Bill Amendment: IL SB2080 | 2019-2020 | 101st General Assembly

NOTE: For additional amemendments please see the Bill Drafting List

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Bill Title: UTILITIES-INFRASTRUCTURE

Status: 2021-01-13 - Session Sine Die [SB2080 Detail]

Download: Illinois-2019-SB2080-Senate_Amendment_004.html

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Sen. Michael E. Hastings

Filed: 4/5/2019

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AMENDMENT TO SENATE BILL 2080
AMENDMENT NO. ______. Amend Senate Bill 2080 by replacing
everything after the enacting clause with the following:
"Article 1.
Section 1-5. The Public Utilities Act is amended by
changing Section 16-108.5 as follows:
(220 ILCS 5/16-108.5)
Sec. 16-108.5. Infrastructure investment and
modernization; regulatory reform.
(a) (Blank).
(b) For purposes of this Section, "participating utility"
means an electric utility or a combination utility serving more
than 1,000,000 customers in Illinois that voluntarily elects
and commits to undertake (i) the infrastructure investment
program consisting of the commitments and obligations

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described in this subsection (b) and (ii) the customer
assistance program consisting of the commitments and
obligations described in subsection (b-10) of this Section,
notwithstanding any other provisions of this Act and without
obtaining any approvals from the Commission or any other agency
other than as set forth in this Section, regardless of whether
any such approval would otherwise be required. "Combination
utility" means a utility that, as of January 1, 2011, provided
electric service to at least one million retail customers in
Illinois and gas service to at least 500,000 retail customers
in Illinois. A participating utility shall recover the
expenditures made under the infrastructure investment program
through the ratemaking process, including, but not limited to,
the performance-based formula rate and process set forth in
this Section.
During the infrastructure investment program's peak
program year, a participating utility other than a combination
utility shall create 2,000 full-time equivalent jobs in
Illinois, and a participating utility that is a combination
utility shall create 450 full-time equivalent jobs in Illinois
related to the provision of electric service. These jobs shall
include direct jobs, contractor positions, and induced jobs,
but shall not include any portion of a job commitment, not
specifically contingent on an amendatory Act of the 97th
General Assembly becoming law, between a participating utility
and a labor union that existed on December 30, 2011 (the

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effective date of Public Act 97-646) and that has not yet been
fulfilled. A portion of the full-time equivalent jobs created
by each participating utility shall include incremental
personnel hired subsequent to December 30, 2011 (the effective
date of Public Act 97-646). For purposes of this Section, "peak
program year" means the consecutive 12-month period with the
highest number of full-time equivalent jobs that occurs between
the beginning of investment year 2 and the end of investment
year 4.
A participating utility shall meet one of the following
commitments, as applicable:
(1) Beginning no later than 180 days after a
participating utility other than a combination utility
files a performance-based formula rate tariff pursuant to
subsection (c) of this Section, or, beginning no later than
January 1, 2012 if such utility files such
performance-based formula rate tariff within 14 days of
October 26, 2011 (the effective date of Public Act 97-616),
the participating utility shall, except as provided in
subsection (b-5):
(A) over a 5-year period, invest an estimated
$1,300,000,000 in electric system upgrades,
modernization projects, and training facilities,
including, but not limited to:
(i) distribution infrastructure improvements
totaling an estimated $1,000,000,000, including

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

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

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performance-based formula rate tariff within 14 days of
October 26, 2011 (the effective date of Public Act 97-616),
the participating utility shall, except as provided in
subsection (b-5):
(A) over a 10-year period, invest an estimated
$265,000,000 in electric system upgrades,
modernization projects, and training facilities,
including, but not limited to:
(i) distribution infrastructure improvements
totaling an estimated $245,000,000, which may
include bulk supply substations, transformers,
reconductoring, and rebuilding overhead
distribution and sub-transmission lines,
underground residential distribution cable
injection and replacement and mainline cable
system refurbishment and replacement projects;
(ii) training facility construction or upgrade
projects totaling an estimated $1,000,000; any
such new facility must be designed for the purpose
of obtaining, and the owner of the facility shall
apply for, certification under the United States
Green Building Council's Leadership in Energy
Efficiency Design Green Building Rating System;
and
(iii) wood pole inspection, treatment, and
replacement programs; and

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(B) over a 10-year period, invest an estimated
$360,000,000 to upgrade and modernize its transmission
and distribution infrastructure and in Smart Grid
electric system upgrades, including, but not limited
to:
(i) additional smart meters;
(ii) distribution automation;
(iii) associated cyber secure data
communication network; and
(iv) substation micro-processor relay
upgrades.
For purposes of this Section, "Smart Grid electric system
upgrades" shall have the meaning set forth in subsection (a) of
Section 16-108.6 of this Act.
The investments in the infrastructure investment program
described in this subsection (b) shall be incremental to the
participating utility's annual capital investment program, as
defined by, for purposes of this subsection (b), the
participating utility's average capital spend for calendar
years 2008, 2009, and 2010 as reported in the applicable
Federal Energy Regulatory Commission (FERC) Form 1; provided
that where one or more utilities have merged, the average
capital spend shall be determined using the aggregate of the
merged utilities' capital spend reported in FERC Form 1 for the
years 2008, 2009, and 2010. A participating utility may add
reasonable construction ramp-up and ramp-down time to the

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

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investment program, plan, or schedule. Further, no later than
45 days following the last day of the first, second, and third
quarters of each year of the plan, a participating utility
shall submit to the Commission a verified quarterly report for
the prior quarter that includes (i) the total number of
full-time equivalent jobs created during the prior quarter,
(ii) the total number of employees as of the last day of the
prior quarter, (iii) the total number of full-time equivalent
hours in each job classification or job title, (iv) the total
number of incremental employees and contractors in support of
the investments undertaken pursuant to this subsection (b) for
the prior quarter, and (v) any other information that the
Commission may require by rule.
With respect to the participating utility's peak job
commitment, if, after considering the utility's corrective
action plan and compliance thereunder, the Commission enters an
order finding, after notice and hearing, that a participating
utility did not satisfy its peak job commitment described in
this subsection (b) for reasons that are reasonably within its
control, then the Commission shall also determine, after
consideration of the evidence, including, but not limited to,
evidence submitted by the Department of Commerce and Economic
Opportunity and the utility, the deficiency in the number of
full-time equivalent jobs during the peak program year due to
such failure. The Commission shall notify the Department of any
proceeding that is initiated pursuant to this paragraph. For

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

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

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Commission requesting that it be permitted to satisfy its
commitments by spending less than the estimated amounts
specified in subsection (b) of this Section. The Commission
shall, after notice and hearing, enter its order approving, or
approving as modified, or denying each such petition within 150
days after the filing of the petition.
In no event, absent General Assembly approval, shall the
capital investment costs incurred by a participating utility
other than a combination utility in satisfying its
infrastructure investment program commitments described in
subsection (b) of this Section exceed $3,000,000,000 or, for a
participating utility that is a combination utility,
$720,000,000. If the participating utility's updated cost
estimates for satisfying its infrastructure investment program
commitments described in subsection (b) of this Section exceed
the limitation imposed by this subsection (b-5), then it shall
submit a report to the Commission that identifies the increased
costs and explains the reason or reasons for the increased
costs no later than the year in which the utility estimates it
will exceed the limitation. The Commission shall review the
report and shall, within 90 days after the participating
utility files the report, report to the General Assembly its
findings regarding the participating utility's report. If the
General Assembly does not amend the limitation imposed by this
subsection (b-5), then the utility may modify its plan so as
not to exceed the limitation imposed by this subsection (b-5)

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and may propose corresponding changes to the metrics
established pursuant to subparagraphs (5) through (8) of
subsection (f) of this Section, and the Commission may modify
the metrics and incremental savings goals established pursuant
to subsection (f) of this Section accordingly.
(b-10) All participating utilities shall make
contributions for an energy low-income and support program in
accordance with this subsection. Beginning no later than 180
days after a participating utility files a performance-based
formula rate tariff pursuant to subsection (c) of this Section,
or beginning no later than January 1, 2012 if such utility
files such performance-based formula rate tariff within 14 days
of December 30, 2011 (the effective date of Public Act 97-646),
and without obtaining any approvals from the Commission or any
other agency other than as set forth in this Section,
regardless of whether any such approval would otherwise be
required, a participating utility other than a combination
utility shall pay $10,000,000 per year for 5 years and a
participating utility that is a combination utility shall pay
$1,000,000 per year for 10 years to the energy low-income and
support program, which is intended to fund customer assistance
programs with the primary purpose being avoidance of imminent
disconnection. Such programs may include:
(1) a residential hardship program that may partner
with community-based organizations, including senior
citizen organizations, and provides grants to low-income

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

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customer assistance programs, including, but not limited to,
those that are administered by the utility.
Programs that use funds that are provided by a
participating utility to reduce utility bills may be
implemented through tariffs that are filed with and reviewed by
the Commission. If a utility elects to file tariffs with the
Commission to implement all or a portion of the programs, those
tariffs shall, regardless of the date actually filed, be deemed
accepted and approved, and shall become effective on December
30, 2011 (the effective date of Public Act 97-646). The
participating utilities whose customers benefit from the funds
that are disbursed as contemplated in this Section shall file
annual reports documenting the disbursement of those funds with
the Commission. The Commission has the authority to audit
disbursement of the funds to ensure they were disbursed
consistently with this Section.
If the Commission finds that a participating utility is no
longer eligible to update the performance-based formula rate
tariff pursuant to subsection (d) of this Section, or the
performance-based formula rate is otherwise terminated, then
the participating utility's voluntary commitments and
obligations under this subsection (b-10) shall immediately
terminate.
(b-15) Beginning in 2022, without obtaining any approvals
from the Commission or any other agency, regardless of whether
any such approval would otherwise be required, each

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participating utility shall pay the following amounts, as
applicable, to the energy low-income and support program, which
is intended to fund customer assistance programs with the
primary purpose being avoidance of imminent disconnection and
reconnecting customers who have been disconnected for
nonpayment. A participating utility other than a combination
utility shall pay $10,000,000 per year for 10 years, and a
participating utility that is a combination utility shall pay
$1,000,000 per year for 10 years. Such programs may include
those described in paragraphs (1) through (5) of subsection
(b-10) of this Section.
The payments made by a participating utility pursuant to
this subsection (b-15) shall not be a recoverable expense. A
participating utility may elect to fund either new or existing
customer assistance programs, including, but not limited to,
those that are administered by the utility.
Programs that use funds that are provided by a
participating utility to reduce utility bills may be
implemented through tariffs that are filed with and reviewed by
the Commission. If a utility elects to file tariffs with the
Commission to implement all or a portion of the programs, those
tariffs shall, regardless of the date actually filed, be deemed
accepted and approved, and shall become effective on the first
business day after they are filed. The participating utilities
whose customers benefit from the funds that are disbursed as
contemplated in this subsection (b-15) shall file annual

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reports documenting the disbursement of those funds with the
Commission. The Commission has the authority to audit
disbursement of the funds to ensure they were disbursed
consistently with this subsection (b-15).
If the Commission finds that a participating utility is no
longer eligible to update the performance-based formula rate
tariff pursuant to subsection (d) of this Section, or the
performance-based formula rate is otherwise terminated, then
the participating utility's voluntary commitments and
obligations under this subsection (b-15) shall immediately
terminate.
(c) A participating utility may elect to recover its
delivery services costs through a performance-based formula
rate approved by the Commission, which shall specify the cost
components that form the basis of the rate charged to customers
with sufficient specificity to operate in a standardized manner
and be updated annually with transparent information that
reflects the utility's actual costs to be recovered during the
applicable rate year, which is the period beginning with the
first billing day of January and extending through the last
billing day of the following December. In the event the utility
recovers a portion of its costs through automatic adjustment
clause tariffs on October 26, 2011 (the effective date of
Public Act 97-616), the utility may elect to continue to
recover these costs through such tariffs, but then these costs
shall not be recovered through the performance-based formula

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rate. In the event the participating utility, prior to December
30, 2011 (the effective date of Public Act 97-646), filed
electric delivery services tariffs with the Commission
pursuant to Section 9-201 of this Act that are related to the
recovery of its electric delivery services costs that are still
pending on December 30, 2011 (the effective date of Public Act
97-646), the participating utility shall, at the time it files
its performance-based formula rate tariff with the Commission,
also file a notice of withdrawal with the Commission to
withdraw the electric delivery services tariffs previously
filed pursuant to Section 9-201 of this Act. Upon receipt of
such notice, the Commission shall dismiss with prejudice any
docket that had been initiated to investigate the electric
delivery services tariffs filed pursuant to Section 9-201 of
this Act, and such tariffs and the record related thereto shall
not be the subject of any further hearing, investigation, or
proceeding of any kind related to rates for electric delivery
services.
The performance-based formula rate shall be implemented
through a tariff filed with the Commission consistent with the
provisions of this subsection (c) that shall be applicable to
all delivery services customers. The Commission shall initiate
and conduct an investigation of the tariff in a manner
consistent with the provisions of this subsection (c) and the
provisions of Article IX of this Act to the extent they do not
conflict with this subsection (c). Except in the case where the

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Commission finds, after notice and hearing, that a
participating utility is not satisfying its investment amount
commitments under subsection (b) of this Section, the
performance-based formula rate shall remain in effect at the
discretion of the utility. The performance-based formula rate
approved by the Commission shall do the following:
(1) Provide for the recovery of the utility's actual
costs of delivery services that are prudently incurred and
reasonable in amount consistent with Commission practice
and law. The sole fact that a cost differs from that
incurred in a prior calendar year or that an investment is
different from that made in a prior calendar year shall not
imply the imprudence or unreasonableness of that cost or
investment.
(2) Reflect the utility's actual year-end capital
structure for the applicable calendar year, excluding
goodwill, subject to a determination of prudence and
reasonableness consistent with Commission practice and
law. To enable the financing of the incremental capital
expenditures, including regulatory assets, for electric
utilities that serve less than 3,000,000 retail customers
but more than 500,000 retail customers in the State, a
participating electric utility's actual year-end capital
structure that includes a common equity ratio, excluding
goodwill, of up to and including 50% of the total capital
structure shall be deemed reasonable and used to set rates.

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(3) Include a cost of equity, which shall be calculated
as the sum of the following:
(A) the average for the applicable calendar year of
the monthly average yields of 30-year U.S. Treasury
bonds published by the Board of Governors of the
Federal Reserve System in its weekly H.15 Statistical
Release or successor publication; and
(B) 580 basis points.
At such time as the Board of Governors of the Federal
Reserve System ceases to include the monthly average yields
of 30-year U.S. Treasury bonds in its weekly H.15
Statistical Release or successor publication, the monthly
average yields of the U.S. Treasury bonds then having the
longest duration published by the Board of Governors in its
weekly H.15 Statistical Release or successor publication
shall instead be used for purposes of this paragraph (3).
(4) Permit and set forth protocols, subject to a
determination of prudence and reasonableness consistent
with Commission practice and law, for the following:
(A) recovery of incentive compensation expense
that is based on the achievement of operational
metrics, including metrics related to budget controls,
outage duration and frequency, safety, customer
service, efficiency and productivity, and
environmental compliance. Incentive compensation
expense that is based on net income or an affiliate's

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earnings per share shall not be recoverable under the
performance-based formula rate;
(B) recovery of pension and other post-employment
benefits expense, provided that such costs are
supported by an actuarial study;
(C) recovery of severance costs, provided that if
the amount is over $3,700,000 for a participating
utility that is a combination utility or $10,000,000
for a participating utility that serves more than 3
million retail customers, then the full amount shall be
amortized consistent with subparagraph (F) of this
paragraph (4);
(D) investment return at a rate equal to the
utility's weighted average cost of long-term debt, on
the pension assets as, and in the amount, reported in
Account 186 (or in such other Account or Accounts as
such asset may subsequently be recorded) of the
utility's most recently filed FERC Form 1, net of
deferred tax benefits;
(E) recovery of the expenses related to the
Commission proceeding under this subsection (c) to
approve this performance-based formula rate and
initial rates or to subsequent proceedings related to
the formula, provided that the recovery shall be
amortized over a 3-year period; recovery of expenses
related to the annual Commission proceedings under

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subsection (d) of this Section to review the inputs to
the performance-based formula rate shall be expensed
and recovered through the performance-based formula
rate;
(F) amortization over a 5-year period of the full
amount of each charge or credit that exceeds $3,700,000
for a participating utility that is a combination
utility or $10,000,000 for a participating utility
that serves more than 3 million retail customers in the
applicable calendar year and that relates to a
workforce reduction program's severance costs, changes
in accounting rules, changes in law, compliance with
any Commission-initiated audit, or a single storm or
other similar expense, provided that any unamortized
balance shall be reflected in rate base. For purposes
of this subparagraph (F), changes in law includes any
enactment, repeal, or amendment in a law, ordinance,
rule, regulation, interpretation, permit, license,
consent, or order, including those relating to taxes,
accounting, or to environmental matters, or in the
interpretation or application thereof by any
governmental authority occurring after October 26,
2011 (the effective date of Public Act 97-616);
(G) recovery of existing regulatory assets over
the periods previously authorized by the Commission;
(H) historical weather normalized billing

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

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

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

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

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

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

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

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

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Within 45 days after the utility files its annual update of
cost inputs to the performance-based formula rate, the
Commission shall have the authority, either upon complaint or
its own initiative, but with reasonable notice, to enter upon a
hearing concerning the prudence and reasonableness of the costs
incurred by the utility to be recovered during the applicable
rate year that are reflected in the inputs to the
performance-based formula rate derived from the utility's FERC
Form 1. During the course of the hearing, each objection shall
be stated with particularity and evidence provided in support
thereof, after which the utility shall have the opportunity to
rebut the evidence. Discovery shall be allowed consistent with
the Commission's Rules of Practice, which Rules shall be
enforced by the Commission or the assigned administrative law
judge. The Commission shall apply the same evidentiary
standards, including, but not limited to, those concerning the
prudence and reasonableness of the costs incurred by the
utility, in the hearing as it would apply in a hearing to
review a filing for a general increase in rates under Article
IX of this Act. The Commission shall not, however, have the
authority in a proceeding under this subsection (d) to consider
or order any changes to the structure or protocols of the
performance-based formula rate approved pursuant to subsection
(c) of this Section. In a proceeding under this subsection (d),
the Commission shall enter its order no later than the earlier
of 240 days after the utility's filing of its annual update of

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cost inputs to the performance-based formula rate or December
31. The Commission's determinations of the prudence and
reasonableness of the costs incurred for the applicable
calendar year shall be final upon entry of the Commission's
order and shall not be subject to reopening, reexamination, or
collateral attack in any other Commission proceeding, case,
docket, order, rule or regulation, provided, however, that
nothing in this subsection (d) shall prohibit a party from
petitioning the Commission to rehear or appeal to the courts
the order pursuant to the provisions of this Act.
In the event the Commission does not, either upon complaint
or its own initiative, enter upon a hearing within 45 days
after the utility files the annual update of cost inputs to its
performance-based formula rate, then the costs incurred for the
applicable calendar year shall be deemed prudent and
reasonable, and the filed charges shall not be subject to
reopening, reexamination, or collateral attack in any other
proceeding, case, docket, order, rule, or regulation.
A participating utility's first filing of the updated cost
inputs, and any Commission investigation of such inputs
pursuant to this subsection (d) shall proceed notwithstanding
the fact that the Commission's investigation under subsection
(c) of this Section is still pending and notwithstanding any
other law, order, rule, or Commission practice to the contrary.
(e) Nothing in subsections (c) or (d) of this Section shall
prohibit the Commission from investigating, or a participating

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utility from filing, revenue-neutral tariff changes related to
rate design of a performance-based formula rate that has been
placed into effect for the utility. Following approval of a
participating utility's performance-based formula rate tariff
pursuant to subsection (c) of this Section, the utility shall
make a filing with the Commission within one year after the
effective date of the performance-based formula rate tariff
that proposes changes to the tariff to incorporate the findings
of any final rate design orders of the Commission applicable to
the participating utility and entered subsequent to the
Commission's approval of the tariff. The Commission shall,
after notice and hearing, enter its order approving, or
approving with modification, the proposed changes to the
performance-based formula rate tariff within 240 days after the
utility's filing. Following such approval, the utility shall
make a filing with the Commission during each subsequent 3-year
period that either proposes revenue-neutral tariff changes or
re-files the existing tariffs without change, which shall
present the Commission with an opportunity to suspend the
tariffs and consider revenue-neutral tariff changes related to
rate design.
(f) Within 30 days after the filing of a tariff pursuant to
subsection (c) of this Section, each participating utility
shall develop and file with the Commission multi-year metrics
designed to achieve, ratably (i.e., in equal segments) over a
10-year period, improvement over baseline performance values

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as follows:
(1) Twenty percent improvement in the System Average
Interruption Frequency Index, using a baseline of the
average of the data from 2001 through 2010.
(2) Fifteen percent improvement in the system Customer
Average Interruption Duration Index, using a baseline of
the average of the data from 2001 through 2010.
(3) For a participating utility other than a
combination utility, 20% improvement in the System Average
Interruption Frequency Index for its Southern Region,
using a baseline of the average of the data from 2001
through 2010. For purposes of this paragraph (3), Southern
Region shall have the meaning set forth in the
participating utility's most recent report filed pursuant
to Section 16-125 of this Act.
(3.5) For a participating utility other than a
combination utility, 20% improvement in the System Average
Interruption Frequency Index for its Northeastern Region,
using a baseline of the average of the data from 2001
through 2010. For purposes of this paragraph (3.5),
Northeastern Region shall have the meaning set forth in the
participating utility's most recent report filed pursuant
to Section 16-125 of this Act.
(4) Seventy-five percent improvement in the total
number of customers who exceed the service reliability
targets as set forth in subparagraphs (A) through (C) of

