made only once for each delivery year at the time that the
renewable energy resources are procured. Once the
determination as to the amount of renewable energy
resources to procure is made based on the calculations set
forth in this subparagraph (E) and the contracts procuring
those amounts are executed, no subsequent rate impact
determinations shall be made and no adjustments to those
contract amounts shall be allowed. All costs incurred under
such contracts shall be fully recoverable by the electric
utility as provided in this Section.
(F) If the limitation on the amount of renewable energy
resources procured in subparagraph (E) of this paragraph

(1) prevents the Agency from meeting all of the goals in
this subsection (c), the Agency's long-term plan shall
prioritize compliance with the requirements of this
subsection (c) regarding renewable energy credits in the
following order:
(i) renewable energy credits under existing
contractual obligations;
(i-5)funding for the Illinois Solar for All
Program, as described in subparagraph (O) of this
paragraph (1);
(ii) renewable energy credits necessary to comply
with the new wind and new photovoltaic procurement
requirements described in items (i) through (iii) of
subparagraph (C) of this paragraph (1); and
(iii) renewable energy credits necessary to meet
the remaining requirements of this subsection (c).
(G) The following provisions shall apply to the
Agency's procurement of renewable energy credits under
this subsection (c):
(i) Notwithstanding whether a long-term renewable
resources procurement plan has been approved, the
Agency shall conduct an initial forward procurement
for renewable energy credits from new utility-scale
wind projects within 160 days after the effective date
of this amendatory Act of the 99th General Assembly.
For the purposes of this initial forward procurement,

the Agency shall solicit 15-year contracts for
delivery of 1,000,000 renewable energy credits
delivered annually from new utility-scale wind
projects to begin delivery on June 1, 2019, if
available, but not later than June 1, 2021. Payments to
suppliers of renewable energy credits shall commence
upon delivery. Renewable energy credits procured under
this initial procurement shall be included in the
Agency's long-term plan and shall apply to all
renewable energy goals in this subsection (c).
(ii) Notwithstanding whether a long-term renewable
resources procurement plan has been approved, the
Agency shall conduct an initial forward procurement
for renewable energy credits from new utility-scale
solar projects and brownfield site photovoltaic
projects within one year after the effective date of
this amendatory Act of the 99th General Assembly. For
the purposes of this initial forward procurement, the
Agency shall solicit 15-year contracts for delivery of
1,000,000 renewable energy credits delivered annually
from new utility-scale solar projects and brownfield
site photovoltaic projects to begin delivery on June 1,
2019, if available, but not later than June 1, 2021.
The Agency may structure this initial procurement in
one or more discrete procurement events. Payments to
suppliers of renewable energy credits shall commence

upon delivery. Renewable energy credits procured under
this initial procurement shall be included in the
Agency's long-term plan and shall apply to all
renewable energy goals in this subsection (c).
(iii) Subsequent forward procurements for
utility-scale wind projects shall solicit at least
1,000,000 renewable energy credits delivered annually
per procurement event and shall be planned, scheduled,
and designed such that the cumulative amount of
renewable energy credits delivered from all new wind
projects in each delivery year shall not exceed the
Agency's projection of the cumulative amount of
renewable energy credits that will be delivered from
all new photovoltaic projects, including utility-scale
and distributed photovoltaic devices, in the same
delivery year at the time scheduled for wind contract
delivery.
(iv) If, at any time after the time set for
delivery of renewable energy credits pursuant to the
initial procurements in items (i) and (ii) of this
subparagraph (G), the cumulative amount of renewable
energy credits projected to be delivered from all new
wind projects in a given delivery year exceeds the
cumulative amount of renewable energy credits
projected to be delivered from all new photovoltaic
projects in that delivery year by 200,000 or more

renewable energy credits, then the Agency shall within
60 days adjust the procurement programs in the
long-term renewable resources procurement plan to
ensure that the projected cumulative amount of
renewable energy credits to be delivered from all new
wind projects does not exceed the projected cumulative
amount of renewable energy credits to be delivered from
all new photovoltaic projects by 200,000 or more
renewable energy credits, provided that nothing in
this Section shall preclude the projected cumulative
amount of renewable energy credits to be delivered from
all new photovoltaic projects from exceeding the
projected cumulative amount of renewable energy
credits to be delivered from all new wind projects in
each delivery year and provided further that nothing in
this item (iv) shall require the curtailment of an
executed contract. The Agency shall update, on a
quarterly basis, its projection of the renewable
energy credits to be delivered from all projects in
each delivery year. Notwithstanding anything to the
contrary, the Agency may adjust the timing of
procurement events conducted under this subparagraph
(G). The long-term renewable resources procurement
plan shall set forth the process by which the
adjustments may be made.
(v) All procurements under this subparagraph (G)

shall comply with the geographic requirements in
subparagraph (I) of this paragraph (1) and shall follow
the procurement processes and procedures described in
this Section and Section 16-111.5 of the Public
Utilities Act to the extent practicable, and these
processes and procedures may be expedited to
accommodate the schedule established by this
subparagraph (G).
(H) The procurement of renewable energy resources for a
given delivery year shall be reduced as described in this
subparagraph (H) if an alternate retail electric supplier
meets the requirements described in this subparagraph (H).
(i) Within 45 days after the effective date of this
amendatory Act of the 99th General Assembly, an
alternative retail electric supplier or its successor
shall submit an informational filing to the Illinois
Commerce Commission certifying that, as of December
31, 2015, the alternative retail electric supplier
owned one or more electric generating facilities that
generates renewable energy resources as defined in
Section 1-10 of this Act, provided that such facilities
are not powered by wind or photovoltaics, and the
facilities generate one renewable energy credit for
each megawatthour of energy produced from the
facility.
The informational filing shall identify each

facility that was eligible to satisfy the alternative
retail electric supplier's obligations under Section
16-115D of the Public Utilities Act as described in
this item (i).
(ii) For a given delivery year, the alternative
retail electric supplier may elect to supply its retail
customers with renewable energy credits from the
facility or facilities described in item (i) of this
subparagraph (H) that continue to be owned by the
alternative retail electric supplier.
(iii) The alternative retail electric supplier
shall notify the Agency and the applicable utility, no
later than February 28 of the year preceding the
applicable delivery year or 15 days after the effective
date of this amendatory Act of the 99th General
Assembly, whichever is later, of its election under
item (ii) of this subparagraph (H) to supply renewable
energy credits to retail customers of the utility. Such
election shall identify the amount of renewable energy
credits to be supplied by the alternative retail
electric supplier to the utility's retail customers
and the source of the renewable energy credits
identified in the informational filing as described in
item (i) of this subparagraph (H), subject to the
following limitations:
For the delivery year beginning June 1, 2018,

the maximum amount of renewable energy credits to
be supplied by an alternative retail electric
supplier under this subparagraph (H) shall be 68%
multiplied by 25% multiplied by 14.5% multiplied
by the amount of metered electricity
(megawatt-hours) delivered by the alternative
retail electric supplier to Illinois retail
customers during the delivery year ending May 31,
2016.
For delivery years beginning June 1, 2019 and
each year thereafter, the maximum amount of
renewable energy credits to be supplied by an
alternative retail electric supplier under this
subparagraph (H) shall be 68% multiplied by 50%
multiplied by 16% multiplied by the amount of
metered electricity (megawatt-hours) delivered by
the alternative retail electric supplier to
Illinois retail customers during the delivery year
ending May 31, 2016, provided that the 16% value
shall increase by 1.5% each delivery year
thereafter to 25% by the delivery year beginning
June 1, 2025, and thereafter the 25% value shall
apply to each delivery year.
For each delivery year, the total amount of
renewable energy credits supplied by all alternative
retail electric suppliers under this subparagraph (H)

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

beginning June 1, 2025, and thereafter the 25% value
shall apply to each delivery year.
On or before April 1 of each year, the Agency shall
annually publish a report on its website that
identifies the aggregate amount of renewable energy
credits supplied by alternative retail electric
suppliers under this subparagraph (H).
(I) The Agency shall design its long-term renewable
energy procurement plan to maximize the State's interest in
the health, safety, and welfare of its residents, including
but not limited to minimizing sulfur dioxide, nitrogen
oxide, particulate matter and other pollution that
adversely affects public health in this State, increasing
fuel and resource diversity in this State, enhancing the
reliability and resiliency of the electricity distribution
system in this State, meeting goals to limit carbon dioxide
emissions under federal or State law, and contributing to a
cleaner and healthier environment for the citizens of this
State. In order to further these legislative purposes,
renewable energy credits shall be eligible to be counted
toward the renewable energy requirements of this
subsection (c) if they are generated from facilities
located in this State. The Agency may qualify renewable
energy credits from facilities located in states adjacent
to Illinois if the generator demonstrates and the Agency
determines that the operation of such facility or

facilities will help promote the State's interest in the
health, safety, and welfare of its residents based on the
public interest criteria described above. To ensure that
the public interest criteria are applied to the procurement
and given full effect, the Agency's long-term procurement
plan shall describe in detail how each public interest
factor shall be considered and weighted for facilities
located in states adjacent to Illinois.
(J) In order to promote the competitive development of
renewable energy resources in furtherance of the State's
interest in the health, safety, and welfare of its
residents, renewable energy credits shall not be eligible
to be counted toward the renewable energy requirements of
this subsection (c) if they are sourced from a generating
unit whose costs were being recovered through rates
regulated by this State or any other state or states on or
after January 1, 2017. Each contract executed to purchase
renewable energy credits under this subsection (c) shall
provide for the contract's termination if the costs of the
generating unit supplying the renewable energy credits
subsequently begin to be recovered through rates regulated
by this State or any other state or states; and each
contract shall further provide that, in that event, the
supplier of the credits must return 110% of all payments
received under the contract. Amounts returned under the
requirements of this subparagraph (J) shall be retained by

the utility and all of these amounts shall be used for the
procurement of additional renewable energy credits from
new wind or new photovoltaic resources as defined in this
subsection (c). The long-term plan shall provide that these
renewable energy credits shall be procured in the next
procurement event.
Notwithstanding the limitations of this subparagraph
(J), renewable energy credits sourced from generating
units that are constructed, purchased, owned, or leased by
an electric utility as part of an approved project,
program, or pilot under Section 1-56 of this Act shall be
eligible to be counted toward the renewable energy
requirements of this subsection (c), regardless of how the
costs of these units are recovered.
(K) The long-term renewable resources procurement plan
developed by the Agency in accordance with subparagraph (A)
of this paragraph (1) shall include an Adjustable Block
program for the procurement of renewable energy credits
from new photovoltaic projects that are distributed
renewable energy generation devices or new photovoltaic
community renewable generation projects. The Adjustable
Block program shall be designed to provide a transparent
schedule of prices and quantities to enable the
photovoltaic market to scale up and for renewable energy
credit prices to adjust at a predictable rate over time.
The prices set by the Adjustable Block program can be

reflected as a set value or as the product of a formula.
The Adjustable Block program shall include for each
category of eligible projects: a schedule of standard block
purchase prices to be offered; a series of steps, with
associated nameplate capacity and purchase prices that
adjust from step to step; and automatic opening of the next
step as soon as the nameplate capacity and available
purchase prices for an open step are fully committed or
reserved. Only projects energized on or after June 1, 2017
shall be eligible for the Adjustable Block program. For
each block group the Agency shall determine the number of
blocks, the amount of generation capacity in each block,
and the purchase price for each block, provided that the
purchase price provided and the total amount of generation
in all blocks for all block groups shall be sufficient to
meet the goals in this subsection (c). The Agency may
periodically review its prior decisions establishing the
number of blocks, the amount of generation capacity in each
block, and the purchase price for each block, and may
propose, on an expedited basis, changes to these previously
set values, including but not limited to redistributing
these amounts and the available funds as necessary and
appropriate, subject to Commission approval as part of the
periodic plan revision process described in Section
16-111.5 of the Public Utilities Act. The Agency may define
different block sizes, purchase prices, or other distinct

terms and conditions for projects located in different
utility service territories if the Agency deems it
necessary to meet the goals in this subsection (c).
The Adjustable Block program shall include at least the
following block groups in at least the following amounts,
which may be adjusted upon review by the Agency and
approval by the Commission as described in this
subparagraph (K):
(i) At least 25% from distributed renewable energy
generation devices with a nameplate capacity of no more
than 10 kilowatts.
(ii) At least 25% from distributed renewable
energy generation devices with a nameplate capacity of
more than 10 kilowatts and no more than 2,000
kilowatts. The Agency may create sub-categories within
this category to account for the differences between
projects for small commercial customers, large
commercial customers, and public or non-profit
customers.
(iii) At least 25% from photovoltaic community
renewable generation projects.
(iv) The remaining 25% shall be allocated as
specified by the Agency in the long-term renewable
resources procurement plan.
The Adjustable Block program shall be designed to
ensure that renewable energy credits are procured from

photovoltaic distributed renewable energy generation
devices and new photovoltaic community renewable energy
generation projects in diverse locations and are not
concentrated in a few geographic areas.
(L) The procurement of photovoltaic renewable energy
credits under items (i) through (iv) of subparagraph (K) of
this paragraph (1) shall be subject to the following
contract and payment terms:
(i) The Agency shall procure contracts of at least
15 years in length.
(ii) For those renewable energy credits that
qualify and are procured under item (i) of subparagraph
(K) of this paragraph (1), the renewable energy credit
purchase price shall be paid in full by the contracting
utilities at the time that the facility producing the
renewable energy credits is interconnected at the
distribution system level of the utility and
energized. The electric utility shall receive and
retire all renewable energy credits generated by the
project for the first 15 years of operation.
(iii) For those renewable energy credits that
qualify and are procured under item (ii) and (iii) of
subparagraph (K) of this paragraph (1) and any
additional categories of distributed generation
included in the long-term renewable resources
procurement plan and approved by the Commission, 20

percent of the renewable energy credit purchase price
shall be paid by the contracting utilities at the time
that the facility producing the renewable energy
credits is interconnected at the distribution system
level of the utility and energized. The remaining
portion shall be paid ratably over the subsequent
4-year period. The electric utility shall receive and
retire all renewable energy credits generated by the
project for the first 15 years of operation.
(iv) Each contract shall include provisions to
ensure the delivery of the renewable energy credits for
the full term of the contract.
(v) The utility shall be the counterparty to the
contracts executed under this subparagraph (L) that
are approved by the Commission under the process
described in Section 16-111.5 of the Public Utilities
Act. No contract shall be executed for an amount that
is less than one renewable energy credit per year.
(vi) If, at any time, approved applications for the
Adjustable Block program exceed funds collected by the
electric utility or would cause the Agency to exceed
the limitation described in subparagraph (E) of this
paragraph (1) on the amount of renewable energy
resources that may be procured, then the Agency shall
consider future uncommitted funds to be reserved for
these contracts on a first-come, first-served basis,

with the delivery of renewable energy credits required
beginning at the time that the reserved funds become
available.
(vii) Nothing in this Section shall require the
utility to advance any payment or pay any amounts that
exceed the actual amount of revenues collected by the
utility under paragraph (6) of this subsection (c) and
subsection (k) of Section 16-108 of the Public
Utilities Act, and contracts executed under this
Section shall expressly incorporate this limitation.
(M) The Agency shall be authorized to retain one or
more experts or expert consulting firms to develop,
administer, implement, operate, and evaluate the
Adjustable Block program described in subparagraph (K) of
this paragraph (1), and the Agency shall retain the
consultant or consultants in the same manner, to the extent
practicable, as the Agency retains others to administer
provisions of this Act, including, but not limited to, the
procurement administrator. The selection of experts and
expert consulting firms and the procurement process
described in this subparagraph (M) are exempt from the
requirements of Section 20-10 of the Illinois Procurement
Code, under Section 20-10 of that Code. The Agency shall
strive to minimize administrative expenses in the
implementation of the Adjustable Block program.
The Agency and its consultant or consultants shall

monitor block activity, share program activity with
stakeholders and conduct regularly scheduled meetings to
discuss program activity and market conditions. If
necessary, the Agency may make prospective administrative
adjustments to the Adjustable Block program design, such as
redistributing available funds or making adjustments to
purchase prices as necessary to achieve the goals of this
subsection (c). Program modifications to any price,
capacity block, or other program element that do not
deviate from the Commission's approved value by more than
25% shall take effect immediately and are not subject to
Commission review and approval. Program modifications to
any price, capacity block, or other program element that
deviate more than 25% from the Commission's approved value
must be approved by the Commission as a long-term plan
amendment under Section 16-111.5 of the Public Utilities
Act. The Agency shall consider stakeholder feedback when
making adjustments to the Adjustable Block design and shall
notify stakeholders in advance of any planned changes.
(N) The long-term renewable resources procurement plan
required by this subsection (c) shall include a community
renewable generation program. The Agency shall establish
the terms, conditions, and program requirements for
community renewable generation projects with a goal to
expand renewable energy generating facility access to a
broader group of energy consumers, to ensure robust

participation opportunities for residential and small
commercial customers and those who cannot install
renewable energy on their own properties. Any plan approved
by the Commission shall allow subscriptions to community
renewable generation projects to be portable and
transferable. For purposes of this subparagraph (N),
"portable" means that subscriptions may be retained by the
subscriber even if the subscriber relocates or changes its
address within the same utility service territory; and
"transferable" means that a subscriber may assign or sell
subscriptions to another person within the same utility
service territory.
Electric utilities shall provide a monetary credit to a
subscriber's subsequent bill for service for the
proportional output of a community renewable generation
project attributable to that subscriber as specified in
Section 16-107.5 of the Public Utilities Act.
The Agency shall purchase renewable energy credits
from subscribed shares of photovoltaic community renewable
generation projects through the Adjustable Block program
described in subparagraph (K) of this paragraph (1) or
through the Illinois Solar for All Program described in
Section 1-56 of this Act. The electric utility shall
purchase any unsubscribed energy from community renewable
generation projects that are Qualifying Facilities ("QF")
under the electric utility's tariff for purchasing the

output from QFs under Public Utilities Regulatory Policies
Act of 1978.
The owners of and any subscribers to a community
renewable generation project shall not be considered
public utilities or alternative retail electricity
suppliers under the Public Utilities Act solely as a result
of their interest in or subscription to a community
renewable generation project and shall not be required to
become an alternative retail electric supplier by
participating in a community renewable generation project
with a public utility.
(O) For the delivery year beginning June 1, 2018, the
long-term renewable resources procurement plan required by
this subsection (c) shall provide for the Agency to procure
contracts to continue offering the Illinois Solar for All
Program described in subsection (b) of Section 1-56 of this
Act, and the contracts approved by the Commission shall be
executed by the utilities that are subject to this
subsection (c). The long-term renewable resources
procurement plan shall allocate 5% of the funds available
under the plan for the applicable delivery year, or
$10,000,000 per delivery year, whichever is greater, to
fund the programs, and the plan shall determine the amount
of funding to be apportioned to the programs identified in
subsection (b) of Section 1-56 of this Act; provided that
for the delivery years beginning June 1, 2017, June 1,

2021, and June 1, 2025, the long-term renewable resources
procurement plan shall allocate 10% of the funds available
under the plan for the applicable delivery year, or
$20,000,000 per delivery year, whichever is greater, and
$10,000,000 of such funds in such year shall be used by an
electric utility that serves more than 3,000,000 retail
customers in the State to implement a Commission-approved
plan under Section 16-108.12 of the Public Utilities Act.
In making the determinations required under this
subparagraph (O), the Commission shall consider the
experience and performance under the programs and any
evaluation reports. The Commission shall also provide for
an independent evaluation of those programs on a periodic
basis that are funded under this subparagraph (O). 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
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
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
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
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
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
June 1, 2017 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.
(6) The electric utility shall be entitled to recover
all of its costs associated with the procurement of
renewable energy credits under plans approved under this
Section and Section 16-111.5 of the Public Utilities Act.
These costs shall include associated reasonable expenses
for implementing the procurement programs, including, but
not limited to, the costs of administering and evaluating
the Adjustable Block program, through an automatic

adjustment clause tariff in accordance with subsection (k)
of Section 16-108 of the Public Utilities Act.
(7) Renewable energy credits procured from new
photovoltaic projects or new distributed renewable energy
generation devices under this Section after the effective
date of this amendatory Act of the 99th General Assembly
must be procured from devices installed by a qualified
person in compliance with the requirements of Section
16-128A of the Public Utilities Act and any rules or
regulations adopted thereunder.
In meeting the renewable energy requirements of this
subsection (c), to the extent feasible and consistent with
State and federal law, the renewable energy credit
procurements, Adjustable Block solar program, and
community renewable generation program shall provide
employment opportunities for all segments of the
population and workforce, including minority-owned and
female-owned business enterprises, and shall not,
consistent with State and federal law, discriminate based
on race or socioeconomic status.
(d) Clean coal portfolio standard.
(1) The procurement plans shall include electricity
generated using clean coal. Each utility shall enter into
one or more sourcing agreements with the initial clean coal
facility, as provided in paragraph (3) of this subsection
(d), covering electricity generated by the initial clean

coal facility representing at least 5% of each utility's
total supply to serve the load of eligible retail customers
in 2015 and each year thereafter, as described in paragraph
(3) of this subsection (d), subject to the limits specified
in paragraph (2) of this subsection (d). It is the goal of
the State that by January 1, 2025, 25% of the electricity
used in the State shall be generated by cost-effective
clean coal facilities. For purposes of this subsection (d),
"cost-effective" means that the expenditures pursuant to
such sourcing agreements do not cause the limit stated in
paragraph (2) of this subsection (d) to be exceeded and do
not exceed cost-based benchmarks, which shall be developed
to assess all expenditures pursuant to such sourcing
agreements covering electricity generated by clean coal
facilities, other than the initial clean coal facility, by
the procurement administrator, in consultation with the
Commission staff, Agency staff, and the procurement
monitor and shall be subject to Commission review and
approval.
A utility party to a sourcing agreement shall
immediately retire any emission credits that it receives in
connection with the electricity covered by such agreement.
Utilities shall maintain adequate records documenting
the purchases under the sourcing agreement to comply with
this subsection (d) and shall file an accounting with the
load forecast that must be filed with the Agency by July 15

of each year, in accordance with subsection (d) of Section
16-111.5 of the Public Utilities Act.
A utility shall be deemed to have complied with the
clean coal portfolio standard specified in this subsection
(d) if the utility enters into a sourcing agreement as
required by this subsection (d).
(2) For purposes of this subsection (d), the required
execution of sourcing agreements with the initial clean
coal facility for a particular year shall be measured as a
percentage of the actual amount of electricity
(megawatt-hours) supplied by the electric utility to
eligible retail customers in the planning year ending
immediately prior to the agreement's execution. For
purposes of this subsection (d), the amount paid per
kilowatthour means the total amount paid for electric
service expressed on a per kilowatthour basis. For purposes
of this subsection (d), the total amount paid for electric
service includes without limitation amounts paid for
supply, transmission, distribution, surcharges and add-on
taxes.
Notwithstanding the requirements of this subsection
(d), the total amount paid under sourcing agreements with
clean coal facilities pursuant to the procurement plan for
any given year shall be reduced by an amount necessary to
limit the annual estimated average net increase due to the
costs of these resources included in the amounts paid by

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

retail customers in connection with electric service
to no more than the greater of (i) 2.015% of the amount
paid per kilowatthour by those customers during the
year ending May 31, 2009 or (ii) the incremental amount
per kilowatthour paid for these resources in 2013.
These requirements may be altered only as provided by
statute.
No later than June 30, 2015, the Commission shall
review the limitation on the total amount paid under
sourcing agreements, if any, with clean coal facilities
pursuant to this subsection (d) and report to the General
Assembly its findings as to whether that limitation unduly
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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.
(d-5) Zero emission standard.
(1) Beginning with the delivery year commencing on June
1, 2017, the Agency shall, for electric utilities that
serve at least 100,000 retail customers in this State,
procure contracts with zero emission facilities that are
reasonably capable of generating cost-effective zero
emission credits in an amount approximately equal to 16% of
the actual amount of electricity delivered by each electric
utility to retail customers in the State during calendar
year 2014. For an electric utility serving fewer than
100,000 retail customers in this State that requested,
under Section 16-111.5 of the Public Utilities Act, that
the Agency procure power and energy for all or a portion of
the utility's Illinois load for the delivery year
commencing June 1, 2016, the Agency shall procure contracts
with zero emission facilities that are reasonably capable
of generating cost-effective zero emission credits in an
amount approximately equal to 16% of the portion of power
and energy to be procured by the Agency for the utility.
The duration of the contracts procured under this
subsection (d-5) shall be for a term of 10 years ending May
31, 2027. The quantity of zero emission credits to be

procured under the contracts shall be all of the zero
emission credits generated by the zero emission facility in
each delivery year; however, if the zero emission facility
is owned by more than one entity, then the quantity of zero
emission credits to be procured under the contracts shall
be the amount of zero emission credits that are generated
from the portion of the zero emission facility that is
owned by the winning supplier.
The 16% value identified in this paragraph (1) is the
average of the percentage targets in subparagraph (B) of
paragraph (1) of subsection (c) of Section 1-75 of this Act
for the 5 delivery years beginning June 1, 2017.
The procurement process shall be subject to the
following provisions:
(A) Those zero emission facilities that intend to
participate in the procurement shall submit to the
Agency the following eligibility information for each
zero emission facility on or before the date
established by the Agency:
(i) the in-service date and remaining useful
life of the zero emission facility;
(ii) the amount of power generated annually
for each of the years 2005 through 2015, and the
projected zero emission credits to be generated
over the remaining useful life of the zero emission
facility, which shall be used to determine the

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

procurement administrator, and the Commission as
confidential and proprietary and exempt from disclosure
under subparagraphs (a) and (g) of paragraph (1) of Section
7 of the Freedom of Information Act. The Office of Attorney
General shall have access to, and maintain the
confidentiality of, such information pursuant to Section
6.5 of the Attorney General Act.
(B) The price for each zero emission credit
procured under this subsection (d-5) for each delivery
year shall be in an amount that equals the Social Cost
of Carbon, expressed on a price per megawatthour basis.
However, to ensure that the procurement remains
affordable to retail customers in this State if
electricity prices increase, the price in an
applicable delivery year shall be reduced below the
Social Cost of Carbon by the amount ("Price
Adjustment") by which the market price index for the
applicable delivery year exceeds the baseline market
price index for the consecutive 12-month period ending
May 31, 2016. If the Price Adjustment is greater than
or equal to the Social Cost of Carbon in an applicable
delivery year, then no payments shall be due in that
delivery year. The components of this calculation are
defined as follows:
(i) Social Cost of Carbon: The Social Cost of
Carbon is $16.50 per megawatthour, which is based

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

projected energy prices and projected capacity
prices determined as follows:
(aa) Projected energy prices: the
projected energy prices for the applicable
delivery year shall be calculated once for the
year using the forward market price for the PJM
Interconnection, LLC Northern Illinois Hub.
The forward market price shall be calculated as
follows: the energy forward prices for each
month of the applicable delivery year averaged
for each trade date during the calendar year
immediately preceding that delivery year to
produce a single energy forward price for the
delivery year. The forward market price
calculation shall use data published by the
Intercontinental Exchange, or its successor.
(bb) Projected capacity prices:
(I) For the delivery years commencing
June 1, 2017, June 1, 2018, and June 1,
2019, the projected capacity price shall
be equal to the sum of (1) 50% multiplied
by the Base Residual Auction, or its
successor, price for the rest of the RTO
zone group as determined by PJM
Interconnection LLC, divided by 24 hours
per day and, (2) 50% multiplied by the

resource auction price determined in the
resource auction administered by the
Midcontinent Independent System Operator,
Inc., in which the largest percentage of
load cleared for Local Resource Zone 4,
divided by 24 hours per day, and where such
price is determined by the Midcontinent
Independent System Operator, Inc.
(II) For the delivery year commencing
June 1, 2020, and each year thereafter, the
projected capacity price shall be equal to
the sum of (1) 50% multiplied by the Base
Residual Auction, or its successor, price
for the ComEd zone as determined by PJM
Interconnection LLC, divided by 24 hours
per day, and (2) 50% multiplied by the
resource auction price determined in the
resource auction administered by the
Midcontinent Independent System Operator,
Inc., in which the largest percentage of
load cleared for Local Resource Zone 4,
divided by 24 hours per day, and where such
price is determined by the Midcontinent
Independent System Operator, Inc.
For purposes of this subsection (d-5):
"Rest of the RTO" and "ComEd Zone" shall have

the meaning ascribed to them by PJM
Interconnection, LLC.
"RTO" means regional transmission
organization.
(C) No later than 45 days after the effective date
of this amendatory Act of the 99th General Assembly,
the Agency shall publish its proposed zero emission
standard procurement plan. The plan shall be
consistent with the provisions of this paragraph (1)
and shall provide that winning bids shall be selected
based on public interest criteria that include, but are
not limited to, minimizing carbon dioxide emissions
that result from electricity consumed in Illinois and
minimizing sulfur dioxide, nitrogen oxide, and
particulate matter emissions that adversely affect the
citizens of this State. In particular, the selection of
winning bids shall take into account the incremental
environmental benefits resulting from the procurement,
such as any existing environmental benefits that are
preserved by the procurements held under this
amendatory Act of the 99th General Assembly and would
cease to exist if the procurements were not held,
including the preservation of zero emission
facilities. The plan shall also describe in detail how
each public interest factor shall be considered and
weighted in the bid selection process to ensure that

the public interest criteria are applied to the
procurement and given full effect.
For purposes of developing the plan, the Agency
shall consider any reports issued by a State agency,
board, or commission under House Resolution 1146 of the
98th General Assembly and paragraph (4) of subsection
(d) of Section 1-75 of this Act, as well as publicly
available analyses and studies performed by or for
regional transmission organizations that serve the
State and their independent market monitors.
Upon publishing of the zero emission standard
procurement plan, copies of the plan shall be posted
and made publicly available on the Agency's website.
All interested parties shall have 10 days following the
date of posting to provide comment to the Agency on the
plan. All comments shall be posted to the Agency's
website. Following the end of the comment period, but
no more than 60 days later than the effective date of
this amendatory Act of the 99th General Assembly, the
Agency shall revise the plan as necessary based on the
comments received and file its zero emission standard
procurement plan with the Commission.
If the Commission determines that the plan will
result in the procurement of cost-effective zero
emission credits, then the Commission shall, after
notice and hearing, but no later than 45 days after the

Agency filed the plan, approve the plan or approve with
modification. For purposes of this subsection (d-5),
"cost effective" means the projected costs of
procuring zero emission credits from zero emission
facilities do not cause the limit stated in paragraph
(2) of this subsection to be exceeded.
(C-5) As part of the Commission's review and
acceptance or rejection of the procurement results,
the Commission shall, in its public notice of
successful bidders:
(i) identify how the winning bids satisfy the
public interest criteria described in subparagraph
(C) of this paragraph (1) of minimizing carbon
dioxide emissions that result from electricity
consumed in Illinois and minimizing sulfur
dioxide, nitrogen oxide, and particulate matter
emissions that adversely affect the citizens of
this State;
(ii) specifically address how the selection of
winning bids takes into account the incremental
environmental benefits resulting from the
procurement, including any existing environmental
benefits that are preserved by the procurements
held under this amendatory Act of the 99th General
Assembly and would have ceased to exist if the
procurements had not been held, such as the

preservation of zero emission facilities;
(iii) quantify the environmental benefit of
preserving the resources identified in item (ii)
of this subparagraph (C-5), including the
following:
(aa) the value of avoided greenhouse gas
emissions measured as the product of the zero
emission facilities' output over the contract
term multiplied by the U.S. Environmental
Protection Agency eGrid subregion carbon
dioxide emission rate and the U.S. Interagency
Working Group on Social Cost of Carbon's price
in the August 2016 Technical Update using a 3%
discount rate, adjusted for inflation for each
delivery year; and
(bb) the costs of replacement with other
zero carbon dioxide resources, including wind
and photovoltaic, based upon the simple
average of the following:
(I) the price, or if there is more than
one price, the average of the prices, paid
for renewable energy credits from new
utility-scale wind projects in the
procurement events specified in item (i)
of subparagraph (G) of paragraph (1) of
subsection (c) of Section 1-75 of this Act;

and
(II) the price, or if there is more
than one price, the average of the prices,
paid for renewable energy credits from new
utility-scale solar projects and
brownfield site photovoltaic projects in
the procurement events specified in item
(ii) of subparagraph (G) of paragraph (1)
of subsection (c) of Section 1-75 of this
Act and, after January 1, 2015, renewable
energy credits from photovoltaic
distributed generation projects in
procurement events held under subsection
(c) of Section 1-75 of this Act.
Each utility shall enter into binding contractual arrangements
with the winning suppliers.
The procurement described in this subsection
(d-5), including, but not limited to, the execution of
all contracts procured, shall be completed no later
than May 10, 2017. Based on the effective date of this
amendatory Act of the 99th General Assembly, the Agency
and Commission may, as appropriate, modify the various
dates and timelines under this subparagraph and
subparagraphs (C) and (D) of this paragraph (1). The
procurement and plan approval processes required by
this subsection (d-5) shall be conducted in

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

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

such generation, ownership, or leasehold of
generation units by a zero emission facility.
However, the provisions of this item (ii) do not
apply to any generally applicable tax, special
assessment or fee, or requirements imposed by
federal law.
(iii) A zero emission facility shall be
permitted to terminate the contract in the event
that the resource requires capital expenditures in
excess of $40,000,000 that were neither known nor
reasonably foreseeable at the time it executed the
contract and that a prudent owner or operator of
such resource would not undertake.
(iv) A zero emission facility shall be
permitted to terminate the contract in the event
the Nuclear Regulatory Commission terminates the
resource's license.
(F) If the zero emission facility elects to
terminate a contract under this subparagraph (E, of
this paragraph (1), then the Commission shall reopen
the docket in which the Commission approved the zero
emission standard procurement plan under subparagraph
(C) of this paragraph (1) and, after notice and
hearing, enter an order acknowledging the contract
termination election if such termination is consistent
with the provisions of this subsection (d-5).

