Public Act 099-0906
 
SB2814 EnrolledLRB099 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