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paragraph (4) of subsection (b) of 83 Ill. Admin. Code Part
411.140 as of May 1, 2011, using 2010 as the baseline year.
(5) Reduction in issuance of estimated electric bills:
90% improvement for a participating utility other than a
combination utility, and 56% improvement for a
participating utility that is a combination utility, using
a baseline of the average number of estimated bills for the
years 2008 through 2010.
(6) Consumption on inactive meters: 90% improvement
for a participating utility other than a combination
utility, and 56% improvement for a participating utility
that is a combination utility, using a baseline of the
average unbilled kilowatthours for the years 2009 and 2010.
(7) Unaccounted for energy: 50% improvement for a
participating utility other than a combination utility
using a baseline of the non-technical line loss unaccounted
for energy kilowatthours for the year 2009.
(8) Uncollectible expense: reduce uncollectible
expense by at least $30,000,000 for a participating utility
other than a combination utility and by at least $3,500,000
for a participating utility that is a combination utility,
using a baseline of the average uncollectible expense for
the years 2008 through 2010.
(9) Opportunities for minority-owned and female-owned
business enterprises: design a performance metric
regarding the creation of opportunities for minority-owned

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and female-owned business enterprises consistent with
State and federal law using a base performance value of the
percentage of the participating utility's capital
expenditures that were paid to minority-owned and
female-owned business enterprises in 2010.
The definitions set forth in 83 Ill. Admin. Code Part
411.20 as of May 1, 2011 shall be used for purposes of
calculating performance under paragraphs (1) through (3.5) of
this subsection (f), provided, however, that the participating
utility may exclude up to 9 extreme weather event days from
such calculation for each year, and provided further that the
participating utility shall exclude 9 extreme weather event
days when calculating each year of the baseline period to the
extent that there are 9 such days in a given year of the
baseline period. For purposes of this Section, an extreme
weather event day is a 24-hour calendar day (beginning at 12:00
a.m. and ending at 11:59 p.m.) during which any weather event
(e.g., storm, tornado) caused interruptions for 10,000 or more
of the participating utility's customers for 3 hours or more.
If there are more than 9 extreme weather event days in a year,
then the utility may choose no more than 9 extreme weather
event days to exclude, provided that the same extreme weather
event days are excluded from each of the calculations performed
under paragraphs (1) through (3.5) of this subsection (f).
The metrics shall include incremental performance goals
for each year of the 10-year period, which shall be designed to

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demonstrate that the utility is on track to achieve the
performance goal in each category at the end of the 10-year
period. The utility shall elect when the 10-year period shall
commence for the metrics set forth in subparagraphs (1) through
(4) and (9) of this subsection (f), provided that it begins no
later than 14 months following the date on which the utility
begins investing pursuant to subsection (b) of this Section,
and when the 10-year period shall commence for the metrics set
forth in subparagraphs (5) through (8) of this subsection (f),
provided that it begins no later than 14 months following the
date on which the Commission enters its order approving the
utility's Advanced Metering Infrastructure Deployment Plan
pursuant to subsection (c) of Section 16-108.6 of this Act.
The metrics and performance goals set forth in
subparagraphs (5) through (8) of this subsection (f) are based
on the assumptions that the participating utility may fully
implement the technology described in subsection (b) of this
Section, including utilizing the full functionality of such
technology and that there is no requirement for personal
on-site notification. If the utility is unable to meet the
metrics and performance goals set forth in subparagraphs (5)
through (8) of this subsection (f) for such reasons, and the
Commission so finds after notice and hearing, then the utility
shall be excused from compliance, but only to the limited
extent achievement of the affected metrics and performance
goals was hindered by the less than full implementation.

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(f-5) The financial penalties applicable to the metrics
described in subparagraphs (1) through (8) of subsection (f) of
this Section, as applicable, shall be applied through an
adjustment to the participating utility's return on equity of
no more than a total of 30 basis points in each of the first 3
years, of no more than a total of 34 basis points in each of the
3 years thereafter, and of no more than a total of 38 basis
points in each of the 4 years thereafter, as follows:
(1) With respect to each of the incremental annual
performance goals established pursuant to paragraph (1) of
subsection (f) of this Section,
(A) for each year that a participating utility
other than a combination utility does not achieve the
annual goal, the participating utility's return on
equity shall be reduced as follows: during years 1
through 3, by 5 basis points; during years 4 through 6,
by 6 basis points; and during years 7 through 10, by 7
basis points; and
(B) for each year that a participating utility that
is a combination utility does not achieve the annual
goal, the participating utility's return on equity
shall be reduced as follows: during years 1 through 3,
by 10 basis points; during years 4 through 6, by 12
basis points; and during years 7 through 10, by 14
basis points.
(2) With respect to each of the incremental annual

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

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of subsection (f) of this Section, for each year that the
participating utility does not achieve at least 95% of each
such goal, the participating utility's return on equity
shall be reduced by 5 basis points for each such unachieved
goal.
(6) With respect to each of the incremental annual
performance goals established pursuant to paragraphs (6),
(7), and (8) of subsection (f) of this Section, as
applicable, which together measure non-operational
customer savings and benefits relating to the
implementation of the Advanced Metering Infrastructure
Deployment Plan, as defined in Section 16-108.6 of this
Act, the performance under each such goal shall be
calculated in terms of the percentage of the goal achieved.
The percentage of goal achieved for each of the goals shall
be aggregated, and an average percentage value calculated,
for each year of the 10-year period. If the utility does
not achieve an average percentage value in a given year of
at least 95%, the participating utility's return on equity
shall be reduced by 5 basis points.
The financial penalties shall be applied as described in
this subsection (f-5) for the 12-month period in which the
deficiency occurred through a separate tariff mechanism, which
shall be filed by the utility together with its metrics. In the
event the formula rate tariff established pursuant to
subsection (c) of this Section terminates, the utility's

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obligations under subsection (f) of this Section and this
subsection (f-5) shall also terminate, provided, however, that
the tariff mechanism established pursuant to subsection (f) of
this Section and this subsection (f-5) shall remain in effect
until any penalties due and owing at the time of such
termination are applied.
The Commission shall, after notice and hearing, enter an
order within 120 days after the metrics are filed approving, or
approving with modification, a participating utility's tariff
or mechanism to satisfy the metrics set forth in subsection (f)
of this Section. On June 1 of each subsequent year, each
participating utility shall file a report with the Commission
that includes, among other things, a description of how the
participating utility performed under each metric and an
identification of any extraordinary events that adversely
impacted the utility's performance. Whenever a participating
utility does not satisfy the metrics required pursuant to
subsection (f) of this Section, the Commission shall, after
notice and hearing, enter an order approving financial
penalties in accordance with this subsection (f-5). The
Commission-approved financial penalties shall be applied
beginning with the next rate year. Nothing in this Section
shall authorize the Commission to reduce or otherwise obviate
the imposition of financial penalties for failing to achieve
one or more of the metrics established pursuant to subparagraph
(1) through (4) of subsection (f) of this Section.

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(f-10) Each applicable 10-year period previously approved
by the Commission pursuant to subsections (f) and (f-5) of this
Section shall be extended for an additional 10-year period that
commences immediately after the termination of the previous
10-year period. The performance goals and financial penalties
applicable to each year of an additional 10-year period shall
be fixed at, and the same as, the performance goals applicable
to year 10 that were previously approved by the Commission
pursuant to subsections (f) and (f-5) of this Section and the
financial penalties applicable to year 10 set forth in
subsection (f-5) of this Section. The total amount of financial
penalties applicable in any given year shall not exceed 38
basis points. During the additional 10-year period, each
participating utility shall continue to file the annual reports
required by subsection (f-5) of this Section, and the
requirements of subsection (f-5) related to Commission
approval of any financial penalties shall continue to apply.
Each participating utility's tariff or tariffs approved under
subsection (f-5) shall remain in effect during the additional
10-year period, and each participating utility is authorized to
submit a compliance filing after the effective date of this
amendatory Act of the 101st General Assembly conforming its
tariff or tariffs to the provisions of this subsection (f-10).
In the event the formula rate tariff established pursuant to
subsection (c) of this Section terminates, the utility's
obligations under this subsection (f-10) shall also terminate;

10100SB2080sam004 - 43 - LRB101 11122 RJF 59369 a
provided, however, that the tariff mechanism established
pursuant to subsections (f) and (f-5) of this Section, and
extended under this subsection (f-10), shall remain in effect
until any penalties due and owing at the time of such
termination are applied.
The metrics and performance goals set forth in
subparagraphs (5) through (8) of subsection (f) of this
Section, and extended under this subsection (f-10), are based
on the assumptions that the participating utility may fully
implement the technology described in subsection (b) of this
Section, including utilizing the full functionality of such
technology and that there is no requirement for personal
on-site notification. If the utility is unable to meet the
metrics and performance goals applicable to subparagraphs (5)
through (8) of subsection (f) of this Section for such reasons
during the additional 10-year period, as those metrics and
goals are set by this subsection (f-10), and the Commission so
finds after notice and hearing, then the utility shall be
excused from compliance, but only to the limited extent
achievement of the affected metrics and performance goals was
hindered by the less than full implementation.
(g) On or before July 31, 2014, each participating utility
shall file a report with the Commission that sets forth the
average annual increase in the average amount paid per
kilowatthour for residential eligible retail customers,
exclusive of the effects of energy efficiency programs,

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comparing the 12-month period ending May 31, 2012; the 12-month
period ending May 31, 2013; and the 12-month period ending May
31, 2014. For a participating utility that is a combination
utility with more than one rate zone, the weighted average
aggregate increase shall be provided. The report shall be filed
together with a statement from an independent auditor attesting
to the accuracy of the report. The cost of the independent
auditor shall be borne by the participating utility and shall
not be a recoverable expense. "The average amount paid per
kilowatthour" shall be based on the participating utility's
tariffed rates actually in effect and shall not be calculated
using any hypothetical rate or adjustments to actual charges
(other than as specified for energy efficiency) as an input.
In the event that the average annual increase exceeds 2.5%
as calculated pursuant to this subsection (g), then Sections
16-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act, other
than this subsection, shall be inoperative as they relate to
the utility and its service area as of the date of the report
due to be submitted pursuant to this subsection and the utility
shall no longer be eligible to annually update the
performance-based formula rate tariff pursuant to subsection
(d) of this Section. In such event, the then current rates
shall remain in effect until such time as new rates are set
pursuant to Article IX of this Act, subject to retroactive
adjustment, with interest, to reconcile rates charged with
actual costs, and the participating utility's voluntary

10100SB2080sam004 - 45 - LRB101 11122 RJF 59369 a
commitments and obligations under subsection (b) of this
Section shall immediately terminate, except for the utility's
obligation to pay an amount already owed to the fund for
training grants pursuant to a Commission order issued under
subsection (b) of this Section.
In the event that the average annual increase is 2.5% or
less as calculated pursuant to this subsection (g), then the
performance-based formula rate shall remain in effect as set
forth in this Section.
For purposes of this Section, the amount per kilowatthour
means the total amount paid for electric service expressed on a
per kilowatthour basis, and the total amount paid for electric
service includes without limitation amounts paid for supply,
transmission, distribution, surcharges, and add-on taxes
exclusive of any increases in taxes or new taxes imposed after
October 26, 2011 (the effective date of Public Act 97-616). For
purposes of this Section, "eligible retail customers" shall
have the meaning set forth in Section 16-111.5 of this Act.
The fact that this Section becomes inoperative as set forth
in this subsection shall not be construed to mean that the
Commission may reexamine or otherwise reopen prudence or
reasonableness determinations already made.
(h) By December 31, 2017, the Commission shall prepare and
file with the General Assembly a report on the infrastructure
program and the performance-based formula rate. The report
shall include the change in the average amount per kilowatthour

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paid by residential customers between June 1, 2011 and May 31,
2017. If the change in the total average rate paid exceeds 2.5%
compounded annually, the Commission shall include in the report
an analysis that shows the portion of the change due to the
delivery services component and the portion of the change due
to the supply component of the rate. The report shall include
separate sections for each participating utility. Sections
16-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act, other
than this subsection (h), are inoperative after December 31,
2032 2022 for every participating utility, after which time a
participating utility shall no longer be eligible to annually
update the performance-based formula rate tariff pursuant to
subsection (d) of this Section. At such time, the then current
rates shall remain in effect until such time as new rates are
set pursuant to Article IX of this Act, subject to retroactive
adjustment, with interest, to reconcile rates charged with
actual costs.
The fact that this Section becomes inoperative as set forth
in this subsection shall not be construed to mean that the
Commission may reexamine or otherwise reopen prudence or
reasonableness determinations already made.
(i) While a participating utility may use, develop, and
maintain broadband systems and the delivery of broadband
services, voice-over-internet-protocol services,
telecommunications services, and cable and video programming
services for use in providing delivery services and Smart Grid

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

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Assembly that are reflected in paragraph (3) of this
subsection. In addition, Public Act 98-15 preempts and
supersedes any final Commission orders entered in Docket Nos.
11-0721, 12-0001, 12-0293, and 12-0321 to the extent
inconsistent with the amendatory language added to subsections
(c) and (d).
(1) No earlier than 5 business days after May 22, 2013
(the effective date of Public Act 98-15), each
participating utility shall file any tariff changes
necessary to implement the amendatory language set forth in
subsections (c) and (d) of this Section by Public Act 98-15
and a revised revenue requirement under the participating
utility's performance-based formula rate. The Commission
shall enter a final order approving such tariff changes and
revised revenue requirement within 21 days after the
participating utility's filing.
(2) Notwithstanding anything that may be to the
contrary, a participating utility may file a tariff to
retroactively recover its previously unrecovered actual
costs of delivery service that are no longer subject to
recovery through a reconciliation adjustment under
subsection (d) of this Section. This retroactive recovery
shall include any derivative adjustments resulting from
the changes to subsections (c) and (d) of this Section by
Public Act 98-15. Such tariff shall allow the utility to
assess, on current customer bills over a period of 12

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

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in full compliance with all requirements of subsection (b) of
this Section, subsection (c) of this Section, Section 16-108.6
of this Act, and all Commission orders entered pursuant to
Sections 16-108.5 and 16-108.6 of this Act, up to and including
May 22, 2013 (the effective date of Public Act 98-15). The
Commission shall not undertake any investigation of such
compliance and no penalty shall be assessed or adverse action
taken against a participating utility for noncompliance with
Commission orders associated with subsection (b) of this
Section, subsection (c) of this Section, and Section 16-108.6
of this Act prior to such date. Each participating utility
other than a combination utility shall be permitted, without
penalty, a period of 12 months after such effective date to
take actions required to ensure its infrastructure investment
program is in compliance with subsection (b) of this Section
and with Section 16-108.6 of this Act. Provided further, the
following subparagraphs shall apply to a participating utility
other than a combination utility:
(A) if the Commission has initiated a proceeding
pursuant to subsection (e) of Section 16-108.6 of this Act
that is pending as of May 22, 2013 (the effective date of
Public Act 98-15), then the order entered in such
proceeding shall, after notice and hearing, accelerate the
commencement of the meter deployment schedule approved in
the final Commission order on rehearing entered in Docket
No. 12-0298;

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

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utility's filing.
Any schedule for meter deployment approved by the
Commission pursuant to this subsection (l) shall take into
consideration procurement times for meters and other equipment
and operational issues. Nothing in Public Act 98-15 shall
shorten or extend the end dates for the 5-year or 10-year
periods set forth in subsection (b) of this Section or Section
16-108.6 of this Act. Nothing in this subsection is intended to
address whether a participating utility has, or has not,
satisfied any or all of the metrics and performance goals
established pursuant to subsection (f) of this Section.
(m) The provisions of Public Act 98-15 are severable under
Section 1.31 of the Statute on Statutes.
(Source: P.A. 99-143, eff. 7-27-15; 99-642, eff. 7-28-16;
99-906, eff. 6-1-17; 100-840, eff. 8-13-18.)
Article 5.
Section 5-5. 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.

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(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
period, except that this limitation on the number of emergency
rules that may be adopted in a 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

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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

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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

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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

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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

10100SB2080sam004 - 58 - LRB101 11122 RJF 59369 a
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

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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

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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

10100SB2080sam004 - 61 - LRB101 11122 RJF 59369 a
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

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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

10100SB2080sam004 - 63 - LRB101 11122 RJF 59369 a
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,
emergency rules to implement Public Act 99-516 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) In order to provide for the expeditious and timely
implementation of the provisions of Public Act 99-796,
emergency rules to implement the changes made by Public Act
99-796 may be adopted in accordance with this subsection (w) by
the Adjutant General. The adoption of emergency rules

10100SB2080sam004 - 64 - LRB101 11122 RJF 59369 a
authorized by this subsection (w) 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 Public Act 99-906,
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 June 1, 2017 (the effective date of Public Act
99-906). The adoption of emergency rules authorized by this
subsection (x) is deemed to be necessary for the public
interest, safety, and welfare.
(y) In order to provide for the expeditious and timely
implementation of the provisions of Public Act 100-23,
emergency rules to implement the changes made by Public Act
100-23 to Section 4.02 of the Illinois Act on the Aging,
Sections 5.5.4 and 5-5.4i of the Illinois Public Aid Code,
Section 55-30 of the Alcoholism and Other Drug Abuse and
Dependency Act, and Sections 74 and 75 of the Mental Health and
Developmental Disabilities Administrative Act may be adopted
in accordance with this subsection (y) by the respective
Department. The adoption of emergency rules authorized by this
subsection (y) is deemed to be necessary for the public
interest, safety, and welfare.

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(z) In order to provide for the expeditious and timely
implementation of the provisions of Public Act 100-554,
emergency rules to implement the changes made by Public Act
100-554 to Section 4.7 of the Lobbyist Registration Act may be
adopted in accordance with this subsection (z) by the Secretary
of State. The adoption of emergency rules authorized by this
subsection (z) is deemed to be necessary for the public
interest, safety, and welfare.
(aa) In order to provide for the expeditious and timely
initial implementation of the changes made to Articles 5, 5A,
12, and 14 of the Illinois Public Aid Code under the provisions
of Public Act 100-581, the Department of Healthcare and Family
Services may adopt emergency rules in accordance with this
subsection (aa). The 24-month limitation on the adoption of
emergency rules does not apply to rules to initially implement
the changes made to Articles 5, 5A, 12, and 14 of the Illinois
Public Aid Code adopted under this subsection (aa). The
adoption of emergency rules authorized by this subsection (aa)
is deemed to be necessary for the public interest, safety, and
welfare.
(bb) In order to provide for the expeditious and timely
implementation of the provisions of Public Act 100-587,
emergency rules to implement the changes made by Public Act
100-587 to Section 4.02 of the Illinois Act on the Aging,
Sections 5.5.4 and 5-5.4i of the Illinois Public Aid Code,
subsection (b) of Section 55-30 of the Alcoholism and Other

10100SB2080sam004 - 66 - LRB101 11122 RJF 59369 a
Drug Abuse and Dependency Act, Section 5-104 of the Specialized
Mental Health Rehabilitation Act of 2013, and Section 75 and
subsection (b) of Section 74 of the Mental Health and
Developmental Disabilities Administrative Act may be adopted
in accordance with this subsection (bb) by the respective
Department. The adoption of emergency rules authorized by this
subsection (bb) is deemed to be necessary for the public
interest, safety, and welfare.
(cc) In order to provide for the expeditious and timely
implementation of the provisions of Public Act 100-587,
emergency rules may be adopted in accordance with this
subsection (cc) to implement the changes made by Public Act
100-587 to: Sections 14-147.5 and 14-147.6 of the Illinois
Pension Code by the Board created under Article 14 of the Code;
Sections 15-185.5 and 15-185.6 of the Illinois Pension Code by
the Board created under Article 15 of the Code; and Sections
16-190.5 and 16-190.6 of the Illinois Pension Code by the Board
created under Article 16 of the Code. The adoption of emergency
rules authorized by this subsection (cc) is deemed to be
necessary for the public interest, safety, and welfare.
(dd) In order to provide for the expeditious and timely
implementation of the provisions of Public Act 100-864,
emergency rules to implement the changes made by Public Act
100-864 to Section 3.35 of the Newborn Metabolic Screening Act
may be adopted in accordance with this subsection (dd) by the
Secretary of State. The adoption of emergency rules authorized

10100SB2080sam004 - 67 - LRB101 11122 RJF 59369 a
by this subsection (dd) is deemed to be necessary for the
public interest, safety, and welfare.
(ee) In order to provide for the expeditious and timely
implementation of the provisions of this amendatory Act of the
100th General Assembly, emergency rules implementing the
Illinois Underground Natural Gas Storage Safety Act may be
adopted in accordance with this subsection by the Department of
Natural Resources. The adoption of emergency rules authorized
by this subsection is deemed to be necessary for the public
interest, safety, and welfare.
(ff) In order to provide for the expeditious and timely
implementation of the provisions of this amendatory Act of the
101st General Assembly, emergency rules may be adopted by the
Department of Labor in accordance with this subsection (ff) to
implement the changes made by this amendatory Act of the 101st
General Assembly to the Minimum Wage Law. The adoption of
emergency rules authorized by this subsection (ff) is deemed to
be necessary for the public interest, safety, and welfare.
(gg) In order to provide for the expeditious and timely
implementation of the provisions of this amendatory Act of the
101st General Assembly, emergency rules to implement the
changes to Section 16-107.5 of the Public Utilities Act may be
adopted in accordance with this subsection by the Illinois
Commerce Commission. The adoption of emergency rules
authorized by this subsection is deemed to be necessary for the
public interest, safety, and welfare.