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

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

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

calculated under subparagraph (A) of this paragraph (3), as
follows:
(A) The average of the Social Cost of Carbon, as
defined in subparagraph (B) of paragraph (1) of this
subsection (d-5), during the term of the contract.
(B) The average of the market price indices, as
defined in subparagraph (B) of paragraph (1) of this
subsection (d-5), during the term of the contract,
minus the baseline market price index, as defined in
subparagraph (B) of paragraph (1) of this subsection
(d-5).
If the subtraction yields a negative number, then the
Average ZEC Payment shall be zero.
(4) Cost-effective zero emission credits procured from
zero emission facilities shall satisfy the applicable
definitions set forth in Section 1-10 of this Act.
(5) The electric utility shall retire all zero emission
credits used to comply with the requirements of this
subsection (d-5).
(6) Electric utilities shall be entitled to recover all
of the costs associated with the procurement of zero
emission credits through an automatic adjustment clause
tariff in accordance with subsection (k) and (m) of Section
16-108 of the Public Utilities Act, and the contracts
executed under this subsection (d-5) shall provide that the
utilities' payment obligations under such contracts shall

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

standard. After such use, the credit must be retired together
with any other credits issued for the same megawatt hour of
energy.
(Source: P.A. 98-463, eff. 8-16-13; 99-536, eff. 7-8-16.)
Section 10. The Illinois Procurement Code is amended by
changing Section 20-10 as follows:
(30 ILCS 500/20-10)
(Text of Section from P.A. 96-159, 96-588, 97-96, 97-895,
and 98-1076)
Sec. 20-10. Competitive sealed bidding; reverse auction.
(a) Conditions for use. All contracts shall be awarded by
competitive sealed bidding except as otherwise provided in
Section 20-5.
(b) Invitation for bids. An invitation for bids shall be
issued and shall include a purchase description and the
material contractual terms and conditions applicable to the
procurement.
(c) Public notice. Public notice of the invitation for bids
shall be published in the Illinois Procurement Bulletin at
least 14 calendar days before the date set in the invitation
for the opening of bids.
(d) Bid opening. Bids shall be opened publicly in the
presence of one or more witnesses at the time and place
designated in the invitation for bids. The name of each bidder,

the amount of each bid, and other relevant information as may
be specified by rule shall be recorded. After the award of the
contract, the winning bid and the record of each unsuccessful
bid shall be open to public inspection.
(e) Bid acceptance and bid evaluation. Bids shall be
unconditionally accepted without alteration or correction,
except as authorized in this Code. Bids shall be evaluated
based on the requirements set forth in the invitation for bids,
which may include criteria to determine acceptability such as
inspection, testing, quality, workmanship, delivery, and
suitability for a particular purpose. Those criteria that will
affect the bid price and be considered in evaluation for award,
such as discounts, transportation costs, and total or life
cycle costs, shall be objectively measurable. The invitation
for bids shall set forth the evaluation criteria to be used.
(f) Correction or withdrawal of bids. Correction or
withdrawal of inadvertently erroneous bids before or after
award, or cancellation of awards of contracts based on bid
mistakes, shall be permitted in accordance with rules. After
bid opening, no changes in bid prices or other provisions of
bids prejudicial to the interest of the State or fair
competition shall be permitted. All decisions to permit the
correction or withdrawal of bids based on bid mistakes shall be
supported by written determination made by a State purchasing
officer.
(g) Award. The contract shall be awarded with reasonable

promptness by written notice to the lowest responsible and
responsive bidder whose bid meets the requirements and criteria
set forth in the invitation for bids, except when a State
purchasing officer determines it is not in the best interest of
the State and by written explanation determines another bidder
shall receive the award. The explanation shall appear in the
appropriate volume of the Illinois Procurement Bulletin. The
written explanation must include:
(1) a description of the agency's needs;
(2) a determination that the anticipated cost will be
fair and reasonable;
(3) a listing of all responsible and responsive
bidders; and
(4) the name of the bidder selected, the total contract
price, and the reasons for selecting that bidder.
Each chief procurement officer may adopt guidelines to
implement the requirements of this subsection (g).
The written explanation shall be filed with the Legislative
Audit Commission and the Procurement Policy Board, and be made
available for inspection by the public, within 30 calendar days
after the agency's decision to award the contract.
(h) Multi-step sealed bidding. When it is considered
impracticable to initially prepare a purchase description to
support an award based on price, an invitation for bids may be
issued requesting the submission of unpriced offers to be
followed by an invitation for bids limited to those bidders

whose offers have been qualified under the criteria set forth
in the first solicitation.
(i) Alternative procedures. Notwithstanding any other
provision of this Act to the contrary, the Director of the
Illinois Power Agency may create alternative bidding
procedures to be used in procuring professional services under
Section 1-56, subsections subsection (a) and (c) of Section
1-75 and subsection (d) of Section 1-78 of the Illinois Power
Agency Act and Section 16-111.5(c) of the Public Utilities Act
and to procure renewable energy resources under Section 1-56 of
the Illinois Power Agency Act. These alternative procedures
shall be set forth together with the other criteria contained
in the invitation for bids, and shall appear in the appropriate
volume of the Illinois Procurement Bulletin.
(j) Reverse auction. Notwithstanding any other provision
of this Section and in accordance with rules adopted by the
chief procurement officer, that chief procurement officer may
procure supplies or services through a competitive electronic
auction bidding process after the chief procurement officer
determines that the use of such a process will be in the best
interest of the State. The chief procurement officer shall
publish that determination in his or her next volume of the
Illinois Procurement Bulletin.
An invitation for bids shall be issued and shall include
(i) a procurement description, (ii) all contractual terms,
whenever practical, and (iii) conditions applicable to the

procurement, including a notice that bids will be received in
an electronic auction manner.
Public notice of the invitation for bids shall be given in
the same manner as provided in subsection (c).
Bids shall be accepted electronically at the time and in
the manner designated in the invitation for bids. During the
auction, a bidder's price shall be disclosed to other bidders.
Bidders shall have the opportunity to reduce their bid prices
during the auction. At the conclusion of the auction, the
record of the bid prices received and the name of each bidder
shall be open to public inspection.
After the auction period has terminated, withdrawal of bids
shall be permitted as provided in subsection (f).
The contract shall be awarded within 60 calendar days after
the auction by written notice to the lowest responsible bidder,
or all bids shall be rejected except as otherwise provided in
this Code. Extensions of the date for the award may be made by
mutual written consent of the State purchasing officer and the
lowest responsible bidder.
This subsection does not apply to (i) procurements of
professional and artistic services, (ii) telecommunications
services, communication services, and information services,
and (iii) contracts for construction projects, including
design professional services.
(Source: P.A. 97-96, eff. 7-13-11; 97-895, eff. 8-3-12;
98-1076, eff. 1-1-15.)

(Text of Section from P.A. 96-159, 96-795, 97-96, 97-895,
and 98-1076)
Sec. 20-10. Competitive sealed bidding; reverse auction.
(a) Conditions for use. All contracts shall be awarded by
competitive sealed bidding except as otherwise provided in
Section 20-5.
(b) Invitation for bids. An invitation for bids shall be
issued and shall include a purchase description and the
material contractual terms and conditions applicable to the
procurement.
(c) Public notice. Public notice of the invitation for bids
shall be published in the Illinois Procurement Bulletin at
least 14 calendar days before the date set in the invitation
for the opening of bids.
(d) Bid opening. Bids shall be opened publicly in the
presence of one or more witnesses at the time and place
designated in the invitation for bids. The name of each bidder,
the amount of each bid, and other relevant information as may
be specified by rule shall be recorded. After the award of the
contract, the winning bid and the record of each unsuccessful
bid shall be open to public inspection.
(e) Bid acceptance and bid evaluation. Bids shall be
unconditionally accepted without alteration or correction,
except as authorized in this Code. Bids shall be evaluated
based on the requirements set forth in the invitation for bids,

which may include criteria to determine acceptability such as
inspection, testing, quality, workmanship, delivery, and
suitability for a particular purpose. Those criteria that will
affect the bid price and be considered in evaluation for award,
such as discounts, transportation costs, and total or life
cycle costs, shall be objectively measurable. The invitation
for bids shall set forth the evaluation criteria to be used.
(f) Correction or withdrawal of bids. Correction or
withdrawal of inadvertently erroneous bids before or after
award, or cancellation of awards of contracts based on bid
mistakes, shall be permitted in accordance with rules. After
bid opening, no changes in bid prices or other provisions of
bids prejudicial to the interest of the State or fair
competition shall be permitted. All decisions to permit the
correction or withdrawal of bids based on bid mistakes shall be
supported by written determination made by a State purchasing
officer.
(g) Award. The contract shall be awarded with reasonable
promptness by written notice to the lowest responsible and
responsive bidder whose bid meets the requirements and criteria
set forth in the invitation for bids, except when a State
purchasing officer determines it is not in the best interest of
the State and by written explanation determines another bidder
shall receive the award. The explanation shall appear in the
appropriate volume of the Illinois Procurement Bulletin. The
written explanation must include:

(1) a description of the agency's needs;
(2) a determination that the anticipated cost will be
fair and reasonable;
(3) a listing of all responsible and responsive
bidders; and
(4) the name of the bidder selected, the total contract
price, and the reasons for selecting that bidder.
Each chief procurement officer may adopt guidelines to
implement the requirements of this subsection (g).
The written explanation shall be filed with the Legislative
Audit Commission and the Procurement Policy Board, and be made
available for inspection by the public, within 30 days after
the agency's decision to award the contract.
(h) Multi-step sealed bidding. When it is considered
impracticable to initially prepare a purchase description to
support an award based on price, an invitation for bids may be
issued requesting the submission of unpriced offers to be
followed by an invitation for bids limited to those bidders
whose offers have been qualified under the criteria set forth
in the first solicitation.
(i) Alternative procedures. Notwithstanding any other
provision of this Act to the contrary, the Director of the
Illinois Power Agency may create alternative bidding
procedures to be used in procuring professional services under
subsections subsection (a) and (c) of Section 1-75 and
subsection (d) of Section 1-78 of the Illinois Power Agency Act

and Section 16-111.5(c) of the Public Utilities Act and to
procure renewable energy resources under Section 1-56 of the
Illinois Power Agency Act. These alternative procedures shall
be set forth together with the other criteria contained in the
invitation for bids, and shall appear in the appropriate volume
of the Illinois Procurement Bulletin.
(j) Reverse auction. Notwithstanding any other provision
of this Section and in accordance with rules adopted by the
chief procurement officer, that chief procurement officer may
procure supplies or services through a competitive electronic
auction bidding process after the chief procurement officer
determines that the use of such a process will be in the best
interest of the State. The chief procurement officer shall
publish that determination in his or her next volume of the
Illinois Procurement Bulletin.
An invitation for bids shall be issued and shall include
(i) a procurement description, (ii) all contractual terms,
whenever practical, and (iii) conditions applicable to the
procurement, including a notice that bids will be received in
an electronic auction manner.
Public notice of the invitation for bids shall be given in
the same manner as provided in subsection (c).
Bids shall be accepted electronically at the time and in
the manner designated in the invitation for bids. During the
auction, a bidder's price shall be disclosed to other bidders.
Bidders shall have the opportunity to reduce their bid prices

during the auction. At the conclusion of the auction, the
record of the bid prices received and the name of each bidder
shall be open to public inspection.
After the auction period has terminated, withdrawal of bids
shall be permitted as provided in subsection (f).
The contract shall be awarded within 60 calendar days after
the auction by written notice to the lowest responsible bidder,
or all bids shall be rejected except as otherwise provided in
this Code. Extensions of the date for the award may be made by
mutual written consent of the State purchasing officer and the
lowest responsible bidder.
This subsection does not apply to (i) procurements of
professional and artistic services, (ii) telecommunications
services, communication services, and information services,
and (iii) contracts for construction projects, including
design professional services.
(Source: P.A. 97-96, eff. 7-13-11; 97-895, eff. 8-3-12;
98-1076, eff. 1-1-15.)
Section 15. The Public Utilities Act is amended by changing
Sections 5-117, 5-202.1, 8-103, 8-104, 16-107, 16-107.5,
16-108, 16-108.5, 16-111.1, 16-111.5, 16-111.5B, 16-111.7,
16-115D, 16-119A, 16-127, and 16-128A and by adding Sections
8-103B, 9-107, 16-107.6, 16-108.10, 16-108.11, 16-108.12,
16-108.15, and 16-108.16 as follows:

(220 ILCS 5/5-117)
Sec. 5-117. Supplier diversity goals.
(a) The public policy of this State is to collaboratively
work with companies that serve Illinois residents to improve
their supplier diversity in a non-antagonistic manner.
(b) The Commission shall require all gas, electric, and
water companies with at least 100,000 customers under its
authority, as well as suppliers of wind energy, solar energy,
hydroelectricity, nuclear energy, and any other supplier of
energy within this State, to submit an annual report by April
15, 2015 and every April 15 thereafter, in a searchable Adobe
PDF format, on all procurement goals and actual spending for
female-owned, minority-owned, veteran-owned, and small
business enterprises in the previous calendar year. These goals
shall be expressed as a percentage of the total work performed
by the entity submitting the report, and the actual spending
for all female-owned, minority-owned, veteran-owned, and small
business enterprises shall also be expressed as a percentage of
the total work performed by the entity submitting the report.
(c) Each participating company in its annual report shall
include the following information:
(1) an explanation of the plan for the next year to
increase participation;
(2) an explanation of the plan to increase the goals;
(3) the areas of procurement each company shall be
actively seeking more participation in in the next year;

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

year thereafter on the state of supplier diversity to
collaboratively seek solutions to structural impediments to
achieving stated goals, including testimony from each
participating entity as well as subject matter experts and
advocates. The Commission shall publish a database on its
website of the point of contact for each participating entity
for supplier diversity, along with a list of certifications
each company recognizes from the information submitted in each
annual report. The Commission shall publish each annual report
on its website and shall maintain each annual report for at
least 5 years.
(Source: P.A. 98-1056, eff. 8-26-14.)
(220 ILCS 5/5-202.1)
Sec. 5-202.1. Misrepresentation before Commission;
penalty.
(a) Any person or corporation, as defined in Sections 3-113
and 3-114 of this Act, who knowingly misrepresents facts to the
Commission in response to any Commission contact, inquiry or
discussion or knowingly aids another in doing so in response to
any Commission contact, inquiry or discussion or knowingly
permits another to misrepresent facts through testimony or the
offering or withholding of material information in any
proceeding shall be subject to a civil penalty. Whenever the
Commission is of the opinion that a person or corporation is
misrepresenting or has misrepresented facts, the Commission

may initiate a proceeding to determine whether a
misrepresentation has in fact occurred. If the Commission finds
that a person or corporation has violated this Section, the
Commission shall impose a penalty of not less than $1,000 and
not greater than $500,000. Each misrepresentation of a fact
found by the Commission shall constitute a separate and
distinct violation. In determining the amount of the penalty to
be assessed, the Commission may consider any matters of record
in aggravation or mitigation of the penalty, as set forth in
Section 4-203, including but not limited to the following:
(1) the presence or absence of due diligence on the
part of the violator in attempting to comply with the Act;
(2) any economic benefits accrued, or expected to be
accrued, by the violator because of the misrepresentation;
and
(3) the amount of monetary penalty that will serve to
deter further violations by the violator and to otherwise
aid in enhancing voluntary compliance with the Act.
(b) Any action to enforce civil penalties arising under
this Section shall be undertaken pursuant to Section 4-203.
(c) For purposes of this Section, "Commission," as defined
in Section 3-102, refers to any Commissioner, agent, or
employee of the Illinois Commerce commission, and also refers
to any other person engaged to represent the Commission in
carrying out its regulatory or law enforcement obligations.
(Source: P.A. 93-457, eff. 8-8-03.)

(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
investment in cost-effective energy efficiency and
demand-response measures will reduce direct and indirect costs
to consumers by decreasing environmental impacts and by
avoiding or delaying the need for new generation, transmission,
and distribution infrastructure. It serves the public interest
to allow electric utilities to recover costs for reasonably and
prudently incurred 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.
(a-5) This Section applies to electric utilities serving
500,000 or less but more than 200,000 retail customers in this
State. Through December 31, 2017, this Section also applies to
electric utilities serving more than 500,000 retail customers
in the State.
(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
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 the year commencing June
1, 2015 and each year thereafter.

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.
(c) Electric utilities shall implement cost-effective
demand-response measures to reduce peak demand by 0.1% over the
prior year for eligible retail customers, as defined in Section
16-111.5 of this Act, and for customers that elect hourly
service from the utility pursuant to Section 16-107 of this
Act, provided those customers have not been declared
competitive. This requirement 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;
(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) 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
efficiency and demand-response measures.
(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. 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.
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 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.
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

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

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. 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 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
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
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.
(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.
(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 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.
(g) No more than 3% of energy efficiency and
demand-response program revenue may be allocated for
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
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.
(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)(1) The energy efficiency and demand-response plans of
electric utilities serving more than 500,000 retail customers
in the State that were approved by the Commission on or before
the effective date of this amendatory Act of the 99th General
Assembly for the period June 1, 2014 through May 31, 2017 shall
continue to be in force and effect through December 31, 2017 so
that the energy efficiency programs set forth in those plans
continue to be offered during the period June 1, 2017 through
December 31, 2017. Each such utility is authorized to increase,
on a pro rata basis, the energy savings goals and budgets
approved in its plan to reflect the additional 7 months of the

plan's operation, provided that such increase shall also
incorporate reductions to goals and budgets to reflect the
proportion of the utility's load attributable to customers who
are exempt from this Section under subsection (m) of this
Section.
(2) If an electric utility serving more than 500,000
retail customers in the State filed with the Commission,
under subsection (f) of this Section, its proposed energy
efficiency and demand-response plan for the period June 1,
2017 through May 31, 2020, and the Commission has not yet
entered its final order approving such plan on or before
the effective date of this amendatory Act of the 99th
General Assembly, then the utility shall file a notice of
withdrawal with the Commission, following such effective
date, to withdraw the proposed energy efficiency and
demand-response plan. Upon receipt of such notice, the
Commission shall dismiss with prejudice any docket that had
been initiated to investigate such plan, and the plan and
the record related thereto shall not be the subject of any
further hearing, investigation, or proceeding of any kind.
(3) For those electric utilities that serve more than
500,000 retail customers in the State, this amendatory Act
of the 99th General Assembly preempts and supersedes any
orders entered by the Commission that approved such
utilities' energy efficiency and demand response plans for
the period commencing June 1, 2017 and ending May 31, 2020.

Any such orders shall be void, and the provisions of
paragraph (1) of this subsection (l) shall apply.
(m) Notwithstanding anything to the contrary, after May 31,
2017, this Section does not apply to any retail customers of an
electric utility that serves more than 3,000,000 retail
customers in the State and whose total highest 30 minute demand
was more than 10,000 kilowatts, or any retail customers of an
electric utility that serves less than 3,000,000 retail
customers but more than 500,000 retail customers in the State
and whose total highest 15 minute demand was more than 10,000
kilowatts. For purposes of this subsection (m), "retail
customer" has the meaning set forth in Section 16-102 of this
Act. The criteria for determining whether this subsection (m)
is applicable to a retail customer shall be based on the 12
consecutive billing periods prior to the start of the first
year of each such multi-year plan.
(Source: P.A. 97-616, eff. 10-26-11; 97-841, eff. 7-20-12;
98-90, eff. 7-15-13.)
(220 ILCS 5/8-103B new)
Sec. 8-103B. Energy efficiency and demand-response
measures.
(a) It is the policy of the State that electric utilities
are required to use cost-effective energy efficiency and
demand-response measures to reduce delivery load. Requiring
investment in cost-effective energy efficiency and

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

subsection (b) and subsection (b-5), the 88,000,000 MWhs of
deemed electric power and energy sales shall be reduced by the
number of MWhs equal to the sum of the annual consumption of
customers that are exempt from subsections (a) through (j) of
this Section under subsection (l) of this Section, as averaged
across the calendar years 2014, 2015, and 2016. After 2017, the
deemed value of cumulative persisting annual savings from
energy efficiency measures and programs implemented during the
period beginning January 1, 2012 and ending December 31, 2017,
shall be reduced each year, as follows, and the applicable
value shall be applied to and count toward the utility's
achievement of the cumulative persisting annual savings goals
set forth in subsection (b-5):
(1) 5.8% deemed cumulative persisting annual savings
for the year ending December 31, 2018;
(2) 5.2% deemed cumulative persisting annual savings
for the year ending December 31, 2019;
(3) 4.5% deemed cumulative persisting annual savings
for the year ending December 31, 2020;
(4) 4.0% deemed cumulative persisting annual savings
for the year ending December 31, 2021;
(5) 3.5% deemed cumulative persisting annual savings
for the year ending December 31, 2022;
(6) 3.1% deemed cumulative persisting annual savings
for the year ending December 31, 2023;
(7) 2.8% deemed cumulative persisting annual savings

for the year ending December 31, 2024;
(8) 2.5% deemed cumulative persisting annual savings
for the year ending December 31, 2025;
(9) 2.3% deemed cumulative persisting annual savings
for the year ending December 31, 2026;
(10) 2.1% deemed cumulative persisting annual savings
for the year ending December 31, 2027;
(11) 1.8% deemed cumulative persisting annual savings
for the year ending December 31, 2028;
(12) 1.7% deemed cumulative persisting annual savings
for the year ending December 31, 2029; and
(13) 1.5% deemed cumulative persisting annual savings
for the year ending December 31, 2030.
For purposes of this Section, "cumulative persisting
annual savings" means the total electric energy savings in a
given year from measures installed in that year or in previous
years, but no earlier than January 1, 2012, that are still
operational and providing savings in that year because the
measures have not yet reached the end of their useful lives.
(b-5) Beginning in 2018, electric utilities subject to this
Section that serve more than 3,000,000 retail customers in the
State shall achieve the following cumulative persisting annual
savings goals, as modified by subsection (f) of this Section
and as compared to the deemed baseline of 88,000,000 MWhs of
electric power and energy sales set forth in subsection (b), as
reduced by the number of MWhs equal to the sum of the annual

consumption of customers that are exempt from subsections (a)
through (j) of this Section under subsection (l) of this
Section as averaged across the calendar years 2014, 2015, and
2016, through the implementation of energy efficiency measures
during the applicable year and in prior years, but no earlier
than January 1, 2012:
(1) 7.8% cumulative persisting annual savings for the
year ending December 31, 2018;
(2) 9.1% cumulative persisting annual savings for the
year ending December 31, 2019;
(3) 10.4% cumulative persisting annual savings for the
year ending December 31, 2020;
(4) 11.8% cumulative persisting annual savings for the
year ending December 31, 2021;
(5) 13.1% cumulative persisting annual savings for the
year ending December 31, 2022;
(6) 14.4% cumulative persisting annual savings for the
year ending December 31, 2023;
(7) 15.7% cumulative persisting annual savings for the
year ending December 31, 2024;
(8) 17% cumulative persisting annual savings for the
year ending December 31, 2025;
(9) 17.9% cumulative persisting annual savings for the
year ending December 31, 2026;
(10) 18.8% cumulative persisting annual savings for
the year ending December 31, 2027;

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

toward the utility's achievement of the cumulative persisting
annual savings goals set forth in subsection (b-15):
(1) 5.8% deemed cumulative persisting annual savings
for the year ending December 31, 2018;
(2) 5.2% deemed cumulative persisting annual savings
for the year ending December 31, 2019;
(3) 4.5% deemed cumulative persisting annual savings
for the year ending December 31, 2020;
(4) 4.0% deemed cumulative persisting annual savings
for the year ending December 31, 2021;
(5) 3.5% deemed cumulative persisting annual savings
for the year ending December 31, 2022;
(6) 3.1% deemed cumulative persisting annual savings
for the year ending December 31, 2023;
(7) 2.8% deemed cumulative persisting annual savings
for the year ending December 31, 2024;
(8) 2.5% deemed cumulative persisting annual savings
for the year ending December 31, 2025;
(9) 2.3% deemed cumulative persisting annual savings
for the year ending December 31, 2026;
(10) 2.1% deemed cumulative persisting annual savings
for the year ending December 31, 2027;
(11) 1.8% deemed cumulative persisting annual savings
for the year ending December 31, 2028;
(12) 1.7% deemed cumulative persisting annual savings
for the year ending December 31, 2029; and

(13) 1.5% deemed cumulative persisting annual savings
for the year ending December 31, 2030.
(b-15) Beginning in 2018, electric utilities subject to
this Section that serve less than 3,000,000 retail customers
but more than 500,000 retail customers in the State shall
achieve the following cumulative persisting annual savings
goals, as modified by subsection (b-20) and subsection (f) of
this Section and as compared to the deemed baseline as reduced
by the number of MWhs equal to the sum of the annual
consumption of customers that are exempt from subsections (a)
through (j) of this Section under subsection (l) of this
Section as averaged across the calendar years 2014, 2015, and
2016, through the implementation of energy efficiency measures
during the applicable year and in prior years, but no earlier
than January 1, 2012:
(1) 7.4% cumulative persisting annual savings for the
year ending December 31, 2018;
(2) 8.2% cumulative persisting annual savings for the
year ending December 31, 2019;
(3) 9.0% cumulative persisting annual savings for the
year ending December 31, 2020;
(4) 9.8% cumulative persisting annual savings for the
year ending December 31, 2021;
(5) 10.6% cumulative persisting annual savings for the
year ending December 31, 2022;
(6) 11.4% cumulative persisting annual savings for the

year ending December 31, 2023;
(7) 12.2% cumulative persisting annual savings for the
year ending December 31, 2024;
(8) 13% cumulative persisting annual savings for the
year ending December 31, 2025;
(9) 13.6% cumulative persisting annual savings for the
year ending December 31, 2026;
(10) 14.2% cumulative persisting annual savings for
the year ending December 31, 2027;
(11) 14.8% cumulative persisting annual savings for
the year ending December 31, 2028;
(12) 15.4% cumulative persisting annual savings for
the year ending December 31, 2029; and
(13) 16% cumulative persisting annual savings for the
year ending December 31, 2030.
The difference between the cumulative persisting annual
savings goal for the applicable calendar year and the
cumulative persisting annual savings goal for the immediately
preceding calendar year is 0.8% for the period of January 1,
2018 through December 31, 2025 and 0.6% for the period of
January 1, 2026 through December 31, 2030.
(b-20) Each electric utility subject to this Section may
include cost-effective voltage optimization measures in its
plans submitted under subsections (f) and (g) of this Section,
and the costs incurred by a utility to implement the measures
under a Commission-approved plan shall be recovered under the

provisions of Article IX or Section 16-108.5 of this Act. For
purposes of this Section, the measure life of voltage
optimization measures shall be 15 years. The measure life
period is independent of the depreciation rate of the voltage
optimization assets deployed.
Within 270 days after the effective date of this amendatory
Act of the 99th General Assembly, an electric utility that
serves less than 3,000,000 retail customers but more than
500,000 retail customers in the State shall file a plan with
the Commission that identifies the cost-effective voltage
optimization investment the electric utility plans to
undertake through December 31, 2024. The Commission, after
notice and hearing, shall approve or approve with modification
the plan within 120 days after the plan's filing and, in the
order approving or approving with modification the plan, the
Commission shall adjust the applicable cumulative persisting
annual savings goals set forth in subsection (b-15) to reflect
any amount of cost-effective energy savings approved by the
Commission that is greater than or less than the following
cumulative persisting annual savings values attributable to
voltage optimization for the applicable year:
(1) 0.0% of cumulative persisting annual savings for
the year ending December 31, 2018;
(2) 0.17% of cumulative persisting annual savings for
the year ending December 31, 2019;
(3) 0.17% of cumulative persisting annual savings for

the year ending December 31, 2020;
(4) 0.33% of cumulative persisting annual savings for
the year ending December 31, 2021;
(5) 0.5% of cumulative persisting annual savings for
the year ending December 31, 2022;
(6) 0.67% of cumulative persisting annual savings for
the year ending December 31, 2023;
(7) 0.83% of cumulative persisting annual savings for
the year ending December 31, 2024; and
(8) 1.0% of cumulative persisting annual savings for
the year ending December 31, 2025.
(b-25) In the event an electric utility jointly offers an
energy efficiency measure or program with a gas utility under
plans approved under this Section and Section 8-104 of this
Act, the electric utility may continue offering the program,
including the gas energy efficiency measures, in the event the
gas utility discontinues funding the program. In that event,
the energy savings value associated with such other fuels shall
be converted to electric energy savings on an equivalent Btu
basis for the premises. However, the electric utility shall
prioritize programs for low-income residential customers to
the extent practicable. An electric utility may recover the
costs of offering the gas energy efficiency measures under this
subsection (b-25).
For those energy efficiency measures or programs that save
both electricity and other fuels but are not jointly offered

with a gas utility under plans approved under this Section and
Section 8-104 or not offered with an affiliated gas utility
under paragraph (6) of subsection (f) of Section 8-104 of this
Act, the electric utility may count savings of fuels other than
electricity toward the achievement of its annual savings goal,
and the energy savings value associated with such other fuels
shall be converted to electric energy savings on an equivalent
Btu basis at the premises.
In no event shall more than 10% of each year's applicable
annual incremental goal as defined in paragraph (7) of
subsection (g) of this Section be met through savings of fuels
other than electricity.
(c) Electric utilities shall be responsible for overseeing
the design, development, and filing of energy efficiency plans
with the Commission and may, as part of that implementation,
outsource various aspects of program development and
implementation. A minimum of 10%, for electric utilities that
serve more than 3,000,000 retail customers in the State, and a
minimum of 7%, for electric utilities that serve less than
3,000,000 retail customers but more than 500,000 retail
customers in the State, of the utility's entire portfolio
funding level for a given year shall be used to procure
cost-effective energy efficiency measures from units of local
government, municipal corporations, school districts, public
housing, and community college districts, provided that a
minimum percentage of available funds shall be used to procure

energy efficiency from public housing, which percentage shall
be equal to public housing's share of public building energy
consumption.
The utilities shall also implement energy efficiency
measures targeted at low-income households, which, for
purposes of this Section, shall be defined as households at or
below 80% of area median income, and expenditures to implement
the measures shall be no less than $25,000,000 per year for
electric utilities that serve more than 3,000,000 retail
customers in the State and no less than $8,350,000 per year for
electric utilities that serve less than 3,000,000 retail
customers but more than 500,000 retail customers in the State.
Each electric utility shall assess opportunities to
implement cost-effective energy efficiency measures and
programs through a public housing authority or authorities
located in its service territory. If such opportunities are
identified, the utility shall propose such measures and
programs to address the opportunities. Expenditures to address
such opportunities shall be credited toward the minimum
procurement and expenditure requirements set forth in this
subsection (c).
Implementation of energy efficiency measures and programs
targeted at low-income households should be contracted, when it
is practicable, to independent third parties that have
demonstrated capabilities to serve such households, with a
preference for not-for-profit entities and government agencies

that have existing relationships with or experience serving
low-income communities in the State.
Each electric utility shall develop and implement
reporting procedures that address and assist in determining the
amount of energy savings that can be applied to the low-income
procurement and expenditure requirements set forth in this
subsection (c).
The electric utilities shall also convene a low-income
energy efficiency advisory committee to assist in the design
and evaluation of the low-income energy efficiency programs.
The committee shall be comprised of the electric utilities
subject to the requirements of this Section, the gas utilities
subject to the requirements of Section 8-104 of this Act, the
utilities' low-income energy efficiency implementation
contractors, and representatives of community-based
organizations.
(d) Notwithstanding any other provision of law to the
contrary, a utility providing approved energy efficiency
measures and, if applicable, demand-response measures in the
State shall be permitted to recover all reasonable and
prudently incurred costs of those measures from all retail
customers, except as provided in subsection (l) of this
Section, as follows, provided that nothing in this subsection
(d) permits the double recovery of such costs from customers:
(1) The utility may recover its costs through an
automatic adjustment clause tariff filed with and approved

by the Commission. The tariff shall be established outside
the context of a general rate case. Each year the
Commission shall initiate a review to reconcile any amounts
collected with the actual costs and to determine the
required adjustment to the annual tariff factor to match
annual expenditures. To enable the financing of the
incremental capital expenditures, including regulatory
assets, for electric utilities that serve less than
3,000,000 retail customers but more than 500,000 retail
customers in the State, the utility's actual year-end
capital structure that includes a common equity ratio,
excluding goodwill, of up to and including 50% of the total
capital structure shall be deemed reasonable and used to
set rates.
(2) A utility may recover its costs through an energy
efficiency formula rate approved by the Commission under a
filing under subsections (f) and (g) of this Section, which
shall specify the cost components that form the basis of
the rate charged to customers with sufficient specificity
to operate in a standardized manner and be updated annually
with transparent information that reflects the utility's
actual costs to be recovered during the applicable rate
year, which is the period beginning with the first billing
day of January and extending through the last billing day
of the following December. The energy efficiency formula
rate shall be implemented through a tariff filed with the