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(Source: P.A. 100-23, eff. 7-6-17; 100-554, eff. 11-16-17;
100-581, eff. 3-12-18; 100-587, Article 95, Section 95-5, eff.
6-4-18; 100-587, Article 110, Section 110-5, eff. 6-4-18;
100-864, eff. 8-14-18; 100-1172, eff. 1-4-19; 101-1, eff.
2-19-19.)
Section 5-10. The Illinois Enterprise Zone Act is amended
by changing Section 5.5 as follows:
(20 ILCS 655/5.5) (from Ch. 67 1/2, par. 609.1)
Sec. 5.5. High Impact Business.
(a) In order to respond to unique opportunities to assist
in the encouragement, development, growth and expansion of the
private sector through large scale investment and development
projects, the Department is authorized to receive and approve
applications for the designation of "High Impact Businesses" in
Illinois subject to the following conditions:
(1) such applications may be submitted at any time
during the year;
(2) such business is not located, at the time of
designation, in an enterprise zone designated pursuant to
this Act;
(3) the business intends to do one or more of the
following:
(A) the business intends to make a minimum
investment of $12,000,000 which will be placed in

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service in qualified property and intends to create 500
full-time equivalent jobs at a designated location in
Illinois or intends to make a minimum investment of
$30,000,000 which will be placed in service in
qualified property and intends to retain 1,500
full-time retained jobs at a designated location in
Illinois. The business must certify in writing that the
investments would not be placed in service in qualified
property and the job creation or job retention would
not occur without the tax credits and exemptions set
forth in subsection (b) of this Section. The terms
"placed in service" and "qualified property" have the
same meanings as described in subsection (h) of Section
201 of the Illinois Income Tax Act; or
(B) the business intends to establish a new
electric generating facility at a designated location
in Illinois. "New electric generating facility", for
purposes of this Section, means a newly-constructed
electric generation plant or a newly-constructed
generation capacity expansion at an existing electric
generation plant, including the transmission lines and
associated equipment that transfers electricity from
points of supply to points of delivery, and for which
such new foundation construction commenced not sooner
than July 1, 2001. Such facility shall be designed to
provide baseload electric generation and shall operate

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on a continuous basis throughout the year; and (i)
shall have an aggregate rated generating capacity of at
least 1,000 megawatts for all new units at one site if
it uses natural gas as its primary fuel and foundation
construction of the facility is commenced on or before
December 31, 2004, or shall have an aggregate rated
generating capacity of at least 400 megawatts for all
new units at one site if it uses coal or gases derived
from coal as its primary fuel and shall support the
creation of at least 150 new Illinois coal mining jobs,
or (ii) shall be funded through a federal Department of
Energy grant before December 31, 2010 and shall support
the creation of Illinois coal-mining jobs, or (iii)
shall use coal gasification or integrated
gasification-combined cycle units that generate
electricity or chemicals, or both, and shall support
the creation of Illinois coal-mining jobs. The
business must certify in writing that the investments
necessary to establish a new electric generating
facility would not be placed in service and the job
creation in the case of a coal-fueled plant would not
occur without the tax credits and exemptions set forth
in subsection (b-5) of this Section. The term "placed
in service" has the same meaning as described in
subsection (h) of Section 201 of the Illinois Income
Tax Act; or

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(B-5) the business intends to establish a new
gasification facility at a designated location in
Illinois. As used in this Section, "new gasification
facility" means a newly constructed coal gasification
facility that generates chemical feedstocks or
transportation fuels derived from coal (which may
include, but are not limited to, methane, methanol, and
nitrogen fertilizer), that supports the creation or
retention of Illinois coal-mining jobs, and that
qualifies for financial assistance from the Department
before December 31, 2010. A new gasification facility
does not include a pilot project located within
Jefferson County or within a county adjacent to
Jefferson County for synthetic natural gas from coal;
or
(C) the business intends to establish production
operations at a new coal mine, re-establish production
operations at a closed coal mine, or expand production
at an existing coal mine at a designated location in
Illinois not sooner than July 1, 2001; provided that
the production operations result in the creation of 150
new Illinois coal mining jobs as described in
subdivision (a)(3)(B) of this Section, and further
provided that the coal extracted from such mine is
utilized as the predominant source for a new electric
generating facility. The business must certify in

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writing that the investments necessary to establish a
new, expanded, or reopened coal mine would not be
placed in service and the job creation would not occur
without the tax credits and exemptions set forth in
subsection (b-5) of this Section. The term "placed in
service" has the same meaning as described in
subsection (h) of Section 201 of the Illinois Income
Tax Act; or
(D) the business intends to construct new
transmission facilities or upgrade existing
transmission facilities at designated locations in
Illinois, for which construction commenced not sooner
than July 1, 2001. For the purposes of this Section,
"transmission facilities" means transmission lines
with a voltage rating of 115 kilovolts or above,
including associated equipment, that transfer
electricity from points of supply to points of delivery
and that transmit a majority of the electricity
generated by a new electric generating facility
designated as a High Impact Business in accordance with
this Section. The business must certify in writing that
the investments necessary to construct new
transmission facilities or upgrade existing
transmission facilities would not be placed in service
without the tax credits and exemptions set forth in
subsection (b-5) of this Section. The term "placed in

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service" has the same meaning as described in
subsection (h) of Section 201 of the Illinois Income
Tax Act; or
(E) the business intends to establish a new wind
power facility at a designated location in Illinois.
For purposes of this Section, "new wind power facility"
means a newly constructed electric generation
facility, or a newly constructed expansion of an
existing electric generation facility, placed in
service on or after July 1, 2009, that generates
electricity using wind energy devices, and such
facility shall be deemed to include all associated
transmission lines, substations, and other equipment
related to the generation of electricity from wind
energy devices. For purposes of this Section, "wind
energy device" means any device, with a nameplate
capacity of at least 0.5 megawatts, that is used in the
process of converting kinetic energy from the wind to
generate electricity; or
(E-5) the business intends to establish a new
utility-scale solar facility at a designated location
in Illinois. For purposes of this Section, "new
utility-scale solar power facility" means a newly
constructed electric generation facility, or a newly
constructed expansion of an existing electric
generation facility, placed in service on or after July

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1, 2019, that (i) generates electricity using
photovoltaic cells and (ii) has a nameplate capacity
that is greater than 2,000 kilowatts, and such facility
shall be deemed to include all associated transmission
lines, substations, and other equipment related to the
generation of electricity from photovoltaic cells; or
(F) the business commits to (i) make a minimum
investment of $500,000,000, which will be placed in
service in a qualified property, (ii) create 125
full-time equivalent jobs at a designated location in
Illinois, (iii) establish a fertilizer plant at a
designated location in Illinois that complies with the
set-back standards as described in Table 1: Initial
Isolation and Protective Action Distances in the 2012
Emergency Response Guidebook published by the United
States Department of Transportation, (iv) pay a
prevailing wage for employees at that location who are
engaged in construction activities, and (v) secure an
appropriate level of general liability insurance to
protect against catastrophic failure of the fertilizer
plant or any of its constituent systems; in addition,
the business must agree to enter into a construction
project labor agreement including provisions
establishing wages, benefits, and other compensation
for employees performing work under the project labor
agreement at that location; for the purposes of this

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Section, "fertilizer plant" means a newly constructed
or upgraded plant utilizing gas used in the production
of anhydrous ammonia and downstream nitrogen
fertilizer products for resale; for the purposes of
this Section, "prevailing wage" means the hourly cash
wages plus fringe benefits for training and
apprenticeship programs approved by the U.S.
Department of Labor, Bureau of Apprenticeship and
Training, health and welfare, insurance, vacations and
pensions paid generally, in the locality in which the
work is being performed, to employees engaged in work
of a similar character on public works; this paragraph
(F) applies only to businesses that submit an
application to the Department within 60 days after the
effective date of this amendatory Act of the 98th
General Assembly; and
(4) no later than 90 days after an application is
submitted, the Department shall notify the applicant of the
Department's determination of the qualification of the
proposed High Impact Business under this Section.
(b) Businesses designated as High Impact Businesses
pursuant to subdivision (a)(3)(A) of this Section shall qualify
for the credits and exemptions described in the following Acts:
Section 9-222 and Section 9-222.1A of the Public Utilities Act,
subsection (h) of Section 201 of the Illinois Income Tax Act,
and Section 1d of the Retailers' Occupation Tax Act; provided

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that these credits and exemptions described in these Acts shall
not be authorized until the minimum investments set forth in
subdivision (a)(3)(A) of this Section have been placed in
service in qualified properties and, in the case of the
exemptions described in the Public Utilities Act and Section 1d
of the Retailers' Occupation Tax Act, the minimum full-time
equivalent jobs or full-time retained jobs set forth in
subdivision (a)(3)(A) of this Section have been created or
retained. Businesses designated as High Impact Businesses
under this Section shall also qualify for the exemption
described in Section 5l of the Retailers' Occupation Tax Act.
The credit provided in subsection (h) of Section 201 of the
Illinois Income Tax Act shall be applicable to investments in
qualified property as set forth in subdivision (a)(3)(A) of
this Section.
(b-5) Businesses designated as High Impact Businesses
pursuant to subdivisions (a)(3)(B), (a)(3)(B-5), (a)(3)(C),
and (a)(3)(D) of this Section shall qualify for the credits and
exemptions described in the following Acts: Section 51 of the
Retailers' Occupation Tax Act, Section 9-222 and Section
9-222.1A of the Public Utilities Act, and subsection (h) of
Section 201 of the Illinois Income Tax Act; however, the
credits and exemptions authorized under Section 9-222 and
Section 9-222.1A of the Public Utilities Act, and subsection
(h) of Section 201 of the Illinois Income Tax Act shall not be
authorized until the new electric generating facility, the new

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gasification facility, the new transmission facility, or the
new, expanded, or reopened coal mine is operational, except
that a new electric generating facility whose primary fuel
source is natural gas is eligible only for the exemption under
Section 5l of the Retailers' Occupation Tax Act.
(b-6) Businesses designated as High Impact Businesses
pursuant to subdivision (a)(3)(E) of this Section shall qualify
for the exemptions described in Section 5l of the Retailers'
Occupation Tax Act; any business so designated as a High Impact
Business being, for purposes of this Section, a "Wind Energy
Business".
(c) High Impact Businesses located in federally designated
foreign trade zones or sub-zones are also eligible for
additional credits, exemptions and deductions as described in
the following Acts: Section 9-221 and Section 9-222.1 of the
Public Utilities Act; and subsection (g) of Section 201, and
Section 203 of the Illinois Income Tax Act.
(d) Except for businesses contemplated under subdivision
(a)(3)(E) of this Section, existing Illinois businesses which
apply for designation as a High Impact Business must provide
the Department with the prospective plan for which 1,500
full-time retained jobs would be eliminated in the event that
the business is not designated.
(e) Except for new wind power facilities contemplated under
subdivision (a)(3)(E) of this Section, new proposed facilities
which apply for designation as High Impact Business must

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provide the Department with proof of alternative non-Illinois
sites which would receive the proposed investment and job
creation in the event that the business is not designated as a
High Impact Business.
(f) Except for businesses contemplated under subdivision
(a)(3)(E) of this Section, in the event that a business is
designated a High Impact Business and it is later determined
after reasonable notice and an opportunity for a hearing as
provided under the Illinois Administrative Procedure Act, that
the business would have placed in service in qualified property
the investments and created or retained the requisite number of
jobs without the benefits of the High Impact Business
designation, the Department shall be required to immediately
revoke the designation and notify the Director of the
Department of Revenue who shall begin proceedings to recover
all wrongfully exempted State taxes with interest. The business
shall also be ineligible for all State funded Department
programs for a period of 10 years.
(g) The Department shall revoke a High Impact Business
designation if the participating business fails to comply with
the terms and conditions of the designation. However, the
penalties for new wind power facilities or Wind Energy
Businesses or new utility-scale solar power facility for
failure to comply with any of the terms or conditions of the
Illinois Prevailing Wage Act shall be only those penalties
identified in the Illinois Prevailing Wage Act, and the

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Department shall not revoke a High Impact Business designation
as a result of the failure to comply with any of the terms or
conditions of the Illinois Prevailing Wage Act in relation to a
new wind power facility or a Wind Energy Business or new
utility-scale solar power facility.
(h) Prior to designating a business, the Department shall
provide the members of the General Assembly and Commission on
Government Forecasting and Accountability with a report
setting forth the terms and conditions of the designation and
guarantees that have been received by the Department in
relation to the proposed business being designated.
(Source: P.A. 97-905, eff. 8-7-12; 98-109, eff. 7-25-13.)
Section 5-15. The Illinois Power Agency Act is amended by
changing Sections 1-10, 1-56, and 1-75 as follows:
(20 ILCS 3855/1-10)
Sec. 1-10. Definitions.
"Agency" means the Illinois Power Agency.
"Agency loan agreement" means any agreement pursuant to
which the Illinois Finance Authority agrees to loan the
proceeds of revenue bonds issued with respect to a project to
the Agency upon terms providing for loan repayment installments
at least sufficient to pay when due all principal of, interest
and premium, if any, on those revenue bonds, and providing for
maintenance, insurance, and other matters in respect of the

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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

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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

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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.

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"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.
"Contractor" means the entity or organization with main
responsibility for the building of a construction project and
is the party signing the prime construction contract for the
project.
"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

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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

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following year.
"Department" means the Department of Commerce and Economic
Opportunity.
"Director" means the Director of the Illinois Power Agency.
"Demand-response" means measures that decrease peak
electricity demand or shift demand from peak to off-peak
periods.
"Distributed renewable energy generation device" means a
device that is:
(1) powered by wind, solar thermal energy,
photovoltaic cells or panels, biodiesel, crops and
untreated and unadulterated organic waste biomass, tree
waste, and hydropower that does not involve new
construction or significant expansion of hydropower dams;
(2) interconnected at the distribution system level of
either an electric utility as defined in this Section, a
municipal utility as defined in this Section that owns or
operates electric distribution facilities, or a rural
electric cooperative as defined in Section 3-119 of the
Public Utilities Act;
(3) located on the customer side of the customer's
electric meter and is primarily used to offset that
customer's electricity load; and
(4) limited in nameplate capacity to less than or equal
to 2,000 kilowatts.
"Energy efficiency" means measures that reduce the amount

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of electricity or natural gas consumed in order to achieve a
given end use. "Energy efficiency" includes voltage
optimization measures that optimize the voltage at points on
the electric distribution voltage system and thereby reduce
electricity consumption by electric customers' end use
devices. "Energy efficiency" also includes measures that
reduce the total Btus of electricity, natural gas, and other
fuels needed to meet the end use or uses.
"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.
"Index price" means the monthly average load-weighted
day-ahead price at the ComEd or Ameren Hub.
"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

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operated by any subdivision or municipal corporation of this
State.
"Nameplate capacity" means the aggregate inverter
nameplate capacity in kilowatts AC.
"Offer strike price" means the price for a renewable energy
credit from a new utility-scale wind project or a utility-scale
solar project resulting from a new utility-scale wind or solar
competitive procurement.
"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.
"Project labor agreement" means a pre-hire collective
bargaining agreement that covers all terms and conditions of
employment on a specific construction project and must include
the following:
(1) provisions establishing the minimum hourly wage
for each class of labor organization employee;
(2) provisions establishing the benefits and other
compensation for each class of labor organization
employee;
(3) provisions establishing that no strike or disputes
will be engaged in by the labor organization employees; and

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(4) provisions establishing that no lockout or
disputes will be engaged in by the contractor building the
project.
A labor organization and the contractor building the
project shall have the authority to include other terms and
conditions as they deem necessary.
"Public utility" has the same definition as found in
Section 3-105 of the Public Utilities Act.
"Real property" means any interest in land together with
all structures, fixtures, and improvements thereon, including
lands under water and riparian rights, any easements,
covenants, licenses, leases, rights-of-way, uses, and other
interests, together with any liens, judgments, mortgages, or
other claims or security interests related to real property.
"Renewable energy credit" means a tradable credit that
represents the environmental attributes of one megawatt hour of
energy produced from a renewable energy resource.
"Renewable energy resources" includes energy and its
associated renewable energy credit or renewable energy credits
from wind, solar thermal energy, photovoltaic cells and panels,
biodiesel, anaerobic digestion, crops and untreated and
unadulterated organic waste biomass, tree waste, and
hydropower that does not involve new construction or
significant expansion of hydropower dams. For purposes of this
Act, landfill gas produced in the State is considered a
renewable energy resource. "Renewable energy resources" does

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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

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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

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

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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.
"Variable renewable energy credit" means a renewable
energy credit which is the difference between the offer strike
price and the index price.
"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

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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. 98-90, eff. 7-15-13; 99-906, eff. 6-1-17.)
(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

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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

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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

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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

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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

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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

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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

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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

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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. If the prices paid for renewable energy
credits under this Section are higher than the prices paid
from programs offered under subsection (c) of Section 1-75
of this Act, then the average difference in price for a
comparable product shall not count toward the limitation or
reduction found in subparagraph (E) of paragraph (1) of
subsection (c) of Section 1-75 of this Act. 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

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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

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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

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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.

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(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)

10100SB2080sam004 - 106 - LRB101 11122 RJF 59369 a
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.
(c) (Blank).
(d) (Blank).
(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.
(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.

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(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

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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

10100SB2080sam004 - 109 - LRB101 11122 RJF 59369 a
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

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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

10100SB2080sam004 - 111 - LRB101 11122 RJF 59369 a
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

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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;

10100SB2080sam004 - 113 - LRB101 11122 RJF 59369 a
(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.

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(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

10100SB2080sam004 - 115 - LRB101 11122 RJF 59369 a
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

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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

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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

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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. 98-672, eff. 6-30-14; 99-906, eff. 6-1-17.)
(20 ILCS 3855/1-75)
Sec. 1-75. Planning and Procurement Bureau. The Planning
and Procurement Bureau has the following duties and
responsibilities:

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(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

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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

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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

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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

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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

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adequate, reliable, affordable, efficient, and environmentally
sustainable electric service at the lowest total cost over
time, taking into account any benefits of price stability, for
eligible retail customers of electric utilities that on
December 31, 2005 provided electric service to at least 100,000
customers in the State of Illinois, and for eligible Illinois
retail customers of small multi-jurisdictional electric
utilities that (i) on December 31, 2005 served less than
100,000 customers in Illinois and (ii) request a procurement
plan for their Illinois jurisdictional load.
(c) Renewable portfolio standard.
(1)(A) The Agency shall develop a long-term renewable
resources procurement plan that shall include procurement
programs and competitive procurement events necessary to
meet the goals set forth in this subsection (c). The
initial long-term renewable resources procurement plan
shall be released for comment no later than 160 days after
June 1, 2017 (the effective date of Public Act 99-906). The
Agency shall review, and may revise on an expedited basis,
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

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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; increasing by at least 2.5% each delivery
year thereafter to at least 37.5% by the 2030 delivery
year; and continuing at no less than 37.5% 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

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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;
increasing by at least 2.5% each delivery year thereafter
to at least 37.5% by June 1, 2030 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)

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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 new
renewable energy credits in amounts equal to at least
10,000,000 renewable energy credits from new wind and solar
projects by the end of delivery year 2020, and increasing
ratably to reach 45,000,000 new renewable energy credits
from wind and solar projects by the end of delivery year
2030 such that the goals in subparagraph (B) of this
paragraph (1) are met entirely by procurements of new
renewable energy credits from wind and solar projects. Of
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: 50% from
wind projects and 50% from solar projects. Of the amount
procured from solar projects, the Agency shall procure, to
the extent reasonably practicable: 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

10100SB2080sam004 - 128 - LRB101 11122 RJF 59369 a
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

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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). For purposes of calculating whether the Agency has
procured enough new wind and solar renewable energy credits
required by this subparagraph (C), renewable energy
facilities that have a multi-year renewable energy credit
delivery contract with the utility through at least

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delivery year 2030 shall be considered new, however no
renewable energy credits from contracts entered into
before June 1, 2019 shall be used to calculate whether the
Agency has procured the correct proportion of new wind and
new solar contracts described in this subparagraph (C) for
delivery year 2020 and thereafter.
(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

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

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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 the percentage limitations as included in
paragraphs (1), (2), and (3) of subsection (m) of Section
8-103B of the Public Utilities Act 2.015% of the amount
paid per kilowatthour by those customers during the year
ending May 31, 2009 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

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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.
(E-5) If the limitation on the amount of renewable
energy resources procured in subparagraph (E) of this
paragraph (1) would prevent the Agency from meeting all of
the goals in this subsection (c), the Agency shall procure
additional renewable energy resources up to an amount equal
to the Social Cost of Carbon as defined in subsection (d-5)
of this Section as of January 1, 2019 multiplied by the
amount of new renewable energy credits to be procured
pursuant to the new renewable energy credit procurement
requirements of subparagraph (C) of this paragraph (1) from
the new build requirements for the relevant planning year.
The deemed savings of renewable energy shall not be subject
to the limitations in subparagraph (E) of this paragraph
(1). The utilities shall be entitled to recover the total
cost associated with procuring renewable energy credits
required by this Section regardless of whether the costs
are subject to the limitations described in subparagraph

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(E) of this paragraph (1) through the automatic adjustment
clause tariff under subsection (k) of Section 16-108 of the
Public Utilities Act.
(F) If the limitation on the amount of renewable energy
(1) 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

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Agency shall conduct an initial forward procurement
for renewable energy credits from new utility-scale
wind projects within 160 days after June 1, 2017 (the
effective date of Public Act 99-906). For the purposes
of this initial forward procurement, the Agency shall
solicit 15-year contracts for delivery of 1,000,000
renewable energy credits delivered annually from new
utility-scale wind projects to begin delivery on June
1, 2019, if available, but not later than June 1, 2021.
Payments to suppliers of renewable energy credits
shall commence upon delivery. Renewable energy credits
procured under this initial procurement shall be
included in the Agency's long-term plan and shall apply
to all renewable energy goals in this subsection (c).
(ii) Notwithstanding whether a long-term renewable
resources procurement plan has been approved, the
Agency shall conduct an initial forward procurement
for renewable energy credits from new utility-scale
solar projects and brownfield site photovoltaic
projects within one year after June 1, 2017 (the
effective date of Public Act 99-906). For the purposes
of this initial forward procurement, the Agency shall
solicit 15-year contracts for delivery of 1,000,000
renewable energy credits delivered annually from new
utility-scale solar projects and brownfield site
photovoltaic projects to begin delivery on June 1,

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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) Notwithstanding whether the Commission has
approved the periodic long-term renewable resources
procurement plan revision described in Section
16-111.5 of the Public Utilities Act, the Agency shall
conduct at least one subsequent forward procurement
for renewable energy credits from new utility-scale
wind projects and new utility-scale solar projects
within 120 days after the effective date of this
amendatory Act of the 101st General Assembly in
quantities needed to meet the requirements of
subparagraph (C). 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

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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) For all competitive procurements under this
subparagraph (G) and any procurements required under
subparagraph (C) of new utility-scale wind and new
utility-scale solar, the Agency shall allow
respondents to bid a fixed price per renewable energy
credit or a variable price per renewable energy credit
that is indexed to the ComEd Hub for projects
interconnecting to PJM Interconnection LLC or the
Illinois Hub for projects interconnecting to MISO.
Variable price renewable energy credit bids shall be
limited to the first 3 new utility-scale wind and solar
procurements following the effective date of this
amendatory act of the 101st General Assembly. Variable
renewable energy credit bids shall be based on the
difference between the offer strike price and the index
price that shall be developed by the Illinois Power
Agency and approved by the Illinois Commerce
Commission. Variable price renewable energy credits
shall not exceed more than 40% or less than 20% of the
total supply for new utility-scale wind and solar
procurements in a procurement year. The Illinois

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Commerce Commission, in consultation with the Illinois
Power Agency, shall determine that variable price
renewable energy credit bids are prudent within the
renewables resources budget. 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

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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 alternative retail electric
supplier meets the requirements described in this
subparagraph (H).
(i) Within 45 days after June 1, 2017 (the

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

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(the effective date of Public Act 99-906), whichever is
later, of its election under item (ii) of this
subparagraph (H) to supply renewable energy credits to
retail customers of the utility. Such election shall
identify the amount of renewable energy credits to be
supplied by the alternative retail electric supplier
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%

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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

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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

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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

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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.

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(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 be continuously open in
order to provide for the steady, predictable, and
sustainable growth of new solar photovoltaic development
in Illinois. To this end, the Adjustable Block program
shall provide a transparent annual 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. The

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Agency shall develop program features and implementation
processes that create consistent market signals, making
the program predictable and sustainable for solar industry
companies, thus allowing them to scale up long-term
Illinois-based hiring and investment activities. 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 shall
establish program eligibility requirements that ensure
that projects that enter the program are sufficiently
mature to indicate a demonstrable path to completion.
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

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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 25 10 kilowatts.
(ii) At least 25% from distributed renewable
energy generation devices with a nameplate capacity of
more than 25 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 in order to respond to
market demand.
The Adjustable Block program shall be designed to
ensure that renewable energy credits are procured from
photovoltaic distributed renewable energy generation

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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

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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

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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.
(viii) Notwithstanding items (ii) and (iii) of
this subparagraph (L), the Agency shall not be
restricted from offering additional payment structures
if it determines that such adjustments will better
achieve the goals of this subsection (c). Any such
adjustments shall be approved by the Commission as a
long-term plan amendment under Section 16-111.5 of the
Public Utilities Act.
(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

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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. Funds
needed to cover the administrative expenses for the
implementation of the Adjustable Block program shall not be
included as part of the limitations described in
subparagraph (E). The utilities shall be entitled to
recover the costs detailed in this subparagraph (M)
regardless of whether the costs are subject to the
limitations described in subparagraph (E) through the
automatic adjustment clause tariff under subsection (k) of
Section 16-108 of the Public Utilities Act.
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

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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

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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 project shall be deemed to be
fully subscribed and the Agency shall purchase all of the
renewable energy credits from photovoltaic community
renewable generation projects as long as a minimum of 80%
of the shares are subscribed. 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

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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 $50,000,000 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 an additional 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 that of such funds in such year
shall be used by an electric utility that serves more than

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3,000,000 retail customers in the State to implement a
Commission-approved plan under Section 16-108.12 of the
Public Utilities Act. Funds allocated under this
subparagraph (O) shall not be included as part of the
limitations described in subparagraph (E) of this Section.
The utilities shall be entitled to recover the total cost
associated with procuring renewable energy credits
detailed in this subparagraph (O) regardless of whether the
costs are subject to the limitations described in
subparagraph (E) through the automatic adjustment clause
tariff under subsection (k) of Section 16-108 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).
(P) All programs and procurements under this
subsection (c) shall be designed to encourage
participating projects to use a diverse and equitable
workforce and a diverse set of contractors, including
minority-owned businesses, disadvantaged businesses, trade
unions, graduates of any workforce training programs
administered under this Act, and small businesses. Any
incremental costs in renewable energy credits associated
with incentives or requirements to meet goals associated

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with geographic diversity, workforce diversity,
subcontractor diversity, or any other public policies
determined by the Agency and approved by the Commission,
shall not be included as part of the limitations described
in subparagraph (E). The utilities shall be entitled to
recover the incremental costs associated with procuring
renewable energy credits that also meet the public policy
goals detailed in this subparagraph (P) regardless of
whether the costs are subject to the limitations described
in subparagraph (E) through the automatic adjustment
clause tariff under subsection (k) of Section 16-108 of the
Public Utilities Act.
(2) (Blank).
(3) (Blank).
(4) The electric utility shall retire all renewable
energy credits used to comply with the standard.
(5) Beginning with the 2010 delivery year and ending
June 1, 2017, an electric utility subject to this
subsection (c) shall apply the lesser of the maximum
alternative compliance payment rate or the most recent
estimated alternative compliance payment rate for its
service territory for the corresponding compliance period,
established pursuant to subsection (d) of Section 16-115D
of the Public Utilities Act to its retail customers that
take service pursuant to the electric utility's hourly
pricing tariff or tariffs. The electric utility shall

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

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including, but not limited to, the costs of administering
and evaluating the Adjustable Block program, shall not be
included as part of the limitations described in
subparagraph (E) of paragraph (1).
(7) Renewable energy credits procured from new
photovoltaic projects or new distributed renewable energy
generation devices under this Section after June 1, 2017
(the effective date of Public Act 99-906) must be procured
from devices installed by a qualified person in compliance
with the requirements of Section 16-128A of the Public
Utilities Act and any rules or regulations adopted
thereunder.
In meeting the renewable energy requirements of this
subsection (c), to the extent feasible and consistent with
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.
(8) Renewable energy credits procured from new wind
projects and new utility-scale solar projects pursuant to
Agency procurement events occurring after this amendatory
Act of the 101st General Assembly must be from facilities

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built by contractors that must enter into a project labor
agreement as defined by this Act prior to construction. A
copy of the project labor agreement shall be filed with the
Agency.
(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

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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

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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

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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

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development of clean coal facilities in Illinois, each
electric utility subject to this Section shall execute a
sourcing agreement to source electricity from a proposed
clean coal facility in Illinois (the "initial clean coal
facility") that will have a nameplate capacity of at least
500 MW when commercial operation commences, that has a
final Clean Air Act permit on June 1, 2009 (the effective
date of Public Act 95-1027), and that will meet the
definition of clean coal facility in Section 1-10 of this
Act when commercial operation commences. The sourcing
agreements with this initial clean coal facility shall be
subject to both approval of the initial clean coal facility
by the General Assembly and satisfaction of the
requirements of paragraph (4) of this subsection (d) and
shall be executed within 90 days after any such approval by
the General Assembly. The Agency and the Commission shall
have authority to inspect all books and records associated
with the initial clean coal facility during the term of
such a sourcing agreement. A utility's sourcing agreement
for electricity produced by the initial clean coal facility
shall include:
(A) a formula contractual price (the "contract
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

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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

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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

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(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

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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;

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(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

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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

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facility fails to fully comply with the applicable
carbon sequestration requirements in any given
year, provided the requisite offsets are
purchased. However, the Attorney General, on
behalf of the People of the State of Illinois, may
specifically enforce the facility's sequestration
requirement and the other terms of this contract
provision. Compliance with the sequestration
requirements and offset purchase requirements
specified in paragraph (3) of this subsection (d)
shall be reviewed annually by an independent
expert retained by the owner of the initial clean
coal facility, with the advance written approval
of the Attorney General. The Commission may, in the
course of the review specified in item (vii),
reduce the allowable return on equity for the
facility if the facility willfully fails to comply
with the carbon capture and sequestration
requirements set forth in this item (v);
(vi) include limits on, and accordingly
provide for modification of, the amount the
utility is required to source under the sourcing
agreement consistent with paragraph (2) of this
subsection (d);
(vii) require Commission review: (1) to
determine the justness, reasonableness, and

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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;

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(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

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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

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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

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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

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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

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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

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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

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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

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the utility's Illinois load for the delivery year
commencing June 1, 2016, the Agency shall procure contracts
with zero emission facilities that are reasonably capable
of generating cost-effective zero emission credits in an
amount approximately equal to 16% of the portion of power
and energy to be procured by the Agency for the utility.
The duration of the contracts procured under this
subsection (d-5) shall be for a term of 10 years ending May
31, 2027. The quantity of zero emission credits to be
procured under the contracts shall be all of the zero
emission credits generated by the zero emission facility in
each delivery year; however, if the zero emission facility
is owned by more than one entity, then the quantity of zero
emission credits to be procured under the contracts shall
be the amount of zero emission credits that are generated
from the portion of the zero emission facility that is
owned by the winning supplier.
The 16% value identified in this paragraph (1) is the
average of the percentage targets in subparagraph (B) of
paragraph (1) of subsection (c) of this Section 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

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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

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(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

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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

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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.

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(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

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resource auction price determined in the
resource auction administered by the
Midcontinent Independent System Operator,
Inc., in which the largest percentage of
load cleared for Local Resource Zone 4,
divided by 24 hours per day, and where such
price is determined by the Midcontinent
Independent System Operator, Inc.
For purposes of this subsection (d-5):
"Rest of the RTO" and "ComEd Zone" shall have
the meaning ascribed to them by PJM
Interconnection, LLC.
"RTO" means regional transmission
organization.
(C) No later than 45 days after June 1, 2017 (the
effective date of Public Act 99-906), the Agency shall
publish its proposed zero emission standard
procurement plan. The plan shall be consistent with the
provisions of this paragraph (1) and shall provide that
winning bids shall be selected based on public interest
criteria that include, but are not limited to,
minimizing carbon dioxide emissions that result from
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

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shall take into account the incremental environmental
benefits resulting from the procurement, such as any
existing environmental benefits that are preserved by
the procurements held under Public Act 99-906 and would
cease to exist if the procurements were not held,
including the preservation of zero emission
facilities. The plan shall also describe in detail how
each public interest factor shall be considered and
weighted in the bid selection process to ensure that
the public interest criteria are applied to the
procurement and given full effect.
For purposes of developing the plan, the Agency
shall consider any reports issued by a State agency,
board, or commission under House Resolution 1146 of the
98th General Assembly and paragraph (4) of subsection
(d) of this Section 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

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no more than 60 days later than June 1, 2017 (the
effective date of Public Act 99-906), the Agency shall
revise the plan as necessary based on the comments
received and file its zero emission standard
procurement plan with the Commission.
If the Commission determines that the plan will
result in the procurement of cost-effective zero
emission credits, then the Commission shall, after
notice and hearing, but no later than 45 days after the
Agency filed the plan, approve the plan or approve with
modification. For purposes of this subsection (d-5),
"cost effective" means the projected costs of
procuring zero emission credits from zero emission
facilities do not cause the limit stated in paragraph
(2) of this subsection to be exceeded.
(C-5) As part of the Commission's review and
acceptance or rejection of the procurement results,
the Commission shall, in its public notice of
successful bidders:
(i) identify how the winning bids satisfy the
public interest criteria described in subparagraph
(C) of this paragraph (1) of minimizing carbon
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

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

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and photovoltaic, based upon the simple
average of the following:
(I) the price, or if there is more than
one price, the average of the prices, paid
for renewable energy credits from new
utility-scale wind projects in the
procurement events specified in item (i)
of subparagraph (G) of paragraph (1) of
subsection (c) of this Section 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 this 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 this Section 1-75 of this Act.
Each utility shall enter into binding contractual
arrangements with the winning suppliers.
The procurement described in this subsection

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(d-5), including, but not limited to, the execution of
all contracts procured, shall be completed no later
than May 10, 2017. Based on the effective date of
Public Act 99-906, the Agency and Commission may, as
appropriate, modify the various dates and timelines
under this subparagraph and subparagraphs (C) and (D)
of this paragraph (1). The procurement and plan
approval processes required by this subsection (d-5)
shall be conducted in conjunction with the procurement
and plan approval processes required by subsection (c)
of this Section and Section 16-111.5 of the Public
Utilities Act, to the extent practicable.
Notwithstanding whether a procurement event is
conducted under Section 16-111.5 of the Public
Utilities Act, the Agency shall immediately initiate a
procurement process on June 1, 2017 (the effective date
of Public Act 99-906).
(D) Following the procurement event described in
this paragraph (1) and consistent with subparagraph
(B) of this paragraph (1), the Agency shall calculate
the payments to be made under each contract for the
next delivery year based on the market price index for
that delivery year. The Agency shall publish the
payment calculations no later than May 25, 2017 and
every May 25 thereafter.
(E) Notwithstanding the requirements of this

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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

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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

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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

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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

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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

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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

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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

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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. 99-536, eff. 7-8-16; 99-906, eff. 6-1-17;
100-863, eff. 8-14-18; revised 10-18-18.)
Section 5-20. The Public Utilities Act is amended by
changing Sections 16-107.5, 16-107.6, 16-108, and 16-111.5 and
by adding Section 16-107.7 as follows:
(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. Further, to achieve

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the goal of this Act that robust options for customer-site
distributed generation continue to thrive in Illinois, the
General Assembly finds that a smooth, predictable transition
must be ensured for customers between full net metering at the
retail electricity rate to the distribution generation rebate
described in Section 16-107.6.
(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, hosts, or operates,
including any third-party owned systems, 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 current or future electrical requirements;
(iii) "electricity provider" means an electric utility or
alternative retail electric supplier; (iv) "eligible renewable
electrical generating facility" means a generator, which may
include the co-location of an energy storage system, 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) "net electricity metering" (or

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"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; and
(viii) "energy storage system" means commercially available
technology that is capable of absorbing energy and storing it
for a period of time for use at a later time, including, but
not limited to, electrochemical, thermal, and
electromechanical technologies, and may be interconnected
behind the customer's meter or interconnected behind its own
meter.
(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

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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

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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 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

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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 or
time-of-use rates 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

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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 or time-of-use period exceeds the
amount of electricity used by the customer during that
hourly period or time-of-use 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 or time-of-use period. The
delivery credit shall be equal to the net kilowatt-hours
produced in such hourly or time-of-use 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

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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

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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

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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

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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

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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.
Within 90 days after the effective date of this amendatory
Act of the 101st General Assembly, the Commission shall open a
proceeding to update the interconnection standards and
applicable utility tariffs. For the public interest, safety,
and welfare of Illinois citizens, the Commission may adopt
emergency rules under Section 5-45 of the Illinois
Administrative Procedure Act to implement this Section. In
addition to items (i) through (iv) in this subsection (h), the
Commission shall also revise the standards to address the
following, including, but not limited to, critical standards
for interconnection:
(i) transparency and accuracy of costs, both direct and
indirect, while maintaining system security through the
effective management of confidentiality agreements;
(ii) standardization of typical costs associated with
interconnection;
(iii) transparency of the interconnection queue or
queues and hosting capacity;

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(iv) development of hosting capacity maps that enable
greater visibility to customers about the locations with
the greatest need or availability;
(v) predictability of the queue management process and
enforcement of timelines;
(vi) benefits and challenges associated with group
studies and cost sharing;
(vii) minimum requirements for application to the
interconnection process and throughout the interconnection
process to avoid queue clogging behavior;
(viii) requiring that the electric utility performing
the interconnection study justify their interconnection
study cost and the estimates of costs for identified
upgrades, and to cap payments required by the
interconnection customer for the electric utility
installed facilities to the lesser of +50% of the
Feasibility Study estimate, +25% of the System Impact Study
estimate, or +10% of the Facilities Study estimate;
(ix) allowing customers to self-supply interconnection
studies when the electric utility are unable provide such
studies at a reasonable cost and schedule;
(x) allowing customers to self-build system upgrades
consistent with electric utility standards when the
electric utility cannot provide such upgrades and
interconnection facilities at a reasonable cost and
schedule;

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(xi) preventing the electric utility from adding
overheads to their actual and estimated costs for both
studies and system upgrades. Provide a mechanism for a
customer to review invoices and internal accounting
statements to verify costs incurred by the electric
utility;
(xii) requiring all interconnection agreements to be
filed with the Illinois Commerce Commission;
(xiii) revising the electric utility reporting
requirements to include information regarding ability of
utilities to meet timelines established under these
interconnection standards and to introduce penalties for
utilities that do not meet such requirements, to be
commensurate with penalties faced by interconnection
customers that fail to meet requirements under these
interconnection standards;
(xiv) facilitating the deployment of energy storage
systems while ensuring the continued grid safety and
reliability of the system, including addressing the
following:
(1) treatment of energy storage systems as
generation for purposes of the interconnection,
ownership and operation;
(2) fair study assumptions that reflect the
operational profile of the energy storage device;
(3) streamlined notification-only interconnection

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requirements for non-exporting systems that meet
utility criteria for safety and reliability, as is
determined through a robust stakeholder process; and
(4) enabling exports from customer-sited energy
storage systems for participation either in utility
programs or wholesale markets; and
(xv) establishment of a dispute resolution process
designed to address instances of unreasonable impediments
by an electric utility to the critical standards for
interconnection enumerated in subsections (i) - (xiv) of
this subsection (h). The Commission will make available
adequate Commission Staff for this dispute resolution
process to ensure that matters are decided on an expedited
basis.
As part of this proceeding, the Commission shall establish
an interconnection working group. The working group shall
include representatives from electric utilities, developers of
renewable electric generating facilities, other industries
that regularly apply for interconnection with the electric
utilities, representatives of distributed generation
customers, the Commission staff, and other stakeholders with a
substantial interest in the topics addressed by the working
group. The working group shall address cost and best available
technology for interconnection and metering, distribution
system upgrade cost avoidance through use of advanced inverter
functions, process and customer service for interconnecting

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customers adopting distributed energy resources, including
energy storage; options for metering distributed energy
resources, including energy storage; interconnection of new
technologies, including smart inverters and energy storage,
and, without limitation, other technical, policy, and tariff
issues related to and affecting interconnection performance
and customer service, as determined by the working group. The
Commission may create working group subcommittees of the
working group to focus on specific issues of importance, as
appropriate. The working group shall report to the Commission
on recommended improvements to interconnection rules and
tariffs and such other recommendations as determined by the
working group, within 6 months of its first meeting, and every
6 months thereafter. Such report shall include consensus
recommendations of the working group and, if applicable,
additional recommendations for which consensus was not
reached. The outcomes of the working group shall inform the
policies, processes, tariffs, and standards associated with
interconnection and should create standards and processes that
support the achievement of the objectives in subparagraph (K)
of paragraph (1) of subsection (c) of Section 1-75 of the
Illinois Power Agency Act.
(i) All electricity providers shall begin to offer net
metering no later than April 1, 2008.
(j) An electricity utility provider shall provide net
metering to eligible customers until the load of its net

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metering customers equals 5% of the total peak demand delivered
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 delivered
supplied by that electricity utility provider during the
previous year, and the Commission has approved the distributed
generation rebate and applicable tariff following
investigation as set out in subsection (e) of Section 16-107.6
of this Act, eligible customers that begin taking net metering
shall only be eligible for netting of energy.
(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.
(l)(1) Notwithstanding the definition of "eligible
customer" in item (ii) of subsection (b) of this Section, each
electricity provider shall allow net metering as set forth in
this subsection (l) and for the following projects, provided
that only electric utilities shall provide net metering for
subparagraph (C) of this paragraph (1):
(A) properties owned or leased by multiple customers
that contribute to the operation of an eligible renewable

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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;
(B) 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

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regulations adopted thereunder.
(2) Notwithstanding anything to the contrary and
regardless of whether a subscriber receives power and energy
service from the electric utility or an alternative retail
electric supplier, the electric utility , an electricity
provider shall provide credits for the electricity produced by
the community renewable generation projects projects described
in paragraph (1) of this subsection (l). The electric utility
electricity provider shall provide credits at the utility's
total price to compare 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). For the purposes of
this subsection, "total price to compare" means the rate or
rates published by the Illinois Commerce Commission for energy
supply for eligible customers receiving supply service from the
electric utility, and shall include energy, capacity,
transmission, and the purchased energy adjustment. The credit
provided by the electric utility shall be adjusted monthly to
reflect the total price to compare of the applicable month but
may never result in a credit equal to less than the total price
to compare as of January 1, 2019. Any applicable credit or
reduction in load obligation from the production of the
community renewable generating projects receiving a credit
under this subsection shall be credited to the electric utility
to offset the cost of providing the credit. To the extent that

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the credit or load obligation reduction does not completely
offset the cost of providing the credit to subscribers of
community renewable generation projects as described in this
subsection the electric utility may recover the remaining costs
through the process established in Section 16-111.8 of this
Act.
(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:
(A) The owner or operator shall, on a monthly basis,
provide to the electric utility the hours 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

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subscribers' electric utility bills. The electric utility
shall be permitted to revise its tariffs to implement the
provisions of this amendatory Act of the 101st General
Assembly 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 in projects
described in subparagraph (A) of this paragraph (3) 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

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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 101st General Assembly 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 101st General Assembly 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,

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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
utility's provider's net metering customers equals 5% of the
total peak demand delivered supplied by that electricity
utility provider during the previous year, as specified in
subsection (j) of this Section, and the Commission has approved
the distributed generation rebate and applicable tariff
following investigation set out in subsection (e) of Section
16-107.6 of this Act, 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, who shall continue to receive net
metering services described in subsections (d), (d-5), (e),
(e-5), and (f) of this Section for the lifetime of the system,
regardless of whether those retail customers change
electricity providers. 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

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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.