Commission under subsections (f) and (g) of this Section
that is consistent with the provisions of this paragraph
(2) and that shall be applicable to all delivery services
customers. The Commission shall conduct an investigation
of the tariff in a manner consistent with the provisions of
this paragraph (2), subsections (f) and (g) of this
Section, and the provisions of Article IX of this Act to
the extent they do not conflict with this paragraph (2).
The energy efficiency formula rate approved by the
Commission shall remain in effect at the discretion of the
utility and shall do the following:
(A) Provide for the recovery of the utility's
actual costs incurred under this Section that are
prudently incurred and reasonable in amount consistent
with Commission practice and law. The sole fact that a
cost differs from that incurred in a prior calendar
year or that an investment is different from that made
in a prior calendar year shall not imply the imprudence
or unreasonableness of that cost or investment.
(B) Reflect the utility's actual year-end capital
structure for the applicable calendar year, excluding
goodwill, subject to a determination of prudence and
reasonableness consistent with Commission practice and
law. To enable the financing of the incremental capital
expenditures, including regulatory assets, for
electric utilities that serve less than 3,000,000

retail customers but more than 500,000 retail
customers in the State, a participating electric
utility's actual year-end capital structure that
includes a common equity ratio, excluding goodwill, of
up to and including 50% of the total capital structure
shall be deemed reasonable and used to set rates.
(C) Include a cost of equity, which shall be
calculated as the sum of the following:
(i) the average for the applicable calendar
year of the monthly average yields of 30-year U.S.
Treasury bonds published by the Board of Governors
of the Federal Reserve System in its weekly H.15
Statistical Release or successor publication; and
(ii) 580 basis points.
At such time as the Board of Governors of the
Federal Reserve System ceases to include the monthly
average yields of 30-year U.S. Treasury bonds in its
weekly H.15 Statistical Release or successor
publication, the monthly average yields of the U.S.
Treasury bonds then having the longest duration
published by the Board of Governors in its weekly H.15
Statistical Release or successor publication shall
instead be used for purposes of this paragraph (2).
(D) Permit and set forth protocols, subject to a
determination of prudence and reasonableness
consistent with Commission practice and law, for the

following:
(i) recovery of incentive compensation expense
that is based on the achievement of operational
metrics, including metrics related to budget
controls, outage duration and frequency, safety,
customer service, efficiency and productivity, and
environmental compliance; however, this protocol
shall not apply if such expense related to costs
incurred under this Section is recovered under
Article IX or Section 16-108.5 of this Act;
incentive compensation expense that is based on
net income or an affiliate's earnings per share
shall not be recoverable under the energy
efficiency formula rate;
(ii) recovery of pension and other
post-employment benefits expense, provided that
such costs are supported by an actuarial study;
however, this protocol shall not apply if such
expense related to costs incurred under this
Section is recovered under Article IX or Section
16-108.5 of this Act;
(iii) recovery of existing regulatory assets
over the periods previously authorized by the
Commission;
(iv) as described in subsection (e),
amortization of costs incurred under this Section;

and
(v) projected, weather normalized billing
determinants for the applicable rate year.
(E) Provide for an annual reconciliation, as
described in paragraph (3) of this subsection (d), less
any deferred taxes related to the reconciliation, with
interest at an annual rate of return equal to the
utility's weighted average cost of capital, including
a revenue conversion factor calculated to recover or
refund all additional income taxes that may be payable
or receivable as a result of that return, of the energy
efficiency revenue requirement reflected in rates for
each calendar year, beginning with the calendar year in
which the utility files its energy efficiency formula
rate tariff under this paragraph (2), with what the
revenue requirement would have been had the actual cost
information for the applicable calendar year been
available at the filing date.
The utility shall file, together with its tariff, the
projected costs to be incurred by the utility during the
rate year under the utility's multi-year plan approved
under subsections (f) and (g) of this Section, including,
but not limited to, the projected capital investment costs
and projected regulatory asset balances with
correspondingly updated depreciation and amortization
reserves and expense, that shall populate the energy

efficiency formula rate and set the initial rates under the
formula.
The Commission shall review the proposed tariff in
conjunction with its review of a proposed multi-year plan,
as specified in paragraph (5) of subsection (g) of this
Section. The review shall be based on the same evidentiary
standards, including, but not limited to, those concerning
the prudence and reasonableness of the costs incurred by
the utility, the Commission applies in a hearing to review
a filing for a general increase in rates under Article IX
of this Act. The initial rates shall take effect beginning
with the January monthly billing period following the
Commission's approval.
The tariff's rate design and cost allocation across
customer classes shall be consistent with the utility's
automatic adjustment clause tariff in effect on the
effective date of this amendatory Act of the 99th General
Assembly; however, the Commission may revise the tariff's
rate design and cost allocation in subsequent proceedings
under paragraph (3) of this subsection (d).
If the energy efficiency formula rate is terminated,
the then current rates shall remain in effect until such
time as the energy efficiency costs are incorporated into
new rates that are set under this subsection (d) or Article
IX of this Act, subject to retroactive rate adjustment,
with interest, to reconcile rates charged with actual

costs.
(3) The provisions of this paragraph (3) shall only
apply to an electric utility that has elected to file an
energy efficiency formula rate under paragraph (2) of this
subsection (d). Subsequent to the Commission's issuance of
an order approving the utility's energy efficiency formula
rate structure and protocols, and initial rates under
paragraph (2) of this subsection (d), the utility shall
file, on or before June 1 of each year, with the Chief
Clerk of the Commission its updated cost inputs to the
energy efficiency formula rate for the applicable rate year
and the corresponding new charges, as well as the
information described in paragraph (9) of subsection (g) of
this Section. Each such filing shall conform to the
following requirements and include the following
information:
(A) The inputs to the energy efficiency formula
rate for the applicable rate year shall be based on the
projected costs to be incurred by the utility during
the rate year under the utility's multi-year plan
approved under subsections (f) and (g) of this Section,
including, but not limited to, projected capital
investment costs and projected regulatory asset
balances with correspondingly updated depreciation and
amortization reserves and expense. The filing shall
also include a reconciliation of the energy efficiency

revenue requirement that was in effect for the prior
rate year (as set by the cost inputs for the prior rate
year) with the actual revenue requirement for the prior
rate year (determined using a year-end rate base) that
uses amounts reflected in the applicable FERC Form 1
that reports the actual costs for the prior rate year.
Any over-collection or under-collection indicated by
such reconciliation shall be reflected as a credit
against, or recovered as an additional charge to,
respectively, with interest calculated at a rate equal
to the utility's weighted average cost of capital
approved by the Commission for the prior rate year, the
charges for the applicable rate year. Such
over-collection or under-collection shall be adjusted
to remove any deferred taxes related to the
reconciliation, for purposes of calculating interest
at an annual rate of return equal to the utility's
weighted average cost of capital approved by the
Commission for the prior rate year, including a revenue
conversion factor calculated to recover or refund all
additional income taxes that may be payable or
receivable as a result of that return. Each
reconciliation shall be certified by the participating
utility in the same manner that FERC Form 1 is
certified. The filing shall also include the charge or
credit, if any, resulting from the calculation

required by subparagraph (E) of paragraph (2) of this
subsection (d).
Notwithstanding any other provision of law to the
contrary, the intent of the reconciliation is to
ultimately reconcile both the revenue requirement
reflected in rates for each calendar year, beginning
with the calendar year in which the utility files its
energy efficiency formula rate tariff under paragraph
(2) of this subsection (d), with what the revenue
requirement determined using a year-end rate base for
the applicable calendar year would have been had the
actual cost information for the applicable calendar
year been available at the filing date.
For purposes of this Section, "FERC Form 1" means
the Annual Report of Major Electric Utilities,
Licensees and Others that electric utilities are
required to file with the Federal Energy Regulatory
Commission under the Federal Power Act, Sections 3,
4(a), 304 and 209, modified as necessary to be
consistent with 83 Ill. Admin. Code Part 415 as of May
1, 2011. Nothing in this Section is intended to allow
costs that are not otherwise recoverable to be
recoverable by virtue of inclusion in FERC Form 1.
(B) The new charges shall take effect beginning on
the first billing day of the following January billing
period and remain in effect through the last billing

day of the next December billing period regardless of
whether the Commission enters upon a hearing under this
paragraph (3).
(C) The filing shall include relevant and
necessary data and documentation for the applicable
rate year. Normalization adjustments shall not be
required.
Within 45 days after the utility files its annual
update of cost inputs to the energy efficiency formula
rate, the Commission shall with reasonable notice,
initiate a proceeding concerning whether the projected
costs to be incurred by the utility and recovered during
the applicable rate year, and that are reflected in the
inputs to the energy efficiency formula rate, are
consistent with the utility's approved multi-year plan
under subsections (f) and (g) of this Section and whether
the costs incurred by the utility during the prior rate
year were prudent and reasonable. The Commission shall also
have the authority to investigate the information and data
described in paragraph (9) of subsection (g) of this
Section, including the proposed adjustment to the
utility's return on equity component of its weighted
average cost of capital. During the course of the
proceeding, each objection shall be stated with
particularity and evidence provided in support thereof,
after which the utility shall have the opportunity to rebut

the evidence. Discovery shall be allowed consistent with
the Commission's Rules of Practice, which Rules of Practice
shall be enforced by the Commission or the assigned 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, during the proceeding as it would apply in a
proceeding to review a filing for a general increase in
rates under Article IX of this Act. The Commission shall
not, however, have the authority in a proceeding under this
paragraph (3) to consider or order any changes to the
structure or protocols of the energy efficiency formula
rate approved under paragraph (2) of this subsection (d).
In a proceeding under this paragraph (3), the Commission
shall enter its order no later than the earlier of 195 days
after the utility's filing of its annual update of cost
inputs to the energy efficiency formula rate or December
15. The utility's proposed return on equity calculation, as
described in paragraphs (7) through (9) of subsection (g)
of this Section, shall be deemed the final, approved
calculation on December 15 of the year in which it is filed
unless the Commission enters an order on or before December
15, after notice and hearing, that modifies such
calculation consistent with this Section. The Commission's
determinations of the prudence and reasonableness of the
costs incurred, and determination of such return on equity

calculation, for the applicable calendar year shall be
final upon entry of the Commission's order and shall not be
subject to reopening, reexamination, or collateral attack
in any other Commission proceeding, case, docket, order,
rule, or regulation; however, nothing in this paragraph (3)
shall prohibit a party from petitioning the Commission to
rehear or appeal to the courts the order under the
provisions of this Act.
(e) Beginning on the effective date of this amendatory Act
of the 99th General Assembly, a utility subject to the
requirements of this Section may elect to defer, as a
regulatory asset, up to the full amount of its expenditures
incurred under this Section for each annual period, including,
but not limited to, any expenditures incurred above the funding
level set by subsection (f) of this Section for a given year.
The total expenditures deferred as a regulatory asset in a
given year shall be amortized and recovered over a period that
is equal to the weighted average of the energy efficiency
measure lives implemented for that year that are reflected in
the regulatory asset. The unamortized balance shall be
recognized as of December 31 for a given year. The utility
shall also earn a return on the total of the unamortized
balances of all of the energy efficiency regulatory assets,
less any deferred taxes related to those unamortized balances,
at an annual rate equal to the utility's weighted average cost
of capital that includes, based on a year-end capital

structure, the utility's actual cost of debt for the applicable
calendar year and a cost of equity, which shall be calculated
as the sum of the (i) the average for the applicable calendar
year of the monthly average yields of 30-year U.S. Treasury
bonds published by the Board of Governors of the Federal
Reserve System in its weekly H.15 Statistical Release or
successor publication; and (ii) 580 basis points, including a
revenue conversion factor calculated to recover or refund all
additional income taxes that may be payable or receivable as a
result of that return. Capital investment costs shall be
depreciated and recovered over their useful lives consistent
with generally accepted accounting principles. The weighted
average cost of capital shall be applied to the capital
investment cost balance, less any accumulated depreciation and
accumulated deferred income taxes, as of December 31 for a
given year.
When an electric utility creates a regulatory asset under
the provisions of this Section, the costs are recovered over a
period during which customers also receive a benefit which is
in the public interest. Accordingly, it is the intent of the
General Assembly that an electric utility that elects to create
a regulatory asset under the provisions of this Section shall
recover all of the associated costs as set forth in this
Section. After the Commission has approved the prudence and
reasonableness of the costs that comprise the regulatory asset,
the electric utility shall be permitted to recover all such

costs, and the value and recoverability through rates of the
associated regulatory asset shall not be limited, altered,
impaired, or reduced.
(f) Beginning in 2017, each electric utility shall file an
energy efficiency plan with the Commission to meet the energy
efficiency standards for the next applicable multi-year period
beginning January 1 of the year following the filing, according
to the schedule set forth in paragraphs (1) through (3) of this
subsection (f). If a utility does not file such a plan on or
before the applicable filing deadline for the plan, it shall
face a penalty of $100,000 per day until the plan is filed.
(1) No later than 30 days after the effective date of
this amendatory Act of the 99th General Assembly or May 1,
2017, whichever is later, each electric utility shall file
a 4-year energy efficiency plan commencing on January 1,
2018 that is designed to achieve the cumulative persisting
annual savings goals specified in paragraphs (1) through
(4) of subsection (b-5) of this Section or in paragraphs
(1) through (4) of subsection (b-15) of this Section, as
applicable, through implementation of energy efficiency
measures; however, the goals may be reduced if the
utility's expenditures are limited pursuant to subsection
(m) of this Section or, for a utility that serves less than
3,000,000 retail customers, if each of the following
conditions are met: (A) the plan's analysis and forecasts
of the utility's ability to acquire energy savings

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

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

the utility's expenditures are limited pursuant to
subsection (m) of this Section or, each of the following
conditions are met: (A) the plan's analysis and forecasts
of the utility's ability to acquire energy savings
demonstrate that achievement of such goals is not cost
effective; and (B) the amount of energy savings achieved by
the utility as determined by the independent evaluator for
the most recent year for which savings have been evaluated
preceding the plan filing was less than the average annual
amount of savings required to achieve the goals for the
applicable 5-year plan period. Except as provided in
subsection (m) of this Section, annual increases in
cumulative persisting annual savings goals during the
applicable 5-year plan period shall not be reduced to
amounts that are less than the maximum amount of cumulative
persisting annual savings that is forecast to be
cost-effectively achievable during the 5-year plan period.
The Commission shall review any proposed goal reduction as
part of its review and approval of the utility's proposed
plan.
Each utility's plan shall set forth the utility's proposals
to meet the energy efficiency standards identified in
subsection (b-5) or (b-15), as applicable and as such standards
may have been modified under this subsection (f), taking into
account the unique circumstances of the utility's service
territory. For those plans commencing on January 1, 2018, the

Commission shall seek public comment on the utility's plan and
shall issue an order approving or disapproving each plan no
later than August 31, 2017, or 105 days after the effective
date of this amendatory Act of the 99th General Assembly,
whichever is later. For those plans commencing after December
31, 2021, the Commission shall seek public comment on the
utility's plan and shall issue an order approving or
disapproving each plan within 6 months after its submission. If
the Commission disapproves a plan, the Commission shall, within
30 days, describe in detail the reasons for the disapproval and
describe a path by which the utility may file a revised draft
of the plan to address the Commission's concerns
satisfactorily. If the utility does not refile with the
Commission within 60 days, the utility shall be subject to
penalties at a rate of $100,000 per day until the plan is
filed. This process shall continue, and penalties shall accrue,
until the utility has successfully filed a portfolio of energy
efficiency and demand-response measures. Penalties shall be
deposited into the Energy Efficiency Trust Fund.
(g) In submitting proposed plans and funding levels under
subsection (f) of this Section to meet the savings goals
identified in subsection (b-5) or (b-15) of this Section, as
applicable, the utility shall:
(1) Demonstrate that its proposed energy efficiency
measures will achieve the applicable requirements that are
identified in subsection (b-5) or (b-15) of this Section,

as modified by subsection (f) of this Section.
(2) Present specific proposals to implement new
building and appliance standards that have been placed into
effect.
(3) Demonstrate that its overall portfolio of
measures, not including low-income programs described in
subsection (c) of this Section, is cost-effective using the
total resource cost test or complies with paragraphs (1)
through (3) of subsection (f) of this Section and
represents a diverse cross-section of opportunities for
customers of all rate classes, other than those customers
described in subsection (l) of this Section, to participate
in the programs. Individual measures need not be cost
effective.
(4) Present a third-party energy efficiency
implementation program subject to the following
requirements:
(A) beginning with the year commencing January 1,
2019, electric utilities that serve more than
3,000,000 retail customers in the State shall fund
third-party energy efficiency programs in an amount
that is no less than $25,000,000 per year, and electric
utilities that serve less than 3,000,000 retail
customers but more than 500,000 retail customers in the
State shall fund third-party energy efficiency
programs in an amount that is no less than $8,350,000

per year;
(B) during 2018, the utility shall conduct a
solicitation process for purposes of requesting
proposals from third-party vendors for those
third-party energy efficiency programs to be offered
during one or more of the years commencing January 1,
2019, January 1, 2020, and January 1, 2021; for those
multi-year plans commencing on January 1, 2022 and
January 1, 2026, the utility shall conduct a
solicitation process during 2021 and 2025,
respectively, for purposes of requesting proposals
from third-party vendors for those third-party energy
efficiency programs to be offered during one or more
years of the respective multi-year plan period; for
each solicitation process, the utility shall identify
the sector, technology, or geographical area for which
it is seeking requests for proposals;
(C) the utility shall propose the bidder
qualifications, performance measurement process, and
contract structure, which must include a performance
payment mechanism and general terms and conditions;
the proposed qualifications, process, and structure
shall be subject to Commission approval; and
(D) the utility shall retain an independent third
party to score the proposals received through the
solicitation process described in this paragraph (4),

rank them according to their cost per lifetime
kilowatt-hours saved, and assemble the portfolio of
third-party programs.
The electric utility shall recover all costs
associated with Commission-approved, third-party
administered programs regardless of the success of those
programs.
(4.5)Implement cost-effective demand-response measures
to reduce peak demand by 0.1% over the prior year for
eligible retail customers, as defined in Section 16-111.5
of this Act, and for customers that elect hourly service
from the utility pursuant to Section 16-107 of this Act,
provided those customers have not been declared
competitive. This requirement continues until December 31,
2026.
(5) Include a proposed or revised cost-recovery tariff
mechanism, as provided for under subsection (d) of this
Section, to fund the proposed energy efficiency and
demand-response measures and to ensure the recovery of the
prudently and reasonably incurred costs of
Commission-approved programs.
(6) Provide for an annual independent evaluation of the
performance of the cost-effectiveness of the utility's
portfolio of measures, as well as a full review of the
multi-year plan results of the broader net program impacts
and, to the extent practical, for adjustment of the

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

basis points in the event that the utility achieved
at least 125% of such goal. If the utility achieved
more than 100% of the applicable annual
incremental goal but less than 125% of such goal,
then the return on equity component shall be
increased by 8 basis points for each percent by
which the utility achieved above the goal. If the
applicable annual incremental goal was reduced
under paragraphs (1) or (2) of subsection (f) of
this Section, then the following adjustments shall
be made to the calculations described in this item
(ii):
(aa) the calculation for determining
achievement that is at least 125% of the
applicable annual incremental goal shall use
the unreduced applicable annual incremental
goal to set the value; and
(bb) the calculation for determining
achievement that is less than 125% but more
than 100% of the applicable annual incremental
goal shall use the reduced applicable annual
incremental goal to set the value for 100%
achievement of the goal and shall use the
unreduced goal to set the value for 125%
achievement. The 8 basis point value shall also
be modified, as necessary, so that the 200

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

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

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

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

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

the calculation for determining achievement that
is less than 125% but more than 100% of the
applicable annual incremental goal shall use the
reduced applicable annual incremental goal to set
the value for 100% achievement of the goal and
shall use the unreduced goal to set the value for
125% achievement. The 8 basis point value shall
also be modified, as necessary, so that the 200
basis points are evenly apportioned among each
percentage point value between 100% and 125%
achievement.
(iii) For the period of January 1, 2026 through
December 31, 2030, the calculation for determining
achievement that is less than 134% but more than
100% of the applicable annual incremental goal
shall use the reduced applicable annual
incremental goal to set the value for 100%
achievement of the goal and shall use the unreduced
goal to set the value for 125% achievement. The 6
basis point value shall also be modified, as
necessary, so that the 200 basis points are evenly
apportioned among each percentage point value
between 100% and 134% achievement.
(9) The utility shall submit the energy savings data to
the independent evaluator no later than 30 days after the
close of the plan year. The independent evaluator shall

determine the cumulative persisting annual savings for a
given plan year no later than 120 days after the close of
the plan year. The utility shall submit an informational
filing to the Commission no later than 160 days after the
close of the plan year that attaches the independent
evaluator's final report identifying the cumulative
persisting annual savings for the year and calculates,
under paragraph (7) or (8) of this subsection (g), as
applicable, any resulting change to the utility's return on
equity component of the weighted average cost of capital
applicable to the next plan year beginning with the January
monthly billing period and extending through the December
monthly billing period. However, if the utility recovers
the costs incurred under this Section under paragraphs (2)
and (3) of subsection (d) of this Section, then the utility
shall not be required to submit such informational filing,
and shall instead submit the information that would
otherwise be included in the informational filing as part
of its filing under paragraph (3) of such subsection (d)
that is due on or before June 1 of each year.
For those utilities that must submit the informational
filing, the Commission may, on its own motion or by
petition, initiate an investigation of such filing,
provided, however, that the utility's proposed return on
equity calculation shall be deemed the final, approved
calculation on December 15 of the year in which it is filed

unless the Commission enters an order on or before December
15, after notice and hearing, that modifies such
calculation consistent with this Section.
The adjustments to the return on equity component
described in paragraphs (7) and (8) of this subsection (g)
shall be applied as described in such paragraphs through a
separate tariff mechanism, which shall be filed by the
utility under subsections (f) and (g) of this Section.
(h) No more than 6% of energy efficiency and
demand-response program revenue may be allocated for research,
development, or pilot deployment of new equipment or measures.
(i) When practicable, electric utilities shall incorporate
advanced metering infrastructure data into the planning,
implementation, and evaluation of energy efficiency measures
and programs, subject to the data privacy and confidentiality
protections of applicable law.
(j) The independent evaluator shall follow the guidelines
and use the savings set forth in Commission-approved energy
efficiency policy manuals and technical reference manuals, as
each may be updated from time to time. Until such time as
measure life values for energy efficiency measures implemented
for low-income households under subsection (c) of this Section
are incorporated into such Commission-approved manuals, the
low-income measures shall have the same measure life values
that are established for same measures implemented in
households that are not low-income households.

(k) Notwithstanding any provision of law to the contrary,
an electric utility subject to the requirements of this Section
may file a tariff cancelling an automatic adjustment clause
tariff in effect under this Section or Section 8-103, which
shall take effect no later than one business day after the date
such tariff is filed. Thereafter, the utility shall be
authorized to defer and recover its expenditures incurred under
this Section through a new tariff authorized under subsection
(d) of this Section or in the utility's next rate case under
Article IX or Section 16-108.5 of this Act, with interest at an
annual rate equal to the utility's weighted average cost of
capital as approved by the Commission in such case. If the
utility elects to file a new tariff under subsection (d) of
this Section, the utility may file the tariff within 10 days
after the effective date of this amendatory Act of the 99th
General Assembly, and the cost inputs to such tariff shall be
based on the projected costs to be incurred by the utility
during the calendar year in which the new tariff is filed and
that were not recovered under the tariff that was cancelled as
provided for in this subsection. Such costs shall include those
incurred or to be incurred by the utility under its multi-year
plan approved under subsections (f) and (g) of this Section,
including, but not limited to, projected capital investment
costs and projected regulatory asset balances with
correspondingly updated depreciation and amortization reserves
and expense. The Commission shall, after notice and hearing,

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

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

eligible retail customers during calendar year 2015. To
determine the total amount that may be spent by an electric
utility in any single year, the applicable percentage of the
average amount paid per kilowatthour shall be multiplied by the
total amount of energy delivered by such electric utility in
the calendar year 2015, adjusted to reflect the proportion of
the utility's load attributable to customers who are exempt
from subsections (a) through (j) of this Section under
subsection (l) of this Section. For purposes of this subsection
(m), the amount paid per kilowatthour includes, without
limitation, estimated amounts paid for supply, transmission,
distribution, surcharges, and add-on taxes. For purposes of
this Section, "eligible retail customers" shall have the
meaning set forth in Section 16-111.5 of this Act. Once the
Commission has approved a plan under subsections (f) and (g) of
this Section, no subsequent rate impact determinations shall be
made.
(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, 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 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 multi-year 3-year planning period associated
with measures implemented after May 31, 2011 were equal to the
sum of each annual incremental savings requirement from the
first day of the multi-year planning period May 31, 2011
through the last day of the multi-year planning period end of
the applicable year:
(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% in the year commencing January
1, 2018 by May 31, 2018, increasing total savings to 5.6%;
(8) an additional 1.5% in the year commencing January
1, 2019 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 multi-year 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 multi-year 3-year reporting period. The energy
savings requirements in subsection (c) of this Section may be
reduced by the Commission 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 multi-year 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) The provisions of this subsection (e) apply to those
multi-year plans that commence prior to January 1, 2018 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 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.
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.
(e-5) The provisions of this subsection (e-5) shall be
applicable to those multi-year plans that commence after
December 31, 2017. Natural gas utilities shall be responsible
for overseeing the design, development, and filing of their
efficiency plans with the Commission and 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 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 utilities shall also 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. Such programs shall be targeted to

households with incomes at or below 80% of area median income.
(e-10) A utility providing approved energy efficiency
measures in this State 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 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.
(e-15) For those multi-year plans that commence prior to
January 1, 2018, each 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.
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
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. No later than
October 1, 2013, each gas utility shall file an energy
efficiency plan with the Commission to meet the energy
efficiency standards through May 31, 2017. Beginning in 2017
and every 4 Every 3 years thereafter, each utility shall file,
no later than October 1, an energy efficiency plan with the
Commission to meet the energy efficiency standards for the next
applicable 4-year period beginning January 1 of the year
following the filing. For those multi-year plans commencing on
January 1, 2018, each utility shall file its proposed energy
efficiency plan no later than 30 days after the effective date
of this amendatory Act of the 99th General Assembly or May 1,
2017, whichever is later. Beginning in 2021 and every 4 years
thereafter, each utility shall file its energy efficiency plan
no later than March 1. If a utility does not file such a plan on
or before the applicable filing deadline for the plan by

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.
For those plans commencing after December 31, 2021, the The
Commission shall seek public comment on the utility's plan and
shall issue an order approving or disapproving each plan within
6 months after its submission. For those plans commencing on
January 1, 2018, the Commission shall seek public comment on
the utility's plan and shall issue an order approving or
disapproving each plan no later than August 31, 2017, or 105
days after the effective date of this amendatory Act of the
99th General Assembly, whichever is later. 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
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) For those multi-year plans that commence prior to
January 1, 2018, coordinate 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. 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 low-income programs
described in covered by item (4) of this subsection (f) and

subsection (e-5) of this Section, 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 or 8-103B 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. For those multi-year
plans that commence prior to January 1, 2018, the 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, if applicable, the Department's
portfolio of measures, an annual independent review, and a
full independent evaluation of the multi-year 3-year
results of the performance and the cost-effectiveness of
the utility's and, if applicable, 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 multi-year 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
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 multi-year
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.
(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
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
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 multi-year
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
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
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
subsequent multi-year 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
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.
(o) Utilities' 3-year energy efficiency plans approved by
the Commission on or before the effective date of this
amendatory Act of the 99th General Assembly for the period June
1, 2014 through May 31, 2017 shall continue to be in force and
effect through December 31, 2017 so that the energy efficiency
programs set forth in those plans continue to be offered during
the period June 1, 2017 through December 31, 2017. Each utility
is authorized to increase, on a pro rata basis, the energy
savings goals and budgets approved in its plan to reflect the
additional 7 months of the plan's operation.
(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 5/9-107 new)
Sec. 9-107. Revenue balancing adjustments.
(a) In this Section:
"Reconciliation period" means a period beginning with the
January monthly billing period and extending through the
December monthly billing period.
"Rate case reconciliation revenue requirement" means the
final distribution revenue requirement or requirements
approved by the Commission in the utility's rate case or
formula rate proceeding to set the rates initially applicable
in the relevant reconciliation period after the conclusion of
the period. In the event the Commission has approved more than
one revenue requirement for the reconciliation period, the
amount of rate case revenue under each approved revenue
requirement shall be prorated based upon the number of days
under which each revenue requirement was in effect.
(b) If an electric utility has a performance-based formula
rate in effect under Section 16-108.5, then the utility shall
be permitted to revise the formula rate and schedules to reduce
the 50 basis point values to zero that would otherwise apply
under paragraph (5) of subsection (c) of Section 16-108.5. Such
revision and reduction shall apply beginning with the
reconciliation conducted for the 2017 calendar year.

If the utility no longer has a performance-based formula in
effect under Section 16-108.5, then the utility shall be
permitted to implement the revenue balancing adjustment tariff
described in subsection (c) of this Section.
(c) An electric utility that is authorized under subsection
(b) of this Section to implement a revenue balancing adjustment
tariff may file the tariff for the purpose of preventing
undercollections or overcollections of distribution revenues
as compared to the revenue requirement or requirements approved
by the Commission on which the rates giving rise to those
revenues were based. The tariff shall calculate an annual
adjustment that reflects any difference between the actual
delivery service revenue billed for services provided during
the relevant reconciliation period and the rate case
reconciliation revenue requirement for the relevant
reconciliation period and shall set forth the reconciliation
categories or classes, or a combination of both, in a manner
determined at the utility's discretion.
(d) A utility that elects to file the tariff authorized by
this Section shall file the tariff outside the context of a
general rate case or formula rate proceeding, and the
Commission shall, after notice and hearing, approve the tariff
or approve with modification no later than 120 days after the
utility files the tariff, and the tariff shall remain in effect
at the discretion of the utility. The tariff shall also require
that the electric utility submit an annual revenue balancing

reconciliation report to the Commission reflecting the
difference between the actual delivery service revenue and rate
case revenue for the applicable reconciliation and identifying
the charges or credits to be applied thereafter. The annual
revenue balancing reconciliation report shall be filed with the
Commission no later than March 20 of the year following a
reconciliation period. The Commission may initiate a review of
the revenue balancing reconciliation report each year to
determine if any subsequent adjustment is necessary to align
actual delivery service revenue and rate case revenue. In the
event the Commission elects to initiate such review, the
Commission shall, after notice and hearing, enter an order
approving, or approving as modified, such revenue balancing
reconciliation report no later than 120 days after the utility
files its report with the Commission. If the Commission does
not initiate such review, the revenue balancing reconciliation
report and the identified charges or credits shall be deemed
accepted and approved 120 days after the utility files the
report and shall not be subject to review in any other
proceeding.
(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
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. The Commission may, after notice and hearing,
approve the tariff or tariffs. 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 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 customer who
elects real-time pricing under a tariff approved under this
subsection (b-5) and thereafter terminates the election shall
not return to taking service under the tariff for a period of
12 months following the date on which the customer terminated
real-time pricing. However, this limitation shall cease to
apply on such date that the provision of electric power and
energy is declared competitive under Section 16-113 of this Act
for the customer group or groups to which this subsection (b-5)
applies.
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
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
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 5/16-107.5)
Sec. 16-107.5. Net electricity metering.
(a) The Legislature finds and declares that a program to
provide net electricity metering, as defined in this Section,
for eligible customers can encourage private investment in
renewable energy resources, stimulate economic growth, enhance
the continued diversification of Illinois' energy resource
mix, and protect the Illinois environment.
(b) As used in this Section, (i) "community renewable
generation project" shall have the meaning set forth in Section
1-10 of the Illinois Power Agency Act; (ii) "eligible customer"
means a retail customer that owns or operates a solar, wind, or
other eligible renewable electrical generating facility with a
rated capacity of not more than 2,000 kilowatts that is located
on the customer's premises and is intended primarily to offset
the customer's own electrical requirements; (iii) (ii)
"electricity provider" means an electric utility or
alternative retail electric supplier; (iv) (iii) "eligible
renewable electrical generating facility" means a generator
that is interconnected under rules adopted by the Commission
and is powered by solar electric energy, wind, dedicated crops
grown for electricity generation, agricultural residues,
untreated and unadulterated wood waste, landscape trimmings,
livestock manure, anaerobic digestion of livestock or food
processing waste, fuel cells or microturbines powered by

renewable fuels, or hydroelectric energy; (v) and (iv) "net
electricity metering" (or "net metering") means the
measurement, during the billing period applicable to an
eligible customer, of the net amount of electricity supplied by
an electricity provider to the customer's premises or provided
to the electricity provider by the customer or subscriber; (vi)
"subscriber" shall have the meaning as set forth in Section
1-10 of the Illinois Power Agency Act; and (vii) "subscription"
shall have the meaning set forth in Section 1-10 of the
Illinois Power Agency Act.
(c) A net metering facility shall be equipped with metering
equipment that can measure the flow of electricity in both
directions at the same rate.
(1) For eligible customers whose electric service has
not been declared competitive pursuant to Section 16-113 of
this Act as of July 1, 2011 and whose electric delivery
service is provided and measured on a kilowatt-hour basis
and electric supply service is not provided based on hourly
pricing, this shall typically be accomplished through use
of a single, bi-directional meter. If the eligible
customer's existing electric revenue meter does not meet
this requirement, the electricity provider shall arrange
for the local electric utility or a meter service provider
to install and maintain a new revenue meter at the
electricity provider's expense, which may be the smart
meter described by subsection (b) of Section 16-108.5 of

this Act.
(2) For eligible customers whose electric service has
not been declared competitive pursuant to Section 16-113 of
this Act as of July 1, 2011 and whose electric delivery
service is provided and measured on a kilowatt demand basis
and electric supply service is not provided based on hourly
pricing, this shall typically be accomplished through use
of a dual channel meter capable of measuring the flow of
electricity both into and out of the customer's facility at
the same rate and ratio. If such customer's existing
electric revenue meter does not meet this requirement, then
the electricity provider shall arrange for the local
electric utility or a meter service provider to install and
maintain a new revenue meter at the electricity provider's
expense, which may be the smart meter described by
subsection (b) of Section 16-108.5 of this Act.
(3) For all other eligible customers, until such time
as the local electric utility installs a smart meter, as
described by subsection (b) of Section 16-108.5 of this
Act, the electricity provider may arrange for the local
electric utility or a meter service provider to install and
maintain metering equipment capable of measuring the flow
of electricity both into and out of the customer's facility
at the same rate and ratio, typically through the use of a
dual channel meter. If the eligible customer's existing
electric revenue meter does not meet this requirement, then

the costs of installing such equipment shall be paid for by
the customer.
(d) An electricity provider shall measure and charge or
credit for the net electricity supplied to eligible customers
or provided by eligible customers whose electric service has
not been declared competitive pursuant to Section 16-113 of
this the Act as of July 1, 2011 and whose electric delivery
service is provided and measured on a kilowatt-hour basis and
electric supply service is not provided based on hourly pricing
in the following manner:
(1) If the amount of electricity used by the customer
during the billing period exceeds the amount of electricity
produced by the customer, the electricity provider shall
charge the customer for the net electricity supplied to and
used by the customer as provided in subsection (e-5) of
this Section.
(2) If the amount of electricity produced by a customer
during the billing period exceeds the amount of electricity
used by the customer during that billing period, the
electricity provider supplying that customer shall apply a
1:1 kilowatt-hour credit to a subsequent bill for service
to the customer for the net electricity supplied to the
electricity provider. The electricity provider shall
continue to carry over any excess kilowatt-hour credits
earned and apply those credits to subsequent billing
periods to offset any customer-generator consumption in

those billing periods until all credits are used or until
the end of the annualized period.
(3) At the end of the year or annualized over the
period that service is supplied by means of net metering,
or in the event that the retail customer terminates service
with the electricity provider prior to the end of the year
or the annualized period, any remaining credits in the
customer's account shall expire.
(d-5) An electricity provider shall measure and charge or
credit for the net electricity supplied to eligible customers
or provided by eligible customers whose electric service has
not been declared competitive pursuant to Section 16-113 of
this Act as of July 1, 2011 and whose electric delivery service
is provided and measured on a kilowatt-hour basis and electric
supply service is provided based on hourly pricing in the
following manner:
(1) If the amount of electricity used by the customer
during any hourly period exceeds the amount of electricity
produced by the customer, the electricity provider shall
charge the customer for the net electricity supplied to and
used by the customer according to the terms of the contract
or tariff to which the same customer would be assigned to
or be eligible for if the customer was not a net metering
customer.
(2) If the amount of electricity produced by a customer
during any hourly period exceeds the amount of electricity

used by the customer during that hourly period, the energy
provider shall apply a credit for the net kilowatt-hours
produced in such period. The credit shall consist of an
energy credit and a delivery service credit. The energy
credit shall be valued at the same price per kilowatt-hour
as the electric service provider would charge for
kilowatt-hour energy sales during that same hourly period.
The delivery credit shall be equal to the net
kilowatt-hours produced in such hourly period times a
credit that reflects all kilowatt-hour based charges in the
customer's electric service rate, excluding energy
charges.
(e) An electricity provider shall measure and charge or
credit for the net electricity supplied to eligible customers
whose electric service has not been declared competitive
pursuant to Section 16-113 of this Act as of July 1, 2011 and
whose electric delivery service is provided and measured on a
kilowatt demand basis and electric supply service is not
provided based on hourly pricing in the following manner:
(1) If the amount of electricity used by the customer
during the billing period exceeds the amount of electricity
produced by the customer, then the electricity provider
shall charge the customer for the net electricity supplied
to and used by the customer as provided in subsection (e-5)
of this Section. The customer shall remain responsible for
all taxes, fees, and utility delivery charges that would