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(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

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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

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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.
(o) Within 90 days after the effective date of this
amendatory Act of the 101st General Assembly, each electric
utility subject to this Section shall file a tariff that shall,
consistent with the provisions this Section, propose the terms
and conditions under which an eligible customer may participate
in net metering. The Commission shall approve, or approve with
modification based on stakeholder process, the tariff within
120 days after effective date of this amendatory Act of the
101st General Assembly. Each electric utility shall file any
changes to terms as a subsequent tariff for approval or
approval with modifications from Commission.
(Source: P.A. 99-906, eff. 6-1-17.)
(220 ILCS 5/16-107.6)
Sec. 16-107.6. Distributed generation rebate.

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(a) In this Section:
"Energy storage system" means commercially available
technology that is capable of absorbing energy and storing it
for a period of time for use at a later time, including, but
not limited to, electrochemical, thermal, and
electromechanical technologies, and may be interconnected
behind the customer's meter or interconnected behind its own
meter.
"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 as approved by the Illinois
Commerce Commission.
"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 utility's provider's net metering customers equals
5% of the total peak demand delivered supplied by that
electricity utility provider during the previous year, as
specified under subsection (j) of Section 16-107.5 of this Act.

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(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, hosts, or
operates distributed generation, including third-party-owned
systems, 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

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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
optional for the owner of the distributed generation owner to
activate and, if activated, shall be separately compensated so
as to mitigate loss of revenue to the owner of the distributed
generation for production curtailment or diminishment of real
power output due to the activation of such uses. Such
additional uses shall and which may include, but are not
limited to, voltage and VAR support, voltage watt, frequency
watt, 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

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conditions of the operation and shall approve compensation for
activation of additional uses in a monetary form. The
Commission shall also approve the ability of the utility to
offer compensation to the owner of the distributed generation
owner in the form of reduced project-specific interconnection
upgrades, and the owner of the distributed generation may
choose either the monetary compensation or the reduction in
interconnection upgrades 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. To
the extent the distributed generation system also has a

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storage device as part of the system, and said storage uses
the same smart inverter as the distributed generation, then
the storage shall be separately compensated at $350 per
kilowatt of nameplate capacity. Energy storage nameplate
capacity means the kilowatt-hour of rated AC capacity of
the installed system.
(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. If, on the threshold date, the proceeding

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outlined in subsection (e) of this Section has not
concluded, the utility shall continue to offer
residential customers to maintain net metering as
outlined in Section 16-107.5 until the proceeding
under subsection (e) of this Section has concluded and
the tariff approved as a result of that proceeding is
available.
(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

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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
utility's provider's net metering customers is equal to 3% of
the total peak demand delivered by that utility, the Commission
shall open an investigation into a 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 process and formula for calculating the value of
the rebate available after the threshold date shall be updated
every 5 years, and shall promote continuity in the distributed
generation market. 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

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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

10100SB2080sam004 - 235 - LRB101 11122 RJF 59369 a
(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) The owner of the distributed generation may apply for
the tariff approved under subsection (d) or (e) of this Section
at the time of application for interconnection with the
distribution utility and shall receive the value of the rebate
available at that time. However, the utility shall issue the
rebate no No later than 60 days after the project is energized
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

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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

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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

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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

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order, or order on rehearing, whichever is later, approving an
electric utility's proposed tariff under subsection (d) of this
Section, the electric utility shall provide notice of the
availability of rebates under this Section. Subsequent to the
utility's notice, any entity that offers in the State, for sale
or lease, distributed generation and estimates the dollar
saving attributable to such distributed generation shall
provide estimates based on both delivery service credits and
the rebates available under this Section.
(Source: P.A. 99-906, eff. 6-1-17.)
(220 ILCS 5/16-107.7 new)
Sec. 16-107.7. Energy Storage Program.
(a) Findings. The Illinois General Assembly hereby finds
and declares that:
(1) Energy storage systems provide opportunities to:
(A) reduce costs to ratepayers by avoiding or
deferring the need for investment in new generation and
for upgrades to systems for the transmission and
distribution of energy;
(B) reduce the use of fossil fuels for meeting
demand during peak load periods when charged off-peak
with low-emitting generation;
(C) provide ancillary services;
(D) assist electric regulated electric companies
with integrating sources of renewable energy into the

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grid for the transmission and distribution of
electricity, and with maintaining grid stability;
(E) support diversification of energy resources;
(F) enhance the resilience and reliability of the
electric grid; and
(G) reduce greenhouse gases and other air
pollutants resulting from power generation, thereby
minimizing public health impacts that result from
power generation.
(2) There are significant barriers to obtaining the
benefits of energy storage systems, including inadequate
valuation of energy storage.
(3) It is in the public interest to:
(A) develop a robust competitive market for
existing and new providers of energy storage systems in
order to leverage Illinois' position as a leader in
energy storage systems and to capture the potential for
economic development;
(B) investigate the costs and benefits of energy
storage systems in the State of Illinois and, if such
an investigation indicates that the benefits of energy
storage systems exceed the costs of such systems, to
implement targets and programs to achieve deployment
of energy storage systems; and
(C) modernize distributed generation programs and
interconnection standards to lower costs and

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efficiently deploy energy storage systems in order to
increase economic development and job creation within
the state's emerging clean energy economy.
(b) Definitions. In this Section:
"Bring Your Own Device program" means a utility pilot
program that enables customers to provide grid services to a
utility in exchange for an on-bill credit, upfront payment, or
other contractual agreement.
"Clean peak standard" means a percentage of annual retail
electricity sales during peak hours that an electric utility
must derive from eligible clean energy resources.
"Deployment" means the installation of energy storage
systems through a variety of mechanisms, including utility
procurement, customer installation, or other processes.
"Electric utility" has the same meaning as provided in
Section 16-102 of the Public Utilities Act.
"Energy storage system" means commercially available
technology that is capable of absorbing energy and storing it
for a period of time for use at a later time including, but not
limited to, electrochemical, thermal, and electromechanical
technologies, and may be interconnected behind the customer's
meter or interconnected behind its own meter.
"Non-wires alternatives solicitation" means a utility
solicitation for third-party-owned or utility-owned
distributed energy resource investment that uses
nontraditional solutions to defer or replace planned

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investment on the distribution or transmission system.
(c) Cost-benefit assessment.
(1) The Commission, in consultation with the Illinois
Power Agency, shall study and produce a report analyzing
the potential for energy storage in Illinois, including the
costs and benefits of energy storage systems, as well as
barriers to the development of energy storage in Illinois.
The Illinois Commerce Commission shall engage a broad group
of Illinois stakeholders, including electric utilities,
the energy storage industry, the renewable energy
industry, and others to develop and provide information for
the report.
(2) The study must, at minimum:
(A) Identify and measure the potential costs and
benefits, along with barriers to realizing such
benefits, that the deployment of energy storage
systems can produce, including, but not limited to:
(i) avoided cost and deferred investments in
generation, transmission, and distribution
facilities;
(ii) reduced ancillary services costs;
(iii) reduced transmission and distribution
congestion;
(iv) lower peak power costs and reduce
capacity costs;
(v) reduced costs for emergency power supplies

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during outages;
(vi) reduced curtailment of renewable energy
generators;
(vii) reduced greenhouse gas emissions and
other criteria air pollutants;
(viii) increased grid hosting capacity of
renewable energy generators that produce energy on
an intermittent basis;
(ix) increased reliability and resilience of
the electric grid;
(x) increased resource diversification;
(xi) increased economic development; and
(xii) electric utility costs associated with
the integration of energy storage on the grid.
(B) Analyze and estimate:
(i) the impact on the system's ability to
integrate renewable resources;
(ii) the benefits of addition of storage at
existing peaking units;
(iii) the impact on grid reliability and power
quality; and
(iv) the effect on retail electric rates over
the useful life of a given energy storage system
compared to providing the same services using
other facilities or resources.
(C) Evaluate and identify cost-effective policies

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and programs to support the deployment of energy
storage systems, including, but not limited to:
(i) rebate programs;
(ii) clean peak standards;
(iii) non-wires alternative solicitation;
(iv) bring Your Own Device Program;
(v) contracted demand-response programs,
similar to the California Demand Response Auction
Mechanisms (DRAM);
(vi) tax incentives; and
(vii) procurement by the Illinois Power Agency
of energy storage resources.
(D) Make a recommendation on appropriate energy
storage deployment targets, including, but not limited
to:
(i) achieving a minimum of 1,000 MW of energy
storage systems by 2030 and more as identified in
the outcome of the energy storage systems
cost-benefit study required under subparagraph (C)
of paragraph (2) of this subsection (c);
(ii) adopting specific sub-categories of
deployment of systems by point of interconnection,
including customer-connected,
distribution-connected, and
transmission-connected;
(iii) adopting requirements or processes by

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the Illinois Power Agency for competitive
deployment of energy storage services from third
parties; and
(iv) appropriate accountability mechanisms.
(3) By December 31, 2019, the findings and
recommendations for the programs, policies, and funding
levels to meet the energy storage deployment targets from
this study shall be submitted to the General Assembly and
the Governor for consideration and appropriate action.
The Illinois Power Agency shall include a plan to procure
energy from energy storage resources pursuant to the results of
this study as part of its Procurement Plan for 2021. An
electric utility shall file tariffs directed by the Commission
to recover from its retail customers the costs associated with
the procurement of energy storage 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

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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

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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

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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

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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

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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

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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

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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

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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

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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

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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

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

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which shall appear as a separate line item on each such
customer's bill.
Notwithstanding whether the Commission has approved the
initial long-term renewable resources procurement plan as of
June 1, 2017, an electric utility shall place new tariffed
charges into effect beginning with the June 2017 monthly
billing period, to the extent practicable, to begin recovering
the costs of procuring renewable energy resources, as those
charges are calculated under the limitations described in
subparagraph (E) of paragraph (1) of subsection (c) of Section
1-75 of the Illinois Power Agency Act. Notwithstanding the date
on which the utility places such new tariffed charges into
effect, the utility shall be permitted to collect the charges
under such tariff as if the tariff had been in effect beginning
with the first day of the June 2017 monthly billing period. For
the delivery years commencing June 1, 2017, through June 1,
2037 June 1, 2018, and June 1, 2019, the electric utility shall
deposit into a separate interest bearing account of a financial
institution the monies collected under the tariffed charges.
Any interest earned shall be credited back to retail customers
under the reconciliation proceeding provided for in this
subsection (k), provided that the electric utility shall first
be reimbursed from the interest for the administrative costs
that it incurs to administer and manage the account. Any taxes
due on the funds in the account, or interest earned on it, will
be paid from the account or, if insufficient monies are

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

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that shall be approved by the Commission in connection with its
approval of such tariffs. The procedure shall provide that any
difference between the electric utility's collections under
the automatic adjustment charges for an annual period and the
electric utility's actual costs of renewable energy resources
and zero emission credits from zero emission facilities for
that same annual period shall be refunded to or collected from,
as applicable, the electric utility's retail customers in
subsequent periods.
Nothing in this subsection (k) is intended to affect,
limit, or change the right of the electric utility to recover
the costs associated with the procurement of renewable energy
resources for periods commencing before, on, or after June 1,
2017, as otherwise provided in the Illinois Power Agency Act.
Notwithstanding anything to the contrary, the Commission
shall not conduct an annual review, reconciliation, and true-up
associated with renewable energy resources' collections and
costs for the delivery years commencing June 1, 2017 through
June 1, 2037 , June 1, 2018, June 1, 2019, and June 1, 2020, and
shall instead conduct a single review, reconciliation, and
true-up associated with renewable energy resources'
collections and costs for the 20-year 4-year period beginning
June 1, 2017 and ending May 31, 2037 2021, provided that the
review, reconciliation, and true-up shall not be initiated
until after August 31, 2037 2021. During the 20-year 4-year
period, the utility shall be permitted to collect and retain

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

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

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

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

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

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(4) The electric utility shall file a notice with the
Commission on May 1 of 2018 and each May 1 thereafter until
May 1, 2026 containing the reduction, if any, which must be
applied for the delivery year which begins in the year of
the filing. The notice shall contain the calculations made
pursuant to this Section. By October 1 of each year
beginning in 2018, each electric utility shall notify the
Commission if it appears, based on an estimate of the
calculation required in this subsection (m), that a
reduction will be required in the next year.
(Source: P.A. 99-906, eff. 6-1-17.)
(220 ILCS 5/16-111.5)
Sec. 16-111.5. Provisions relating to procurement.
(a) An electric utility that on December 31, 2005 served at
least 100,000 customers in Illinois shall procure power and
energy for its eligible retail customers in accordance with the
applicable provisions set forth in Section 1-75 of the Illinois
Power Agency Act and this Section. Beginning with the delivery
year commencing on June 1, 2017, such electric utility shall
also procure zero emission credits from zero emission
facilities in accordance with the applicable provisions set
forth in Section 1-75 of the Illinois Power Agency Act, and,
for years beginning on or after June 1, 2017, the utility shall
procure renewable energy resources in accordance with the
applicable provisions set forth in Section 1-75 of the Illinois

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Power Agency Act and this Section. A small multi-jurisdictional
electric utility that on December 31, 2005 served less than
100,000 customers in Illinois may elect to procure power and
energy for all or a portion of its eligible Illinois retail
customers in accordance with the applicable provisions set
forth in this Section and Section 1-75 of the Illinois Power
Agency Act. This Section shall not apply to a small
multi-jurisdictional utility until such time as a small
multi-jurisdictional utility requests the Illinois Power
Agency to prepare a procurement plan for its eligible retail
customers. "Eligible retail customers" for the purposes of this
Section means those retail customers that purchase power and
energy from the electric utility under fixed-price bundled
service tariffs, other than those retail customers whose
service is declared or deemed competitive under Section 16-113
and those other customer groups specified in this Section,
including self-generating customers, customers electing hourly
pricing, or those customers who are otherwise ineligible for
fixed-price bundled tariff service. For those customers that
are excluded from the procurement plan's electric supply
service requirements, and the utility shall procure any supply
requirements, including capacity, ancillary services, and
hourly priced energy, in the applicable markets as needed to
serve those customers, provided that the utility may include in
its procurement plan load requirements for the load that is
associated with those retail customers whose service has been

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declared or deemed competitive pursuant to Section 16-113 of
this Act to the extent that those customers are purchasing
power and energy during one of the transition periods
identified in subsection (b) of Section 16-113 of this Act.
(b) A procurement plan shall be prepared for each electric
utility consistent with the applicable requirements of the
Illinois Power Agency Act and this Section. For purposes of
this Section, Illinois electric utilities that are affiliated
by virtue of a common parent company are considered to be a
single electric utility. Small multi-jurisdictional utilities
may request a procurement plan for a portion of or all of its
Illinois load. Each procurement plan shall analyze the
projected balance of supply and demand for those retail
customers to be included in the plan's electric supply service
requirements over a 5-year period, with the first planning year
beginning on June 1 of the year following the year in which the
plan is filed. The plan shall specifically identify the
wholesale products to be procured following plan approval, and
shall follow all the requirements set forth in the Public
Utilities Act and all applicable State and federal laws,
statutes, rules, or regulations, as well as Commission orders.
Nothing in this Section precludes consideration of contracts
longer than 5 years and related forecast data. Unless specified
otherwise in this Section, in the procurement plan or in the
implementing tariff, any procurement occurring in accordance
with this plan shall be competitively bid through a request for

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proposals process. Approval and implementation of the
procurement plan shall be subject to review and approval by the
Commission according to the provisions set forth in this
Section. A procurement plan shall include each of the following
components:
(1) Hourly load analysis. This analysis shall include:
(i) multi-year historical analysis of hourly
loads;
(ii) switching trends and competitive retail
market analysis;
(iii) known or projected changes to future loads;
and
(iv) growth forecasts by customer class.
(2) Analysis of the impact of any demand side and
renewable energy initiatives. This analysis shall include:
(i) the impact of demand response programs and
energy efficiency programs, both current and
projected; for small multi-jurisdictional utilities,
the impact of demand response and energy efficiency
programs approved pursuant to Section 8-408 of this
Act, both current and projected; and
(ii) supply side needs that are projected to be
offset by purchases of renewable energy resources, if
any.
(3) A plan for meeting the expected load requirements
that will not be met through preexisting contracts. This

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plan shall include:
(i) definitions of the different Illinois retail
customer classes for which supply is being purchased;
(ii) the proposed mix of demand-response products
for which contracts will be executed during the next
year. For small multi-jurisdictional electric
utilities that on December 31, 2005 served fewer than
100,000 customers in Illinois, these shall be defined
as demand-response products offered in an energy
efficiency plan approved pursuant to Section 8-408 of
this Act. The cost-effective demand-response measures
shall be procured whenever the cost is lower than
procuring comparable capacity products, provided that
such products shall:
(A) be procured by a demand-response provider
from those retail customers included in the plan's
electric supply service requirements;
(B) at least satisfy the demand-response
requirements of the regional transmission
organization market in which the utility's service
territory is located, including, but not limited
to, any applicable capacity or dispatch
requirements;
(C) provide for customers' participation in
the stream of benefits produced by the
demand-response products;

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(D) provide for reimbursement by the
demand-response provider of the utility for any
costs incurred as a result of the failure of the
supplier of such products to perform its
obligations thereunder; and
(E) meet the same credit requirements as apply
to suppliers of capacity, in the applicable
regional transmission organization market;
(iii) monthly forecasted system supply
requirements, including expected minimum, maximum, and
average values for the planning period;
(iv) the proposed mix and selection of standard
wholesale products for which contracts will be
executed during the next year, separately or in
combination, to meet that portion of its load
requirements not met through pre-existing contracts,
including but not limited to monthly 5 x 16 peak period
block energy, monthly off-peak wrap energy, monthly 7 x
24 energy, annual 5 x 16 energy, annual off-peak wrap
energy, annual 7 x 24 energy, monthly capacity, annual
capacity, peak load capacity obligations, capacity
purchase plan, and ancillary services;
(v) proposed term structures for each wholesale
product type included in the proposed procurement plan
portfolio of products; and
(vi) an assessment of the price risk, load

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uncertainty, and other factors that are associated
with the proposed procurement plan; this assessment,
to the extent possible, shall include an analysis of
the following factors: contract terms, time frames for
securing products or services, fuel costs, weather
patterns, transmission costs, market conditions, and
the governmental regulatory environment; the proposed
procurement plan shall also identify alternatives for
those portfolio measures that are identified as having
significant price risk.
(4) Proposed procedures for balancing loads. The
procurement plan shall include, for load requirements
included in the procurement plan, the process for (i)
hourly balancing of supply and demand and (ii) the criteria
for portfolio re-balancing in the event of significant
shifts in load.
(5) Long-Term Renewable Resources Procurement Plan.
The Agency shall prepare a long-term renewable resources
procurement plan for the procurement of renewable energy
credits under Sections 1-56 and 1-75 of the Illinois Power
Agency Act for delivery beginning in the 2017 delivery
year.
(i) The initial long-term renewable resources
procurement plan and all subsequent revisions shall be
subject to review and approval by the Commission. For
the purposes of this Section, "delivery year" has the

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same meaning as in Section 1-10 of the Illinois Power
Agency Act. For purposes of this Section, "Agency"
shall mean the Illinois Power Agency.
(ii) The long-term renewable resources planning
process shall be conducted as follows:
(A) Electric utilities shall provide a range
of load forecasts to the Illinois Power Agency
within 45 days of the Agency's request for
forecasts, which request shall specify the length
and conditions for the forecasts including, but
not limited to, the quantity of distributed
generation expected to be interconnected for each
year.
(B) The Agency shall publish for comment the
initial long-term renewable resources procurement
plan no later than 120 days after the effective
date of this amendatory Act of the 99th General
Assembly and shall review, and may revise, the plan
at least every 2 years thereafter, with the final
plan issued no later than September 15 of any
particular year. To the extent practicable, the
Agency shall review and propose any revisions to
the long-term renewable energy resources
procurement plan in conjunction with the Agency's
other planning and approval processes conducted
under this Section. The initial long-term

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renewable resources procurement plan shall:
(aa) Identify the procurement programs and
competitive procurement events consistent with
the applicable requirements of the Illinois
Power Agency Act and shall be designed to
achieve the goals set forth in subsection (c)
of Section 1-75 of that Act.
(bb) Include a schedule for procurements
for renewable energy credits from
utility-scale wind projects, utility-scale
solar projects, and brownfield site
photovoltaic projects consistent with
subparagraph (G) of paragraph (1) of
subsection (c) of Section 1-75 of the Illinois
Power Agency Act.
(cc) Identify the process whereby the
Agency will submit to the Commission for review
and approval the proposed contracts to
implement the programs required by such plan.
Copies of the initial long-term renewable
resources procurement plan and all subsequent
revisions shall be posted and made publicly
available on the Agency's and Commission's
websites, and copies shall also be provided to each
affected electric utility. An affected utility and
other interested parties shall have 45 days

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

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

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

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of subsection (c) of Section 1-75 of the Illinois Power
Agency Act and subsection (k) of Section 16-108 of this
Act, and contracts executed under this Section shall
expressly incorporate this limitation.
(v) For the public interest, safety, and welfare,
the Agency and the Commission may adopt rules to carry
out the provisions of this Section on an emergency
basis immediately following the effective date of this
amendatory Act of the 99th General Assembly.
(vi) On or before July 1 of each year, the
Commission shall hold an informal hearing for the
purpose of receiving comments on the prior year's
procurement process and any recommendations for
change.
(vii) As part of the long-term renewable resources
procurement plan for the 2019 delivery year or within
30 days after the effective date of this amendatory Act
of the 101st General Assembly, whichever comes first,
and each revision thereafter, the Illinois Power
Agency and its consultant or consultants shall engage
stakeholders in a retrospective evaluation of the
design and implementation of the Adjustable Block
program. Specifically, the evaluation shall address:
(A) Interdependencies between the Adjustable
Block program and interconnection standards,
tariffs, and processes addressed or directed in