otherwise be applicable to the net amount of electricity
used by the customer.
(2) If the amount of electricity produced by a customer
during the billing period exceeds the amount of electricity
used by the customer during that billing period, then the
electricity provider supplying that customer shall apply a
1:1 kilowatt-hour credit that reflects the kilowatt-hour
based charges in the customer's electric service rate to a
subsequent bill for service to the customer for the net
electricity supplied to the electricity provider. The
electricity provider shall continue to carry over any
excess kilowatt-hour credits earned and apply those
credits to subsequent billing periods to offset any
customer-generator consumption in those billing periods
until all credits are used or until the end of the
annualized period.
(3) At the end of the year or annualized over the
period that service is supplied by means of net metering,
or in the event that the retail customer terminates service
with the electricity provider prior to the end of the year
or the annualized period, any remaining credits in the
customer's account shall expire.
(e-5) An electricity provider shall provide electric
service to eligible customers who utilize net metering at
non-discriminatory rates that are identical, with respect to
rate structure, retail rate components, and any monthly

charges, to the rates that the customer would be charged if not
a net metering customer. An electricity provider shall not
charge net metering customers any fee or charge or require
additional equipment, insurance, or any other requirements not
specifically authorized by interconnection standards
authorized by the Commission, unless the fee, charge, or other
requirement would apply to other similarly situated customers
who are not net metering customers. The customer will remain
responsible for all taxes, fees, and utility delivery charges
that would otherwise be applicable to the net amount of
electricity used by the customer. Subsections (c) through (e)
of this Section shall not be construed to prevent an
arms-length agreement between an electricity provider and an
eligible customer that sets forth different prices, terms, and
conditions for the provision of net metering service,
including, but not limited to, the provision of the appropriate
metering equipment for non-residential customers.
(f) Notwithstanding the requirements of subsections (c)
through (e-5) of this Section, an electricity provider must
require dual-channel metering for customers operating eligible
renewable electrical generating facilities with a nameplate
rating up to 2,000 kilowatts and to whom the provisions of
neither subsection (d), (d-5), nor (e) of this Section apply.
In such cases, electricity charges and credits shall be
determined as follows:
(1) The electricity provider shall assess and the

customer remains responsible for all taxes, fees, and
utility delivery charges that would otherwise be
applicable to the gross amount of kilowatt-hours supplied
to the eligible customer by the electricity provider.
(2) Each month that service is supplied by means of
dual-channel metering, the electricity provider shall
compensate the eligible customer for any excess
kilowatt-hour credits at the electricity provider's
avoided cost of electricity supply over the monthly period
or as otherwise specified by the terms of a power-purchase
agreement negotiated between the customer and electricity
provider.
(3) For all eligible net metering customers taking
service from an electricity provider under contracts or
tariffs employing hourly or time of use rates, any monthly
consumption of electricity shall be calculated according
to the terms of the contract or tariff to which the same
customer would be assigned to or be eligible for if the
customer was not a net metering customer. When those same
customer-generators are net generators during any discrete
hourly or time of use period, the net kilowatt-hours
produced shall be valued at the same price per
kilowatt-hour as the electric service provider would
charge for retail kilowatt-hour sales during that same time
of use period.
(g) For purposes of federal and State laws providing

renewable energy credits or greenhouse gas credits, the
eligible customer shall be treated as owning and having title
to the renewable energy attributes, renewable energy credits,
and greenhouse gas emission credits related to any electricity
produced by the qualified generating unit. The electricity
provider may not condition participation in a net metering
program on the signing over of a customer's renewable energy
credits; provided, however, this subsection (g) shall not be
construed to prevent an arms-length agreement between an
electricity provider and an eligible customer that sets forth
the ownership or title of the credits.
(h) Within 120 days after the effective date of this
amendatory Act of the 95th General Assembly, the Commission
shall establish standards for net metering and, if the
Commission has not already acted on its own initiative,
standards for the interconnection of eligible renewable
generating equipment to the utility system. The
interconnection standards shall address any procedural
barriers, delays, and administrative costs associated with the
interconnection of customer-generation while ensuring the
safety and reliability of the units and the electric utility
system. The Commission shall consider the Institute of
Electrical and Electronics Engineers (IEEE) Standard 1547 and
the issues of (i) reasonable and fair fees and costs, (ii)
clear timelines for major milestones in the interconnection
process, (iii) nondiscriminatory terms of agreement, and (iv)

any best practices for interconnection of distributed
generation.
(i) All electricity providers shall begin to offer net
metering no later than April 1, 2008.
(j) An electricity provider shall provide net metering to
eligible customers until the load of its net metering customers
equals 5% of the total peak demand supplied by that electricity
provider during the previous year. After such time as the load
of the electricity provider's net metering customers equals 5%
of the total peak demand supplied by that electricity provider
during the previous year, eligible customers that begin taking
net metering shall only be eligible for netting of energy.
Electricity providers are authorized to offer net metering
beyond the 5% level if they so choose.
(k) Each electricity provider shall maintain records and
report annually to the Commission the total number of net
metering customers served by the provider, as well as the type,
capacity, and energy sources of the generating systems used by
the net metering customers. Nothing in this Section shall limit
the ability of an electricity provider to request the redaction
of information deemed by the Commission to be confidential
business information. Each electricity provider shall notify
the Commission when the total generating capacity of its net
metering customers is equal to or in excess of the 5% cap
specified in subsection (j) of this Section.
(l)(1) Notwithstanding the definition of "eligible

customer" in item (ii) (i) of subsection (b) of this
Section, each electricity provider shall consider whether
to allow meter aggregation for the purposes of net metering
as set forth in this subsection (l) and for the following
projects on:
(A) (1) properties owned or leased by multiple
customers that contribute to the operation of an
eligible renewable electrical generating facility
through an ownership or leasehold interest of at least
200 watts in such facility, such as a community-owned
wind project, a community-owned biomass project, a
community-owned solar project, or a community methane
digester processing livestock waste from multiple
sources, provided that the facility is also located
within the utility's service territory; and
(B) (2) individual units, apartments, or
properties located in a single building that are owned
or leased by multiple customers and collectively
served by a common eligible renewable electrical
generating facility, such as an office or apartment
building, a shopping center or strip mall served by
photovoltaic panels on the roof; and .
(C) subscriptions to community renewable
generation projects.
In addition, the nameplate capacity of the eligible
renewable electric generating facility that serves the

demand of the properties, units, or apartments identified
in paragraphs (1) and (2) of this subsection (l) shall not
exceed 2,000 kilowatts in nameplate capacity in total. Any
eligible renewable electrical generating facility or
community renewable generation project that is powered by
photovoltaic electric energy and installed after the
effective date of this amendatory Act of the 99th General
Assembly must be installed by a qualified person in
compliance with the requirements of Section 16-128A of the
Public Utilities Act and any rules or regulations adopted
thereunder.
(2) Notwithstanding anything to the contrary, an
electricity provider shall provide credits for the
electricity produced by the projects described in
paragraph (1) of this subsection (l). The electricity
provider shall provide credits at the subscriber's energy
supply rate on the subscriber's monthly bill equal to the
subscriber's share of the production of electricity from
the project, as determined by paragraph (3) of this
subsection (l).
(3) For the purposes of facilitating net metering, the
owner or operator of the eligible renewable electrical
generating facility or community renewable generation
project shall be responsible for determining the amount of
the credit that each customer or subscriber participating
in a project under this subsection (l) is to receive in the

following manner: this subsection (l), "meter aggregation"
means the combination of reading and billing on a pro rata
basis for the types of eligible customers described in this
Section.
(A) The owner or operator shall, on a monthly
basis, provide to the electric utility the
kilowatthours of generation attributable to each of
the utility's retail customers and subscribers
participating in projects under this subsection (l) in
accordance with the customer's or subscriber's share
of the eligible renewable electric generating
facility's or community renewable generation project's
output of power and energy for such month. The owner or
operator shall electronically transmit such
calculations and associated documentation to the
electric utility, in a format or method set forth in
the applicable tariff, on a monthly basis so that the
electric utility can reflect the monetary credits on
customers' and subscribers' electric utility bills.
The electric utility shall be permitted to revise its
tariffs to implement the provisions of this amendatory
Act of the 99th General Assembly. The owner or operator
shall separately provide the electric utility with the
documentation detailing the calculations supporting
the credit in the manner set forth in the applicable
tariff.

(B) For those participating customers and
subscribers who receive their energy supply from an
alternative retail electric supplier, the electric
utility shall remit to the applicable alternative
retail electric supplier the information provided
under subparagraph (A) of this paragraph (3) for such
customers and subscribers in a manner set forth in such
alternative retail electric supplier's net metering
program, or as otherwise agreed between the utility and
the alternative retail electric supplier. The
alternative retail electric supplier shall then submit
to the utility the amount of the charges for power and
energy to be applied to such customers and subscribers,
including the amount of the credit associated with net
metering.
(C) A participating customer or subscriber may
provide authorization as required by applicable law
that directs the electric utility to submit
information to the owner or operator of the eligible
renewable electrical generating facility or community
renewable generation project to which the customer or
subscriber has an ownership or leasehold interest or a
subscription. Such information shall be limited to the
components of the net metering credit calculated under
this subsection (l), including the bill credit rate,
total kilowatthours, and total monetary credit value

applied to the customer's or subscriber's bill for the
monthly billing period.
(l-5) Within 90 days after the effective date of this
amendatory Act of the 99th General Assembly, each electric
utility subject to this Section shall file a tariff to
implement the provisions of subsection (l) of this Section,
which shall, consistent with the provisions of subsection (l),
describe the terms and conditions under which owners or
operators of qualifying properties, units, or apartments may
participate in net metering. The Commission shall approve, or
approve with modification, the tariff within 120 days after the
effective date of this amendatory Act of the 99th General
Assembly.
(m) Nothing in this Section shall affect the right of an
electricity provider to continue to provide, or the right of a
retail customer to continue to receive service pursuant to a
contract for electric service between the electricity provider
and the retail customer in accordance with the prices, terms,
and conditions provided for in that contract. Either the
electricity provider or the customer may require compliance
with the prices, terms, and conditions of the contract.
(n) At such time, if any, that the load of the electricity
provider's net metering customers equals 5% of the total peak
demand supplied by that electricity provider during the
previous year, as specified in subsection (j) of this Section,
the net metering services described in subsections (d), (d-5),

(e), (e-5), and (f) of this Section shall no longer be offered,
except as to those retail customers that are receiving net
metering service under these subsections at the time the net
metering services under those subsections are no longer
offered. Those retail customers that begin taking net metering
service after the date that net metering services are no longer
offered under such subsections shall be subject to the
provisions set forth in the following paragraphs (1) through
(3) of this subsection (n):
(1) An electricity provider shall charge or credit for
the net electricity supplied to eligible customers or
provided by eligible customers whose electric supply
service is not provided based on hourly pricing in the
following manner:
(A) If the amount of electricity used by the
customer during the billing period exceeds the amount
of electricity produced by the customer, then the
electricity provider shall charge the customer for the
net kilowatt-hour based electricity charges reflected
in the customer's electric service rate supplied to and
used by the customer as provided in paragraph (3) of
this subsection (n).
(B) If the amount of electricity produced by a
customer during the billing period exceeds the amount
of electricity used by the customer during that billing
period, then the electricity provider supplying that

customer shall apply a 1:1 kilowatt-hour energy credit
that reflects the kilowatt-hour based energy charges
in the customer's electric service rate to a subsequent
bill for service to the customer for the net
electricity supplied to the electricity provider. The
electricity provider shall continue to carry over any
excess kilowatt-hour energy credits earned and apply
those credits to subsequent billing periods to offset
any customer-generator consumption in those billing
periods until all credits are used or until the end of
the annualized period.
(C) At the end of the year or annualized over the
period that service is supplied by means of net
metering, or in the event that the retail customer
terminates service with the electricity provider prior
to the end of the year or the annualized period, any
remaining credits in the customer's account shall
expire.
(2) An electricity provider shall charge or credit for
the net electricity supplied to eligible customers or
provided by eligible customers whose electric supply
service is provided based on hourly pricing in the
following manner:
(A) If the amount of electricity used by the
customer during any hourly period exceeds the amount of
electricity produced by the customer, then the

electricity provider shall charge the customer for the
net electricity supplied to and used by the customer as
provided in paragraph (3) of this subsection (n).
(B) If the amount of electricity produced by a
customer during any hourly period exceeds the amount of
electricity used by the customer during that hourly
period, the energy provider shall calculate an energy
credit for the net kilowatt-hours produced in such
period. The value of the energy credit shall be
calculated using the same price per kilowatt-hour as
the electric service provider would charge for
kilowatt-hour energy sales during that same hourly
period.
(3) An electricity provider shall provide electric
service to eligible customers who utilize net metering at
non-discriminatory rates that are identical, with respect
to rate structure, retail rate components, and any monthly
charges, to the rates that the customer would be charged if
not a net metering customer. An electricity provider shall
charge the customer for the net electricity supplied to and
used by the customer according to the terms of the contract
or tariff to which the same customer would be assigned or
be eligible for if the customer was not a net metering
customer. An electricity provider shall not charge net
metering customers any fee or charge or require additional
equipment, insurance, or any other requirements not

specifically authorized by interconnection standards
authorized by the Commission, unless the fee, charge, or
other requirement would apply to other similarly situated
customers who are not net metering customers. The charge or
credit that the customer receives for net electricity shall
be at a rate equal to the customer's energy supply rate.
The customer remains responsible for the gross amount of
delivery services charges, supply-related charges that are
kilowatt based, and all taxes and fees related to such
charges. The customer also remains responsible for all
taxes and fees that would otherwise be applicable to the
net amount of electricity used by the customer. Paragraphs
(1) and (2) of this subsection (n) shall not be construed
to prevent an arms-length agreement between an electricity
provider and an eligible customer that sets forth different
prices, terms, and conditions for the provision of net
metering service, including, but not limited to, the
provision of the appropriate metering equipment for
non-residential customers. Nothing in this paragraph (3)
shall be interpreted to mandate that a utility that is only
required to provide delivery services to a given customer
must also sell electricity to such customer.
(Source: P.A. 97-616, eff. 10-26-11; 97-646, eff. 12-30-11;
97-824, eff. 7-18-12.)
(220 ILCS 5/16-107.6 new)

Sec. 16-107.6. Distributed generation rebate.
(a) In this Section:
"Smart inverter" means a device that converts direct
current into alternating current and can autonomously
contribute to grid support during excursions from normal
operating voltage and frequency conditions by providing each of
the following: dynamic reactive and real power support, voltage
and frequency ride-through, ramp rate controls, communication
systems with ability to accept external commands, and other
functions from the electric utility.
"Subscriber" has the meaning set forth in Section 1-10 of
the Illinois Power Agency Act.
"Subscription" has the meaning set forth in Section 1-10 of
the Illinois Power Agency Act.
"Threshold date" means the date on which the load of an
electricity provider's net metering customers equals 5% of the
total peak demand supplied by that electricity provider during
the previous year, as specified under subsection (j) of Section
16-107.5 of this Act.
(b) An electric utility that serves more than 200,000
customers in the State shall file a petition with the
Commission requesting approval of the utility's tariff to
provide a rebate to a retail customer who owns or operates
distributed generation that meets the following criteria:
(1) has a nameplate generating capacity no greater than
2,000 kilowatts and is primarily used to offset that

customer's electricity load;
(2) is located on the customer's premises, for the
customer's own use, and not for commercial use or sales,
including, but not limited to, wholesale sales of electric
power and energy;
(3) is located in the electric utility's service
territory; and
(4) is interconnected under rules adopted by the
Commission by means of the inverter or smart inverter
required by this Section, as applicable.
For purposes of this Section, "distributed generation"
shall satisfy the definition of distributed renewable energy
generation device set forth in Section 1-10 of the Illinois
Power Agency Act to the extent such definition is consistent
with the requirements of this Section.
In addition, any new photovoltaic distributed generation
that is installed after the effective date of this amendatory
Act of the 99th General Assembly must be installed by a
qualified person, as defined by subsection (i) of Section 1-56
of the Illinois Power Agency Act.
The tariff shall provide that the utility shall be
permitted to operate and control the smart inverter associated
with the distributed generation that is the subject of the
rebate for the purpose of preserving reliability during
distribution system reliability events and shall address the
terms and conditions of the operation and the compensation

associated with the operation. Nothing in this Section shall
negate or supersede Institute of Electrical and Electronics
Engineers interconnection requirements or standards or other
similar standards or requirements. The tariff shall also
provide for additional uses of the smart inverter that shall be
separately compensated and which may include, but are not
limited to, voltage and VAR support, regulation, and other grid
services. As part of the proceeding described in subsection (e)
of this Section, the Commission shall review and determine
whether smart inverters can provide any additional uses or
services. If the Commission determines that an additional use
or service would be beneficial, the Commission shall determine
the terms and conditions of the operation and how the use or
service should be separately compensated.
(c) The proposed tariff authorized by subsection (b) of
this Section shall include the following participation terms
and formulae to calculate the value of the rebates to be
applied under this Section for distributed generation that
satisfies the criteria set forth in subsection (b) of this
Section:
(1) Until the utility files its tariff or tariffs to
place into effect the rebate values established by the
Commission under subsection (e) of this Section,
non-residential customers that are taking service under a
net metering program offered by an electricity provider
under the terms of Section 16-107.5 of this Act may apply

for a rebate as provided for in this Section. The value of
the rebate shall be $250 per kilowatt of nameplate
generating capacity, measured as nominal DC power output,
of a non-residential customer's distributed generation.
(2) After the utility's tariff or tariffs setting the
new rebate values established under subsection (d) of this
Section take effect, retail customers may, as applicable,
make the following elections:
(A) Residential customers that are taking service
under a net metering program offered by an electricity
provider under the terms of Section 16-107.5 of this
Act on the threshold date may elect to either continue
to take such service under the terms of such program as
in effect on such threshold date for the useful life of
the customer's eligible renewable electric generating
facility as defined in such Section, or file an
application to receive a rebate under the terms of this
Section, provided that such application must be
submitted within 6 months after the effective date of
the tariff approved under subsection (d) of this
Section. The value of the rebate shall be the amount
established by the Commission and reflected in the
utility's tariff pursuant to subsection (e) of this
Section.
(B) Non-residential customers that are taking
service under a net metering program offered by an

electricity provider under the terms of Section
16-107.5 of this Act on the threshold date may apply
for a rebate as provided for in this Section. The value
of the rebate shall be the amount established by the
Commission and reflected in the utility's tariff
pursuant to subsection (e) of this Section.
(3) Upon approval of a rebate application submitted
under this subsection (c), the retail customer shall no
longer be entitled to receive any delivery service credits
for the excess electricity generated by its facility and
shall be subject to the provisions of subsection (n) of
Section 16-107.5 of this Act.
(4) To be eligible for a rebate described in this
subsection (c), customers who begin taking service after
the effective date of this amendatory Act of the 99th
General Assembly under a net metering program offered by an
electricity provider under the terms of Section 16-107.5 of
this Act must have a smart inverter associated with the
customer's distributed generation.
(d) The Commission shall review the proposed tariff
submitted under subsections (b) and (c) of this Section and may
make changes to the tariff that are consistent with this
Section and with the Commission's authority under Article IX of
this Act, subject to notice and hearing. Following notice and
hearing, the Commission shall issue an order approving, or
approving with modification, such tariff no later than 240 days

after the utility files its tariff.
(e) When the total generating capacity of the electricity
provider's net metering customers is equal to 3%, the
Commission shall open an investigation into an annual process
and formula for calculating the value of rebates for the retail
customers described in subsections (b) and (f) of this Section
that submit rebate applications after the threshold date for an
electric utility that elected to file a tariff pursuant to this
Section. The investigation shall include diverse sets of
stakeholders, calculations for valuing distributed energy
resource benefits to the grid based on best practices, and
assessments of present and future technological capabilities
of distributed energy resources. The value of such rebates
shall reflect the value of the distributed generation to the
distribution system at the location at which it is
interconnected, taking into account the geographic,
time-based, and performance-based benefits, as well as
technological capabilities and present and future grid needs.
No later than 10 days after the Commission enters its final
order under this subsection (e), the utility shall file its
tariff or tariffs in compliance with the order, and the
Commission shall approve, or approve with modification, the
tariff or tariffs within 45 days after the utility's filing.
For those rebate applications filed after the threshold date
but before the utility's tariff or tariffs filed pursuant to
this subsection (e) take effect, the value of the rebate shall

remain at the value established in subsection (c) of this
Section until the tariff is approved.
(f) Notwithstanding any provision of this Act to the
contrary, the owner, developer, or subscriber of a generation
facility that is part of a net metering program provided under
subsection (l) of Section 16-107.5 shall also be eligible to
apply for the rebate described in this Section. A subscriber to
the generation facility may apply for a rebate in the amount of
the subscriber's subscription only if the owner, developer, or
previous subscriber to the same panel or panels has not already
submitted an application, and, regardless of whether the
subscriber is a residential or non-residential customer, may be
allowed the amount identified in paragraph (1) of subsection
(c) or in subsection (e) of this Section applicable to such
customer on the date that the application is submitted. An
application for a rebate for a portion of a project described
in this subsection (f) may be submitted at or after the time
that a related request for net metering is made.
(g) No later than 60 days after the utility receives an
application for a rebate under its tariff approved under
subsection (d) or (e) of this Section, the utility shall issue
a rebate to the applicant under the terms of the tariff. In the
event the application is incomplete or the utility is otherwise
unable to calculate the payment based on the information
provided by the owner, the utility shall issue the payment no
later than 60 days after the application is complete or all

requested information is received.
(h) An electric utility shall recover from its retail
customers all of the costs of the rebates made under a tariff
or tariffs placed into effect under this Section, including,
but not limited to, the value of the rebates and all costs
incurred by the utility to comply with and implement this
Section, consistent with the following provisions:
(1) The utility shall defer the full amount of its
costs incurred under this Section as a regulatory asset.
The total costs deferred as a regulatory asset shall be
amortized over a 15-year period. The unamortized balance
shall be recognized as of December 31 for a given year. The
utility shall also earn a return on the total of the
unamortized balance of the regulatory assets, less any
deferred taxes related to the unamortized balance, at an
annual rate equal to the utility's weighted average cost of
capital that includes, based on a year-end capital
structure, the utility's actual cost of debt for the
applicable calendar year and a cost of equity, which shall
be calculated as the sum of (i) the average for the
applicable calendar year of the monthly average yields of
30-year U.S. Treasury bonds published by the Board of
Governors of the Federal Reserve System in its weekly H.15
Statistical Release or successor publication; and (ii) 580
basis points, including a revenue conversion factor
calculated to recover or refund all additional income taxes

that may be payable or receivable as a result of that
return.
When an electric utility creates a regulatory asset
under the provisions of this Section, the costs are
recovered over a period during which customers also receive
a benefit, which is in the public interest. Accordingly, it
is the intent of the General Assembly that an electric
utility that elects to create a regulatory asset under the
provisions of this Section shall recover all of the
associated costs, including, but not limited to, its cost
of capital as set forth in this Section. After the
Commission has approved the prudence and reasonableness of
the costs that comprise the regulatory asset, the electric
utility shall be permitted to recover all such costs, and
the value and recoverability through rates of the
associated regulatory asset shall not be limited, altered,
impaired, or reduced. To enable the financing of the
incremental capital expenditures, including regulatory
assets, for electric utilities that serve less than
3,000,000 retail customers but more than 500,000 retail
customers in the State, the utility's actual year-end
capital structure that includes a common equity ratio,
excluding goodwill, of up to and including 50% of the total
capital structure shall be deemed reasonable and used to
set rates.
(2) The utility, at its election, may recover all of

the costs it incurs under this Section as part of a filing
for a general increase in rates under Article IX of this
Act, as part of an annual filing to update a
performance-based formula rate under subsection (d) of
Section 16-108.5 of this Act, or through an automatic
adjustment clause tariff, provided that nothing in this
paragraph (2) permits the double recovery of such costs
from customers. If the utility elects to recover the costs
it incurs under this Section through an automatic
adjustment clause tariff, the utility may file its proposed
tariff together with the tariff it files under subsection
(b) of this Section or at a later time. The proposed tariff
shall provide for an annual reconciliation, less any
deferred taxes related to the reconciliation, with
interest at an annual rate of return equal to the utility's
weighted average cost of capital as calculated under
paragraph (1) of this subsection (h), including a revenue
conversion factor calculated to recover or refund all
additional income taxes that may be payable or receivable
as a result of that return, of the revenue requirement
reflected in rates for each calendar year, beginning with
the calendar year in which the utility files its automatic
adjustment clause tariff under this subsection (h), with
what the revenue requirement would have been had the actual
cost information for the applicable calendar year been
available at the filing date. The Commission shall review

the proposed tariff and may make changes to the tariff that
are consistent with this Section and with the Commission's
authority under Article IX of this Act, subject to notice
and hearing. Following notice and hearing, the Commission
shall issue an order approving, or approving with
modification, such tariff no later than 240 days after the
utility files its tariff.
(i) No later than 90 days after the Commission enters an
order, or order on rehearing, whichever is later, approving an
electric utility's proposed tariff under subsection (d) of this
Section, the electric utility shall provide notice of the
availability of rebates under this Section. Subsequent to the
utility's notice, any entity that offers in the State, for sale
or lease, distributed generation and estimates the dollar
saving attributable to such distributed generation shall
provide estimates based on both delivery service credits and
the rebates available under this Section.
(220 ILCS 5/16-108)
Sec. 16-108. Recovery of costs associated with the
provision of delivery and other services.
(a) An electric utility shall file a delivery services
tariff with the Commission at least 210 days prior to the date
that it is required to begin offering such services pursuant to
this Act. An electric utility shall provide the components of
delivery services that are subject to the jurisdiction of the

Federal Energy Regulatory Commission at the same prices, terms
and conditions set forth in its applicable tariff as approved
or allowed into effect by that Commission. The Commission shall
otherwise have the authority pursuant to Article IX to review,
approve, and modify the prices, terms and conditions of those
components of delivery services not subject to the jurisdiction
of the Federal Energy Regulatory Commission, including the
authority to determine the extent to which such delivery
services should be offered on an unbundled basis. In making any
such determination the Commission shall consider, at a minimum,
the effect of additional unbundling on (i) the objective of
just and reasonable rates, (ii) electric utility employees, and
(iii) the development of competitive markets for electric
energy services in Illinois.
(b) The Commission shall enter an order approving, or
approving as modified, the delivery services tariff no later
than 30 days prior to the date on which the electric utility
must commence offering such services. The Commission may
subsequently modify such tariff pursuant to this Act.
(c) The electric utility's tariffs shall define the classes
of its customers for purposes of delivery services charges.
Delivery services shall be priced and made available to all
retail customers electing delivery services in each such class
on a nondiscriminatory basis regardless of whether the retail
customer chooses the electric utility, an affiliate of the
electric utility, or another entity as its supplier of electric

power and energy. Charges for delivery services shall be cost
based, and shall allow the electric utility to recover the
costs of providing delivery services through its charges to its
delivery service customers that use the facilities and services
associated with such costs. Such costs shall include the costs
of owning, operating and maintaining transmission and
distribution facilities. The Commission shall also be
authorized to consider whether, and if so to what extent, the
following costs are appropriately included in the electric
utility's delivery services rates: (i) the costs of that
portion of generation facilities used for the production and
absorption of reactive power in order that retail customers
located in the electric utility's service area can receive
electric power and energy from suppliers other than the
electric utility, and (ii) the costs associated with the use
and redispatch of generation facilities to mitigate
constraints on the transmission or distribution system in order
that retail customers located in the electric utility's service
area can receive electric power and energy from suppliers other
than the electric utility. Nothing in this subsection shall be
construed as directing the Commission to allocate any of the
costs described in (i) or (ii) that are found to be
appropriately included in the electric utility's delivery
services rates to any particular customer group or geographic
area in setting delivery services rates.
(d) The Commission shall establish charges, terms and

conditions for delivery services that are just and reasonable
and shall take into account customer impacts when establishing
such charges. In establishing charges, terms and conditions for
delivery services, the Commission shall take into account
voltage level differences. A retail customer shall have the
option to request to purchase electric service at any delivery
service voltage reasonably and technically feasible from the
electric facilities serving that customer's premises provided
that there are no significant adverse impacts upon system
reliability or system efficiency. A retail customer shall also
have the option to request to purchase electric service at any
point of delivery that is reasonably and technically feasible
provided that there are no significant adverse impacts on
system reliability or efficiency. Such requests shall not be
unreasonably denied.
(e) Electric utilities shall recover the costs of
installing, operating or maintaining facilities for the
particular benefit of one or more delivery services customers,
including without limitation any costs incurred in complying
with a customer's request to be served at a different voltage
level, directly from the retail customer or customers for whose
benefit the costs were incurred, to the extent such costs are
not recovered through the charges referred to in subsections
(c) and (d) of this Section.
(f) An electric utility shall be entitled but not required
to implement transition charges in conjunction with the

offering of delivery services pursuant to Section 16-104. If an
electric utility implements transition charges, it shall
implement such charges for all delivery services customers and
for all customers described in subsection (h), but shall not
implement transition charges for power and energy that a retail
customer takes from cogeneration or self-generation facilities
located on that retail customer's premises, if such facilities
meet the following criteria:
(i) the cogeneration or self-generation facilities
serve a single retail customer and are located on that
retail customer's premises (for purposes of this
subparagraph and subparagraph (ii), an industrial or
manufacturing retail customer and a third party contractor
that is served by such industrial or manufacturing customer
through such retail customer's own electrical distribution
facilities under the circumstances described in subsection
(vi) of the definition of "alternative retail electric
supplier" set forth in Section 16-102, shall be considered
a single retail customer);
(ii) the cogeneration or self-generation facilities
either (A) are sized pursuant to generally accepted
engineering standards for the retail customer's electrical
load at that premises (taking into account standby or other
reliability considerations related to that retail
customer's operations at that site) or (B) if the facility
is a cogeneration facility located on the retail customer's

premises, the retail customer is the thermal host for that
facility and the facility has been designed to meet that
retail customer's thermal energy requirements resulting in
electrical output beyond that retail customer's electrical
demand at that premises, comply with the operating and
efficiency standards applicable to "qualifying facilities"
specified in title 18 Code of Federal Regulations Section
292.205 as in effect on the effective date of this
amendatory Act of 1999;
(iii) the retail customer on whose premises the
facilities are located either has an exclusive right to
receive, and corresponding obligation to pay for, all of
the electrical capacity of the facility, or in the case of
a cogeneration facility that has been designed to meet the
retail customer's thermal energy requirements at that
premises, an identified amount of the electrical capacity
of the facility, over a minimum 5-year period; and
(iv) if the cogeneration facility is sized for the
retail customer's thermal load at that premises but exceeds
the electrical load, any sales of excess power or energy
are made only at wholesale, are subject to the jurisdiction
of the Federal Energy Regulatory Commission, and are not
for the purpose of circumventing the provisions of this
subsection (f).
If a generation facility located at a retail customer's
premises does not meet the above criteria, an electric utility

implementing transition charges shall implement a transition
charge until December 31, 2006 for any power and energy taken
by such retail customer from such facility as if such power and
energy had been delivered by the electric utility. Provided,
however, that an industrial retail customer that is taking
power from a generation facility that does not meet the above
criteria but that is located on such customer's premises will
not be subject to a transition charge for the power and energy
taken by such retail customer from such generation facility if
the facility does not serve any other retail customer and
either was installed on behalf of the customer and for its own
use prior to January 1, 1997, or is both predominantly fueled
by byproducts of such customer's manufacturing process at such
premises and sells or offers an average of 300 megawatts or
more of electricity produced from such generation facility into
the wholesale market. Such charges shall be calculated as
provided in Section 16-102, and shall be collected on each
kilowatt-hour delivered under a delivery services tariff to a
retail customer from the date the customer first takes delivery
services until December 31, 2006 except as provided in
subsection (h) of this Section. Provided, however, that an
electric utility, other than an electric utility providing
service to at least 1,000,000 customers in this State on
January 1, 1999, shall be entitled to petition for entry of an
order by the Commission authorizing the electric utility to
implement transition charges for an additional period ending no

later than December 31, 2008. The electric utility shall file
its petition with supporting evidence no earlier than 16
months, and no later than 12 months, prior to December 31,
2006. The Commission shall hold a hearing on the electric
utility's petition and shall enter its order no later than 8
months after the petition is filed. The Commission shall
determine whether and to what extent the electric utility shall
be authorized to implement transition charges for an additional
period. The Commission may authorize the electric utility to
implement transition charges for some or all of the additional
period, and shall determine the mitigation factors to be used
in implementing such transition charges; provided, that the
Commission shall not authorize mitigation factors less than
110% of those in effect during the 12 months ended December 31,
2006. In making its determination, the Commission shall
consider the following factors: the necessity to implement
transition charges for an additional period in order to
maintain the financial integrity of the electric utility; the
prudence of the electric utility's actions in reducing its
costs since the effective date of this amendatory Act of 1997;
the ability of the electric utility to provide safe, adequate
and reliable service to retail customers in its service area;
and the impact on competition of allowing the electric utility
to implement transition charges for the additional period.
(g) The electric utility shall file tariffs that establish
the transition charges to be paid by each class of customers to

the electric utility in conjunction with the provision of
delivery services. The electric utility's tariffs shall define
the classes of its customers for purposes of calculating
transition charges. The electric utility's tariffs shall
provide for the calculation of transition charges on a
customer-specific basis for any retail customer whose average
monthly maximum electrical demand on the electric utility's
system during the 6 months with the customer's highest monthly
maximum electrical demands equals or exceeds 3.0 megawatts for
electric utilities having more than 1,000,000 customers, and
for other electric utilities for any customer that has an
average monthly maximum electrical demand on the electric
utility's system of one megawatt or more, and (A) for which
there exists data on the customer's usage during the 3 years
preceding the date that the customer became eligible to take
delivery services, or (B) for which there does not exist data
on the customer's usage during the 3 years preceding the date
that the customer became eligible to take delivery services, if
in the electric utility's reasonable judgment there exists
comparable usage information or a sufficient basis to develop
such information, and further provided that the electric
utility can require customers for which an individual
calculation is made to sign contracts that set forth the
transition charges to be paid by the customer to the electric
utility pursuant to the tariff.
(h) An electric utility shall also be entitled to file

tariffs that allow it to collect transition charges from retail
customers in the electric utility's service area that do not
take delivery services but that take electric power or energy
from an alternative retail electric supplier or from an
electric utility other than the electric utility in whose
service area the customer is located. Such charges shall be
calculated, in accordance with the definition of transition
charges in Section 16-102, for the period of time that the
customer would be obligated to pay transition charges if it
were taking delivery services, except that no deduction for
delivery services revenues shall be made in such calculation,
and usage data from the customer's class shall be used where
historical usage data is not available for the individual
customer. The customer shall be obligated to pay such charges
on a lump sum basis on or before the date on which the customer
commences to take service from the alternative retail electric
supplier or other electric utility, provided, that the electric
utility in whose service area the customer is located shall
offer the customer the option of signing a contract pursuant to
which the customer pays such charges ratably over the period in
which the charges would otherwise have applied.
(i) An electric utility shall be entitled to add to the
bills of delivery services customers charges pursuant to
Sections 9-221, 9-222 (except as provided in Section 9-222.1),
and Section 16-114 of this Act, Section 5-5 of the Electricity
Infrastructure Maintenance Fee Law, Section 6-5 of the

Renewable Energy, Energy Efficiency, and Coal Resources
Development Law of 1997, and Section 13 of the Energy
Assistance Act.
(j) If a retail customer that obtains electric power and
energy from cogeneration or self-generation facilities
installed for its own use on or before January 1, 1997,
subsequently takes service from an alternative retail electric
supplier or an electric utility other than the electric utility
in whose service area the customer is located for any portion
of the customer's electric power and energy requirements
formerly obtained from those facilities (including that amount
purchased from the utility in lieu of such generation and not
as standby power purchases, under a cogeneration displacement
tariff in effect as of the effective date of this amendatory
Act of 1997), the transition charges otherwise applicable
pursuant to subsections (f), (g), or (h) of this Section shall
not be applicable in any year to that portion of the customer's
electric power and energy requirements formerly obtained from
those facilities, provided, that for purposes of this
subsection (j), such portion shall not exceed the average
number of kilowatt-hours per year obtained from the
cogeneration or self-generation facilities during the 3 years
prior to the date on which the customer became eligible for
delivery services, except as provided in subsection (f) of
Section 16-110.
(k) The electric utility shall be entitled to recover

through tariffed charges all of the costs associated with the
purchase of zero emission credits from zero emission facilities
to meet the requirements of subsection (d-5) of Section 1-75 of
the Illinois Power Agency Act. Such costs shall include the
costs of procuring the zero emission credits, as well as the
reasonable costs that the utility incurs as part of the
procurement processes and to implement and comply with plans
and processes approved by the Commission under such subsection
(d-5). The costs shall be allocated across all retail customers
through a single, uniform cents per kilowatt-hour charge
applicable to all retail customers, which shall appear as a
separate line item on each customer's bill. Beginning June 1,
2017, the electric utility shall be entitled to recover through
tariffed charges all of the costs associated with the purchase
of renewable energy resources to meet the renewable energy
resource standards of subsection (c) of Section 1-75 of the
Illinois Power Agency Act, under procurement plans as approved
in accordance with that Section and Section 16-111.5 of this
Act. Such costs shall include the costs of procuring the
renewable energy resources, as well as the reasonable costs
that the utility incurs as part of the procurement processes
and to implement and comply with plans and processes approved
by the Commission under such Sections. The costs associated
with the purchase of renewable energy resources shall be
allocated across all retail customers in proportion to the
amount of renewable energy resources the utility procures for

such customers through a single, uniform cents per
kilowatt-hour charge applicable to such retail customers,
which shall appear as a separate line item on each such
customer's bill.
Notwithstanding whether the Commission has approved the
initial long-term renewable resources procurement plan as of
June 1, 2017, an electric utility shall place new tariffed
charges into effect beginning with the June 2017 monthly
billing period, to the extent practicable, to begin recovering
the costs of procuring renewable energy resources, as those
charges are calculated under the limitations described in
subparagraph (E) of paragraph (1) of subsection (c) of Section
1-75 of the Illinois Power Agency Act. Notwithstanding the date
on which the utility places such new tariffed charges into
effect, the utility shall be permitted to collect the charges
under such tariff as if the tariff had been in effect beginning
with the first day of the June 2017 monthly billing period. For
the delivery years commencing June 1, 2017, June 1, 2018, and
June 1, 2019, the electric utility shall deposit into a
separate interest bearing account of a financial institution
the monies collected under the tariffed charges. Any interest
earned shall be credited back to retail customers under the
reconciliation proceeding provided for in this subsection (k),
provided that the electric utility shall first be reimbursed
from the interest for the administrative costs that it incurs
to administer and manage the account. Any taxes due on the

funds in the account, or interest earned on it, will be paid
from the account or, if insufficient monies are available in
the account, from the monies collected under the tariffed
charges to recover the costs of procuring renewable energy
resources. Monies deposited in the account shall be subject to
the review, reconciliation, and true-up process described in
this subsection (k) that is applicable to the funds collected
and costs incurred for the procurement of renewable energy
resources.
The electric utility shall be entitled to recover all of
the costs identified in this subsection (k) through automatic
adjustment clause tariffs applicable to all of the utility's
retail customers that allow the electric utility to adjust its
tariffed charges consistent with this subsection (k). The
determination as to whether any excess funds were collected
during a given delivery year for the purchase of renewable
energy resources, and the crediting of any excess funds back to
retail customers, shall not be made until after the close of
the delivery year, which will ensure that the maximum amount of
funds is available to implement the approved long-term
renewable resources procurement plan during a given delivery
year. The electric utility's collections under such automatic
adjustment clause tariffs to recover the costs of renewable
energy resources and zero emission credits from zero emission
facilities shall be subject to separate annual review,
reconciliation, and true-up against actual costs by the

Commission under a procedure that shall be specified in the
electric utility's automatic adjustment clause tariffs and
that shall be approved by the Commission in connection with its
approval of such tariffs. The procedure shall provide that any
difference between the electric utility's collections under
the automatic adjustment charges for an annual period and the
electric utility's actual costs of renewable energy resources
and zero emission credits from zero emission facilities for
that same annual period shall be refunded to or collected from,
as applicable, the electric utility's retail customers in
subsequent periods.
Nothing in this subsection (k) is intended to affect,
limit, or change the right of the electric utility to recover
the costs associated with the procurement of renewable energy
resources for periods commencing before, on, or after June 1,
2017, as otherwise provided in the Illinois Power Agency Act.
Notwithstanding anything to the contrary, the Commission
shall not conduct an annual review, reconciliation, and true-up
associated with renewable energy resources' collections and
costs for the delivery years commencing June 1, 2017, June 1,
2018, June 1, 2019, and June 1, 2020, and shall instead conduct
a single review, reconciliation, and true-up associated with
renewable energy resources' collections and costs for the
4-year period beginning June 1, 2017 and ending May 31, 2021,
provided that the review, reconciliation, and true-up shall not
be initiated until after August 31, 2021. During the 4-year

period, the utility shall be permitted to collect and retain
funds under this subsection (k) and to purchase renewable
energy resources under an approved long-term renewable
resources procurement plan using those funds regardless of the
delivery year in which the funds were collected during the
4-year period.
If the amount of funds collected during the delivery year
commencing June 1, 2017, exceeds the costs incurred during that
delivery year, then up to half of this excess amount, as
calculated on June 1, 2018, may be used to fund the programs
under subsection (b) of Section 1-56 of the Illinois Power
Agency Act in the same proportion the programs are funded under
that subsection (b). However, any amount identified under this
subsection (k) to fund programs under subsection (b) of Section
1-56 of the Illinois Power Agency Act shall be reduced if it
exceeds the funding shortfall. For purposes of this Section,
"funding shortfall" means the difference between $200,000,000
and the amount appropriated by the General Assembly to the
Illinois Power Agency Renewable Energy Resources Fund during
the period that commences on the effective date of this
amendatory act of the 99th General Assembly and ends on August
1, 2018.
If the amount of funds collected during the delivery year
commencing June 1, 2018, exceeds the costs incurred during that
delivery year, then up to half of this excess amount, as
calculated on June 1, 2019, may be used to fund the programs

under subsection (b) of Section 1-56 of the Illinois Power
Agency Act in the same proportion the programs are funded under
that subsection (b). However, any amount identified under this
subsection (k) to fund programs under subsection (b) of Section
1-56 of the Illinois Power Agency Act shall be reduced if it
exceeds the funding shortfall.
If the amount of funds collected during the delivery year
commencing June 1, 2019, exceeds the costs incurred during that
delivery year, then up to half of this excess amount, as
calculated on June 1, 2020, may be used to fund the programs
under subsection (b) of Section 1-56 of the Illinois Power
Agency Act in the same proportion the programs are funded under
that subsection (b). However, any amount identified under this
subsection (k) to fund programs under subsection (b) of Section
1-56 of the Illinois Power Agency Act shall be reduced if it
exceeds the funding shortfall.
The funding available under this subsection (k), if any,
for the programs described under subsection (b) of Section 1-56
of the Illinois Power Agency Act shall not reduce the amount of
funding for the programs described in subparagraph (O) of
paragraph (1) of subsection (c) of Section 1-75 of the Illinois
Power Agency Act. If funding is available under this subsection
(k) for programs described under subsection (b) of Section 1-56
of the Illinois Power Agency Act, then the long-term renewable
resources plan shall provide for the Agency to procure
contracts in an amount that does not exceed the funding, and

the contracts approved by the Commission shall be executed by
the applicable utility or utilities.
(l) A utility that has terminated any contract executed
under subsection (d-5) of Section 1-75 of the Illinois Power
Agency Act shall be entitled to recover any remaining balance
associated with the purchase of zero emission credits prior to
such termination, and such utility shall also apply a credit to
its retail customer bills in the event of any over-collection.
(m)(1) An electric utility that recovers its costs of
procuring zero emission credits from zero emission
facilities through a cents-per-kilowatthour charge under
to subsection (k) of this Section shall be subject to the
requirements of this subsection (m). Notwithstanding
anything to the contrary, such electric utility shall,
beginning on April 30, 2018, and each April 30 thereafter
until April 30, 2026, calculate whether any reduction must
be applied to such cents-per-kilowatthour charge that is
paid by retail customers of the electric utility that are
exempt from subsections (a) through (j) of Section 8-103B
of this Act under subsection (l) of Section 8-103B. Such
charge shall be reduced for such customers for the next
delivery year commencing on June 1 based on the amount
necessary, if any, to limit the annual estimated average
net increase for the prior calendar year due to the future
energy investment costs to no more than 1.3% of 5.98 cents
per kilowatt-hour, which is the average amount paid per

kilowatthour for electric service during the year ending
December 31, 2015 by Illinois industrial retail customers,
as reported to the Edison Electric Institute.
The calculations required by this subsection (m) shall
be made only once for each year, and no subsequent rate
impact determinations shall be made.
(2) For purposes of this Section, "future energy
investment costs" shall be calculated by subtracting the
cents-per-kilowatthour charge identified in subparagraph
(A) of this paragraph (2) from the sum of the
cents-per-kilowatthour charges identified in subparagraph
(B) of this paragraph (2):
(A) The cents-per-kilowatthour charge identified
in the electric utility's tariff placed into effect
under Section 8-103 of the Public Utilities Act that,
on December 1, 2016, was applicable to those retail
customers that are exempt from subsections (a) through
(j) of Section 8-103B of this Act under subsection (l)
of Section 8-103B.
(B) The sum of the following
cents-per-kilowatthour charges applicable to those
retail customers that are exempt from subsections (a)
through (j) of Section 8-103B of this Act under
subsection (l) of Section 8-103B, provided that if one
or more of the following charges has been in effect and
applied to such customers for more than one calendar

year, then each charge shall be equal to the average of
the charges applied over a period that commences with
the calendar year ending December 31, 2017 and ends
with the most recently completed calendar year prior to
the calculation required by this subsection (m):
(i) the cents-per-kilowatthour charge to
recover the costs incurred by the utility under
subsection (d-5) of Section 1-75 of the Illinois
Power Agency Act, adjusted for any reductions
required under this subsection (m); and
(ii) the cents-per-kilowatthour charge to
recover the costs incurred by the utility under
Section 16-107.6 of the Public Utilities Act.
If no charge was applied for a given calendar year
under item (i) or (ii) of this subparagraph (B), then
the value of the charge for that year shall be zero.
(3) If a reduction is required by the calculation
performed under this subsection (m), then the amount of the
reduction shall be multiplied by the number of years
reflected in the averages calculated under subparagraph
(B) of paragraph (2) of this subsection (m). Such reduction
shall be applied to the cents-per-kilowatthour charge that
is applicable to those retail customers that are exempt
from subsections (a) through (j) of Section 8-103B of this
Act under subsection (l) of Section 8-103B beginning with
the next delivery year commencing after the date of the

calculation required by this subsection (m).
(4) The electric utility shall file a notice with the
Commission on May 1 of 2018 and each May 1 thereafter until
May 1, 2026 containing the reduction, if any, which must be
applied for the delivery year which begins in the year of
the filing. The notice shall contain the calculations made
pursuant to this section. By October 1 of each year
beginning in 2018, each electric utility shall notify the
Commission if it appears, based on an estimate of the
calculation required in this subsection (m), that a
reduction will be required in the next year.
(Source: P.A. 91-50, eff. 6-30-99; 92-690, eff. 7-18-02.)
(220 ILCS 5/16-108.5)
Sec. 16-108.5. Infrastructure investment and
modernization; regulatory reform.
(a) (Blank).
(b) For purposes of this Section, "participating utility"
means an electric utility or a combination utility serving more
than 1,000,000 customers in Illinois that voluntarily elects
and commits to undertake (i) the infrastructure investment
program consisting of the commitments and obligations
described in this subsection (b) and (ii) the customer
assistance program consisting of the commitments and
obligations described in subsection (b-10) of this Section,
notwithstanding any other provisions of this Act and without

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

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

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

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

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

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

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

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

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

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

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

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

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

implemented through tariffs that are filed with and reviewed by
the Commission. If a utility elects to file tariffs with the
Commission to implement all or a portion of the programs, those
tariffs shall, regardless of the date actually filed, be deemed
accepted and approved, and shall become effective on December
30, 2011 (the effective date of Public Act 97-646). The
participating utilities whose customers benefit from the funds
that are disbursed as contemplated in this Section shall file
annual reports documenting the disbursement of those funds with
the Commission. The Commission has the authority to audit
disbursement of the funds to ensure they were disbursed
consistently with this Section.
If the Commission finds that a participating utility is no
longer eligible to update the performance-based formula rate
tariff pursuant to subsection (d) of this Section, or the
performance-based formula rate is otherwise terminated, then
the participating utility's voluntary commitments and
obligations under this subsection (b-10) shall immediately
terminate.
(c) A participating utility may elect to recover its
delivery services costs through a performance-based formula
rate approved by the Commission, which shall specify the cost
components that form the basis of the rate charged to customers
with sufficient specificity to operate in a standardized manner
and be updated annually with transparent information that
reflects the utility's actual costs to be recovered during the

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

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

law. To enable the financing of the incremental capital
expenditures, including regulatory assets, for electric
utilities that serve less than 3,000,000 retail customers
but more than 500,000 retail customers in the State, a
participating electric utility's actual year-end capital
structure that includes a common equity ratio, excluding
goodwill, of up to and including 50% of the total capital
structure shall be deemed reasonable and used to set rates.
(3) Include a cost of equity, which 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
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
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
interpretation or application thereof by any
governmental authority occurring after October 26,
2011 (the effective date of Public Act 97-616);
(G) recovery of existing regulatory assets over
the periods previously authorized by the Commission;
(H) historical weather normalized billing
determinants; and
(I) allocation methods for common costs.
(5) Provide that if the participating utility's earned
rate of return on common equity related to the provision of
delivery services for the prior rate year (calculated using
costs and capital structure approved by the Commission as
provided in subparagraph (2) of this subsection (c),
consistent with this Section, in accordance with
Commission rules and orders, including, but not limited to,
adjustments for goodwill, and after any Commission-ordered
disallowances and taxes) is more than 50 basis points
higher than the rate of return on common equity calculated
pursuant to paragraph (3) of this subsection (c) (after
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
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
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
to allow costs that are not otherwise recoverable to be
recoverable by virtue of inclusion in FERC Form 1.
After the utility files its proposed performance-based
formula rate structure and protocols and initial rates, the
Commission shall initiate a docket to review the filing. The
Commission shall enter an order approving, or approving as
modified, the performance-based formula rate, including the
initial rates, as just and reasonable within 270 days after the
date on which the tariff was filed, or, if the tariff is filed
within 14 days after October 26, 2011 (the effective date of
Public Act 97-616), then by May 31, 2012. Such review shall be
based on the same evidentiary standards, including, but not
limited to, those concerning the prudence and reasonableness of
the costs incurred by the utility, the Commission applies in a
hearing to review a filing for a general increase in rates
under Article IX of this Act. The initial rates shall take
effect within 30 days after the Commission's order approving
the performance-based formula rate tariff.
Until such time as the Commission approves a different rate
design and cost allocation pursuant to subsection (e) of this
Section, rate design and cost allocation across customer
classes shall be consistent with the Commission's most recent
order regarding the participating utility's request for a
general increase in its delivery services rates.
Subsequent changes to the performance-based formula rate

structure or protocols shall be made as set forth in Section
9-201 of this Act, but nothing in this subsection (c) is
intended to limit the Commission's authority under Article IX
and other provisions of this Act to initiate an investigation
of a participating utility's performance-based formula rate
tariff, provided that any such changes shall be consistent with
paragraphs (1) through (6) of this subsection (c). Any change
ordered by the Commission shall be made at the same time new
rates take effect following the Commission's next order
pursuant to subsection (d) of this Section, provided that the
new rates take effect no less than 30 days after the date on
which the Commission issues an order adopting the change.
A participating utility that files a tariff pursuant to
this subsection (c) must submit a one-time $200,000 filing fee
at the time the Chief Clerk of the Commission accepts the
filing, which shall be a recoverable expense.
In the event the performance-based formula rate is
terminated, the then current rates shall remain in effect until
such time as new rates are set pursuant to Article IX of this
Act, subject to retroactive rate adjustment, with interest, to
reconcile rates charged with actual costs. At such time that
the performance-based formula rate is terminated, the
participating utility's voluntary commitments and obligations
under subsection (b) of this Section shall immediately
terminate, except for the utility's obligation to pay an amount
already owed to the fund for training grants pursuant to a

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

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

include the charge or credit, if any, resulting from the
calculation required by paragraph (6) of subsection (c) of
this Section.
Notwithstanding anything that may be to the contrary,
the intent of the reconciliation is to ultimately reconcile
the revenue requirement reflected in rates for each
calendar year, beginning with the calendar year in which
the utility files its performance-based formula rate
tariff pursuant to subsection (c) of this Section, with
what the revenue requirement determined using a year-end
rate base for the applicable calendar year would have been
had the actual cost information for the applicable calendar
year been available at the filing date.
(2) The new charges shall take effect beginning on the
first billing day of the following January billing period
and remain in effect through the last billing day of the
next December billing period regardless of whether the
Commission enters upon a hearing pursuant to this
subsection (d).
(3) The filing shall include relevant and necessary
data and documentation for the applicable rate year that is
consistent with the Commission's rules applicable to a
filing for a general increase in rates or any rules adopted
by the Commission to implement this Section. Normalization
adjustments shall not be required. Notwithstanding any
other provision of this Section or Act or any rule or other

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

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

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

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),

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

for a participating utility that is a combination utility,
using a baseline of the average uncollectible expense for
the years 2008 through 2010.
(9) Opportunities for minority-owned and female-owned
business enterprises: design a performance metric
regarding the creation of opportunities for minority-owned
and female-owned business enterprises consistent with
State and federal law using a base performance value of the
percentage of the participating utility's capital
expenditures that were paid to minority-owned and
female-owned business enterprises in 2010.
The definitions set forth in 83 Ill. Admin. Code Part
411.20 as of May 1, 2011 shall be used for purposes of
calculating performance under paragraphs (1) through (3.5) of
this subsection (f), provided, however, that the participating
utility may exclude up to 9 extreme weather event days from
such calculation for each year, and provided further that the
participating utility shall exclude 9 extreme weather event
days when calculating each year of the baseline period to the
extent that there are 9 such days in a given year of the
baseline period. For purposes of this Section, an extreme
weather event day is a 24-hour calendar day (beginning at 12:00
a.m. and ending at 11:59 p.m.) during which any weather event
(e.g., storm, tornado) caused interruptions for 10,000 or more
of the participating utility's customers for 3 hours or more.
If there are more than 9 extreme weather event days in a year,

then the utility may choose no more than 9 extreme weather
event days to exclude, provided that the same extreme weather
event days are excluded from each of the calculations performed
under paragraphs (1) through (3.5) of this subsection (f).
The metrics shall include incremental performance goals
for each year of the 10-year period, which shall be designed to
demonstrate that the utility is on track to achieve the
performance goal in each category at the end of the 10-year
period. The utility shall elect when the 10-year period shall
commence for the metrics set forth in subparagraphs (1) through
(4) and (9) of this subsection (f), provided that it begins no
later than 14 months following the date on which the utility
begins investing pursuant to subsection (b) of this Section,
and when the 10-year period shall commence for the metrics set
forth in subparagraphs (5) through (8) of this subsection (f),
provided that it begins no later than 14 months following the
date on which the Commission enters its order approving the
utility's Advanced Metering Infrastructure Deployment Plan
pursuant to subsection (c) of Section 16-108.6 of this Act.
The metrics and performance goals set forth in
subparagraphs (5) through (8) of this subsection (f) are based
on the assumptions that the participating utility may fully
implement the technology described in subsection (b) of this
Section, including utilizing the full functionality of such
technology and that there is no requirement for personal
on-site notification. If the utility is unable to meet the

metrics and performance goals set forth in subparagraphs (5)
through (8) of this subsection (f) for such reasons, and the
Commission so finds after notice and hearing, then the utility
shall be excused from compliance, but only to the limited
extent achievement of the affected metrics and performance
goals was hindered by the less than full implementation.
(f-5) The financial penalties applicable to the metrics
described in subparagraphs (1) through (8) of subsection (f) of
this Section, as applicable, shall be applied through an
adjustment to the participating utility's return on equity of
no more than a total of 30 basis points in each of the first 3
years, of no more than a total of 34 basis points in each of the
3 years thereafter, and of no more than a total of 38 basis
points in each of the 4 years thereafter, as follows:
(1) With respect to each of the incremental annual
performance goals established pursuant to paragraph (1) of
subsection (f) of this Section,
(A) for each year that a participating utility
other than a combination utility does not achieve the
annual goal, the participating utility's return on
equity shall be reduced as follows: during years 1
through 3, by 5 basis points; during years 4 through 6,
by 6 basis points; and during years 7 through 10, by 7
basis points; and
(B) for each year that a participating utility that
is a combination utility does not achieve the annual

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

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

The financial penalties shall be applied as described in
this subsection (f-5) for the 12-month period in which the
deficiency occurred through a separate tariff mechanism, which
shall be filed by the utility together with its metrics. In the
event the formula rate tariff established pursuant to
subsection (c) of this Section terminates, the utility's
obligations under subsection (f) of this Section and this
subsection (f-5) shall also terminate, provided, however, that
the tariff mechanism established pursuant to subsection (f) of
this Section and this subsection (f-5) shall remain in effect
until any penalties due and owing at the time of such
termination are applied.
The Commission shall, after notice and hearing, enter an
order within 120 days after the metrics are filed approving, or
approving with modification, a participating utility's tariff
or mechanism to satisfy the metrics set forth in subsection (f)
of this Section. On June 1 of each subsequent year, each
participating utility shall file a report with the Commission
that includes, among other things, a description of how the
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
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.
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

October 26, 2011 (the effective date of Public Act 97-616). For
purposes of this Section, "eligible retail customers" shall
have the meaning set forth in Section 16-111.5 of this Act.
The fact that this Section becomes inoperative as set forth
in this subsection shall not be construed to mean that the
Commission may reexamine or otherwise reopen prudence or
reasonableness determinations already made.
(h) 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, 2019 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.
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, other than this subsection (h), do not
become inoperative after December 31, 2019, 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
Commission may reexamine or otherwise reopen prudence or
reasonableness determinations already made.
(i) While a participating utility may use, develop, and
maintain broadband systems and the delivery of broadband
services, voice-over-internet-protocol services,
telecommunications services, and cable and video programming
services for use in providing delivery services and Smart Grid
functionality or application to its retail customers,
including, but not limited to, the installation,
implementation and maintenance of Smart Grid electric system
upgrades as defined in Section 16-108.6 of this Act, a

participating utility is prohibited from offering to its retail
customers broadband services or the delivery of broadband
services, voice-over-internet-protocol services,
telecommunications services, or cable or video programming
services, unless they are part of a service directly related to
delivery services or Smart Grid functionality or applications
as defined in Section 16-108.6 of this Act, and from recovering
the costs of such offerings from retail customers.
(j) Nothing in this Section is intended to legislatively
overturn the opinion issued in Commonwealth Edison Co. v. Ill.
Commerce Comm'n, Nos. 2-08-0959, 2-08-1037, 2-08-1137,
1-08-3008, 1-08-3030, 1-08-3054, 1-08-3313 cons. (Ill. App.
Ct. 2d Dist. Sept. 30, 2010). Public Act 97-616 shall not be
construed as creating a contract between the General Assembly
and the participating utility, and shall not establish a
property right in the participating utility.
(k) The changes made in subsections (c) and (d) of this
Section by Public Act 98-15 are intended to be a restatement
and clarification of existing law, and intended to give binding
effect to the provisions of House Resolution 1157 adopted by
the House of Representatives of the 97th General Assembly and
Senate Resolution 821 adopted by the Senate of the 97th General
Assembly that are reflected in paragraph (3) of this
subsection. In addition, Public Act 98-15 preempts and
supersedes any final Commission orders entered in Docket Nos.
11-0721, 12-0001, 12-0293, and 12-0321 to the extent

inconsistent with the amendatory language added to subsections
(c) and (d).
(1) No earlier than 5 business days after May 22, 2013
(the effective date of Public Act 98-15), each
participating utility shall file any tariff changes
necessary to implement the amendatory language set forth in
subsections (c) and (d) of this Section by Public Act 98-15
and a revised revenue requirement under the participating
utility's performance-based formula rate. The Commission
shall enter a final order approving such tariff changes and
revised revenue requirement within 21 days after the
participating utility's filing.
(2) Notwithstanding anything that may be to the
contrary, a participating utility may file a tariff to
retroactively recover its previously unrecovered actual
costs of delivery service that are no longer subject to
recovery through a reconciliation adjustment under
subsection (d) of this Section. This retroactive recovery
shall include any derivative adjustments resulting from
the changes to subsections (c) and (d) of this Section by
Public Act 98-15. Such tariff shall allow the utility to
assess, on current customer bills over a period of 12
monthly billing periods, a charge or credit related to
those unrecovered costs with interest at the utility's
weighted average cost of capital during the period in which
those costs were unrecovered. A participating utility may

file a tariff that implements a retroactive charge or
credit as described in this paragraph for amounts not
otherwise included in the tariff filing provided for in
paragraph (1) of this subsection (k). The Commission shall
enter a final order approving such tariff within 21 days
after the participating utility's filing.
(3) The tariff changes described in paragraphs (1) and
(2) of this subsection (k) shall relate only to, and be
consistent with, the following provisions of Public Act
98-15: paragraph (2) of subsection (c) regarding year-end
capital structure, subparagraph (D) of paragraph (4) of
subsection (c) regarding pension assets, and subsection
(d) regarding the reconciliation components related to
year-end rate base and interest calculated at a rate equal
to the utility's weighted average cost of capital.
(4) Nothing in this subsection is intended to effect a
dismissal of or otherwise affect an appeal from any final
Commission orders entered in Docket Nos. 11-0721, 12-0001,
12-0293, and 12-0321 other than to the extent of the
amendatory language contained in subsections (c) and (d) of
this Section of Public Act 98-15.
(l) Each participating utility shall be deemed to have been
in full compliance with all requirements of subsection (b) of
this Section, subsection (c) of this Section, Section 16-108.6
of this Act, and all Commission orders entered pursuant to
Sections 16-108.5 and 16-108.6 of this Act, up to and including

May 22, 2013 (the effective date of Public Act 98-15). The
Commission shall not undertake any investigation of such
compliance and no penalty shall be assessed or adverse action
taken against a participating utility for noncompliance with
Commission orders associated with subsection (b) of this
Section, subsection (c) of this Section, and Section 16-108.6
of this Act prior to such date. Each participating utility
other than a combination utility shall be permitted, without
penalty, a period of 12 months after such effective date to
take actions required to ensure its infrastructure investment
program is in compliance with subsection (b) of this Section
and with Section 16-108.6 of this Act. Provided further, the
following subparagraphs shall apply to a participating utility
other than a combination utility:
(A) if the Commission has initiated a proceeding
pursuant to subsection (e) of Section 16-108.6 of this Act
that is pending as of May 22, 2013 (the effective date of
Public Act 98-15), then the order entered in such
proceeding shall, after notice and hearing, accelerate the
commencement of the meter deployment schedule approved in
the final Commission order on rehearing entered in Docket
No. 12-0298;
(B) if the Commission has entered an order pursuant to
subsection (e) of Section 16-108.6 of this Act prior to May
22, 2013 (the effective date of Public Act 98-15) that does
not accelerate the commencement of the meter deployment

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

and operational issues. Nothing in Public Act 98-15 shall
shorten or extend the end dates for the 5-year or 10-year
periods set forth in subsection (b) of this Section or Section
16-108.6 of this Act. Nothing in this subsection is intended to
address whether a participating utility has, or has not,
satisfied any or all of the metrics and performance goals
established pursuant to subsection (f) of this Section.
(m) The provisions of Public Act 98-15 are severable under
Section 1.31 of the Statute on Statutes.
(Source: P.A. 98-15, eff. 5-22-13; 98-1175, eff. 6-1-15;
99-143, eff. 7-27-15; 99-642, eff. 7-28-16.)
(220 ILCS 5/16-108.10 new)
Sec. 16-108.10. Energy low-income and support program.
Beginning in 2017, without obtaining any approvals from the
Commission or any other agency, regardless of whether any such
approval would otherwise be required, a participating utility
that is not a combination utility, as defined by Section
16-108.5 of this Act, shall contribute $10,000,000 per year for
5 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 and
reconnecting customers who have been disconnected for
non-payment. Such programs may include:
(1) a residential hardship program that may partner
with community-based organizations, including senior

citizen organizations, and provides grants to low-income
residential customers, including low-income senior
citizens, who demonstrate a hardship;
(2) a program that provides grants and other bill
payment concessions to 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 under 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 under this
Section shall not be a recoverable expense. A participating

utility may elect to fund either new or existing customer
assistance programs, including, but not limited to, those that
are administered by the utility.
Programs that use funds that are provided by an electric
utility to reduce utility bills may be implemented through
tariffs that are filed with and reviewed by the Commission. If
a utility elects to file tariffs with the Commission to
implement all or a portion of the programs, those tariffs
shall, regardless of the date actually filed, be deemed
accepted and approved and shall become effective on the first
business day after they are filed. The electric 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 may 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 under subsection (d) of Section 16-108.5 of this Act or
the performance-based formula rate is otherwise terminated,
then the participating utility's obligations under this
Section shall immediately terminate.
(220 ILCS 5/16-108.11 new)
Sec. 16-108.11. Employment opportunities. To the extent
feasible and consistent with State and federal law, the

procurement of contracted labor, materials, and supplies by
electric utilities in connection with the offering of delivery
services under Article XVI of this Act 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.
(220 ILCS 5/16-108.12 new)
Sec. 16-108.12. Utility job training program.
(a) An electric utility that serves more than 3,000,000
customers in the State shall spend $10,000,000 per year in
2017, 2021, and 2025 to fund the programs described in this
Section.
(1) The utility shall fund a solar training pipeline
program in the amount of $3,000,000. The utility may
administer the program or contract with another entity to
administer the program. The program shall be designed to
establish a solar installer training pipeline for projects
authorized under Section 1-56 of the Illinois Power Agency
Act and to establish a pool of trained installers who will
be able to install solar projects authorized under
subsection (c) of Section 1-75 of the Illinois Power Agency
Act and otherwise. The program may include single event
training programs. The program described in this paragraph
(1) shall be designed to ensure that entities that offer

training are located in, and trainees are recruited from,
the same communities that the program aims to serve and
that the program provides trainees with the opportunity to
obtain real-world experience. The program described in
this paragraph (1) shall also be designed to assist
trainees so that they can obtain applicable certifications
or participate in an apprenticeship program. The utility or
administrator shall include funding for programs that
provide training to individuals who are or were foster
children or that target persons with a record who are
transitioning with job training and job placement
programs. The program shall include an incentive to
facilitate an increase of hiring of qualified persons who
are or were foster children and persons with a record. It
is a goal of the program described in this paragraph (1)
that at least 50% of the trainees in this program come from
within environmental justice communities and that 2,000
jobs are created for persons who are or were foster
children and persons with a record.
(2) The utility shall fund a craft apprenticeship
program in the amount of $3,000,000. The program shall be
an accredited or otherwise recognized apprenticeship
program over a period not to exceed 4 years, for particular
crafts, trades, or skills in the electric industry that
may, but need not, be related to solar installation.
(3) The utility shall fund multi-cultural jobs

programs in the amount of $4,000,000. The funding shall be
allocated in the applicable year to individual programs as
set forth in subparagraphs (A) through (F) of this
paragraph (3) and may, but need not, be related to solar
installation, over a period not to exceed 4 years, by
diversity-focused community organizations that have a
record of successfully delivering job training.
(A) $1,000,000 to a community-based civil rights
and human services not-for-profit organization that
provides economic development, human capital, and
education program services.
(B) $500,000 to a not-for-profit organization that
is also an education institution that offers training
programs approved by the Illinois State Board of
Education and United States Department of Education
with the goal of providing workforce initiatives
leading to economic independence.
(C) $500,000 to a not-for-profit organization
dedicated to developing the educational and leadership
capacity of minority youth through the operation of
schools, youth leadership clubs and youth development
centers.
(D) $1,000,000 to a not-for-profit organization
dedicated to providing equal access to opportunities
in the construction industry that offer training
programs that include Occupational Safety and Health