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Section 16-107.5.
(B) Revisions to the Adjustable Block program
and interconnection standards, tariffs, and
processes that will facilitate implementation of
the Adjustable Block program.
(C) Ensuring that the objectives stated in
subparagraph (K) of paragraph (1) of subsection
(c) of Section 1-75 of the Illinois Power Agency
Act, as well as subsection (h) of Section 16-107.5
of this Act are met.
The results of this evaluation shall be used by the
Illinois Power Agency to amend the Adjustable Block
program accordingly.
(c) The procurement process set forth in Section 1-75 of
the Illinois Power Agency Act and subsection (e) of this
Section shall be administered by a procurement administrator
and monitored by a procurement monitor.
(1) The procurement administrator shall:
(i) design the final procurement process in
accordance with Section 1-75 of the Illinois Power
Agency Act and subsection (e) of this Section following
Commission approval of the procurement plan;
(ii) develop benchmarks in accordance with
subsection (e)(3) to be used to evaluate bids; these
benchmarks shall be submitted to the Commission for
review and approval on a confidential basis prior to

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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plan costs. The electric utility shall also recover its full
costs of procuring electric supply for which it contracted
before the effective date of this Section in conjunction with
the provision of full requirements service under fixed-price
bundled service tariffs subsequent to December 31, 2006. All
such costs shall be deemed to have been prudently incurred. The
pass-through tariffs that are filed and approved pursuant to
this Section shall not be subject to review under, or in any
way limited by, Section 16-111(i) of this Act. All of the costs
incurred by the electric utility associated with the purchase
of zero emission credits in accordance with subsection (d-5) of
Section 1-75 of the Illinois Power Agency Act and, beginning
June 1, 2017, all of the costs incurred by the electric utility
associated with the purchase of renewable energy resources in
accordance with Sections 1-56 and 1-75 of the Illinois Power
Agency Act, shall be recovered through the electric utility's
tariffed charges applicable to all of its retail customers, as
specified in subsection (k) of Section 16-108 of this Act, and
shall not be recovered through the electric utility's tariffed
charges for electric power and energy supply to its eligible
retail customers.
(m) The Commission has the authority to adopt rules to
carry out the provisions of this Section. For the public
interest, safety, and welfare, the Commission also has
authority to adopt rules to carry out the provisions of this
Section on an emergency basis immediately following August 28,

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2007 (the effective date of Public Act 95-481).
(n) Notwithstanding any other provision of this Act, any
affiliated electric utilities that submit a single procurement
plan covering their combined needs may procure for those
combined needs in conjunction with that plan, and may enter
jointly into power supply contracts, purchases, and other
procurement arrangements, and allocate capacity and energy and
cost responsibility therefor among themselves in proportion to
their requirements.
(o) On or before June 1 of each year, the Commission shall
hold an informal hearing for the purpose of receiving comments
on the prior year's procurement process and any recommendations
for change.
(p) An electric utility subject to this Section may propose
to invest, lease, own, or operate an electric generation
facility as part of its procurement plan, provided the utility
demonstrates that such facility is the least-cost option to
provide electric service to those retail customers included in
the plan's electric supply service requirements. If the
facility is shown to be the least-cost option and is included
in a procurement plan prepared in accordance with Section 1-75
of the Illinois Power Agency Act and this Section, then the
electric utility shall make a filing pursuant to Section 8-406
of this Act, and may request of the Commission any statutory
relief required thereunder. If the Commission grants all of the
necessary approvals for the proposed facility, such supply

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

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

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than the procurement of renewable energy credits for
distributed renewable energy generation devices.
(Source: P.A. 99-906, eff. 6-1-17.)
Article 10.
Section 10-1. This Article may be referred to as the Coal
to Solar and Energy Storage Act.
Section 10-5. Legislative findings. The General Assembly
finds and declares:
(1) The overall objectives of regulation of the
electric utility industry in this State, as expressed by
the General Assembly in the Illinois Power Agency Act and
the Public Utilities Act, include the provision of
adequate, efficient, reliable, environmentally safe, and
least-cost utility services at prices that accurately
reflect the long-term cost of such services and which are
equitable to all citizens.
(2) For many years, a significant portion of the
electricity consumed by consumers and businesses in this
State, particularly in the downstate region of this State,
has been produced by large electric generating stations,
located in the downstate region, that burn coal as their
primary source of fuel. Further, these electric generating
stations are typically available to provide electricity to

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serve the demands of retail customers 24 hours per day, 7
days per week, without regard to natural conditions such as
wind speeds or the hours in which solar energy is
available.
(3) The electric generating stations located in the
downstate region of this State are, and have been for many
years, significant sources of employment, economic
activity, and tax revenues for the communities and
surrounding areas in which they are located; in many cases,
these electric generating stations are the largest
employers in the communities in which they are located and
the largest property taxpayers to the school districts,
municipalities, counties, and other units of local
government in which the generating stations are located.
(4) In recent years, the prices for electric generating
capacity and electric energy available to coal-fueled
electric generating stations located in the downstate
region of this State have not been sufficient to enable
some electric generating facilities located within the
downstate region to remain in operation, and has placed
other electric generating stations in the downstate region
at economic risk of closure.
(5) Additionally, the burning of coal as a fuel to
generate electricity has been cited by some academic,
governmental, and other sources as a cause of potential
environmental damage, particularly through the production

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and release of carbon dioxide as a by-product and due to
issues associated with the storage and disposition of ash
resulting from the combustion of coal.
(6) Since 2015, electric generating facilities located
in the downstate region with generating capacity, in the
aggregate, of more than 1,700 megawatts have been
permanently retired so that this capacity is no longer
available to serve the demands of Illinois electricity
consumers. It is estimated that additional electric
generating facilities located in the downstate region with
generating capacity, in the aggregate, of at least 3,000
megawatts is currently at risk of retirement in light of
low prices for electric generating capacity and electric
energy prevailing in Load Zone 4 of the Midcontinent
Independent System Operator, Inc. The vast majority of
these retired, mothballed, and at-risk electric generating
facilities in the downstate region burn or burned coal as
their primary fuel source for the generation of
electricity.
(7) To a significant extent, as the existing bulk power
system is configured, electricity, when generated, cannot
be stored for future use. Rather, for the most part,
electricity must be generated instantaneously at the time
and in the amount that it is demanded by residential and
business consumers. This characteristic of the existing
bulk power system is unlikely to change significantly in

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the near term. This requires that there be sufficient
generating capacity available and ready to produce
electricity to meet the demands of consumers within each
load zone in this State, 24 hours per day, 7 days per week,
on every day of the year. Reliable electric service at all
times is essential to the functioning of a modern economy
and of society in general. The health, welfare, and
prosperity of Illinois citizens, including the
attractiveness of the State of Illinois to business and
industry, requires the availability of sufficient electric
generating capacity to meet the demands of consumers and
businesses in this State at all times.
(8) In the near term, there is uncertainty as to the
sufficiency of electric generating resources to reliably
serve the electric capacity and energy needs of residential
and business electricity customers in the downstate
region, particularly in light of the large amount of
coal-fueled electric generating resources in the downstate
region that are economically at risk and may retire in the
near future. Both the Midcontinent Independent System
Operator, Inc., which is the independent transmission
system operator for downstate Illinois, and its
Independent Market Monitor, have expressed concerns about
the sufficiency of electric generating resources in
downstate Illinois overall the next several years, due
primarily to the possibility of additional retirements of

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coal-fueled electric generating facilities and concerns
about how quickly and extensively new wind and photovoltaic
generating facilities will be placed into service.
Concerns have also been expressed, based on the
intermittent nature of wind and solar generating
facilities, as to whether the grid can operate reliably
without sufficient dispatchable generation resources or
energy storage to balance the output of renewable
generating facilities. Other commentators have stated that
such concerns about resource adequacy in downstate
Illinois are overstated. However, the General Assembly
believes that the State cannot afford to find itself in a
situation of insufficient electric generating resources to
meet the needs of Illinois residential and business
consumers.
(9) Consistent with the overall objectives of the
regulation of the electric utility industry in this State,
regulation should ensure that sufficient generating
capacity resources are available on both a short-term basis
and a long-term basis to enable the electric utility grid
to meet the demands of Illinois electricity consumers at
all times.
(10) Through previous enactments beginning in 1997,
the General Assembly has mandated that electric utilities
and other load-serving entities in this State obtain
specified portions of the electric energy needed to serve

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their retail loads in this State through the procurement of
electricity or renewable energy credits from renewable
energy resources, among other means through procurement
events managed and supervised by the Illinois Power Agency.
(11) Correspondingly, through previous enactments
beginning in 1997, the General Assembly has provided
incentives for the construction and operation of wind,
photovoltaic, and other types of renewable energy
resources to serve load in Illinois, and has mandated the
imposition of charges to retail customers, subject to caps,
to fund the procurement of electricity and renewable energy
credits from such facilities. In such enactments, the
General Assembly has recognized that providing
opportunities to enter into long-term contracts for the
purchase of electricity and/or renewable energy credits
from renewable energy resources creates incentives for the
construction and operation of such resources.
(12) However, the permitting and siting of new wind and
photovoltaic generating resources in Illinois is subject
to local governmental control, rather than State control,
and in many areas of this State, there has been strong
opposition to the siting and construction of new
utility-scale wind and photovoltaic generating resources,
which in turn has resulted in the denial of, or withdrawal
of requests for, necessary approvals for some projects and
the enactment of local zoning ordinances imposing

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requirements and restrictions that increase the costs and
reduce the economic attractiveness of such projects. This
has resulted in the delay or cancellation of a number of
new renewable energy resource projects.
(13) In light of the intermittent nature of many types
of renewable energy resources, such as wind and
photovoltaic generation resources, the installation and
operation of electricity storage facilities in conjunction
with installation and operation of renewable generation
resources can enhance the value of such resources to the
electric grid, particularly as a source of electric
capacity as well as electric energy.
(14) Through legislation enacted in 2016, the General
Assembly, through the program commonly referred to as the
zero emission credit program, has provided for the
continued economic viability of certain
economically-challenged electric generating facilities in
Illinois that are also significant employers and
taxpayers, through requiring certain Illinois electric
utilities to purchase specified amounts of zero emission
credits from these generating facilities, with such
purchases to be funded through an additional charge to the
electric utilities' retail customers as specified in the
legislation.
(15) Many of the large electric generating stations
located in the downstate region of this State have existing

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infrastructure and other characteristics which make them
suitable sites for development of new renewable energy
resources, including large amounts of available land
situated at a suitable distance from inhabited areas, and
high voltage interconnections to the bulk electric system
transmission grid.
(16) It is appropriate for the State of Illinois to
establish a program to provide for incentives for the
installation and operation of new renewable energy
resources at the sites of existing coal-fueled electric
generating facilities in the downstate region of this
State, to provide incentives for continued operation, in
the near term, of some portion of the coal-fueled
generating facilities in the downstate region to ensure the
availability of sufficient electric capacity and energy
resources to meet the demands of residential and business
electricity consumers in the downstate region as well as in
the State as a whole, while at the same time also providing
incentives for the transition to retirement of some
additional portion of the electric generating facilities
in the downstate region that burn coal as their fuel
source.
Section 10-10. The Illinois Power Agency Act is amended by
changing Sections 1-20 and 1-75 as follows:

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(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 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

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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.
(2.10) Oversee the procurement, by electric utilities
serving more than 300,000 customers in this State as of
January 1, 2019, of renewable energy credits from new
renewable energy resources to be installed at the sites of
electric generating facilities that burned coal as their
primary fuel source as of January 1, 2019, in accordance
with subsection (c-5) of Section 1-75 of this Act.

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(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,

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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

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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.

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(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.

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(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

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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. 99-906, eff. 6-1-17.)
(20 ILCS 3855/1-75)
Sec. 1-75. Planning and Procurement Bureau. The Planning
and Procurement Bureau has the following duties and
responsibilities:
(a) The Planning and Procurement Bureau shall each year,
beginning in 2008, develop procurement plans and conduct
competitive procurement processes in accordance with the
requirements of Section 16-111.5 of the Public Utilities Act
for the eligible retail customers of electric utilities that on
December 31, 2005 provided electric service to at least 100,000
customers in Illinois. Beginning with the delivery year
commencing on June 1, 2017, the Planning and Procurement Bureau
shall develop plans and processes for the procurement of zero
emission credits from zero emission facilities in accordance
with the requirements of subsection (d-5) of this Section. The
Planning and Procurement Bureau shall also develop procurement
plans and conduct competitive procurement processes in

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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.
In accordance with subsection (c-5) of this Section, the
Planning and Procurement Bureau shall oversee the procurement
by electric utilities serving more than 300,000 retail
customers in this State as of January 1, 2019 of renewable
energy credits from new renewable energy resources to be
installed at the sites of electric generating facilities that

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as of January 1, 2019, burned coal as their primary fuel
source.
(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

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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

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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.

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(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

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customers in the State of Illinois, and for eligible Illinois
retail customers of small multi-jurisdictional electric
utilities that (i) on December 31, 2005 served less than
100,000 customers in Illinois and (ii) request a procurement
plan for their Illinois jurisdictional load.
(c) Renewable portfolio standard.
(1)(A) The Agency shall develop a long-term renewable
resources procurement plan that shall include procurement
programs and competitive procurement events necessary to
meet the goals set forth in this subsection (c). The
initial long-term renewable resources procurement plan
shall be released for comment no later than 160 days after
June 1, 2017 (the effective date of Public Act 99-906). The
Agency shall review, and may revise on an expedited basis,
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:

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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

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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

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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

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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

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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),

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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 June 1, 2017 (the effective date of Public
Act 99-906).
(E) For purposes of this subsection (c), the required
procurement of cost-effective renewable energy resources
for a particular year commencing prior to June 1, 2017
shall be measured as a percentage of the actual amount of
electricity (megawatt-hours) supplied by the electric
utility to eligible retail customers in the delivery year
ending immediately prior to the procurement, and, for
delivery years commencing on and after June 1, 2017, the
required procurement of cost-effective renewable energy
resources for a particular year shall be measured as a
percentage of the actual amount of electricity

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(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

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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

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Program, as described in subparagraph (O) of this
paragraph (1);
(ii) renewable energy credits necessary to comply
with the new wind and new photovoltaic procurement
requirements described in items (i) through (iii) of
subparagraph (C) of this paragraph (1); and
(iii) renewable energy credits necessary to meet
the remaining requirements of this subsection (c).
(G) The following provisions shall apply to the
Agency's procurement of renewable energy credits under
this subsection (c):
(i) Notwithstanding whether a long-term renewable
resources procurement plan has been approved, the
Agency shall conduct an initial forward procurement
for renewable energy credits from new utility-scale
wind projects within 160 days after June 1, 2017 (the
effective date of Public Act 99-906). For the purposes
of this initial forward procurement, the Agency shall
solicit 15-year contracts for delivery of 1,000,000
renewable energy credits delivered annually from new
utility-scale wind projects to begin delivery on June
1, 2019, if available, but not later than June 1, 2021.
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

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to all renewable energy goals in this subsection (c).
(ii) Notwithstanding whether a long-term renewable
resources procurement plan has been approved, the
Agency shall conduct an initial forward procurement
for renewable energy credits from new utility-scale
solar projects and brownfield site photovoltaic
projects within one year after June 1, 2017 (the
effective date of Public Act 99-906). For the purposes
of this initial forward procurement, the Agency shall
solicit 15-year contracts for delivery of 1,000,000
renewable energy credits delivered annually from new
utility-scale solar projects and brownfield site
photovoltaic projects to begin delivery on June 1,
2019, if available, but not later than June 1, 2021.
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

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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

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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

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given delivery year shall be reduced as described in this
subparagraph (H) if an alternative retail electric
supplier meets the requirements described in this
subparagraph (H).
(i) Within 45 days after June 1, 2017 (the
effective date of Public Act 99-906), an alternative
retail electric supplier or its successor shall submit
an informational filing to the Illinois Commerce
Commission certifying that, as of December 31, 2015,
the alternative retail electric supplier owned one or
more electric generating facilities that generates
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

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alternative retail electric supplier.
(iii) The alternative retail electric supplier
shall notify the Agency and the applicable utility, no
later than February 28 of the year preceding the
applicable delivery year or 15 days after June 1, 2017
(the effective date of Public Act 99-906), whichever is
later, of its election under item (ii) of this
subparagraph (H) to supply renewable energy credits to
retail customers of the utility. Such election shall
identify the amount of renewable energy credits to be
supplied by the alternative retail electric supplier
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.

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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%

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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

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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

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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

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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

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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

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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

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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.

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(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

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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

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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

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"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

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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

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subparagraph (O), the Commission shall consider the
experience and performance under the programs and any
evaluation reports. The Commission shall also provide for
an independent evaluation of those programs on a periodic
basis that are funded under this subparagraph (O).
(2) (Blank).
(3) (Blank).
(4) The electric utility shall retire all renewable
energy credits used to comply with the standard.
(5) Beginning with the 2010 delivery year and ending
June 1, 2017, an electric utility subject to this
subsection (c) shall apply the lesser of the maximum
alternative compliance payment rate or the most recent
estimated alternative compliance payment rate for its
service territory for the corresponding compliance period,
established pursuant to subsection (d) of Section 16-115D
of the Public Utilities Act to its retail customers that
take service pursuant to the electric utility's hourly
pricing tariff or tariffs. The electric utility shall
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.

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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 June 1, 2017
(the effective date of Public Act 99-906) must be procured
from devices installed by a qualified person in compliance
with the requirements of Section 16-128A of the Public
Utilities Act and any rules or regulations adopted
thereunder.

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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.
(c-5) Procurement of renewable energy credits from new
renewable energy resources installed at the sites of electric
generating facilities that burn coal as their primary fuel
source.
(1) In addition to the procurement of renewable energy
credits pursuant to long-term renewable resources
procurement plans in accordance with subsection (c) of this
Section and Section 16-111.5 of the Public Utilities Act,
the Agency shall conduct a procurement event in accordance
with this subsection (c-5) for the procurement, by electric
utilities serving more than 300,000 retail customers in
this State as of January 1, 2019, of renewable energy
credits from new renewable energy resources to be installed
at the sites of electric generating facilities that, as of
January 1, 2019, burned coal as their primary fuel source.
The renewable energy credits procured pursuant to this

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subsection (c-5) shall not be included or counted for
purposes of compliance with the amounts of renewable energy
credits required to be procured pursuant to subsection (c)
of this Section. The procurement of renewable energy
credits by electric utilities pursuant to this subsection
(c-5) shall be funded solely by revenues collected from the
Coal to Solar Energy Storage Initiative Charge provided for
in this subsection (c-5) and subsection (i-5) of Section
16-108 of the Public Utilities Act and shall not be funded
by revenues collected through any of the other funding
mechanisms provided for in subsection (c) of this Section.
(2) No later than September 30, 2019, the Agency shall
conduct a procurement event to select owners of electric
generating facilities meeting the eligibility criteria
specified in this subsection (c-5) to enter into long-term
contracts to sell renewable energy credits to electric
utilities serving more than 300,000 retail customers in
this State. The Agency shall establish and announce a time
period, which shall begin no later than 30 days prior to
the scheduled date for the procurement event, during which
applicants may submit applications to be selected as
suppliers of renewable energy credits pursuant to this
subsection (c-5). The eligibility criteria for selection
as a supplier of renewable energy credits pursuant to this
subsection (c-5) shall be as follows:
(A) The applicant owns and operates an electric

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generating facility located in this State and south of
federal Interstate Highway 80 that (i) as of January 1,
2019, burned coal as its primary fuel to generate
electricity and (ii) has an electric generating
capacity of at least 150 megawatts.
(B) The applicant is not (i) a public utility as
defined in Section 3-105 of the Public Utilities Act,
(ii) an electric cooperative as defined in Section
3-119 of the Public Utilities Act, or (iii) an entity
described in subsection (b)(1) of Section 3-105 of the
Public Utilities Act, or an association or consortium
of or an entity owned by entities described in (ii) or
(iii).
(C) The applicant proposes and commits to
construct and operate, at the site, or on property
immediately adjacent to the existing property, of the
electric generating facility identified in paragraph
(A), (i) a new renewable energy resource of at least 20
megawatts but no more than 100 megawatts of electric
generating capacity, and (ii) an energy storage
facility to be operated in conjunction with the new
renewable energy resource and having a storage
capacity in megawatthours equal to or greater than the
product of the electric generating capacity of the new
renewable energy resource in megawatts times 0.5.
(D) The applicant and its ultimate parent company

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commit that by the year ended December 31, 2030,
aggregate annual carbon dioxide emissions from the
electric generating facilities that the applicant and
its corporate affiliates owned in this State on January
1, 2019, including electric generating facilities
retired or otherwise taken out of operation between
January 1, 2006 and December 31, 2018, but still owned
by the applicant or a corporate affiliate on January 1,
2019, will be reduced by at least 75% from the
aggregate annual carbon dioxide emissions of those
electric generating facilities for the year ended
December 31, 2005.
(E) The applicant agrees that (i) the new renewable
energy resource and the energy storage facility will be
constructed or installed by a qualified person or
persons in compliance with the requirements of
subsection (g) of Section 16-128A of the Public
Utilities Act and any rules or regulations adopted
thereunder, and (ii) the personnel operating the new
renewable energy resource and the energy storage
facility will have the requisite skills, knowledge,
training, experience, and competence consistent with
subsection (a) of Section 16-128 of the Public
Utilities Act, including through training and
education courses and opportunities offered by the
applicant to employees of the coal-fueled generating

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facilities being retired.
(F) The applicant and its ultimate parent company,
if any, commits that no earlier than January 1, 2025,
and no later than December 31, 2030, the applicant or a
company owned by the same parent company as the
applicant will permanently retire electric generating
facilities located in this State that burn coal as
their primary fuel source and have, in the aggregate,
electric generating capacity, in megawatts, equal to
at least 5 times the electric generating capacity, in
megawatts, of the new renewable energy resource to be
constructed in accordance with paragraph (C). The
applicant may include in the amount of capacity of
coal-fueled electric generating facilities required to
be retired coal-fueled electric generating facilities
in Illinois that the applicant or a company owned by
the same ultimate parent company commits or elects to
retire prior to January 1, 2025, as required by, as a
result of, or in connection with the adoption of a new
or amended regulation of the Illinois Environmental
Protection Agency pertaining to the Multipollutant
Settlement Rule in Illinois Pollution Control Board
Docket no. Rl8-20 or an order of the Illinois Pollution
Control Board adopting or approving such regulation.
If a coal-fueled electric generating facility that is
designated pursuant to this paragraph for retirement

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no earlier than January 1, 2025 is required, prior to
January 1, 2025, either (i) to make capital
expenditures of at least $10,000,000 in order to remain
in or attain compliance with any environmental law or
regulation, or (ii) to make capital expenditures for
purposes other than environmental compliance of at
least $10,000,000 that were neither known or
reasonably foreseeable as of September 1, 2019, then
such coal-fueled electric generating facility may be
retired by December 31 of the year prior to the year in
which such capital expenditures must be incurred.
(G) The applicant commits to enter into a contract
or contracts of 15 years duration to provide renewable
energy credits to electric utilities serving more than
300,000 retail customers in this State as of January 1,
2019, at a price of $35 per renewable energy credit,
with the amount of renewable energy credits to be
supplied during each year of the contract term to be
equal to or greater than the product of the electric
generating capacity of the new renewable energy
resource in megawatts times 8,760 hours times 0.22.
(H) The applicant's application is certified by
the President or Chief Executive Officer of the
applicant and by the President or Chief Executive
Officer of the applicant's ultimate parent company, if
any.

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(3) An applicant may submit applications to contract to
supply renewable energy credits from more than one new
renewable energy resource to be constructed at more than
one qualifying electric generating facility site owned by
the applicant. The Agency may select new renewable energy
resources to be located at the sites of more than one
qualifying electric generating facility owned by an
applicant to contract with electric utilities to supply
renewable energy credits from such facilities.
(4) The Agency shall assess fees to each applicant to
recover the Agency's costs incurred in receiving and
evaluating applications, conducting the procurement event,
developing contracts for sale, delivery and purchase of
renewable energy credits, and monitoring the
administration of such contracts, as provided for in this
subsection (c-5), including fees paid to a procurement
administrator retained by the Agency for one or more of
these purposes.
(5) The Agency shall select the applicants and the new
renewable energy resources to contract with electric
utilities to supply renewable energy credits in accordance
with this subsection (c-5). The Agency shall select
applicants and new renewable energy resources to supply
renewable energy credits aggregating to no less than
800,000 renewable energy credits per year for 15 years,
assuming sufficient qualifying applications to supply at

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least that amount of renewable energy credits per year; and
no more than 1,000,000 renewable energy credits per year
for 15 years. The obligation to purchase renewable energy
credits from the applicants and their new renewable energy
resources selected by the Agency shall be allocated to
electric utilities as follows: (i) electric utilities
serving more than 1,000,000 retail customers in this State
shall be required to contract to purchase 70%, and electric
utilities serving more than 300,000 but less than 1,000,000
retail customers in this State shall be required to
contract to purchase 30 %, of the renewable energy credits
from the applicants and the new renewable energy resources
selected by the Agency. In order to achieve these
allocation percentages between or among the electric
utilities, the Agency may require an applicant to enter
into contracts with more than one electric utility for the
sale and purchase of renewable energy credits from a new
renewable energy resource to be constructed and operated by
the applicant, with the sale and purchase obligations under
the contracts to aggregate to the total number of renewable
energy credits per year to be supplied by the applicant
from such new renewable energy resource. The Agency shall
submit its proposed selection of applicants, new renewable
energy resources to be constructed, and renewable energy
credit amounts, to the Commission for approval. The
Commission shall, within 2 business days after receipt of

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the Agency's proposed selections, approve the proposed
selections if it determines that the applicants and the new
renewable energy resources to be constructed meet the
selection criteria set forth in this subsection (c-5) and
that the Agency proposes to select applicants for contracts
aggregating to no more than 1,000,000 renewable energy
credits per year for 15 years.
(6) The Agency, in conjunction with its procurement
administrator if one is retained and the electric
utilities, shall develop a standard form contract for the
sale, delivery and purchase of renewable energy credits
pursuant to this subsection (c-5). The contracts shall
provide for commercial operation dates for the new
renewable energy resources such that (i) the new renewable
energy resources from which approximately 50% of the
renewable energy credits are contracted will be required to
achieve commercial operation on or about December 31, 2021,
and will receive payments for renewable energy credits for
the 15-year period beginning January 1, 2022, and (ii) the
new renewable energy resources from which the remainder of
the renewable energy credits are contracted will be
required to achieve commercial operation on or about
December 31, 2022, and will receive payments for renewable
energy credits for the 15-year period beginning January 1,
2023. The form contract shall be, to the maximum extent
possible, consistent with standard electric industry

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contracts for sale, delivery, and purchase of renewable
energy credits while taking into account the specific
requirements of this subsection (c-5). The contract shall
include penalty, default, and enforcement provisions for
failure of the selling party to deliver renewable energy
credits in the amounts specified in the contract and to
comply with the requirements of this subsection (c-5). The
standard form contract shall specify that all renewable
energy credits delivered to the electric utility pursuant
to the contract shall be retired. The Agency shall make the
proposed contracts available for a reasonable period for
comment by potential applicants, and shall publish the
final form contract at least 30 days before the date of the
procurement event.
(7) Coal to Solar Energy Storage Initiative Charge.
(A) Within 30 days following the effective date of
this amendatory Act of the 101st General Assembly, each
electric utility serving more than 300,000 retail
customers in this State as of January 1, 2019, shall
file a tariff for the billing and collection of a Coal
to Solar Energy Storage Initiative Charge in
accordance with subsection (i-5) of Section 16-108 of
the Public Utilities Act. The electric utility's
tariff shall provide for the billing and collection of
a Coal to Solar Energy Storage Initiative Charge on
each kilowatthour of electricity delivered to its

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delivery services customers within its service
territory of (i) 0.1333 cents per kilowatthour from the
effective date of the tariff through December 31, 2024,
and (ii) 0.03 cents per kilowatthour from January 1,
2025 through December 31 of the year in which the last
renewable energy credit sale and purchase contract
entered into pursuant to this subsection (c-5)
terminates.
(B) Each electric utility shall remit, on a monthly
basis, the following percent of its collections of the
Coal to Solar Energy Storage Initiative Charge to the
Agency for deposit in the Coal to Solar and Energy
Storage Incentive and Plant Transition Fund provided
for in this subsection (c-5): (i) from September 1,
2019, through December 31, 2021, 100%; (ii) from
January 1 through December 31, 2022, 88.75%; and (iii)
from January 1, 2023 through December 31, 2024, 77.5%;
provided, that the electric utilities' deposits into
the Coal to Solar and Energy Storage Incentive and
Plant Transition Fund for the last 3 calendar months of
each of the years 2022, 2023, and 2024 shall be
adjusted so that the aggregate deposits by the electric
utilities for the year 2022 into the Coal to Solar and
Energy Storage Incentive and Plant Transition Fund
constitute all collections of the Coal to Solar Energy
Storage Initiative Charge in excess of $18,000,000 and

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that the aggregate deposits by the electric utilities
for the years 2023 and 2024 into the Coal to Solar and
Energy Storage Incentive and Plant Transition Fund
constitute all collections of the Coal to Solar Energy
Storage Initiative Charge in excess of $36,000,000 in
each year. All other collections of the Coal to Solar
Energy Storage Initiative Charge shall be held in
reserves by the electric utility until deliveries
begin of renewable energy credits pursuant to
contracts entered into in accordance with this
subsection (c-5), and thereafter such reserves and
collections shall be used by the electric utility to
pay for renewable energy credits delivered pursuant to
such contracts. Provided, that if as of May 31 of any
year beginning May 31, 2025, an electric utility holds,
after taking into account payments projected to be due
for renewable energy credits delivered pursuant to
such contracts through May 31 of such year, Coal to
Solar Energy Storage Initiative Charge collections
greater than 10% of its projected payment obligations
under the renewable energy contracts for the next
delivery year, the electric utility shall refund
one-half of such excess collections to its delivery
services customers on a uniform cents per kilowatthour
basis over a 6-month period, in accordance with a
procedure specified in its Coal to Solar Energy Storage

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Initiative Charge tariff.
(8) Coal to Solar and Energy Storage Incentive and
Plant Transition Fund.
(A) The Coal to Solar and Energy Storage Incentive
and Plant Transition Fund is established as a special
fund in the State treasury. The Coal to Solar and
Energy Storage Incentive and Plant Transition Fund is
authorized to receive, by statutory deposit, that
portion specified in paragraph (7)(B) of this
subsection (c-5) of moneys collected by electric
utilities through imposition of the Coal to Solar
Energy Storage Initiative Charge required by this
subsection (c-5). The Coal to Solar and Energy Storage
Incentive and Plant Transition Fund shall be
administered by the Agency to provide transitional
support funding to coal-fueled electric generating
facilities in this State owned by an applicant, or by a
company with a common parent company as an applicant,
that has been selected by the Agency to enter into a
contract or contracts to sell renewable energy credits
from a new renewable energy resource to an electric
utility in accordance with this subsection (c-5).
(B) The objective of the transitional support
funding provided for in this paragraph (8) is to assist
and enable qualifying electric generating facilities
in this State to remain in operation during the period

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from the effective date of this amendatory Act of the
101st General Assembly through December 31, 2024, in
order to ensure that adequate electric generating
resources are available in this State through that
date, while the State's portfolio of renewable energy
resources is being expanded.
(C) The Coal to Solar and Energy Storage Incentive
and Plant Transition 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 those funds from the Coal
to Solar and Energy Storage Incentive and Plant
Transition 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 paragraph
(8) of subsection (c-5).
(D) The Agency shall provide grants of
transitional support funding from the Coal to Solar and
Energy Storage Incentive and Plant Transition Fund to
owners of qualifying electric generating facilities in
this State that meet the criteria specified in this
paragraph (8) of subsection (c-5), for the period
January 1, 2020 through December 31, 2024, in aggregate
amounts not exceeding $140 million in each calendar
year in such period. The amount of transitional support

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funding granted to the owner of a qualifying electric
generating facility for a calendar year shall be equal
to the product of $150 times the megawatts of electric
generating capacity of the qualifying electric
generating facility times 365; provided, that the
owner may request that a lower number of megawatts than
the full rated generating capacity of an electric
generating facility be used to calculate the amount of
transitional support funding provided to that electric
generating facility. The grant amounts shall be paid to
the recipients on a quarterly basis with payments to be
made on May 31, August 31, November 30, and February 28
for the immediately preceding calendar quarter. No
grant payments for transitional support funding shall
be made to the owner of a qualifying electric
generating facility in respect of any period
subsequent to the retirement date of the electric
generating facility.
(E) The qualifications for a grant of transitional
support funding from the Coal to Solar and Energy
Storage Incentive and Plant Transition Fund for an
electric generating facility are as follows: (i) the
electric generating facility is located in this State
south of federal Interstate Highway 80; (ii) the
electric generating facility has an electric
generating capacity of at least 150 megawatts; (iii)

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the electric generating facility burned coal as its
primary source of fuel as of January 1, 2019; (iv) the
electric generating facility is owned by an applicant
that has been selected by the Agency to contract with
an electric utility to deliver renewable energy
credits from a new renewable energy resource to be
constructed at an existing electric generating
facility owned by the applicant, or is owned by a
company that has a common parent company with such an
applicant and has been designated by the applicant to
the Agency as a candidate to receive a grant of
transitional support funding; (v) the owner of the
electric generating facility commits, as a condition
to receiving the grant of transitional support
funding, to maintain the electric generating facility
in operation until at least December 31, 2024 and to
permanently retire the electric generating facility by
no later than December 31, 2030; if a coal-fueled
electric generating facility that is designated
pursuant to this paragraph for retirement no earlier
than January 1, 2025 is required, prior to January 1,
2025, either (A) to make capital expenditures of at
least $10,000,000 in order to remain in or attain
compliance with any environmental law or regulation,
or (B) to make capital expenditures for purposes other
than environmental compliance of at least $10,000,000

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that were neither known or reasonably foreseeable as of
September 1, 2019, then such coal-fueled electric
generating facility may be retired by December 31 of
the year prior to the year in which such capital
expenditures must be incurred, and the owner of the
retired coal-fueled electric generating facility shall
receive no further grant payments of transitional
support funding in respect of that facility for periods
after its retirement date.
(F) An owner may receive a grant of transitional
support funding from the Coal to Solar and Energy
Storage Incentive and Plant Transition Fund for more
than one qualifying electric generating facility.
(G) The Agency shall establish a schedule for
receiving and evaluating applications for grants of
transitional support funding from the Coal to Solar and
Energy Storage Incentive and Plant Transition Fund.
The schedule shall be consistent with the schedule for
receiving and evaluating applications to be selected
to enter into contracts to sell renewable energy
credits from new renewable energy resources in
accordance with this subsection (c-5). The Agency
shall announce the qualifying electric generating
facilities that will receive grants of transitional
funding support from the Coal to Solar and Energy
Storage Incentive and Plant Transition Fund no later

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than November 1, 2019.
(H) In addition to the grants for transitional
support funding provided for in this paragraph (8), the
Agency shall set aside and utilize up to $66,000,000 in
the Coal to Solar and Energy Storage Incentive and
Plant Transition Fund for grants, assuming sufficient
qualifying applicants, to support installation of
energy storage facilities at the sites of up to 3
electric generating facilities in Illinois located
south of federal Interstate Highway 80 that burned coal
as their primary sources of fuel as of January 1, 2019,
and which the owner commits to retire by December 31,
2030, but at which the installation of a new renewable
energy resource is not planned. A qualifying energy
storage facility must be a 4-hour energy storage
facility with a capacity of no less than 40
megawatthours and no more than 80 megawatthours. The
owner must commit to place the energy storage facility
into commercial operation by no later than January 1,
2024. The owner must also agree that (i) the new energy
storage facility will be constructed or installed by a
qualified person or persons in compliance with the
requirements of subsection (g) of Section 16-128A of
the Public Utilities Act and any rules or regulations
adopted thereunder, and (ii) the personnel operating
the energy storage facility will have the requisite

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skills, knowledge, training, experience, and
competence consistent with subsection (a) of Section
16-128 of the Public Utilities Act, including through
training and education courses and opportunities
offered by the owner to employees of the coal-fueled
generating facility being retired. The Agency shall
accept applications for this grant program until
December 31, 2021, and shall announce the award of
grants no later than March 31, 2022. The Agency shall
make the grant payments in equal annual amounts for 10
years beginning on the commercial operation date of the
energy storage facility. The annual grant payments to a
qualifying energy storage facility shall be no less
than $1,100,000 per year for a 4-hour, 40 megawatthour
energy storage facility and no more than $2,200,000 per
year for a 4-hour, 80 megawatthour energy storage
facility. Any uncommitted portion of the amount of
funding set aside by the Agency for grants to support
installation of energy storage facilities pursuant to
this subparagraph (H) shall be utilized for grants of
transitional support funding in accordance with this
paragraph (8).
(I) Grants of transitional support funding, and of
funding for energy storage facilities pursuant to
subparagraph (H) of this paragraph (8), from the Coal
to Solar and Energy Storage Incentive and Plant

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Transition Fund shall be memorialized in grant
contracts between the Agency and the recipient.
(J) During the year ending December 31, 2025, any
amounts remaining in the Coal to Solar and Energy
Storage Incentive and Plant Transition Fund that are
not needed to fund contracted grant payments to support
new energy storage facilities pursuant to subparagraph
(H) of this paragraph (8) shall be returned by the
Agency to the electric utilities, in the same
proportion as the electric utilities' original
deposits into the Coal to Solar and Energy Storage
Incentive and Plant Transition Fund. Each electric
utility shall refund any such amounts it receives to
its delivery services customers on a uniform cents per
kilowatthour basis over a 6-month period in accordance
with procedures specified in the electric utility's
tariff for billing and collection of the Coal to Solar
Energy Storage Initiative Charge.
(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

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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.

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

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

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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, in
each of cases (i) and (ii) reduced (A) during the
period from September 1, 2019 through December 31, 2024
by 0.1333 cents per kilowatthour and (B) during the
period from January 1, 2025 through the termination of
all of the renewable energy credit procurement
contracts entered into pursuant to subsection (c-5) of
this Section, by 0.03 cents per kilowatthour. 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

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500 MW when commercial operation commences, that has a
final Clean Air Act permit on June 1, 2009 (the effective
date of Public Act 95-1027), and that will meet the
definition of clean coal facility in Section 1-10 of this
Act when commercial operation commences. The sourcing
agreements with this initial clean coal facility shall be
subject to both approval of the initial clean coal facility
by the General Assembly and satisfaction of the
requirements of paragraph (4) of this subsection (d) and
shall be executed within 90 days after any such approval by
the General Assembly. The Agency and the Commission shall
have authority to inspect all books and records associated
with the initial clean coal facility during the term of
such a sourcing agreement. A utility's sourcing agreement
for electricity produced by the initial clean coal facility
shall include:
(A) a formula contractual price (the "contract
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

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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;

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(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:

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(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

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(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

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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,

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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

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specifically enforce the facility's sequestration
requirement and the other terms of this contract
provision. Compliance with the sequestration
requirements and offset purchase requirements
specified in paragraph (3) of this subsection (d)
shall be reviewed annually by an independent
expert retained by the owner of the initial clean
coal facility, with the advance written approval
of the Attorney General. The Commission may, in the
course of the review specified in item (vii),
reduce the allowable return on equity for the
facility if the facility willfully fails to comply
with the carbon capture and sequestration
requirements set forth in this item (v);
(vi) include limits on, and accordingly
provide for modification of, the amount the
utility is required to source under the sourcing
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

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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

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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,

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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,

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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

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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

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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

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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

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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

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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

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and energy to be procured by the Agency for the utility.
The duration of the contracts procured under this
subsection (d-5) shall be for a term of 10 years ending May
31, 2027. The quantity of zero emission credits to be
procured under the contracts shall be all of the zero
emission credits generated by the zero emission facility in
each delivery year; however, if the zero emission facility
is owned by more than one entity, then the quantity of zero
emission credits to be procured under the contracts shall
be the amount of zero emission credits that are generated
from the portion of the zero emission facility that is
owned by the winning supplier.
The 16% value identified in this paragraph (1) is the
average of the percentage targets in subparagraph (B) of
paragraph (1) of subsection (c) of this Section 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

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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

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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

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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,

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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

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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,

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

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including the preservation of zero emission
facilities. The plan shall also describe in detail how
each public interest factor shall be considered and
weighted in the bid selection process to ensure that
the public interest criteria are applied to the
procurement and given full effect.
For purposes of developing the plan, the Agency
shall consider any reports issued by a State agency,
board, or commission under House Resolution 1146 of the
98th General Assembly and paragraph (4) of subsection
(d) of this Section 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 June 1, 2017 (the
effective date of Public Act 99-906), the Agency shall
revise the plan as necessary based on the comments
received and file its zero emission standard
procurement plan with the Commission.

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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

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

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utility-scale wind projects in the
procurement events specified in item (i)
of subparagraph (G) of paragraph (1) of
subsection (c) of this 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 this 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 this 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
Public Act 99-906, the Agency and Commission may, as
appropriate, modify the various dates and timelines

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under this subparagraph and subparagraphs (C) and (D)
of this paragraph (1). The procurement and plan
approval processes required by this subsection (d-5)
shall be conducted in conjunction with the procurement
and plan approval processes required by subsection (c)
of this Section and Section 16-111.5 of the Public
Utilities Act, to the extent practicable.
Notwithstanding whether a procurement event is
conducted under Section 16-111.5 of the Public
Utilities Act, the Agency shall immediately initiate a
procurement process on June 1, 2017 (the effective date
of Public Act 99-906).
(D) Following the procurement event described in
this paragraph (1) and consistent with subparagraph
(B) of this paragraph (1), the Agency shall calculate
the payments to be made under each contract for the
next delivery year based on the market price index for
that delivery year. The Agency shall publish the
payment calculations no later than May 25, 2017 and
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:

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(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

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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

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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

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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.