Administration 10 and 30 certifications, Environmental
Protection Agency Renovation, Repair and Painting
Certification and Leadership in Energy and
Environmental Design Accredited Green Associate Exam
preparation courses.
(E) $500,000 to a non-profit organization that has
a proven record of successfully implementing utility
industry training programs, with expertise in creating
programs that strengthen the economics of communities
including technical training workshops and economic
development through community and financial partners.
(F) $500,000 to a nonprofit organization that
provides family services, housing education, job and
career education opportunities that has successfully
partnered with the utility on electric industry job
training.
For the purposes of this Section, "person with a record"
means any person who (1) has been convicted of a crime in this
State or of an offense in any other jurisdiction, not including
an offense or attempted offense that would subject a person to
registration under the Sex Offender Registration Act; (2) has a
record of an arrest or an arrest that did not result in
conviction for any crime in this State or of an offense in any
other jurisdiction; or (3) has a juvenile delinquency
adjudication.
(b) Within 60 days after the effective date of this

amendatory Act of the 99th General Assembly, an electric
utility that serves more than 3,000,000 customers in the State
shall file with the Commission a plan to implement this
Section. Within 60 days after the plan is filed, the Commission
shall enter an order approving the plan if it is consistent
with this Section or, if the plan is not consistent with this
Section, the Commission shall explain the deficiencies, after
which time the utility shall file a new plan. The utility shall
use the funds described in subparagraph (O) of paragraph (1) of
subsection (c) of Section 1-75 of the Illinois Power Agency Act
to pay for the Commission approved programs under this Section.
(220 ILCS 5/16-108.15 new)
Sec. 16-108.15. Rate impacts.
(a) Each electric utility that serves more than 500,000
retail customers in the State shall file with the Commission
the reports required by this Section, which shall identify the
actual and projected average monthly increases in residential
retail customers' electric bills due to future energy
investment costs for the applicable period or periods.
(b) The average monthly increase calculation shall be
comprised of the following components:
(1) Beginning with the 2017 calendar year, the average
monthly amount paid by residential retail customers,
expressed on a cents-per-kilowatthour basis, to recover
future energy investment costs, which include the charges

to recover the costs incurred by the utility under the
following provisions:
(A) Sections 8-103, Section 8-103B, and 16-111.5B
of this Act, as applicable, and as such costs may be
recovered under Sections 8-103, 8-103B, 16-111.5B or
Section 16-108.5 of this Act;
(B) subsection (d-5) of Section 1-75 of the
Illinois Power Agency Act, as such costs may be
recovered under subsection (k) of Section 16-108 of
this Act; and
(C) Section 16-107.6 of this Act.
Beginning with the 2018 calendar year, each of the
average monthly charges calculated in subparagraphs (A)
through (C) of this paragraph (1) shall be equal to the
average of each such charge applied over a period that
commences with the calendar year ending December 31, 2017
and ends with the most recently completed calendar year
prior to the calculation or calculations required by this
Section.
(2) The sum of the following:
(A) net energy savings to residential retail
customers that are attributable to the implementation
of voltage optimization measures under Section 8-103B
of this Act, expressed on a cents-per-kilowatthour
basis, which are estimated energy and capacity
benefits for residential retail customers minus the

measure costs recovered from those customers, divided
by the total number of residential retail customers,
which quotient shall be divided by the months in the
relevant period; notwithstanding this subparagraph
(A), a utility may elect not to include an estimate of
net energy savings as described in this subparagraph
(A), in which case the value under this subparagraph
(A) shall be zero; and
(B) for an electric utility that serves more than
3,000,000 retail customers in the State, the benefits
of the programs described in Section 16-108.10 of this
Act, which are $0.00030 per kilowatthour for the 2017,
2018, 2019, 2020, and 2021 calendar years.
Beginning with the 2018 calendar year, each of the
values identified in subparagraphs (A) and (B) of this
paragraph (2) shall be equal to the average of each
such value during a period that commences with the
calendar year ending December 31, 2017 and ends with
the most recently completed calendar year prior to the
calculation or calculations required by this Section.
(3) For an electric utility that serves more than
3,000,000 retail customers in the State, the residential
retail customer energy efficiency charges shall be $2.33
per month for the 2017 calendar year, provided that such
charge shall be increased by 4% per year thereafter; for an
electric utility that serves more than 500,000 but less

than 3,000,000 retail customers in the State, the
residential retail customer energy efficiency charges
shall be $3.94 per month for the 2017 calendar year,
provided that such charge shall be increased by 4% per year
thereafter. Beginning with the 2018 calendar year, this
charge shall be equal to the average of the charges applied
over a period that commences with the calendar year ending
December 31, 2017 and ends with the most recently completed
calendar year prior to the calculation or calculations
required by this Section.
(c)(1) No later than June 30, 2017, an electric utility
subject to this Section shall submit a report to the
Commission that sets forth the utility's rolling 10-year
projection of the values of each of the components
described in paragraphs (1) through (3) of subsection (b)
of this Section. No later than February 15, 2018 and every
February 15 thereafter until February 15, 2031, each
utility shall submit a report to the Commission that
identifies the value of the actual charges applied during
the immediately preceding calendar year and updates its
rolling 10-year projection based on such actual charges
provided that, beginning with the February 15, 2021 report
and for each report thereafter, the period of time covered
by such projection shall not extend beyond December 31,
2030. Each report submitted under this subsection (c) shall
calculate the actual average monthly increase in

residential retail customers' electric bills due to future
energy investment costs during the immediately preceding
calendar year and shall also calculate the projected
average monthly increase in residential retail customers'
electric bills due to such costs over the rolling 10-year
period. Such calculations shall be performed by
subtracting the sum of paragraph (2) of subsection (b) of
this Section from the sum of paragraph (1) of such
subsection (b), multiplying such difference by, as
applicable, the actual or forecasted average monthly
kilowatthour consumption for the residential retail
customer class for the applicable period, and subtracting
from such product the applicable value identified under
paragraph (3) of such subsection (b).
If the actual or projected average monthly increase for
residential retail customers of electric utility that
serves more than 3 million retail customers in the State
exceeds $0.25, or the actual or projected average monthly
increase for residential retail customers of an electric
utility that serves more than 500,000 but less than 3
million retail customers in the State exceeds $0.35, then
the applicable utility shall comply with the provisions of
paragraphs (2) through (4) of this subsection (c), as
applicable.
(2) If the projected average monthly increase for
residential retail customers during a calendar year

exceeds the applicable limitation set forth in paragraph
(1) of this subsection (c), then the utility shall comply
with the following provisions, as applicable:
(A) If an exceedance is projected during the first
four calendar year of the rolling 10-year projection,
then the utility shall include in its report submitted
under paragraph (1) of this subsection (c) the
utility's proposal or proposals to decrease the future
energy investment costs described in paragraph (1) of
subsection (b) of this Section to ensure that the
limitation set forth in such paragraph (1) is not
exceeded. The Commission shall, after notice and
hearing, enter an order directing the utility to
implement one or more proposals, as such proposals may
be modified by the Commission. The Commission shall
have the authority under this subparagraph (A) to
approve modifications to the contracts executed under
subsection (d-5) of Section 1-75 of the Illinois Power
Agency Act. If the Commission approves modifications
to such contracts, then the supplier shall have the
option of accepting the modifications or terminating
the modified contract or contracts, subject to the
termination requirements and notice provisions set
forth in item (i) of subparagraph (B) of paragraph (4)
of this Section.
(B) If an exceedance is projected during any

calendar year during the last 6 years of the 10-year
projection, then the utility shall demonstrate in its
report submitted under paragraph (1) of this
subsection (c) how the utility will reduce the future
energy investment costs described in paragraph (1) of
subsection (b) of this Section to ensure that the
limitation set forth in such paragraph (1) is not
exceeded.
(3) If the actual average monthly increase for
residential retail customers during a calendar year
exceeded the limitation set forth in paragraph (1) of this
subsection (c), then the utility shall prepare and file
with the Commission, at the time it submits its report
under paragraph (1) of this subsection (c), a corrective
action plan that identifies how the utility will
immediately reduce expenditures so that the utility will be
in compliance with such limitation beginning on January 1
of the next calendar year. The Commission shall initiate an
investigation to determine the factors that contributed to
the actual average monthly increase exceeding such
limitation for the applicable calendar year, and shall,
after notice and hearing, enter an order approving, or
approving with modification, the utility's corrective
action plan within 120 days after the utility files such
plan. The Commission shall also submit a report to the
General Assembly no later than 30 days after it enters such

order, and the report shall explain the results of the
Commission's investigation and findings and conclusions of
its order.
(4) If the actual average monthly increase for
residential retail customers during a calendar year
exceeds the limitation set forth in paragraph (1) of this
subsection (c) for two consecutive years, then the utility
shall indicate in its report filed under paragraph (1) of
this subsection (c) whether the utility will proceed with
or terminate the future energy investments described and
authorized under subsection (d-5) of the Illinois Power
Agency Act and Sections 8-103B and 16-107.6 of this Act.
The utility shall be subject to the requirements of
subparagraph (A) or (B) of this paragraph (4), as
applicable.
(A) If the utility indicates that it will proceed
with the future energy investments, then it shall be
subject to the corrective action plan requirements set
forth in paragraph (3) of this subsection (c). In
addition, the utility must commit to apply a credit to
residential retail customers' bills if the actual
average monthly increase for such customers exceeds
the limitation set forth in paragraph (1) of this
subsection (c) for the year in which the utility files
its corrective action plan, which credit shall be in an
amount that equals the portion by which the increase

exceeds such limitation. The Commission shall initiate
an investigation to determine the factors that
contributed to the actual average monthly increase
exceeding such limitation for the applicable calendar
year, including an analysis of the factors
contributing to the limitation being exceeded for two
consecutive years, and shall, after notice and
hearing, enter an order approving, or approving with
modification, the utility's corrective action plan
within 120 days after the utility files such plan. The
Commission shall also submit a supplemental report to
the General Assembly no later than 30 days after it
enters such order, and the report shall explain the
results of the Commission's investigation and findings
and conclusions of its order.
(B) If the utility indicates that it will terminate
future energy investments, then the Commission shall,
notwithstanding anything to the contrary:
(i) Order the utility to terminate the
contract or contracts executed under subsection
(d-5) of Section 1-75 of the Illinois Power Agency
Act, pursuant to the contract termination
provisions set forth in such subsection (d-5),
provided that notice of such termination must be
made at least 3 years and 75 days prior to the
effective date of such termination. In the event

that only a portion of the contracts executed under
such subsection (d-5) are terminated for a
particular zero emission facility, then the zero
emission facility may elect to terminate all of the
contracts executed for that facility under such
subsection (d-5).
(ii) Within 30 days after the utility submits
its report indicates that it will terminate future
energy investments, initiate a proceeding to
approve the process for terminating future
expenditures under Section 16-107.6 of the Public
Utilities Act. The Commission shall, after notice
and hearing, enter its order approving such
process no later than 120 days after initiating
such proceeding.
(iii) Within 30 days after the utility submits
its report indicates that it will terminate future
energy investments, initiate a proceeding under
Section 8-103B of this Act to reduce the cumulative
persisting annual savings goals previously
approved by the Commission under such Section to
ensure just and reasonable rates. The Commission
shall, after notice and hearing, enter its order
approving such goal reductions no later than 120
days after initiating such proceeding.
Notwithstanding the termination of future energy

investments pursuant to this subparagraph (B), the
utility shall be permitted to continue to recover the
costs of such investments that were incurred prior to
such termination, including but not limited to all
costs that are recovered through regulatory assets
created under Sections 8-103B and 16-107.6 of this Act.
Nothing in this Section shall limit the utility's
ability to fully recover such costs. The utility shall
also be permitted to continue to recover the costs of
all payments made under contracts executed under
subsection (d-5) until the effective date of the
contract's termination.
(220 ILCS 5/16-108.16 new)
Sec. 16-108.16. Commercial Rate Impacts.
(a) Each electric utility that serves more than 500,000
retail customers in the State shall file with the Commission
the reports required by this Section, which shall identify the
annual average increases due to future energy investment costs
for the applicable period or periods in electric bills to
commercial and industrial retail customers. For purposes of
this Section, "commercial and industrial retail customers"
means non-residential retail customers other than those
customers who are exempt from subsections (a) through (j) of
Section 8-103B of this Act under subsection (l) of Section
8-103B.

(b) The increase determination required by subsection (a)
of this Section shall be based on a calculation comprised of
the following components:
(1 )Beginning with the 2017 calendar year, the average
annual amount paid by commercial and industrial retail
customers, expressed on a cents-per-kilowatthour basis, to
recover future energy investment costs, which include the
charges to recover the costs incurred by the utility under
the following provisions:
(A) Sections 8-103, Section 8-103B, and 16-111.5B
of this Act, as applicable, and as such costs may be
recovered under Sections 8-103, 8-103B, 16-111.5B or
Section 16-108.5 of this Act;
(B) subsection (d-5) of Section 1-75 of the
Illinois Power Agency Act, as such costs may be
recovered under subsection (k) of Section 16-108 of
this Act; and
(C) Section 16-107.6 of this Act.
Beginning with the 2018 calendar year, each of the
average annual charges calculated in subparagraphs (A)
through (C) of this paragraph (1) shall be equal to the
average of each such charge applied over a period that
commences with the calendar year ending December 31, 2017
and ends with the most recently completed calendar year
prior to the calculation or calculations required by this
Section.

(2) The sum of the following:
(A) annual net energy savings to commercial and
industrial retail customers that are attributable to
the implementation of voltage optimization measures
under Section 8-103B of this Act, expressed on a
cents-per-kilowatthour basis, which are estimated
energy and capacity benefits for commercial and
industrial retail customers minus the measure costs
recovered from those customers, divided by the average
annual kilowatt-hour consumption of commercial and
industrial retail customers; notwithstanding this
subparagraph (A), a utility may elect not to include an
estimate of net energy savings as described in this
subparagraph (A), in which case the value under this
subparagraph (A) shall be zero;
(B) the average annual cents-per-kilowatthour
charge applied under Section 8-103 of this Act to
commercial and industrial retail customers during
calendar year 2016 to recover the costs authorized by
such Section; and
(C) incremental energy efficiency savings, which
shall be calculated by subtracting the value
determined in item (ii) of this subparagraph (C) from
the value determined in item (i) of this subparagraph
and dividing the difference by the value identified in
item (iii) of this subparagraph:

(i) Total value, in dollars, of the cumulative
persisting annual saving achieved from the
installation or implementation of all energy
efficiency measures for commercial and industrial
retail customers under Sections 8-103, 8-103B and
16-111.5 of this Act, net of the cumulative annual
percentage savings in kilowatt-hours, if any,
calculated under subparagraph (A) of this
paragraph (2).
(ii) 2016 value, which shall equal the value
calculated under item (i) of this subparagraph (C)
multiplied by the quotient of (aa) the cumulative
persisting annual savings, in kilowatt-hours,
achieved from the installation or implementation
of all energy efficiency measures for commercial
and industrial retail customers under Sections
8-103, 8-103B and 16-111.5B of this Act as of
December 31, 2016, divided by (bb) the cumulative
persisting annual savings, in kilowatt-hours, from
the installation or implementation of all energy
efficiency measures for commercial and industrial
retail customers under Sections 8-103, 8-103B and
16-111.5 of this Act, net of the cumulative annual
percentage savings in kilowatt-hours, if any,
calculated under subparagraph (A) of this
paragraph (2).

(iii) The average annual kilowatt-hour
consumption of those commercial and industrial
retail customers that installed or implemented
energy efficiency measures under energy efficiency
programs or plans approved pursuant to Sections
8-103, 8-103B or 16-111.5B of this Act.
Beginning with the 2018 calendar year, each of the
values identified in subparagraphs (A) and (C) of this
paragraph (2) shall be equal to the average of each
such value during a period that commences with the
calendar year ending December 31, 2017 and ends with
the most recently completed calendar year prior to the
calculation or calculations required by this Section.
For purposes of this Section, cumulative
persisting annual savings shall have the meaning set
forth in Section 8-103B of this Act, and energy
efficiency measures shall have the meaning set forth in
Section 1-10 of the Illinois Power Agency Act.
(c)(1) No later than June 30, 2017, and every June 30
thereafter until June 30, 2027, an electric utility subject
to this Section shall submit a report to the Commission
that sets forth the utility's 10-year projection of the
values of each of the components described in paragraphs
(1) and (2) of subsection (b) of this Section. Each
utility's report to the Commission shall identify the
result of the computation performed under this Section for

the immediately preceding calendar year and update its
10-year projection. Such calculations shall be performed
by subtracting the sum of paragraph (2) of subsection (b)
of this Section from the sum of paragraph (1) of such
subsection (b).
In the event that the actual or projected average
annual increase for commercial and industrial retail
customers exceeds 1.3% of 8.90 cents-per-kilowatthour,
which is the average amount paid per kilowatt-hour for
electric service during the year ending December 31, 2015
by Illinois commercial retail customers, as reported to the
Edison Electric Institute, then the applicable utility
shall comply with the provisions of paragraphs (2) through
(4) of this subsection (c), as applicable.
(2) In the event that the projected average annual
increase for commercial and industrial retail customers
during a calendar year exceeds the applicable limitation
set forth in paragraph (1) of this subsection (c), then the
utility shall comply with the following provisions, as
applicable:
(A) If an exceedance is projected during the first
four calendar years of the 10-year projection, then the
utility shall include in its report submitted under
paragraph (1) of this subsection (c) the utility's
proposal or proposals to decrease the future energy
investment costs described in paragraph (1) of

subsection (b) of this Section to ensure that the
limitation set forth in such paragraph (1) is not
exceeded. The Commission shall, after notice and
hearing, enter an order directing the utility to
implement one or more proposals, as such proposals may
be modified by the Commission. The Commission shall
have the authority under this subparagraph (A) to
approve modifications to the contracts executed under
subsection (d-5) of Section 1-75 of the Illinois Power
Agency Act. If the Commission approves modifications
to such contracts that are in an amount that reduces
the quantities to be procured under such contracts by
more than 7%, then the supplier shall have the option
of accepting the modifications or terminating the
modified contract or contracts, subject to the
termination requirements and notice provisions set
forth in item (i) of subparagraph (B) of paragraph (4)
of this Section.
(B) If an exceedance is projected during any
calendar year during the last 6 years of the 10-year
projection, then the utility shall demonstrate in its
report submitted under paragraph (1) of this
subsection (c) how the utility will reduce the future
energy investment costs described in paragraph (1) of
subsection (b) of this Section to ensure that the
limitation set forth in such paragraph (1) is not

exceeded.
(3) If the actual average annual increase for
commercial and industrial retail customers during a
calendar year exceeded the limitation set forth in
paragraph (1) of this subsection (c), then the utility
shall prepare and file with the Commission, at the time it
submits its report under paragraph (1) of this subsection
(c), a corrective action plan. The Commission shall
initiate an investigation to determine the factors that
contributed to the actual average annual increase
exceeding such limitation for the applicable calendar
year, and shall, after notice and hearing, enter an order
approving, or approving with modification, the utility's
corrective action plan within 120 days after the utility
files such plan. The Commission shall also submit a report
to the General Assembly no later than 30 days after it
enters such order, and the report shall explain the results
of the Commission's investigation and findings and
conclusions of its order.
(4) If the actual average annual increase for
commercial and industrial retail customers during a
calendar year exceeds the limitation set forth in paragraph
(1) of this subsection (c) for two consecutive years, then
the utility shall indicate in its report filed under
paragraph (1) of this subsection (c) whether the utility
will proceed with or terminate the future energy

investments described and authorized under subsection
(d-5) of the Illinois Power Agency Act and Sections 8-103B
and 16-107.6 of this Act. The utility's election shall be
subject to the requirements of subparagraph (A) or (B) of
this paragraph (4), as applicable.
(A) If the utility elects to proceed with the
future energy investments, then it shall be subject to
the corrective action plan requirements set forth in
paragraph (3) of this subsection (c). In addition, the
utility must commit to apply a credit to commercial and
industrial retail customers' bills if the actual
average annual increase for such customers exceeds the
limitation set forth in paragraph (1) of this
subsection (c) for the year in which the utility files
its corrective action plan, which credit shall be in an
amount that equals the portion by which the increase
exceeds such limitation. The Commission shall initiate
an investigation to determine the factors that
contributed to the actual average annual increase
exceeding such limitation for the applicable calendar
year, including an analysis of the factors
contributing to the limitation being exceeded for two
consecutive years, and shall, after notice and
hearing, enter an order approving, or approving with
modification, the utility's corrective action plan
within 120 days after the utility files such plan. The

Commission shall also submit a supplemental report to
the General Assembly no later than 30 days after it
enters such order, and the report shall explain the
results of the Commission's investigation and findings
and conclusions of its order.
(B) If the utility elects to terminate future
energy investments, then the Commission shall,
notwithstanding anything to the contrary:
(i) Order the utility to terminate the
contract or contracts executed under subsection
(d-5) of Section 1-75 of the Illinois Power Agency
Act, pursuant to the contract termination
provisions set forth in such subsection (d-5),
provided that notice of such termination must be
made at least 3 years and 75 days prior to the
effective date of such termination. In the event
that only a portion of the contracts executed under
such subsection (d-5) are terminated for a
particular zero emission facility, then the zero
emission facility may elect to terminate all of the
contracts executed for that facility under such
subsection (d-5).
(ii) Within 30 days of the utility's report
identifying its election to terminate future
energy investments, initiate a proceeding to
approve the process for terminating future

expenditures under Sections 16-107.6 of the Public
Utilities Act. The Commission shall, after notice
and hearing, enter its order approving such
process no later than 120 days after initiating
such proceeding.
(iii) Within 30 days of the utility's report
identifying its election to terminate future
energy investments, initiate a proceeding under
Section 8-103B of this Act to reduce the cumulative
persisting annual savings goals previously
approved by the Commission under such Section to
ensure just and reasonable rates. The Commission
shall, after notice and hearing, enter its order
approving such goal reductions no later than 120
days after initiating such proceeding.
Notwithstanding the termination of future energy
investments pursuant to this subparagraph (B), the
utility shall be permitted to continue to recover the
costs of such investments that were incurred prior to
such termination, including but not limited to all
costs that are recovered through regulatory assets
created under Sections 8-103B and 16-107.6 of this Act.
Nothing in this Section shall limit the utility's
ability to fully recover such costs. The utility shall
also be permitted to continue to recover the costs of
all payments made under contracts executed under

subsection (d-5) until the effective date of the
contract's termination.
(5) Notwithstanding anything to the contrary, if,
under this Section or subsection (m) of Section 16-108 of
this Act, modifications to the contracts executed under
subsection (d-5) of Section 1-75 of the Illinois Power
Agency Act are, in total, in an amount that reduces the
quantities to procured under such contracts by more than
10%, then the supplier shall have the option of accepting
the modifications or terminating the modified contract or
contracts, subject to the termination requirements and
notice provisions set forth in item (i) of subparagraph (B)
of paragraph (4) of this Section.
(220 ILCS 5/16-111.1)
Sec. 16-111.1. Illinois Clean Energy Community Trust.
(a) An electric utility which has sold or transferred
generating facilities in a transaction to which subsection (k)
of Section 16-111 applies is authorized to establish an
Illinois clean energy community trust or foundation for the
purposes of providing financial support and assistance to
entities, public or private, within the State of Illinois
including, but not limited to, units of State and local
government, educational institutions, corporations, and
charitable, educational, environmental and community
organizations, for programs and projects that benefit the

public by improving energy efficiency, developing renewable
energy resources, supporting other energy related projects
that improve the State's environmental quality, and supporting
projects and programs intended to preserve or enhance the
natural habitats and wildlife areas of the State. Provided,
however, that the trust or foundation funds shall not be used
for the remediation of environmentally impaired property. The
trust or foundation may also assist in identifying other energy
and environmental grant opportunities.
(b) Such trust or foundation shall be governed by a
declaration of trust or articles of incorporation and bylaws
which shall, at a minimum, provide that:
(1) There shall be 6 voting trustees of the trust or
foundation, one of whom shall be appointed by the Governor,
one of whom shall be appointed by the President of the
Illinois Senate, one of whom shall be appointed by the
Minority Leader of the Illinois Senate, one of whom shall
be appointed by the Speaker of the Illinois House of
Representatives, one of whom shall be appointed by the
Minority Leader of the Illinois House of Representatives,
and one of whom shall be appointed by the electric utility
establishing the trust or foundation, provided that the
voting trustee appointed by the utility shall be a
representative of a recognized environmental action group
selected by the utility. The Governor shall designate one
of the 6 voting trustees to serve as chairman of the trust

or foundation, who shall serve as chairman of the trust or
foundation at the pleasure of the Governor. In addition,
there shall be 5 4 non-voting trustees, one of whom shall
be appointed by the Director of Commerce and Economic
Opportunity, one of whom shall be appointed by the Director
of the Illinois Environmental Protection Agency, one of
whom shall be appointed by the Director of Natural
Resources, and 2 one of whom shall be appointed by the
electric utility establishing the trust or foundation,
provided that the non-voting trustee appointed by the
utility shall bring financial expertise to the trust or
foundation and shall have appropriate credentials
therefor.
(2) All voting trustees and the non-voting trustee with
financial expertise shall be entitled to compensation for
their services as trustees, provided, however, that no
member of the General Assembly and no employee of the
electric utility establishing the trust or foundation
serving as a voting trustee shall receive any compensation
for his or her services as a trustee, and provided further
that the compensation to the chairman of the trust shall
not exceed $25,000 annually and the compensation to any
other trustee shall not exceed $20,000 annually. All
trustees shall be entitled to reimbursement for reasonable
expenses incurred on behalf of the trust in the performance
of their duties as trustees. All such compensation and

reimbursements shall be paid out of the trust.
(3) Trustees shall be appointed within 30 days after
the creation of the trust or foundation and shall serve for
a term of 5 years commencing upon the date of their
respective appointments, until their respective successors
are appointed and qualified.
(4) A vacancy in the office of trustee shall be filled
by the person holding the office responsible for appointing
the trustee whose death or resignation creates the vacancy,
and a trustee appointed to fill a vacancy shall serve the
remainder of the term of the trustee whose resignation or
death created the vacancy.
(5) The trust or foundation shall have an indefinite
term, and shall terminate at such time as no trust assets
remain.
(6) The trust or foundation shall be funded in the
minimum amount of $250,000,000, with the allocation and
disbursement of funds for the various purposes for which
the trust or foundation is established to be determined by
the trustees in accordance with the declaration of trust or
the articles of incorporation and bylaws; provided,
however, that this amount may be reduced by up to
$25,000,000 if, at the time the trust or foundation is
funded, a corresponding amount is contributed by the
electric utility establishing the trust or foundation to
the Board of Trustees of Southern Illinois University for

the purpose of funding programs or projects related to
clean coal and provided further that $25,000,000 of the
amount contributed to the trust or foundation shall be
available to fund programs or projects related to clean
coal.
(7) The trust or foundation shall be authorized to
employ an executive director and other employees, to enter
into leases, contracts and other obligations on behalf of
the trust or foundation, and to incur expenses that the
trustees deem necessary or appropriate for the fulfillment
of the purposes for which the trust or foundation is
established, provided, however, that salaries and
administrative expenses incurred on behalf of the trust or
foundation shall not exceed $500,000 in the first fiscal
year after the trust or foundation is established and shall
not exceed $1,000,000 in each subsequent fiscal year.
(8) The trustees may create and appoint advisory boards
or committees to assist them with the administration of the
trust or foundation, and to advise and make recommendations
to them regarding the contribution and disbursement of the
trust or foundation funds.
(c)(1) In addition to the allocation and disbursement of
funds for the purposes set forth in subsection (a) of this
Section, the trustees of the trust or foundation shall
annually contribute funds in amounts set forth in
subparagraph (2) of this subsection to the Citizens Utility

Board created by the Citizens Utility Board Act; provided,
however, that any such funds shall be used solely for the
representation of the interests of utility consumers
before the Illinois Commerce Commission, the Federal
Energy Regulatory Commission, and the Federal
Communications Commission and for the provision of
consumer education on utility service and prices and on
benefits and methods of energy conservation. Provided,
however, that no part of such funds shall be used to
support (i) any lobbying activity, (ii) activities related
to fundraising, (iii) advertising or other marketing
efforts regarding a particular utility, or (iv)
solicitation of support for, or advocacy of, a particular
position regarding any specific utility or a utility's
docketed proceeding.
(2) In the calendar year in which the trust or
foundation is first funded, the trustees shall contribute
$1,000,000 to the Citizens Utility Board within 60 days
after such trust or foundation is established; provided,
however, that such contribution shall be made after
December 31, 1999. In each of the 6 calendar years
subsequent to the first contribution, if the trust or
foundation is in existence, the trustees shall contribute
to the Citizens Utility Board an amount equal to the total
expenditures by such organization in the prior calendar
year, as set forth in the report filed by the Citizens

Utility Board with the chairman of such trust or foundation
as required by subparagraph (3) of this subsection. Such
subsequent contributions shall be made within 30 days of
submission by the Citizens Utility Board of such report to
the Chairman of the trust or foundation, but in no event
shall any annual contribution by the trustees to the
Citizens Utility Board exceed $1,000,000. Following such
7-year period, an Illinois statutory consumer protection
agency may petition the trust or foundation for
contributions to fund expenditures of the type identified
in paragraph (1), but in no event shall annual
contributions by the trust or foundation for such
expenditures exceed $1,000,000.
(3) The Citizens Utility Board shall file a report with
the chairman of such trust or foundation for each year in
which it expends any funds received from the trust or
foundation setting forth the amount of any expenditures
(regardless of the source of funds for such expenditures)
for: (i) the representation of the interests of utility
consumers before the Illinois Commerce Commission, the
Federal Energy Regulatory Commission, and the Federal
Communications Commission, and (ii) the provision of
consumer education on utility service and prices and on
benefits and methods of energy conservation. Such report
shall separately state the total amount of expenditures for
the purposes or activities identified by items (i) and (ii)

of this paragraph, the name and address of the external
recipient of any such expenditure, if applicable, and the
specific purposes or activities (including internal
purposes or activities) for which each expenditure was
made. Any report required by this subsection shall be filed
with the chairman of such trust or foundation no later than
March 31 of the year immediately following the year for
which the report is required.
(d) In addition to any other allocation and disbursement of
funds in this Section, the trustees of the trust or foundation
shall contribute an amount up to $125,000,000 (1) for deposit
into the General Obligation Bond Retirement and Interest Fund
held in the State treasury to assist in the repayment on
general obligation bonds issued under subsection (d) of Section
7 of the General Obligation Bond Act, and (2) for deposit into
funds administered by agencies with responsibility for
environmental activities to assist in payment for
environmental programs. The amount required to be contributed
shall be provided to the trustees in a certification letter
from the Director of the Bureau of the Budget that shall be
provided no later than August 1, 2003. The payment from the
trustees shall be paid to the State no later than December 31st
following the receipt of the letter.
(Source: P.A. 93-32, eff. 6-20-03; 94-793, eff. 5-19-06.)
(220 ILCS 5/16-111.5)

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

service tariffs, other than those retail customers whose
service is declared or deemed competitive under Section 16-113
and those other customer groups specified in this Section,
including self-generating customers, customers electing hourly
pricing, or those customers who are otherwise ineligible for
fixed-price bundled tariff service. For those Those customers
that are excluded from the definition of "eligible retail
customers" shall not be included in the procurement plan's
electric supply service 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 procurement plan load requirements
for the load that is associated with those retail customers
whose service has been declared or deemed competitive pursuant
to Section 16-113 of this Act to the extent that those
customers are purchasing power and energy during one of the
transition periods identified in subsection (b) of Section
16-113 of this Act.
(b) A procurement plan shall be prepared for each electric
utility consistent with the applicable requirements of the
Illinois Power Agency Act and this Section. For purposes of
this Section, Illinois electric utilities that are affiliated
by virtue of a common parent company are considered to be a
single electric utility. Small multi-jurisdictional utilities
may request a procurement plan for a portion of or all of its

Illinois load. Each procurement plan shall analyze the
projected balance of supply and demand for those retail
customers to be included in the plan's electric supply service
requirements 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 procurement plan or in the implementing tariff, any
procurement occurring in accordance with this plan shall be
competitively bid through a request for proposals process.
Approval and implementation of the procurement plan shall be
subject to review and approval by the Commission according to
the provisions set forth in this Section. A procurement plan
shall include each of the following components:
(1) Hourly load analysis. This analysis shall include:
(i) multi-year historical analysis of hourly
loads;
(ii) switching trends and competitive retail
market analysis;
(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
this Act. The cost-effective demand-response measures

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

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

procurement plan shall include, for load requirements
included in the procurement plan, the process for (i)
hourly balancing of supply and demand and (ii) the criteria
for portfolio re-balancing in the event of significant
shifts in load.
(5) Long-Term Renewable Resources Procurement Plan.
The Agency shall prepare a long-term renewable resources
procurement plan for the procurement of renewable energy
credits under Sections 1-56 and 1-75 of the Illinois Power
Agency Act for delivery beginning in the 2017 delivery
year.
(i) The initial long-term renewable resources
procurement plan and all subsequent revisions shall be
subject to review and approval by the Commission. For
the purposes of this Section, "delivery year" has the
same meaning as in Section 1-10 of the Illinois Power
Agency Act. For purposes of this Section, "Agency"
shall mean the Illinois Power Agency.
(ii) The long-term renewable resources planning
process shall be conducted as follows:
(A) Electric utilities shall provide a range
of load forecasts to the Illinois Power Agency
within 45 days of the Agency's request for
forecasts, which request shall specify the length
and conditions for the forecasts including, but
not limited to, the quantity of distributed

generation expected to be interconnected for each
year.
(B) The Agency shall publish for comment the
initial long-term renewable resources procurement
plan no later than 120 days after the effective
date of this amendatory Act of the 99th General
Assembly and shall review, and may revise, the plan
at least every 2 years thereafter. To the extent
practicable, the Agency shall review and propose
any revisions to the long-term renewable energy
resources procurement plan in conjunction with the
Agency's other planning and approval processes
conducted under this Section. The initial
long-term renewable resources procurement plan
shall:
(aa) Identify the procurement programs and
competitive procurement events consistent with
the applicable requirements of the Illinois
Power Agency Act and shall be designed to
achieve the goals set forth in subsection (c)
of Section 1-75 of that Act.
(bb) Include a schedule for procurements
for renewable energy credits from
utility-scale wind projects, utility-scale
solar projects, and brownfield site
photovoltaic projects consistent with

subparagraph (G) of paragraph (1) of
subsection (c) of Section 1-75 of the Illinois
Power Agency Act.
(cc) Identify the process whereby the
Agency will submit to the Commission for review
and approval the proposed contracts to
implement the programs required by such plan.
Copies of the initial long-term renewable
resources procurement plan and all subsequent
revisions shall be posted and made publicly
available on the Agency's and Commission's
websites, and copies shall also be provided to each
affected electric utility. An affected utility and
other interested parties shall have 45 days
following the date of posting to provide comment to
the Agency on the initial long-term renewable
resources procurement plan and all subsequent
revisions. All comments submitted to the Agency
shall be specific, supported by data or other
detailed analyses, and, if objecting to all or a
portion of the procurement plan, accompanied by
specific alternative wording or proposals. All
comments shall be posted on the Agency's and
Commission's websites. During this 45-day comment
period, the Agency shall hold at least one public
hearing within each utility's service area that is

subject to the requirements of this paragraph (5)
for the purpose of receiving public comment.
Within 21 days following the end of the 45-day
review period, the Agency may revise the long-term
renewable resources procurement plan based on the
comments received and shall file the plan with the
Commission for review and approval.
(C) Within 14 days after the filing of the
initial long-term renewable resources procurement
plan or any subsequent revisions, any person
objecting to the plan may file an objection with
the Commission. Within 21 days after the filing of
the plan, the Commission shall determine whether a
hearing is necessary. The Commission shall enter
its order confirming or modifying the initial
long-term renewable resources procurement plan or
any subsequent revisions within 120 days after the
filing of the plan by the Illinois Power Agency.
(D) The Commission shall approve the initial
long-term renewable resources procurement plan and
any subsequent revisions, including expressly the
forecast used in the plan and taking into account
that funding will be limited to the amount of
revenues actually collected by the utilities, if
the Commission determines that the plan will
reasonably and prudently accomplish the

requirements of Section 1-56 and subsection (c) of
Section 1-75 of the Illinois Power Agency Act. The
Commission shall also approve the process for the
submission, review, and approval of the proposed
contracts to procure renewable energy credits or
implement the programs authorized by the
Commission pursuant to a long-term renewable
resources procurement plan approved under this
Section.
(iii) The Agency or third parties contracted by the
Agency shall implement all programs authorized by the
Commission in an approved long-term renewable
resources procurement plan without further review and
approval by the Commission. Third parties shall not
begin implementing any programs or receive any payment
under this Section until the Commission has approved
the contract or contracts under the process authorized
by the Commission in item (D) of subparagraph (ii) of
paragraph (5) of this subsection (b) and the third
party and the Agency or utility, as applicable, have
executed the contract. For those renewable energy
credits subject to procurement through a competitive
bid process under the plan or under the initial forward
procurements for wind and solar resources described in
subparagraph (G) of paragraph (1) of subsection (c) of
Section 1-75 of the Illinois Power Agency Act, the

Agency shall follow the procurement process specified
in the provisions relating to electricity procurement
in subsections (e) through (i) of this Section.
(iv) An electric utility shall recover its costs
associated with the procurement of renewable energy
credits under this Section through an automatic
adjustment clause tariff under subsection (k) of
Section 16-108 of this Act. A utility shall not be
required to advance any payment or pay any amounts
under this Section that exceed the actual amount of
revenues collected by the utility under paragraph (6)
of subsection (c) of Section 1-75 of the Illinois Power
Agency Act and subsection (k) of Section 16-108 of this
Act, and contracts executed under this Section shall
expressly incorporate this limitation.
(v) For the public interest, safety, and welfare,
the Agency and the Commission may adopt rules to carry
out the provisions of this Section on an emergency
basis immediately following the effective date of this
amendatory Act of the 99th General Assembly.
(vi) On or before July 1 of each year, the
Commission shall hold an informal hearing for the
purpose of receiving comments on the prior year's
procurement process and any recommendations for
change.
(c) The procurement process set forth in Section 1-75 of

the Illinois Power Agency Act and subsection (e) of this
Section shall be administered by a procurement administrator
and monitored by a procurement monitor.
(1) The procurement administrator shall:
(i) design the final procurement process in
accordance with Section 1-75 of the Illinois Power
Agency Act and subsection (e) of this Section following
Commission approval of the procurement plan;
(ii) develop benchmarks in accordance with
subsection (e)(3) to be used to evaluate bids; these
benchmarks shall be submitted to the Commission for
review and approval on a confidential basis prior to
the procurement event;
(iii) serve as the interface between the electric
utility and suppliers;
(iv) manage the bidder pre-qualification and
registration process;
(v) obtain the electric utilities' agreement to
the final form of all supply contracts and credit
collateral agreements;
(vi) administer the request for proposals process;
(vii) have the discretion to negotiate to
determine whether bidders are willing to lower the
price of bids that meet the benchmarks approved by the
Commission; any post-bid negotiations with bidders
shall be limited to price only and shall be completed

within 24 hours after opening the sealed bids and shall
be conducted in a fair and unbiased manner; in
conducting the negotiations, there shall be no
disclosure of any information derived from proposals
submitted by competing bidders; if information is
disclosed to any bidder, it shall be provided to all
competing bidders;
(viii) maintain confidentiality of supplier and
bidding information in a manner consistent with all
applicable laws, rules, regulations, and tariffs;
(ix) submit a confidential report to the
Commission recommending acceptance or rejection of
bids;
(x) notify the utility of contract counterparties
and contract specifics; and
(xi) administer related contingency procurement
events.
(2) The procurement monitor, who shall be retained by
the Commission, shall:
(i) monitor interactions among the procurement
administrator, suppliers, and utility;
(ii) monitor and report to the Commission on the
progress of the procurement process;
(iii) provide an independent confidential report
to the Commission regarding the results of the
procurement event;

(iv) assess compliance with the procurement plans
approved by the Commission for each utility that on
December 31, 2005 provided electric service to at 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.
(d) Except as provided in subsection (j), the planning
process shall be conducted as follows:
(1) Beginning in 2008, each Illinois utility procuring
power pursuant to this Section shall annually provide a
range of load forecasts to the Illinois Power Agency by
July 15 of each year, or such other date as may be required
by the Commission or Agency. The load forecasts shall cover
the 5-year procurement planning period for the next
procurement plan and shall include hourly data

representing a high-load, low-load, and expected-load
scenario for the load of those the eligible retail
customers included in the plan's electric supply service
requirements. The utility shall provide supporting data
and assumptions for each of the scenarios.
(2) Beginning in 2008, the Illinois Power Agency shall
prepare a procurement plan by August 15th of each year, or
such other date as may be required by the Commission. The
procurement plan shall identify the portfolio of
demand-response and power and energy products to be
procured. Cost-effective demand-response measures shall be
procured as set forth in item (iii) of subsection (b) of
this Section. Copies of the procurement plan shall be
posted and made publicly available on the Agency's and
Commission's websites, and copies shall also be provided to
each affected electric utility. An affected utility shall
have 30 days following the date of posting to provide
comment to the Agency on the procurement plan. Other
interested entities also may comment on the procurement
plan. All comments submitted to the Agency shall be
specific, supported by data or other detailed analyses,
and, if objecting to all or a portion of the procurement
plan, accompanied by specific alternative wording or
proposals. All comments shall be posted on the Agency's and
Commission's websites. During this 30-day comment period,
the Agency shall hold at least one public hearing within

each utility's service area for the purpose of receiving
public comment on the procurement plan. Within 14 days
following the end of the 30-day review period, the Agency
shall revise the procurement plan as necessary based on the
comments received and file the procurement plan with the
Commission and post the procurement plan on the websites.
(3) Within 5 days after the filing of the procurement
plan, any person objecting to the procurement plan shall
file an objection with the Commission. Within 10 days after
the filing, the Commission shall determine whether a
hearing is necessary. The Commission shall enter its order
confirming or modifying the procurement plan within 90 days
after the filing of the procurement plan by the Illinois
Power Agency.
(4) The Commission shall approve the procurement plan,
including expressly the forecast used in the procurement
plan, if the Commission determines that it will ensure
adequate, reliable, affordable, efficient, and
environmentally sustainable electric service at the lowest
total cost over time, taking into account any benefits of
price stability.
(e) The procurement process shall include each of the
following components:
(1) Solicitation, pre-qualification, and registration
of bidders. The procurement administrator shall
disseminate information to potential bidders to promote a

procurement event, notify potential bidders that the
procurement administrator may enter into a post-bid price
negotiation with bidders that meet the applicable
benchmarks, provide supply requirements, and otherwise
explain the competitive procurement process. In addition
to such other publication as the procurement administrator
determines is appropriate, this information shall be
posted on the Illinois Power Agency's and the Commission's
websites. The procurement administrator shall also
administer the prequalification process, including
evaluation of credit worthiness, compliance with
procurement rules, and agreement to the standard form
contract developed pursuant to paragraph (2) of this
subsection (e). The procurement administrator shall then
identify and register bidders to participate in the
procurement event.
(2) Standard contract forms and credit terms and
instruments. The procurement administrator, in
consultation with the utilities, the Commission, and other
interested parties and subject to Commission oversight,
shall develop and provide standard contract forms for the
supplier contracts that meet generally accepted industry
practices. Standard credit terms and instruments that meet
generally accepted industry practices shall be similarly
developed. The procurement administrator shall make
available to the Commission all written comments it

receives on the contract forms, credit terms, or
instruments. If the procurement administrator cannot reach
agreement with the applicable electric utility as to the
contract terms and conditions, the procurement
administrator must notify the Commission of any disputed
terms and the Commission shall resolve the dispute. The
terms of the contracts shall not be subject to negotiation
by winning bidders, and the bidders must agree to the terms
of the contract in advance so that winning bids are
selected solely on the basis of price.
(3) Establishment of a market-based price benchmark.
As part of the development of the procurement process, the
procurement administrator, in consultation with the
Commission staff, Agency staff, and the procurement
monitor, shall establish benchmarks for evaluating the
final prices in the contracts for each of the products that
will be procured through the procurement process. The
benchmarks shall be based on price data for similar
products for the same delivery period and same delivery
hub, or other delivery hubs after adjusting for that
difference. The price benchmarks may also be adjusted to
take into account differences between the information
reflected in the underlying data sources and the specific
products and procurement process being used to procure
power for the Illinois utilities. The benchmarks shall be
confidential but shall be provided to, and will be subject

to Commission review and approval, prior to a procurement
event.
(4) Request for proposals competitive procurement
process. The procurement administrator shall design and
issue a request for proposals to supply electricity in
accordance with each utility's procurement plan, as
approved by the Commission. The request for proposals shall
set forth a procedure for sealed, binding commitment
bidding with pay-as-bid settlement, and provision for
selection of bids on the basis of price.
(5) A plan for implementing contingencies in the event
of supplier default or failure of the procurement process
to fully meet the expected load requirement due to
insufficient supplier participation, Commission rejection
of results, or any other cause.
(i) Event of supplier default: In the event of
supplier default, the utility shall review the
contract of the defaulting supplier to determine if the
amount of supply is 200 megawatts or greater, and if
there are more than 60 days remaining of the contract
term. If both of these conditions are met, and the
default results in termination of the contract, the
utility shall immediately notify the Illinois Power
Agency that a request for proposals must be issued to
procure replacement power, and the procurement
administrator shall run an additional procurement

event. If the contracted supply of the defaulting
supplier is less than 200 megawatts or there are less
than 60 days remaining of the contract term, the
utility shall procure power and energy from the
applicable regional transmission organization market,
including ancillary services, capacity, and day-ahead
or real time energy, or both, for the duration of the
contract term to replace the contracted supply;
provided, however, that if a needed product is not
available through the regional transmission
organization market it shall be purchased from the
wholesale market.
(ii) Failure of the procurement process to fully
meet the expected load requirement: If the procurement
process fails to fully meet the expected load
requirement due to insufficient supplier participation
or due to a Commission rejection of the procurement
results, the procurement administrator, the
procurement monitor, and the Commission staff shall
meet within 10 days to analyze potential causes of low
supplier interest or causes for the Commission
decision. If changes are identified that would likely
result in increased supplier participation, or that
would address concerns causing the Commission to
reject the results of the prior procurement event, the
procurement administrator may implement those changes

and rerun the request for proposals process according
to a schedule determined by those parties and
consistent with Section 1-75 of the Illinois Power
Agency Act and this subsection. In any event, a new
request for proposals process shall be implemented by
the procurement administrator within 90 days after the
determination that the procurement process has failed
to fully meet the expected load requirement.
(iii) In all cases where there is insufficient
supply provided under contracts awarded through the
procurement process to fully meet the electric
utility's load requirement, the utility shall meet the
load requirement by procuring power and energy from the
applicable regional transmission organization market,
including ancillary services, capacity, and day-ahead
or real time energy, or both; provided, however, that
if a needed product is not available through the
regional transmission organization market it shall be
purchased from the wholesale market.
(6) The procurement process described in this
subsection is exempt from the requirements of the Illinois
Procurement Code, pursuant to Section 20-10 of that Code.
(f) Within 2 business days after opening the sealed bids,
the procurement administrator shall submit a confidential
report to the Commission. The report shall contain the results
of the bidding for each of the products along with the

procurement administrator's recommendation for the acceptance
and rejection of bids based on the price benchmark criteria and
other factors observed in the process. The procurement monitor
also shall submit a confidential report to the Commission
within 2 business days after opening the sealed bids. The
report shall contain the procurement monitor's assessment of
bidder behavior in the process as well as an assessment of the
procurement administrator's compliance with the procurement
process and rules. The Commission shall review the confidential
reports submitted by the procurement administrator and
procurement monitor, and shall accept or reject the
recommendations of the procurement administrator within 2
business days after receipt of the reports.
(g) Within 3 business days after the Commission decision
approving the results of a procurement event, the utility shall
enter into binding contractual arrangements with the winning
suppliers using the standard form contracts; except that the
utility shall not be required either directly or indirectly to
execute the contracts if a tariff that is consistent with
subsection (l) of this Section has not been approved and placed
into effect for that utility.
(h) The names of the successful bidders and the load
weighted average of the winning bid prices for each contract
type and for each contract term shall be made available to the
public at the time of Commission approval of a procurement
event. The Commission, the procurement monitor, the

procurement administrator, the Illinois Power Agency, and all
participants in the procurement process shall maintain the
confidentiality of all other supplier and bidding information
in a manner consistent with all applicable laws, rules,
regulations, and tariffs. Confidential information, including
the confidential reports submitted by the procurement
administrator and procurement monitor pursuant to subsection
(f) of this Section, shall not be made publicly available and
shall not be discoverable by any party in any proceeding,
absent a compelling demonstration of need, nor shall those
reports be admissible in any proceeding other than one for law
enforcement purposes.
(i) Within 2 business days after a Commission decision
approving the results of a procurement event or such other date
as may be required by the Commission from time to time, the
utility shall file for informational purposes with the
Commission its actual or estimated retail supply charges, as
applicable, by customer supply group reflecting the costs
associated with the procurement and computed in accordance with
the tariffs filed pursuant to subsection (l) of this Section
and approved by the Commission.
(j) Within 60 days following August 28, 2007 (the effective
date of Public Act 95-481) 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 procurement plan, which shall

conform in all material respects to the requirements of the
procurement plan set forth in subsection (b); provided,
however, that the Illinois Power Agency Act shall not apply to
the initial procurement plan prepared pursuant to this
subsection. The initial procurement plan shall identify the
portfolio of power and energy products to be procured and
delivered for the period June 2008 through May 2009, and shall
identify the proposed procurement administrator, who shall
have the same experience and expertise as is required of a
procurement administrator hired pursuant to Section 1-75 of the
Illinois Power Agency Act. Copies of the procurement plan shall
be posted and made publicly available on the Commission's
website. The initial procurement plan may include contracts for
renewable resources that extend beyond May 2009.
(i) Within 14 days following filing of the initial
procurement plan, any person may file a detailed objection
with the Commission contesting the procurement plan
submitted by the electric utility. All objections to the
electric utility's plan shall be specific, supported by
data or other detailed analyses. The electric utility may
file a response to any objections to its procurement plan
within 7 days after the date objections are due to be
filed. Within 7 days after the date the utility's response
is due, the Commission shall determine whether a hearing is
necessary. If it determines that a hearing is necessary, it
shall require the hearing to be completed and issue an

order on the procurement plan within 60 days after the
filing of the procurement plan by the electric utility.
(ii) The order shall approve or modify the procurement
plan, approve an independent procurement administrator,
and approve or modify the electric utility's tariffs that
are proposed with the initial procurement plan. The
Commission shall approve the procurement plan if the
Commission determines that it will ensure adequate,
reliable, affordable, efficient, and environmentally
sustainable electric service at the lowest total cost over
time, taking into account any benefits of price stability.
(k)(Blank). 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' 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
tariffs filed with the Commission.
(k-5) (Blank). 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
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
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
procurement plan its proposed tariffs through which its costs
of procuring power that are incurred pursuant to a
Commission-approved procurement plan and those other costs
identified in this subsection (l), will be recovered. The

tariffs shall include a formula rate or charge designed to pass
through both the costs incurred by the utility in procuring a
supply of electric power and energy for the applicable customer
classes with no mark-up or return on the price paid by the
utility for that supply, plus any just and reasonable costs
that the utility incurs in arranging and providing for the
supply of electric power and energy. The formula rate or charge
shall also contain provisions that ensure that its application
does not result in over or under recovery due to changes in
customer usage and demand patterns, and that provide for the
correction, on at least an annual basis, of any accounting
errors that may occur. A utility shall recover through the
tariff all reasonable costs incurred to implement or comply
with any procurement plan that is developed and put into effect
pursuant to Section 1-75 of the Illinois Power Agency Act and
this Section, including any fees assessed by the Illinois Power
Agency, costs associated with load balancing, and contingency
plan costs. The electric utility shall also recover its full
costs of procuring electric supply for which it contracted
before the effective date of this Section in conjunction with
the provision of full requirements service under fixed-price
bundled service tariffs subsequent to December 31, 2006. All
such costs shall be deemed to have been prudently incurred. The
pass-through tariffs that are filed and approved pursuant to
this Section shall not be subject to review under, or in any
way limited by, Section 16-111(i) of this Act. All of the costs

incurred by the electric utility associated with the purchase
of zero emission credits in accordance with subsection (d-5) of
Section 1-75 of the Illinois Power Agency Act and, beginning
June 1, 2017, all of the costs incurred by the electric utility
associated with the purchase of renewable energy resources in
accordance with Sections 1-56 and 1-75 of the Illinois Power
Agency Act, shall be recovered through the electric utility's
tariffed charges applicable to all of its retail customers, as
specified in subsection (k) of Section 16-108 of this Act, and
shall not be recovered through the electric utility's tariffed
charges for electric power and energy supply to its eligible
retail customers.
(m) The Commission has the authority to adopt rules to
carry out the provisions of this Section. For the public
interest, safety, and welfare, the Commission also has
authority to adopt rules to carry out the provisions of this
Section on an emergency basis immediately following August 28,
2007 (the effective date of Public Act 95-481) this amendatory
Act.
(n) Notwithstanding any other provision of this Act, any
affiliated electric utilities that submit a single procurement
plan covering their combined needs may procure for those
combined needs in conjunction with that plan, and may enter
jointly into power supply contracts, purchases, and other
procurement arrangements, and allocate capacity and energy and
cost responsibility therefor among themselves in proportion to

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

facilities included in the utility's procurement plan pursuant
to this subsection shall not be subject to review under or in
any way limited by the provisions of Section 16-111(i) of this
Act. Nothing in this Section is intended to prohibit a utility
from filing for a fuel adjustment clause as is otherwise
permitted under Section 9-220 of this Act.
(q) If the Illinois Power Agency filed with the Commission,
under Section 16-111.5 of this Act, its proposed procurement
plan for the period commencing June 1, 2017, and the Commission
has not yet entered its final order approving the plan on or
before the effective date of this amendatory Act of the 99th
General Assembly, then the Illinois Power Agency shall file a
notice of withdrawal with the Commission, after the effective
date of this amendatory Act of the 99th General Assembly, to
withdraw the proposed procurement of renewable energy
resources to be approved under the plan, other than the
procurement of renewable energy credits from distributed
renewable energy generation devices using funds previously
collected from electric utilities' retail customers that take
service pursuant to electric utilities' hourly pricing tariff
or tariffs and, for an electric utility that serves less than
100,000 retail customers in the State, other than the
procurement of renewable energy credits from distributed
renewable energy generation devices. Upon receipt of the
notice, the Commission shall enter an order that approves the
withdrawal of the proposed procurement of renewable energy

resources from the plan. The initially proposed procurement of
renewable energy resources shall not be approved or be the
subject of any further hearing, investigation, proceeding, or
order of any kind.
This amendatory Act of the 99th General Assembly preempts
and supersedes any order entered by the Commission that
approved the Illinois Power Agency's procurement plan for the
period commencing June 1, 2017, to the extent it is
inconsistent with the provisions of this amendatory Act of the
99th General Assembly. To the extent any previously entered
order approved the procurement of renewable energy resources,
the portion of that order approving the procurement shall be
void, other than the procurement of renewable energy credits
from distributed renewable energy generation devices using
funds previously collected from electric utilities' retail
customers that take service under electric utilities' hourly
pricing tariff or tariffs and, for an electric utility that
serves less than 100,000 retail customers in the State, other
than the procurement of renewable energy credits for
distributed renewable energy generation devices.
(Source: P.A. 97-325, eff. 8-12-11; 97-616, eff. 10-26-11;
97-813, eff. 7-13-12; revised 9-14-16.)
(220 ILCS 5/16-111.5B)
Sec. 16-111.5B. Provisions relating to energy efficiency
procurement.

(a) Procurement Beginning in 2012, procurement plans
prepared and filed pursuant to Section 16-111.5 of this Act
during the years 2012 through 2015 shall be subject to the
following additional requirements:
(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
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
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
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. The requirements set forth in paragraphs (1)
through (5) of this subsection (a) shall terminate after
the filing of the procurement plan in 2015, and no energy
efficiency shall be procured by the Agency thereafter.
Energy efficiency programs approved previously under this
Section shall terminate no later than December 31, 2017.
(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
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.
(c) The changes to this Section made by this amendatory Act
of the 99th General Assembly shall not interfere with existing
contracts executed under a Commission order entered under this
Section.
(d)(1) For those electric utilities subject to the
requirements of Section 8-103B of this Act, the contracts
governing the energy efficiency programs and measures approved

by the Commission in its order approving the procurement plan
for the period June 1, 2016 through May 31, 2017 may be
extended through December 31, 2017 so that the energy
efficiency programs subject to such contracts and approved in
such plan continue to be offered during the period June 1, 2017
through December 31, 2017. Each such utility is authorized to
increase, on a pro rata basis, the energy savings goals and
budgets approved under this Section to reflect the additional 7
months of implementation of the energy efficiency programs and
measures.
(2) If the Illinois Power Agency filed with the
Commission, under Section 16-111.5 of this Act, its
proposed procurement plan for the period commencing June 1,
2017, and the Commission has not yet entered its final
order approving such plan on or before the effective date
of this amendatory Act of the 99th General Assembly, then
the Illinois Power Agency shall file a notice of withdrawal
with the Commission to withdraw the proposed energy
efficiency programs to be approved under such plan. Upon
receipt of such notice, the Commission shall enter an order
that approves the withdrawal of all proposed energy
efficiency programs from the plan. The initially proposed
energy efficiency programs shall not be approved or be the
subject of any further hearing, investigation, proceeding,
or order of any kind.
(3) This amendatory Act of the 99th General Assembly

preempts and supersedes any order entered by the Commission
that approved the Illinois Power Agency's procurement plan
for the period commencing June 1, 2017, to the extent
inconsistent with the provisions of this amendatory Act of
the 99th General Assembly. To the extent any such
previously entered order approved energy efficiency
programs under this Section, the portion of such order
approving such programs shall be void, and the provisions
of paragraph (1) of this subsection (d) shall apply.
(Source: P.A. 97-616, eff. 10-26-11; 97-824, eff. 7-18-12.)
(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 or 8-103B 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.
(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
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 2 years after the effective date of
this amendatory Act of the 99th General Assembly, the 50
residential unit limitation described in this paragraph shall
no longer apply, and the utility shall replace the per site
loan limit of $150,000 with a loan limit that correlates to a
maximum monthly payment that does not exceed 50% of the
customer's average utility bill over the prior 12-month period.
Beginning no later than 2 years after the effective date of
this amendatory Act of the 99th General Assembly, 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 the Condominium Property Act. 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.
(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 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:
(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 or 8-103B of
this Act.
(1.5) Beginning no later than 2 years after the
effective date of this amendatory Act of the 99th General
Assembly, an eligible electric energy efficiency measure
(measure) shall be a product or service that qualifies
under subparagraph (B) or (C) of paragraph (1) of this
subsection (c) or for which one or more of the following is
true:
(A) a building energy assessment, performed by an
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; or
(B) 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. However, the costs of the
product or service described in this subparagraph (B)

shall not exceed 25% of the total cost of installing
the measure.
(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. 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
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 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. 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
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, and the
utility shall be entitled to recover all costs related to a

participant's nonpayment through the automatic adjustment
clause tariff established pursuant to Section 16-111.8 of
this Act. In addition, the electric 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 $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. Beginning after the effective date of this
amendatory Act of the 99th General Assembly, the total
maximum outstanding amount financed under the program in
this subsection and subsections (c-5) and (c-10) of this
Section shall increase by $5,000,000 per year until such
time as the total maximum outstanding amount financed
reaches $20,000,000. For purposes of this Section,
"maximum outstanding amount financed" means the sum of all
principal that has been loaned and not yet repaid.
(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.
(c-10) No later than 365 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 an informational filing to the Commission that describes
its plan for implementing the provisions of this amendatory Act
of the 99th General Assembly that were incorporated into this
Section. Such filing shall also include the criteria to be used
by the program for determining if measures to be financed are
eligible electric energy efficiency measures, as defined by
paragraph (1.5) of subsection (c) of this Section.
(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 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 or 8-103B 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
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.
(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
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) 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) Through May 31, 2017, the 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 this subsection (a).
(3) Through May 31, 2017, the 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) and 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) and 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.
(3.5) For the delivery year commencing June 1, 2017,
the quantity of renewable energy resources shall be at
least 13.0% of the uncovered amount of metered electricity
(megawatt-hours) delivered by the alternative retail
electric supplier to Illinois retail customers during the
delivery year, which uncovered amount shall equal 50% of
such metered electricity delivered by the alternative
retail electric supplier. For the delivery year commencing

June 1, 2018, the quantity of renewable energy resources
shall be at least 14.5% of the uncovered amount of metered
electricity (megawatt-hours) delivered by the alternative
retail electric supplier to Illinois retail customers
during the delivery year, which uncovered amount shall
equal 25% of such metered electricity delivered by the
alternative retail electric supplier. At least 32% of the
renewable energy resources procured by the alternative
retail electric supplier for its uncovered portion under
this paragraph (3.5) shall come from wind or photovoltaic
generation. The renewable energy resources procured under
this paragraph (3.5) shall not include any resources from a
facility whose costs were being recovered through rates
regulated by any state or states on or after January 1,
2017.
(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
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) Compliance obligations.
(1) Through May 31, 2017, 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 for the period prior to
June 1, 2017.
(2) For the delivery years beginning June 1, 2017 and

June 1, 2018, an alternative retail electric supplier need
not make any alternative compliance payment to meet any
portion of its compliance obligation, as set forth in
paragraph (3.5) of subsection (a) of this Section.
(3) An alternative retail electric supplier shall use
and any one or combination of the following means to cover
the remainder of the alternative retail electric
supplier's compliance obligation, as set forth in
paragraphs (3) and (3.5) of subsection (a) of this Section,
not covered by an alternative compliance payment made under
paragraphs (1) and (2) of this subsection (b) of this
Section:
(A) (1) Generating electricity using renewable
energy resources identified pursuant to item (4) of
subsection (a) of this Section.
(B) (2) Purchasing electricity generated using
renewable energy resources identified pursuant to item
(4) of subsection (a) of this Section through an energy
contract.
(C) (3) Purchasing renewable energy credits from
renewable energy resources identified pursuant to item
(4) of subsection (a) of this Section.
(D) (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
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
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
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 for which the
utility is procuring renewable energy resources in a given
delivery year, 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
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 for which the supplier has a compliance
obligation 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) or (3.5)
of subsection (a) of this Section and the actual amount of
metered electricity delivered by the alternative retail
electrical electric supplier to retail customers for which
the supplier has a compliance obligation within the service
territory during the compliance period.
(4) Through May 31, 2017, all 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.
(4.5) Beginning with the delivery year commencing June
1, 2017, all alternative compliance payments by
alternative retail electric suppliers shall be remitted to
the applicable electric utility. To facilitate this
remittance, each electric utility shall file a tariff with
the Commission no later than 30 days following the
effective date of this amendatory Act of the 99th General
Assembly, which the Commission shall approve, after notice
and hearing, no later than 45 days after its filing. The
Illinois Power Agency shall use such payments to increase
the amount of renewable energy resources otherwise to be
procured under subsection (c) of Section 1-75 of the
Illinois Power Agency Act.

(5) The Commission, in consultation with the Illinois
Power Agency, shall establish a process or proceeding to
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.
(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
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
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 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 after
May 31, 2019, 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, 2019, but were not paid as of
that date. The Commission shall continue to enforce the payment
of unpaid alternative compliance payments in accordance with

subsections (f) and (g) of this Section. All alternative
compliance payments made after May 31, 2016 shall be remitted
to the applicable electric utility and used to purchase
renewable energy credits, in accordance with Section 1-75 of
the Illinois Power Agency Act.
This subsection (i) is intended to accommodate the
transition to the procurement of renewable energy resources for
all retail customers in the amounts specified under subsection
(c) of Section 1-75 of the Illinois Power Agency Act and
Section 16-111.5 of this Act, including but not limited to the
transition to a single charge applicable to all retail
customers to recover the costs of these resources. Each
alternative retail electric supplier shall certify in its
annual reports filed pursuant to subsection (e) of this Section
after May 31, 2019, that its retail customers are not paying
the costs of alternative compliance payments or renewable
energy resources that the alternative retail electric supplier
is not required to remit or purchase under this Section. The
Commission shall have the authority to initiate an emergency
rulemaking to adopt rules regarding such certification.
(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 5/16-119A)
Sec. 16-119A. Functional separation.
(a) Within 90 days after the effective date of this

amendatory Act of 1997, the Commission shall open a rulemaking
proceeding to establish standards of conduct for every electric
utility described in subsection (b). To create efficient
competition between suppliers of generating services and
sellers of such services at retail and wholesale, the rules
shall allow all customers of a public utility that distributes
electric power and energy to purchase electric power and energy
from the supplier of their choice in accordance with the
provisions of Section 16-104. In addition, the rules shall
address relations between providers of any 2 services described
in subsection (b) to prevent undue discrimination and promote
efficient competition. Provided, however, that a proposed rule
shall not be published prior to May 15, 1999.
(b) The Commission shall also have the authority to
investigate the need for, and adopt rules requiring, functional
separation between the generation services and the delivery
services of those electric utilities whose principal service
area is in Illinois as necessary to meet the objective of
creating efficient competition between suppliers of generating
services and sellers of such services at retail and wholesale.
After January 1, 2003, the Commission shall also have the
authority to investigate the need for, and adopt rules
requiring, functional separation between an electric utility's
competitive and non-competitive services.
(b-5) If there is a change in ownership of a majority of
the voting capital stock of an electric utility or the

ownership or control of any entity that owns or controls a
majority of the voting capital stock of an electric utility,
the electric utility shall have the right to file with the
Commission a new plan. The newly filed plan shall supersede any
plan previously approved by the Commission pursuant to this
Section for that electric utility, subject to Commission
approval. This subsection only applies to the extent that the
Commission rules for the functional separation of delivery
services and generation services provide an electric utility
with the ability to select from 2 or more options to comply
with this Section. The electric utility may file its revised
plan with the Commission up to one calendar year after the
conclusion of the sale, purchase, or any other transfer of
ownership described in this subsection. In all other respects,
an electric utility must comply with the Commission rules in
effect under this Section. The Commission may promulgate rules
to implement this subsection. This subsection shall have no
legal effect after January 1, 2005.
(c) In establishing or considering the need for rules under
subsections (a) and (b), the Commission shall take into account
the effects on the cost and reliability of service and the
obligation of the utility to provide bundled service under this
Act. The Commission shall adopt rules that are a cost effective
means to ensure compliance with this Section.
(d) Nothing in this Section shall be construed as imposing
any requirements or obligations that are in conflict with

federal law.
(e) Notwithstanding anything to the contrary, an electric
utility may market and promote the services, rates and programs
authorized by Sections 16-107, and 16-108.6 of this Act.
(Source: P.A. 92-756, eff. 8-2-02.)
(220 ILCS 5/16-127)
Sec. 16-127. Environmental disclosure.
(a) Effective January 1, 2013, every electric utility and
alternative retail electric supplier shall provide the
following information, to the maximum extent practicable, to
its customers on a quarterly basis:
(i) the known sources of electricity supplied,
broken-out by percentages, of biomass power, coal-fired
power, hydro power, natural gas-fired power, nuclear
power, oil-fired power, solar power, wind power and other
resources, respectively;
(ii) a pie chart pie-chart that graphically depicts the
percentages of the sources of the electricity supplied as
set forth in subparagraph (i) of this subsection; and
(iii) a pie chart pie-chart that graphically depicts
the quantity of renewable energy resources procured
pursuant to Section 1-75 of the Illinois Power Agency Act
as a percentage of electricity supplied to serve eligible
retail customers as defined in Section 16-111.5(a) of this
Act; and .

(iv) after May, 31, 2017, a pie chart that graphically
depicts the quantity of zero emission credits from zero
emission facilities procured under Section 1-75 of the
Illinois Power Agency Act as a percentage of the actual
load of retail customers within its service area.
(b) In addition, every electric utility and alternative
retail electric supplier shall provide, to the maximum extent
practicable, to its customers on a quarterly basis, a
standardized chart in a format to be determined by the
Commission in a rule following notice and hearings which
provides the amounts of carbon dioxide, nitrogen oxides and
sulfur dioxide emissions and nuclear waste attributable to the
known sources of electricity supplied as set forth in
subparagraph (i) of subsection (a) of this Section.
(c) The electric utilities and alternative retail electric
suppliers may provide their customers with such other
information as they believe relevant to the information
required in subsections (a) and (b) of this Section. All of the
information required in subsections (a) and (b) of this Section
shall be made available by the electric utilities or
alternative retail electric suppliers either in an electronic
medium, such as on a website or by electronic mail, or through
the U.S. Postal Service.
(d) For the purposes of subsection (a) of this Section,
"biomass" means dedicated crops grown for energy production and
organic wastes.

(e) All of the information provided in subsections (a) and
(b) of this Section shall be presented to the Commission for
inclusion in its World Wide Web Site.
(Source: P.A. 97-1092, eff. 1-1-13.)
(220 ILCS 5/16-128A)
Sec. 16-128A. Certification of installers, maintainers, or
repairers.
(a) Within 18 months of the effective date of this
amendatory Act of the 97th General Assembly, the Commission
shall adopt rules, including emergency rules, establishing
certification requirements ensuring that entities installing
distributed generation facilities are in compliance with the
requirements of subsection (a) of Section 16-128 of this Act.
For purposes of this Section, the phrase "entities
installing distributed generation facilities" shall include,
but not be limited to, all entities that are exempt from the
definition of "alternative retail electric supplier" under
item (v) of Section 16-102 of this Act. For purposes of this
Section, the phrase "self-installer" means an individual who
(i) leases or purchases a cogeneration facility for his or her
own personal use and (ii) installs such cogeneration or
self-generation facility on his or her own premises without the
assistance of any other person.
(b) In addition to any authority granted to the Commission
under this Act, the Commission is also authorized to: (1)

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

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

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

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

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

installation and when installation is complete and provide any
other information required by the Commission's rules
established under subsection (d) of this Section. An electric
utility shall file a tariff or tariffs with the Commission
setting forth the documentation, as specified by Commission
rule, that a retail customer who owns, uses, operates, or
maintains an electric vehicle charging station must provide to
an electric utility.
For the purposes of this subsection, an electric vehicle
charging station shall constitute a distribution facility or
equipment as that term is used in subsection (a) of Section
16-128 of this Act. The phrase "self-installer" means an
individual who (i) leases or purchases an electric vehicle
charging station for his or her own personal use and (ii)
installs an electric vehicle charging station on his or her own
premises without the assistance of any other person.
(e) Fees and penalties collected under this Section shall
be deposited into the Public Utility Fund and used to fund the
Commission's compliance with the obligations imposed by this
Section.
(f) The rules established under subsection (d) of this
Section shall specify the initial dates for compliance with the
rules.
(g) Within 18 months of the effective date of this
amendatory Act of the 99th General Assembly, the Commission
shall adopt rules, including emergency rules, establishing a

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

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

new photovoltaic projects, distributed generation facilities,
or electric vehicle charging stations. This Section is a
limitation under subsection (h) of Section 6 of Article VII of
the Illinois Constitution on the exercise by home rule units of
powers and functions exclusively exercised by the State.
(Source: P.A. 97-616, eff. 10-26-11; 97-1128, eff. 8-28-12.)
(220 ILCS 5/16-128B new)
Sec. 16-128B. Qualified energy efficiency installers.
(a) Within 18 months after the effective date of this
amendatory Act of the 99th General Assembly, the Commission
shall adopt rules, including emergency rules, establishing a
process for entities installing energy efficiency measures to
certify compliance with the requirements of this Section.
The process shall include an option to complete the
certification electronically by completing forms on-line. An
entity installing energy efficiency measures shall be
permitted to complete the certification after the subject work
has been completed.
The Commission shall maintain on its website a list of
entities installing energy efficiency measures that have
successfully completed the certification process.
(b) In addition to any authority granted to the Commission
under this Act, the Commission may:
(1) determine which entities are subject to
certification under this Section;

(2) impose reasonable certification fees and
penalties;
(3) adopt disciplinary procedures;
(4) investigate any and all activities subject to this
Section, including violations thereof;
(5) adopt procedures to issue or renew, or to refuse to
issue or renew, a certification or to revoke, suspend,
place on probation, reprimand, or otherwise discipline a
certified entity under this Act or take other enforcement
action against an entity subject to this Section; and
(6) prescribe forms to be issued for the administration
and enforcement of this Section.
(c) An electric utility may not provide a retail customer
with a rebate or other energy efficiency incentive for a
measure that exceeds a minimal amount determined by the
Commission unless the customer provides the electric utility
with (1) a certification that the person installing the energy
efficiency measure was a self-installer; or (2) evidence that
the energy efficiency measure was installed by an entity
certified under this Section that is also in good standing with
the Commission.
(d) The Commission shall:
(1) require entities installing energy efficiency
measures to be certified to do business and to be bonded in
this State;
(2) ensure that entities installing energy efficiency

measures have the requisite knowledge, skill, training,
experience, and competence to perform functions in a safe
and reliable manner as required under subsection (a) of
Section 16-128 of this Act;
(3) ensure that entities installing energy efficiency
measures conform to applicable building and electrical
codes;
(4) ensure that all entities installing energy
efficiency measures meet recognized industry standards as
the Commission deems appropriate;
(5) include any additional requirements that the
Commission deems reasonable to ensure that entities
installing energy efficiency measures meet adequate
training, financial, and competency requirements;
(6) ensure that all entities installing energy
efficiency measures obtain certificates of insurance in
sufficient amounts and coverages that the Commission so
determines; and
(7) identify and determine the training or other
programs by which persons or entities may obtain the
requisite training, skill, or experience necessary to
achieve and maintain compliance with the requirements of
this Section.
(e) Fees and penalties collected under this Section shall
be deposited into the Public Utility Fund and used to fund the
Commission's compliance with the obligations imposed by this

Section.
(f) The rules adopted under this Section shall specify the
initial dates for compliance with the rules.
(g) For purposes of this Section, entities installing
energy efficiency measures shall endeavor to support the
diversity goals of this State by attracting, developing,
retaining, and providing opportunities to employees of all
backgrounds and by supporting female-owned, minority-owned,
veteran-owned, and small businesses.
Section 20. The Energy Assistance Act is amended by
changing Sections 13 and 18 as follows:
(305 ILCS 20/13)
(Section scheduled to be repealed on December 31, 2018)
Sec. 13. Supplemental Low-Income Energy Assistance Fund.
(a) The Supplemental Low-Income Energy Assistance Fund is
hereby created as a special fund in the State Treasury. The
Supplemental Low-Income Energy Assistance Fund is authorized
to receive moneys from voluntary donations from individuals,
foundations, corporations, and other sources, moneys received
pursuant to Section 17, and, by statutory deposit, the moneys
collected pursuant to this Section. The Fund is also authorized
to receive voluntary donations from individuals, foundations,
corporations, and other sources, as well as contributions made
in accordance with Section 507MM of the Illinois Income Tax

Act. Subject to appropriation, the Department shall use moneys
from the Supplemental Low-Income Energy Assistance Fund for
payments to electric or gas public utilities, municipal
electric or gas utilities, and electric cooperatives on behalf
of their customers who are participants in the program
authorized by Sections 4 and 18 of this Act, for the provision
of weatherization services and for administration of the
Supplemental Low-Income Energy Assistance Fund. The yearly
expenditures for weatherization may not exceed 10% of the
amount collected during the year pursuant to this Section. The
yearly administrative expenses of the Supplemental Low-Income
Energy Assistance Fund may not exceed 10% of the amount
collected during that year pursuant to this Section, except
when unspent funds from the Supplemental Low-Income Energy
Assistance Fund are reallocated from a previous year; any
unspent balance of the 10% administrative allowance may be
utilized for administrative expenses in the year they are
reallocated.
(b) Notwithstanding the provisions of Section 16-111 of the
Public Utilities Act but subject to subsection (k) of this
Section, each public utility, electric cooperative, as defined
in Section 3.4 of the Electric Supplier Act, and municipal
utility, as referenced in Section 3-105 of the Public Utilities
Act, that is engaged in the delivery of electricity or the
distribution of natural gas within the State of Illinois shall,
effective January 1, 1998, assess each of its customer accounts

a monthly Energy Assistance Charge for the Supplemental
Low-Income Energy Assistance Fund. The delivering public
utility, municipal electric or gas utility, or electric or gas
cooperative for a self-assessing purchaser remains subject to
the collection of the fee imposed by this Section. The monthly
charge shall be as follows:
(1) $0.48 per month on each account for residential
electric service;
(2) $0.48 per month on each account for residential gas
service;
(3) $4.80 per month on each account for non-residential
electric service which had less than 10 megawatts of peak
demand during the previous calendar year;
(4) $4.80 per month on each account for non-residential
gas service which had distributed to it less than 4,000,000
therms of gas during the previous calendar year;
(5) $360 per month on each account for non-residential
electric service which had 10 megawatts or greater of peak
demand during the previous calendar year; and
(6) $360 per month on each account for non-residential
gas service which had 4,000,000 or more therms of gas
distributed to it during the previous calendar year.
The incremental change to such charges imposed by this
amendatory Act of the 96th General Assembly shall not (i) be
used for any purpose other than to directly assist customers
and (ii) be applicable to utilities serving less than 100,000

customers in Illinois on January 1, 2009.
In addition, electric and gas utilities have committed, and
shall contribute, a one-time payment of $22 million to the
Fund, within 10 days after the effective date of the tariffs
established pursuant to Sections 16-111.8 and 19-145 of the
Public Utilities Act to be used for the Department's cost of
implementing the programs described in Section 18 of this
amendatory Act of the 96th General Assembly, the Arrearage
Reduction Program described in Section 18, and the programs
described in Section 8-105 of the Public Utilities Act. If a
utility elects not to file a rider within 90 days after the
effective date of this amendatory Act of the 96th General
Assembly, then the contribution from such utility shall be made
no later than February 1, 2010.
(c) For purposes of this Section:
(1) "residential electric service" means electric
utility service for household purposes delivered to a
dwelling of 2 or fewer units which is billed under a
residential rate, or electric utility service for
household purposes delivered to a dwelling unit or units
which is billed under a residential rate and is registered
by a separate meter for each dwelling unit;
(2) "residential gas service" means gas utility
service for household purposes distributed to a dwelling of
2 or fewer units which is billed under a residential rate,
or gas utility service for household purposes distributed

to a dwelling unit or units which is billed under a
residential rate and is registered by a separate meter for
each dwelling unit;
(3) "non-residential electric service" means electric
utility service which is not residential electric service;
and
(4) "non-residential gas service" means gas utility
service which is not residential gas service.
(d) Within 30 days after the effective date of this
amendatory Act of the 96th General Assembly, each public
utility engaged in the delivery of electricity or the
distribution of natural gas shall file with the Illinois
Commerce Commission tariffs incorporating the Energy
Assistance Charge in other charges stated in such tariffs,
which shall become effective no later than the beginning of the
first billing cycle following such filing.
(e) The Energy Assistance Charge assessed by electric and
gas public utilities shall be considered a charge for public
utility service.
(f) By the 20th day of the month following the month in
which the charges imposed by the Section were collected, each
public utility, municipal utility, and electric cooperative
shall remit to the Department of Revenue all moneys received as
payment of the Energy Assistance Charge on a return prescribed
and furnished by the Department of Revenue showing such
information as the Department of Revenue may reasonably

require; provided, however, that a utility offering an
Arrearage Reduction Program or Supplemental Arrearage
Reduction Program pursuant to Section 18 of this Act shall be
entitled to net those amounts necessary to fund and recover the
costs of such Programs Program as authorized by that Section
that is no more than the incremental change in such Energy
Assistance Charge authorized by Public Act 96-33 this
amendatory Act of the 96th General Assembly. If a customer
makes a partial payment, a public utility, municipal utility,
or electric cooperative may elect either: (i) to apply such
partial payments first to amounts owed to the utility or
cooperative for its services and then to payment for the Energy
Assistance Charge or (ii) to apply such partial payments on a
pro-rata basis between amounts owed to the utility or
cooperative for its services and to payment for the Energy
Assistance Charge.
(g) The Department of Revenue shall deposit into the
Supplemental Low-Income Energy Assistance Fund all moneys
remitted to it in accordance with subsection (f) of this
Section; provided, however, that the amounts remitted by each
utility shall be used to provide assistance to that utility's
customers. The utilities shall coordinate with the Department
to establish an equitable and practical methodology for
implementing this subsection (g) beginning with the 2010
program year.
(h) On or before December 31, 2002, the Department shall

prepare a report for the General Assembly on the expenditure of
funds appropriated from the Low-Income Energy Assistance Block
Grant Fund for the program authorized under Section 4 of this
Act.
(i) The Department of Revenue may establish such rules as
it deems necessary to implement this Section.
(j) The Department of Commerce and Economic Opportunity may
establish such rules as it deems necessary to implement this
Section.
(k) The charges imposed by this Section shall only apply to
customers of municipal electric or gas utilities and electric
or gas cooperatives if the municipal electric or gas utility or
electric or gas cooperative makes an affirmative decision to
impose the charge. If a municipal electric or gas utility or an
electric cooperative makes an affirmative decision to impose
the charge provided by this Section, the municipal electric or
gas utility or electric cooperative shall inform the Department
of Revenue in writing of such decision when it begins to impose
the charge. If a municipal electric or gas utility or electric
or gas cooperative does not assess this charge, the Department
may not use funds from the Supplemental Low-Income Energy
Assistance Fund to provide benefits to its customers under the
program authorized by Section 4 of this Act.
In its use of federal funds under this Act, the Department
may not cause a disproportionate share of those federal funds
to benefit customers of systems which do not assess the charge

provided by this Section.
This Section is repealed on January 1, 2025 effective
December 31, 2018 unless renewed by action of the General
Assembly. The General Assembly shall consider the results of
the evaluations described in Section 8 in its deliberations.
(Source: P.A. 98-429, eff. 8-16-13; 99-457, eff. 1-1-16.)
(305 ILCS 20/18)
Sec. 18. Financial assistance; payment plans.
(a) The Percentage of Income Payment Plan (PIPP or PIP
Plan) is hereby created as a mandatory bill payment assistance
program for low-income residential customers of utilities
serving more than 100,000 retail customers as of January 1,
2009. The PIP Plan will:
(1) bring participants' gas and electric bills into the
range of affordability;
(2) provide incentives for participants to make timely
payments;
(3) encourage participants to reduce usage and
participate in conservation and energy efficiency measures
that reduce the customer's bill and payment requirements;
and
(4) identify participants whose homes are most in need
of weatherization.
(b) For purposes of this Section:
(1) "LIHEAP" means the energy assistance program

established under the Illinois Energy Assistance Act and
the Low-Income Home Energy Assistance Act of 1981.
(2) "Plan participant" is an eligible participant who
is also eligible for the PIPP and who will receive either a
percentage of income payment credit under the PIPP criteria
set forth in this Act or a benefit pursuant to Section 4 of
this Act. Plan participants are a subset of eligible
participants.
(3) "Pre-program arrears" means the amount a plan
participant owes for gas or electric service at the time
the participant is determined to be eligible for the PIPP
or the program set forth in Section 4 of this Act.
(4) "Eligible participant" means any person who has
applied for, been accepted and is receiving residential
service from a gas or electric utility and who is also
eligible for LIHEAP.
(c) The PIP Plan shall be administered as follows:
(1) The Department shall coordinate with Local
Administrative Agencies (LAAs), to determine eligibility
for the Illinois Low Income Home Energy Assistance Program
(LIHEAP) pursuant to the Energy Assistance Act, provided
that eligible income shall be no more than 150% of the
poverty level. Applicants will be screened to determine
whether the applicant's projected payments for electric
service or natural gas service over a 12-month period
exceed the criteria established in this Section. To

maintain the financial integrity of the program, the
Department may limit eligibility to households with income
below 125% of the poverty level.
(2) The Department shall establish the percentage of
income formula to determine the amount of a monthly credit,
not to exceed $150 per month per household, not to exceed
$1,800 annually, that will be applied to PIP Plan
participants' utility bills based on the portion of the
bill that is the responsibility of the participant provided
that the percentage shall be no more than a total of 6% of
the relevant income for gas and electric utility bills
combined, but in any event no less than $10 per month,
unless the household does not pay directly for heat, in
which case its payment shall be 2.4% of income but in any
event no less than $5 per month. The Department may
establish a minimum credit amount based on the cost of
administering the program and may deny credits to otherwise
eligible participants if the cost of administering the
credit exceeds the actual amount of any monthly credit to a
participant. If the participant takes both gas and electric
service, 66.67% of the credit shall be allocated to the
entity that provides the participant's primary energy
supply for heating. Each participant shall enter into a
levelized payment plan for, as applicable, gas and electric
service and such plans shall be implemented by the utility
so that a participant's usage and required payments are

reviewed and adjusted regularly, but no more frequently
than quarterly. Nothing in this Section is intended to
prohibit a customer, who is otherwise eligible for LIHEAP,
from participating in the program described in Section 4 of
this Act. Eligible participants who receive such a benefit
shall be considered plan participants and shall be eligible
to participate in the Arrearage Reduction Program
described in item (5) of this subsection (c).
(3) The Department shall remit, through the LAAs, to
the utility or participating alternative supplier that
portion of the plan participant's bill that is not the
responsibility of the participant. In the event that the
Department fails to timely remit payment to the utility,
the utility shall be entitled to recover all costs related
to such nonpayment through the automatic adjustment clause
tariffs established pursuant to Section 16-111.8 and
Section 19-145 of the Public Utilities Act. For purposes of
this item (3) of this subsection (c), payment is due on the
date specified on the participant's bill. The Department,
the Department of Revenue and LAAs shall adopt processes
that provide for the timely payment required by this item
(3) of this subsection (c).
(4) A plan participant is responsible for all actual
charges for utility service in excess of the PIPP credit.
Pre-program arrears that are included in the Arrearage
Reduction Program described in item (5) of this subsection

(c) shall not be included in the calculation of the
levelized payment plan. Emergency or crisis assistance
payments shall not affect the amount of any PIPP credit to
which a participant is entitled.
(5) Electric and gas utilities subject to this Section
shall implement an Arrearage Reduction Program (ARP) for
plan participants as follows: for each month that a plan
participant timely pays his or her utility bill, the
utility shall apply a credit to a portion of the
participant's pre-program arrears, if any, equal to
one-twelfth of such arrearage provided that the total
amount of arrearage credits shall equal no more than $1,000
annually for each participant for gas and no more than
$1,000 annually for each participant for electricity. In
the third year of the PIPP, the Department, in consultation
with the Policy Advisory Council established pursuant to
Section 5 of this Act, shall determine by rule an
appropriate per participant total cap on such amounts, if
any. Those plan participants participating in the ARP shall
not be subject to the imposition of any additional late
payment fees on pre-program arrears covered by the ARP. In
all other respects, the utility shall bill and collect the
monthly bill of a plan participant pursuant to the same
rules, regulations, programs and policies as applicable to
residential customers generally. Participation in the
Arrearage Reduction Program shall be limited to the maximum

amount of funds available as set forth in subsection (f) of
Section 13 of this Act. In the event any donated funds
under Section 13 of this Act are specifically designated
for the purpose of funding the ARP, the Department shall
remit such amounts to the utilities upon verification that
such funds are needed to fund the ARP. Nothing in this
Section shall preclude a utility from continuing to
implement, and apply credits under, an ARP in the event
that the PIPP or LIHEAP is suspended due to lack of funding
such that the plan participant does not receive a benefit
under either the PIPP or LIHEAP.
(5.5) In addition to the ARP described in paragraph (5)
of this subsection (c), utilities may also implement a
Supplemental Arrearage Reduction Program (SARP) for
eligible participants who are not able to become plan
participants due to PIPP timing or funding constraints. If
a utility elects to implement a SARP, it shall be
administered as follows: for each month that a SARP
participant timely pays his or her utility bill, the
utility shall apply a credit to a portion of the
participant's pre-program arrears, if any, equal to
one-twelfth of such arrearage, provided that the utility
may limit the total amount of arrearage credits to no more
than $1,000 annually for each participant for gas and no
more than $1,000 annually for each participant for
electricity. SARP participants shall not be subject to the

imposition of any additional late payment fees on
pre-program arrears covered by the SARP. In all other
respects, the utility shall bill and collect the monthly
bill of a SARP participant under the same rules,
regulations, programs, and policies as applicable to
residential customers generally. Participation in the SARP
shall be limited to the maximum amount of funds available
as set forth in subsection (f) of Section 13 of this Act.
In the event any donated funds under Section 13 of this Act
are specifically designated for the purpose of funding the
SARP, the Department shall remit such amounts to the
utilities upon verification that such funds are needed to
fund the SARP.
(6) The Department may terminate a plan participant's
eligibility for the PIP Plan upon notification by the
utility that the participant's monthly utility payment is
more than 45 days past due.
(7) The Department, in consultation with the Policy
Advisory Council, may adjust the number of PIP Plan
participants annually, if necessary, to match the
availability of funds from LIHEAP. Any plan participant who
qualifies for a PIPP credit under a utility's PIPP shall be
entitled to participate in and receive a credit under such
utility's ARP for so long as such utility has ARP funds
available, regardless of whether the customer's
participation under another utility's PIPP or ARP has been

curtailed or limited because of a lack of funds.
(8) The Department shall fully implement the PIPP at
the earliest possible date it is able to effectively
administer the PIPP. Within 90 days of the effective date
of this amendatory Act of the 96th General Assembly, the
Department shall, in consultation with utility companies,
participating alternative suppliers, LAAs and the Illinois
Commerce Commission (Commission), issue a detailed
implementation plan which shall include detailed testing
protocols and analysis of the capacity for implementation
by the LAAs and utilities. Such consultation process also
shall address how to implement the PIPP in the most
cost-effective and timely manner, and shall identify
opportunities for relying on the expertise of utilities,
LAAs and the Commission. Following the implementation of
the testing protocols, the Department shall issue a written
report on the feasibility of full or gradual
implementation. The PIPP shall be fully implemented by
September 1, 2011, but may be phased in prior to that date.
(9) As part of the screening process established under
item (1) of this subsection (c), the Department and LAAs
shall assess whether any energy efficiency or demand
response measures are available to the plan participant at
no cost, and if so, the participant shall enroll in any
such program for which he or she is eligible. The LAAs
shall assist the participant in the applicable enrollment

or application process.
(10) Each alternative retail electric and gas supplier
serving residential customers shall elect whether to
participate in the PIPP or ARP described in this Section.
Any such supplier electing to participate in the PIPP shall
provide to the Department such information as the
Department may require, including, without limitation,
information sufficient for the Department to determine the
proportionate allocation of credits between the
alternative supplier and the utility. If a utility in whose
service territory an alternative supplier serves customers
contributes money to the ARP fund which is not recovered
from ratepayers, then an alternative supplier which
participates in ARP in that utility's service territory
shall also contribute to the ARP fund in an amount that is
commensurate with the number of alternative supplier
customers who elect to participate in the program.
(d) The Department, in consultation with the Policy
Advisory Council, shall develop and implement a program to
educate customers about the PIP Plan and about their rights and
responsibilities under the percentage of income component. The
Department, in consultation with the Policy Advisory Council,
shall establish a process that LAAs shall use to contact
customers in jeopardy of losing eligibility due to late
payments. The Department shall ensure that LAAs are adequately
funded to perform all necessary educational tasks.

(e) The PIPP shall be administered in a manner which
ensures that credits to plan participants will not be counted
as income or as a resource in other means-tested assistance
programs for low-income households or otherwise result in the
loss of federal or State assistance dollars for low-income
households.
(f) In order to ensure that implementation costs are
minimized, the Department and utilities shall work together to
identify cost-effective ways to transfer information
electronically and to employ available protocols that will
minimize their respective administrative costs as follows:
(1) The Commission may require utilities to provide
such information on customer usage and billing and payment
information as required by the Department to implement the
PIP Plan and to provide written notices and communications
to plan participants.
(2) Each utility and participating alternative
supplier shall file annual reports with the Department and
the Commission that cumulatively summarize and update
program information as required by the Commission's rules.
The reports shall track implementation costs and contain
such information as is necessary to evaluate the success of
the PIPP.
(3) The Department and the Commission shall have the
authority to promulgate rules and regulations necessary to
execute and administer the provisions of this Section.

(g) Each utility shall be entitled to recover reasonable
administrative and operational costs incurred to comply with
this Section from the Supplemental Low Income Energy Assistance
Fund. The utility may net such costs against monies it would
otherwise remit to the Funds, and each utility shall include in
the annual report required under subsection (f) of this Section
an accounting for the funds collected.
(Source: P.A. 96-33, eff. 7-10-09.)
Section 85. The Public Utilities Act is amended by changing
Section 2-202 as follows:
(220 ILCS 5/2-202) (from Ch. 111 2/3, par. 2-202)
Sec. 2-202. Policy; Public Utility Fund; tax.
(a) It is declared to be the public policy of this State
that in order to maintain and foster the effective regulation
of public utilities under this Act in the interests of the
People of the State of Illinois and the public utilities as
well, the public utilities subject to regulation under this Act
and which enjoy the privilege of operating as public utilities
in this State, shall bear the expense of administering this Act
by means of a tax on such privilege measured by the annual
gross revenue of such public utilities in the manner provided
in this Section. For purposes of this Section, "expense of
administering this Act" includes any costs incident to studies,
whether made by the Commission or under contract entered into

by the Commission, concerning environmental pollution problems
caused or contributed to by public utilities and the means for
eliminating or abating those problems. Such proceeds shall be
deposited in the Public Utility Fund in the State treasury.
(b) All of the ordinary and contingent expenses of the
Commission incident to the administration of this Act shall be
paid out of the Public Utility Fund except the compensation of
the members of the Commission which shall be paid from the
General Revenue Fund. Notwithstanding other provisions of this
Act to the contrary, the ordinary and contingent expenses of
the Commission incident to the administration of the Illinois
Commercial Transportation Law may be paid from appropriations
from the Public Utility Fund through the end of fiscal year
1986.
(c) A tax is imposed upon each public utility subject to
the provisions of this Act equal to .08% of its gross revenue
for each calendar year commencing with the calendar year
beginning January 1, 1982, except that the Commission may, by
rule, establish a different rate no greater than 0.1%. For
purposes of this Section, "gross revenue" shall not include
revenue from the production, transmission, distribution, sale,
delivery, or furnishing of electricity. "Gross revenue" shall
not include amounts paid by telecommunications retailers under
the Telecommunications Infrastructure Maintenance Fee Act.
(d) Annual gross revenue returns shall be filed in
accordance with paragraph (1) or (2) of this subsection (d).

(1) Except as provided in paragraph (2) of this
subsection (d), on or before January 10 of each year each
public utility subject to the provisions of this Act shall
file with the Commission an estimated annual gross revenue
return containing an estimate of the amount of its gross
revenue for the calendar year commencing January 1 of said
year and a statement of the amount of tax due for said
calendar year on the basis of that estimate. Public
utilities may also file revised returns containing updated
estimates and updated amounts of tax due during the
calendar year. These revised returns, if filed, shall form
the basis for quarterly payments due during the remainder
of the calendar year. In addition, on or before March 31 of
each year, each public utility shall file an amended return
showing the actual amount of gross revenues shown by the
company's books and records as of December 31 of the
previous year. Forms and instructions for such estimated,
revised, and amended returns shall be devised and supplied
by the Commission.
(2) Beginning with returns due after January 1, 2002,
the requirements of paragraph (1) of this subsection (d)
shall not apply to any public utility in any calendar year
for which the total tax the public utility owes under this
Section is less than $10,000. For such public utilities
with respect to such years, the public utility shall file
with the Commission, on or before March 31 of the following

year, an annual gross revenue return for the year and a
statement of the amount of tax due for that year on the
basis of such a return. Forms and instructions for such
returns and corrected returns shall be devised and supplied
by the Commission.
(e) All returns submitted to the Commission by a public
utility as provided in this subsection (e) or subsection (d) of
this Section shall contain or be verified by a written
declaration by an appropriate officer of the public utility
that the return is made under the penalties of perjury. The
Commission may audit each such return submitted and may, under
the provisions of Section 5-101 of this Act, take such measures
as are necessary to ascertain the correctness of the returns
submitted. The Commission has the power to direct the filing of
a corrected return by any utility which has filed an incorrect
return and to direct the filing of a return by any utility
which has failed to submit a return. A taxpayer's signing a
fraudulent return under this Section is perjury, as defined in
Section 32-2 of the Criminal Code of 2012.
(f) (1) For all public utilities subject to paragraph (1)
of subsection (d), at least one quarter of the annual amount of
tax due under subsection (c) shall be paid to the Commission on
or before the tenth day of January, April, July, and October of
the calendar year subject to tax. In the event that an
adjustment in the amount of tax due should be necessary as a
result of the filing of an amended or corrected return under

subsection (d) or subsection (e) of this Section, the amount of
any deficiency shall be paid by the public utility together
with the amended or corrected return and the amount of any
excess shall, after the filing of a claim for credit by the
public utility, be returned to the public utility in the form
of a credit memorandum in the amount of such excess or be
refunded to the public utility in accordance with the
provisions of subsection (k) of this Section. However, if such
deficiency or excess is less than $1, then the public utility
need not pay the deficiency and may not claim a credit.
(2) Any public utility subject to paragraph (2) of
subsection (d) shall pay the amount of tax due under subsection
(c) on or before March 31 next following the end of the
calendar year subject to tax. In the event that an adjustment
in the amount of tax due should be necessary as a result of the
filing of a corrected return under subsection (e), the amount
of any deficiency shall be paid by the public utility at the
time the corrected return is filed. Any excess tax payment by
the public utility shall be returned to it after the filing of
a claim for credit, in the form of a credit memorandum in the
amount of the excess. However, if such deficiency or excess is
less than $1, the public utility need not pay the deficiency
and may not claim a credit.
(g) Each installment or required payment of the tax imposed
by subsection (c) becomes delinquent at midnight of the date
that it is due. Failure to make a payment as required by this

Section shall result in the imposition of a late payment
penalty, an underestimation penalty, or both, as provided by
this subsection. The late payment penalty shall be the greater
of:
(1) $25 for each month or portion of a month that the
installment or required payment is unpaid or
(2) an amount equal to the difference between what
should have been paid on the due date, based upon the most
recently filed estimated, annual, or amended return, and
what was actually paid, times 1%, for each month or portion
of a month that the installment or required payment goes
unpaid. This penalty may be assessed as soon as the
installment or required payment becomes delinquent.
The underestimation penalty shall apply to those public
utilities subject to paragraph (1) of subsection (d) and shall
be calculated after the filing of the amended return. It shall
be imposed if the amount actually paid on any of the dates
specified in subsection (f) is not equal to at least one-fourth
of the amount actually due for the year, and shall equal the
greater of:
(1) $25 for each month or portion of a month that the
amount due is unpaid or
(2) an amount equal to the difference between what
should have been paid, based on the amended return, and
what was actually paid as of the date specified in
subsection (f), times a percentage equal to 1/12 of the sum

of 10% and the percentage most recently established by the
Commission for interest to be paid on customer deposits
under 83 Ill. Adm. Code 280.70(e)(1), for each month or
portion of a month that the amount due goes unpaid, except
that no underestimation penalty shall be assessed if the
amount actually paid on or before each of the dates
specified in subsection (f) was based on an estimate of
gross revenues at least equal to the actual gross revenues
for the previous year. The Commission may enforce the
collection of any delinquent installment or payment, or
portion thereof by legal action or in any other manner by
which the collection of debts due the State of Illinois may
be enforced under the laws of this State. The executive
director or his designee may excuse the payment of an
assessed penalty or a portion of an assessed penalty if he
determines that enforced collection of the penalty as
assessed would be unjust.
(h) All sums collected by the Commission under the
provisions of this Section shall be paid promptly after the
receipt of the same, accompanied by a detailed statement
thereof, into the Public Utility Fund in the State treasury.
(i) During the month of October of each odd-numbered year
the Commission shall:
(1) determine the amount of all moneys deposited in the
Public Utility Fund during the preceding fiscal biennium
plus the balance, if any, in that fund at the beginning of

that biennium;
(2) determine the sum total of the following items: (A)
all moneys expended or obligated against appropriations
made from the Public Utility Fund during the preceding
fiscal biennium, plus (B) the sum of the credit memoranda
then outstanding against the Public Utility Fund, if any;
and
(3) determine the amount, if any, by which the sum
determined as provided in item (1) exceeds the amount
determined as provided in item (2).
If the amount determined as provided in item (3) of this
subsection exceeds 50% of the previous fiscal year's
appropriation level, the Commission shall then compute the
proportionate amount, if any, which (x) the tax paid hereunder
by each utility during the preceding biennium, and (y) the
amount paid into the Public Utility Fund during the preceding
biennium by the Department of Revenue pursuant to Sections 2-9
and 2-11 of the Electricity Excise Tax Law, bears to the
difference between the amount determined as provided in item
(3) of this subsection (i) and 50% of the previous fiscal
year's appropriation level. The Commission shall cause the
proportionate amount determined with respect to payments made
under the Electricity Excise Tax Law to be transferred into the
General Revenue Fund in the State Treasury, and notify each
public utility that it may file during the 3 month period after
the date of notification a claim for credit for the

proportionate amount determined with respect to payments made
hereunder by the public utility. If the proportionate amount is
less than $10, no notification will be sent by the Commission,
and no right to a claim exists as to that amount. Upon the
filing of a claim for credit within the period provided, the
Commission shall issue a credit memorandum in such amount to
such public utility. Any claim for credit filed after the
period provided for in this Section is void.
(i-5) During the month of October of each year the
Commission shall:
(1) determine the amount of all moneys expected to be
deposited in the Public Utility Fund during the current
fiscal year, plus the balance, if any, in that fund at the
beginning of that year;
(2) determine the total of all moneys expected to be
expended or obligated against appropriations made from the
Public Utility Fund during the current fiscal year; and
(3) determine the amount, if any, by which the amount
determined in paragraph (2) exceeds the amount determined
as provided in paragraph (1).
If the amount determined as provided in paragraph (3) of
this subsection (i-5) results in a deficit, the Commission may
assess electric utilities and gas utilities for the difference
between the amount appropriated for the ordinary and contingent
expenses of the Commission and the amount derived under
paragraph (1) of this subsection (i-5). Such proceeds shall be

deposited in the Public Utility Fund in the State treasury. The
Commission shall apportion that difference among those public
utilities on the basis of each utility's share of the total
intrastate gross revenues of the utilities subject to this
subsection (i-5). Payments required under this subsection
(i-5) shall be made in the time and manner directed by the
Commission. The Commission shall permit utilities to recover
Illinois Commerce Commission assessments effective pursuant to
this subsection through an automatic adjustment mechanism that
is incorporated into an existing tariff that recovers costs
associated with this Section, or through a supplemental
customer charge.
Within 6 months after the first time assessments are made
under this subsection (i-5), the Commission shall initiate a
docketed proceeding in which it shall consider, in addition to
assessments from electric and gas utilities subject to this
subsection, the raising of assessments from, or the payment of
fees by, water and sewer utilities, entities possessing
certificates of service authority as alternative retail
electric suppliers under Section 16-115 of this Act, entities
possessing certificates of service authority as alternative
gas suppliers under Section 19-110 of this Act, and
telecommunications carriers providing local exchange
telecommunications service or interexchange telecommunications
service under sections 13-204 or 13-205 of this Act. The
amounts so determined shall be based on the costs to the agency

of the exercise of its regulatory and supervisory functions
with regard to the different industries and service providers
subject to the proceeding. No less often than every 3 years
after the end of a proceeding under this subsection (i-5), the
Commission shall initiate another proceeding for that purpose.
The Commission may use this apportionment method until the
docketed proceeding in which the Commission considers the
raising of assessments from other entities subject to its
jurisdiction under this Act has concluded. No credit memoranda
shall be issued pursuant to subsection (i) if the amount
determined as provided in paragraph (3) of this subsection
(i-5) results in a deficit.
(j) Credit memoranda issued pursuant to subsection (f) and
credit memoranda issued after notification and filing pursuant
to subsection (i) may be applied for the 2 year period from the
date of issuance, against the payment of any amount due during
that period under the tax imposed by subsection (c), or,
subject to reasonable rule of the Commission including
requirement of notification, may be assigned to any other
public utility subject to regulation under this Act. Any
application of credit memoranda after the period provided for
in this Section is void.
(k) The chairman or executive director may make refund of
fees, taxes or other charges whenever he shall determine that
the person or public utility will not be liable for payment of
such fees, taxes or charges during the next 24 months and he

determines that the issuance of a credit memorandum would be
unjust.
(Source: P.A. 97-1150, eff. 1-25-13.)