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

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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

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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 (including renewable energy
credits sold, delivered, and purchased under a contract entered
into pursuant to subsection (c-5) of this Section), 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 (c-5), subsection (d), or

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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. 99-536, eff. 7-8-16; 99-906, eff. 6-1-17;
100-863, eff. 8-14-18; revised 10-18-18.)
Section 10-15. The State Finance Act is amended by adding
Section 5.891 as follows:
(30 ILCS 105/5.891 new)
Sec. 5.891. The Coal to Solar and Energy Storage Incentive
and Plant Transition Fund.
Section 10-20. The Public Utilities Act is amended by
changing Sections 16-108 and 16-111.5 as follows:
(220 ILCS 5/16-108)
Sec. 16-108. Recovery of costs associated with the
provision of delivery and other services and certain other
charges.
(a) An electric utility shall file a delivery services

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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

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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

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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

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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

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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

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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

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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;

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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

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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

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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.
(i-5) An electric utility required to impose the Coal to
Solar Energy Storage Initiative Charge provided for in
subsection (c-5) of Section 1-75 of the Illinois Power Agency
Act shall add such charge to the bills of its delivery services
customers pursuant to the terms of a tariff conforming to the
requirements of subsection (c-5) of Section 1-75 of the
Illinois Power Agency Act and filed with and approved by the
Commission. The electric utility shall file its proposed tariff
with the Commission within 30 days following the effective date
of this amendatory Act of the 101st General Assembly. Within 45
days following the date the proposed tariff is filed with the
Commission, the Commission shall review and approve the
electric utility's proposed tariff, or direct the electric
utility to make modifications to conform to the requirements of
subsection (c-5) of Section 1-75 of the Illinois Power Agency
Act. The electric utility's tariff shall be placed into effect
90 days following the effective date of this amendatory Act of
the 101st General Assembly. The electric utility shall use the
funds collected pursuant to the tariff in accordance with

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subsection (c-5) of Section 1-75 of the Illinois Power Agency
Act, including depositing a portion of such funds in the Coal
to Solar and Energy Storage Incentive and Plant Transition Fund
as provided for in subsection (c-5) of Section 1-75 of the
Illinois Power Agency 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

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Section 16-110.
(k) The electric utility shall be entitled to recover
through tariffed charges all of the costs associated with the
purchase of zero emission credits from zero emission facilities
to meet the requirements of subsection (d-5) of Section 1-75 of
the Illinois Power Agency Act. Such costs shall include the
costs of procuring the zero emission credits, as well as the
reasonable costs that the utility incurs as part of the
procurement processes and to implement and comply with plans
and processes approved by the Commission under such subsection
(d-5). The costs shall be allocated across all retail customers
through a single, uniform cents per kilowatt-hour charge
applicable to all retail customers, which shall appear as a
separate line item on each customer's bill. Beginning June 1,
2017, the electric utility shall be entitled to recover through
tariffed charges all of the costs associated with the purchase
of renewable energy resources to meet the renewable energy
resource standards of subsection (c) of Section 1-75 of the
Illinois Power Agency Act, under procurement plans as approved
in accordance with that Section and Section 16-111.5 of this
Act. Such costs shall include the costs of procuring the
renewable energy resources, as well as the reasonable costs
that the utility incurs as part of the procurement processes
and to implement and comply with plans and processes approved
by the Commission under such Sections. The costs associated
with the purchase of renewable energy resources shall be

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

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

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

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provided that the review, reconciliation, and true-up shall not
be initiated until after August 31, 2021. During the 4-year
period, the utility shall be permitted to collect and retain
funds under this subsection (k) and to purchase renewable
energy resources under an approved long-term renewable
resources procurement plan using those funds regardless of the
delivery year in which the funds were collected during the
4-year period.
If the amount of funds collected during the delivery year
commencing June 1, 2017, exceeds the costs incurred during that
delivery year, then up to half of this excess amount, as
calculated on June 1, 2018, may be used to fund the programs
under subsection (b) of Section 1-56 of the Illinois Power
Agency Act in the same proportion the programs are funded under
that subsection (b). However, any amount identified under this
subsection (k) to fund programs under subsection (b) of Section
1-56 of the Illinois Power Agency Act shall be reduced if it
exceeds the funding shortfall. For purposes of this Section,
"funding shortfall" means the difference between $200,000,000
and the amount appropriated by the General Assembly to the
Illinois Power Agency Renewable Energy Resources Fund during
the period that commences on the effective date of this
amendatory act of the 99th General Assembly and ends on August
1, 2018.
If the amount of funds collected during the delivery year
commencing June 1, 2018, exceeds the costs incurred during that

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

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resources plan shall provide for the Agency to procure
contracts in an amount that does not exceed the funding, and
the contracts approved by the Commission shall be executed by
the applicable utility or utilities.
(l) A utility that has terminated any contract executed
under subsection (d-5) of Section 1-75 of the Illinois Power
Agency Act shall be entitled to recover any remaining balance
associated with the purchase of zero emission credits prior to
such termination, and such utility shall also apply a credit to
its retail customer bills in the event of any over-collection.
(m)(1) An electric utility that recovers its costs of
procuring zero emission credits from zero emission
facilities through a cents-per-kilowatthour charge under
to subsection (k) of this Section shall be subject to the
requirements of this subsection (m). Notwithstanding
anything to the contrary, such electric utility shall,
beginning on April 30, 2018, and each April 30 thereafter
until April 30, 2026, calculate whether any reduction must
be applied to such cents-per-kilowatthour charge that is
paid by retail customers of the electric utility that are
exempt from subsections (a) through (j) of Section 8-103B
of this Act under subsection (l) of Section 8-103B. Such
charge shall be reduced for such customers for the next
delivery year commencing on June 1 based on the amount
necessary, if any, to limit the annual estimated average
net increase for the prior calendar year due to the future

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energy investment costs to no more than 1.3% of 5.98 cents
per kilowatt-hour, which is the average amount paid per
kilowatthour for electric service during the year ending
December 31, 2015 by Illinois industrial retail customers,
as reported to the Edison Electric Institute.
The calculations required by this subsection (m) shall
be made only once for each year, and no subsequent rate
impact determinations shall be made.
(2) For purposes of this Section, "future energy
investment costs" shall be calculated by subtracting the
cents-per-kilowatthour charge identified in subparagraph
(A) of this paragraph (2) from the sum of the
cents-per-kilowatthour charges identified in subparagraph
(B) of this paragraph (2):
(A) The cents-per-kilowatthour charge identified
in the electric utility's tariff placed into effect
under Section 8-103 of the Public Utilities Act that,
on December 1, 2016, was applicable to those retail
customers that are exempt from subsections (a) through
(j) of Section 8-103B of this Act under subsection (l)
of Section 8-103B.
(B) The sum of the following
cents-per-kilowatthour charges applicable to those
retail customers that are exempt from subsections (a)
through (j) of Section 8-103B of this Act under
subsection (l) of Section 8-103B, provided that if one

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

10100SB2080sam004 - 429 - LRB101 11122 RJF 59369 a
Act under subsection (l) of Section 8-103B beginning with
the next delivery year commencing after the date of the
calculation required by this subsection (m).
(4) The electric utility shall file a notice with the
Commission on May 1 of 2018 and each May 1 thereafter until
May 1, 2026 containing the reduction, if any, which must be
applied for the delivery year which begins in the year of
the filing. The notice shall contain the calculations made
pursuant to this Section. By October 1 of each year
beginning in 2018, each electric utility shall notify the
Commission if it appears, based on an estimate of the
calculation required in this subsection (m), that a
reduction will be required in the next year.
(Source: P.A. 99-906, eff. 6-1-17.)
(220 ILCS 5/16-111.5)
Sec. 16-111.5. Provisions relating to procurement.
(a) An electric utility that on December 31, 2005 served at
least 100,000 customers in Illinois shall procure power and
energy for its eligible retail customers in accordance with the
applicable provisions set forth in Section 1-75 of the Illinois
Power Agency Act and this Section. Beginning with the delivery
year commencing on June 1, 2017, such electric utility shall
also procure zero emission credits from zero emission
facilities in accordance with the applicable provisions set
forth in Section 1-75 of the Illinois Power Agency Act, and,

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for years beginning on or after June 1, 2017, the utility shall
procure renewable energy resources in accordance with the
applicable provisions set forth in Section 1-75 of the Illinois
Power Agency Act and this Section. A small multi-jurisdictional
electric utility that on December 31, 2005 served less than
100,000 customers in Illinois may elect to procure power and
energy for all or a portion of its eligible Illinois retail
customers in accordance with the applicable provisions set
forth in this Section and Section 1-75 of the Illinois Power
Agency Act. This Section shall not apply to a small
multi-jurisdictional utility until such time as a small
multi-jurisdictional utility requests the Illinois Power
Agency to prepare a procurement plan for its eligible retail
customers. "Eligible retail customers" for the purposes of this
Section means those retail customers that purchase power and
energy from the electric utility under fixed-price bundled
service tariffs, other than those retail customers whose
service is declared or deemed competitive under Section 16-113
and those other customer groups specified in this Section,
including self-generating customers, customers electing hourly
pricing, or those customers who are otherwise ineligible for
fixed-price bundled tariff service. For those customers that
are excluded from the procurement plan's electric supply
service requirements, and the utility shall procure any supply
requirements, including capacity, ancillary services, and
hourly priced energy, in the applicable markets as needed to

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serve those customers, provided that the utility may include in
its procurement plan load requirements for the load that is
associated with those retail customers whose service has been
declared or deemed competitive pursuant to Section 16-113 of
this Act to the extent that those customers are purchasing
power and energy during one of the transition periods
identified in subsection (b) of Section 16-113 of this Act.
(b) A procurement plan shall be prepared for each electric
utility consistent with the applicable requirements of the
Illinois Power Agency Act and this Section. For purposes of
this Section, Illinois electric utilities that are affiliated
by virtue of a common parent company are considered to be a
single electric utility. Small multi-jurisdictional utilities
may request a procurement plan for a portion of or all of its
Illinois load. Each procurement plan shall analyze the
projected balance of supply and demand for those retail
customers to be included in the plan's electric supply service
requirements over a 5-year period, with the first planning year
beginning on June 1 of the year following the year in which the
plan is filed. The plan shall specifically identify the
wholesale products to be procured following plan approval, and
shall follow all the requirements set forth in the Public
Utilities Act and all applicable State and federal laws,
statutes, rules, or regulations, as well as Commission orders.
Nothing in this Section precludes consideration of contracts
longer than 5 years and related forecast data. Unless specified

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otherwise in this Section, in the procurement plan or in the
implementing tariff, any procurement occurring in accordance
with this plan shall be competitively bid through a request for
proposals process. Approval and implementation of the
procurement plan shall be subject to review and approval by the
Commission according to the provisions set forth in this
Section. A procurement plan shall include each of the following
components:
(1) Hourly load analysis. This analysis shall include:
(i) multi-year historical analysis of hourly
loads;
(ii) switching trends and competitive retail
market analysis;
(iii) known or projected changes to future loads;
and
(iv) growth forecasts by customer class.
(2) Analysis of the impact of any demand side and
renewable energy initiatives. This analysis shall include:
(i) the impact of demand response programs and
energy efficiency programs, both current and
projected; for small multi-jurisdictional utilities,
the impact of demand response and energy efficiency
programs approved pursuant to Section 8-408 of this
Act, both current and projected; and
(ii) supply side needs that are projected to be
offset by purchases of renewable energy resources, if

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any.
(3) A plan for meeting the expected load requirements
that will not be met through preexisting contracts. This
plan shall include:
(i) definitions of the different Illinois retail
customer classes for which supply is being purchased;
(ii) the proposed mix of demand-response products
for which contracts will be executed during the next
year. For small multi-jurisdictional electric
utilities that on December 31, 2005 served fewer than
100,000 customers in Illinois, these shall be defined
as demand-response products offered in an energy
efficiency plan approved pursuant to Section 8-408 of
this Act. The cost-effective demand-response measures
shall be procured whenever the cost is lower than
procuring comparable capacity products, provided that
such products shall:
(A) be procured by a demand-response provider
from those retail customers included in the plan's
electric supply service requirements;
(B) at least satisfy the demand-response
requirements of the regional transmission
organization market in which the utility's service
territory is located, including, but not limited
to, any applicable capacity or dispatch
requirements;

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(C) provide for customers' participation in
the stream of benefits produced by the
demand-response products;
(D) provide for reimbursement by the
demand-response provider of the utility for any
costs incurred as a result of the failure of the
supplier of such products to perform its
obligations thereunder; and
(E) meet the same credit requirements as apply
to suppliers of capacity, in the applicable
regional transmission organization market;
(iii) monthly forecasted system supply
requirements, including expected minimum, maximum, and
average values for the planning period;
(iv) the proposed mix and selection of standard
wholesale products for which contracts will be
executed during the next year, separately or in
combination, to meet that portion of its load
requirements not met through pre-existing contracts,
including but not limited to monthly 5 x 16 peak period
block energy, monthly off-peak wrap energy, monthly 7 x
24 energy, annual 5 x 16 energy, annual off-peak wrap
energy, annual 7 x 24 energy, monthly capacity, annual
capacity, peak load capacity obligations, capacity
purchase plan, and ancillary services;
(v) proposed term structures for each wholesale

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product type included in the proposed procurement plan
portfolio of products; and
(vi) an assessment of the price risk, load
uncertainty, and other factors that are associated
with the proposed procurement plan; this assessment,
to the extent possible, shall include an analysis of
the following factors: contract terms, time frames for
securing products or services, fuel costs, weather
patterns, transmission costs, market conditions, and
the governmental regulatory environment; the proposed
procurement plan shall also identify alternatives for
those portfolio measures that are identified as having
significant price risk.
(4) Proposed procedures for balancing loads. The
procurement plan shall include, for load requirements
included in the procurement plan, the process for (i)
hourly balancing of supply and demand and (ii) the criteria
for portfolio re-balancing in the event of significant
shifts in load.
(5) Long-Term Renewable Resources Procurement Plan.
The Agency shall prepare a long-term renewable resources
procurement plan for the procurement of renewable energy
credits under Sections 1-56 and 1-75 of the Illinois Power
Agency Act for delivery beginning in the 2017 delivery
year.
(i) The initial long-term renewable resources

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procurement plan and all subsequent revisions shall be
subject to review and approval by the Commission. For
the purposes of this Section, "delivery year" has the
same meaning as in Section 1-10 of the Illinois Power
Agency Act. For purposes of this Section, "Agency"
shall mean the Illinois Power Agency.
(ii) The long-term renewable resources planning
process shall be conducted as follows:
(A) Electric utilities shall provide a range
of load forecasts to the Illinois Power Agency
within 45 days of the Agency's request for
forecasts, which request shall specify the length
and conditions for the forecasts including, but
not limited to, the quantity of distributed
generation expected to be interconnected for each
year.
(B) The Agency shall publish for comment the
initial long-term renewable resources procurement
plan no later than 120 days after the effective
date of this amendatory Act of the 99th General
Assembly and shall review, and may revise, the plan
at least every 2 years thereafter. To the extent
practicable, the Agency shall review and propose
any revisions to the long-term renewable energy
resources procurement plan in conjunction with the
Agency's other planning and approval processes

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conducted under this Section. The initial
long-term renewable resources procurement plan
shall:
(aa) Identify the procurement programs and
competitive procurement events consistent with
the applicable requirements of the Illinois
Power Agency Act and shall be designed to
achieve the goals set forth in subsection (c)
of Section 1-75 of that Act.
(bb) Include a schedule for procurements
for renewable energy credits from
utility-scale wind projects, utility-scale
solar projects, and brownfield site
photovoltaic projects consistent with
subparagraph (G) of paragraph (1) of
subsection (c) of Section 1-75 of the Illinois
Power Agency Act.
(cc) Identify the process whereby the
Agency will submit to the Commission for review
and approval the proposed contracts to
implement the programs required by such plan.
Copies of the initial long-term renewable
resources procurement plan and all subsequent
revisions shall be posted and made publicly
available on the Agency's and Commission's
websites, and copies shall also be provided to each

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

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the plan, the Commission shall determine whether a
hearing is necessary. The Commission shall enter
its order confirming or modifying the initial
long-term renewable resources procurement plan or
any subsequent revisions within 120 days after the
filing of the plan by the Illinois Power Agency.
(D) The Commission shall approve the initial
long-term renewable resources procurement plan and
any subsequent revisions, including expressly the
forecast used in the plan and taking into account
that funding will be limited to the amount of
revenues actually collected by the utilities, if
the Commission determines that the plan will
reasonably and prudently accomplish the
requirements of Section 1-56 and subsection (c) of
Section 1-75 of the Illinois Power Agency Act. The
Commission shall also approve the process for the
submission, review, and approval of the proposed
contracts to procure renewable energy credits or
implement the programs authorized by the
Commission pursuant to a long-term renewable
resources procurement plan approved under this
Section.
(iii) The Agency or third parties contracted by the
Agency shall implement all programs authorized by the
Commission in an approved long-term renewable

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resources procurement plan without further review and
approval by the Commission. Third parties shall not
begin implementing any programs or receive any payment
under this Section until the Commission has approved
the contract or contracts under the process authorized
by the Commission in item (D) of subparagraph (ii) of
paragraph (5) of this subsection (b) and the third
party and the Agency or utility, as applicable, have
executed the contract. For those renewable energy
credits subject to procurement through a competitive
bid process under the plan or under the initial forward
procurements for wind and solar resources described in
subparagraph (G) of paragraph (1) of subsection (c) of
Section 1-75 of the Illinois Power Agency Act, the
Agency shall follow the procurement process specified
in the provisions relating to electricity procurement
in subsections (e) through (i) of this Section.
(iv) An electric utility shall recover its costs
associated with the procurement of renewable energy
credits under this Section and pursuant to subsection
(c-5) of Section 1-75 of the Illinois Power Agency Act
through an automatic adjustment clause tariff under
subsection (k) or subsection (i-5), as applicable, of
Section 16-108 of this Act. A utility shall not be
required to advance any payment or pay any amounts
under this Section that exceed the actual amount of

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revenues collected by the utility under paragraph (6)
of subsection (c) of Section 1-75 of the Illinois Power
Agency Act, subsection (c-5) of Section 1-75 of the
Illinois Power Agency Act, and subsection (k) or
subsection (i-5), as applicable, of Section 16-108 of
this Act, and contracts executed under this Section
shall expressly incorporate this limitation.
(v) For the public interest, safety, and welfare,
the Agency and the Commission may adopt rules to carry
out the provisions of this Section on an emergency
basis immediately following the effective date of this
amendatory Act of the 99th General Assembly.
(vi) On or before July 1 of each year, the
Commission shall hold an informal hearing for the
purpose of receiving comments on the prior year's
procurement process and any recommendations for
change.
(b-5) An electric utility that as of January 1, 2019 serves
more than 300,000 retail customers in this State shall purchase
renewable energy credits from new renewable energy resources
constructed at the sites of coal-fueled electric generating
facilities in this State in accordance with subsection (c-5) of
Section 1-75 of the Illinois Power Agency Act. Except as
expressly provided in this Section 16-111.5, the plans and
procedures for such procurements shall not be included in the
procurement plans provided for in this Section 16-111.5, but

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rather shall be conducted and implemented solely in accordance
with subsection (c-5) of Section 1-75 of the Illinois Power
Agency Act.
(c) The provisions of this subsection (c) shall not apply
to procurements conducted pursuant to subsection (c-5) of
Section 1-75 of the Illinois Power Agency Act. However, the
Agency may retain a procurement administrator to assist the
Agency in planning and carrying out the procurement events and
implementing the other requirements specified in such
subsection (c-5) of Section 1-75 of the Illinois Power Agency
Act, with the costs incurred by the Agency for the procurement
administrator to be recovered through fees charged to
applicants for selection to sell and deliver renewable energy
credits to electric utilities pursuant to such subsection
(c-5). The procurement process set forth in Section 1-75 of the
Illinois Power Agency Act and subsection (e) of this Section
shall be administered by a procurement administrator and
monitored by a procurement monitor.
(1) The procurement administrator shall:
(i) design the final procurement process in
accordance with Section 1-75 of the Illinois Power
Agency Act and subsection (e) of this Section following
Commission approval of the procurement plan;
(ii) develop benchmarks in accordance with
subsection (e)(3) to be used to evaluate bids; these
benchmarks shall be submitted to the Commission for

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

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

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

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

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confirming or modifying the procurement plan within 90 days
after the filing of the procurement plan by the Illinois
Power Agency.
(4) The Commission shall approve the procurement plan,
including expressly the forecast used in the procurement
plan, if the Commission determines that it will ensure
adequate, reliable, affordable, efficient, and
environmentally sustainable electric service at the lowest
total cost over time, taking into account any benefits of
price stability.
(4.5) The Commission shall review and approve the
Agency's recommendation for the selection of applicants to
enter into long-term contracts for the sale and delivery of
renewable energy credits from new renewable energy
resources to be constructed at the sites of coal-fueled
electric generating facilities in this State in accordance
with the provisions of subsection (c-5) of Section 1-75 of
the Illinois Power Agency Act, if the Commission determines
that the applicants recommended by the Agency for
selection, the proposed new renewable energy resources to
be constructed, the amounts of renewable energy credits to
be delivered pursuant to such contracts, and the other
terms of the contracts, are consistent with the
requirements of subsection (c-5) of Section 1-75 of the
Illinois Power Agency Act.
(e) The procurement process shall include each of the

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

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practices. Standard credit terms and instruments that meet
generally accepted industry practices shall be similarly
developed. The procurement administrator shall make
available to the Commission all written comments it
receives on the contract forms, credit terms, or
instruments. If the procurement administrator cannot reach
agreement with the applicable electric utility as to the
contract terms and conditions, the procurement
administrator must notify the Commission of any disputed
terms and the Commission shall resolve the dispute. The
terms of the contracts shall not be subject to negotiation
by winning bidders, and the bidders must agree to the terms
of the contract in advance so that winning bids are
selected solely on the basis of price.
(3) Establishment of a market-based price benchmark.
As part of the development of the procurement process, the
procurement administrator, in consultation with the
Commission staff, Agency staff, and the procurement
monitor, shall establish benchmarks for evaluating the
final prices in the contracts for each of the products that
will be procured through the procurement process. The
benchmarks shall be based on price data for similar
products for the same delivery period and same delivery
hub, or other delivery hubs after adjusting for that
difference. The price benchmarks may also be adjusted to
take into account differences between the information

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

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

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result in increased supplier participation, or that
would address concerns causing the Commission to
reject the results of the prior procurement event, the
procurement administrator may implement those changes
and rerun the request for proposals process according
to a schedule determined by those parties and
consistent with Section 1-75 of the Illinois Power
Agency Act and this subsection. In any event, a new
request for proposals process shall be implemented by
the procurement administrator within 90 days after the
determination that the procurement process has failed
to fully meet the expected load requirement.
(iii) In all cases where there is insufficient
supply provided under contracts awarded through the
procurement process to fully meet the electric
utility's load requirement, the utility shall meet the
load requirement by procuring power and energy from the
applicable regional transmission organization market,
including ancillary services, capacity, and day-ahead
or real time energy, or both; provided, however, that
if a needed product is not available through the
regional transmission organization market it shall be
purchased from the wholesale market.
(6) The procurement processes process described in
this subsection and in subsection (c-5) of Section 1-75 of
the Illinois Power Agency Act are is exempt from the

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requirements of the Illinois Procurement Code, pursuant to
Section 20-10 of that Code.
(f) Within 2 business days after opening the sealed bids,
the procurement administrator shall submit a confidential
report to the Commission. The report shall contain the results
of the bidding for each of the products along with the
procurement administrator's recommendation for the acceptance
and rejection of bids based on the price benchmark criteria and
other factors observed in the process. The procurement monitor
also shall submit a confidential report to the Commission
within 2 business days after opening the sealed bids. The
report shall contain the procurement monitor's assessment of
bidder behavior in the process as well as an assessment of the
procurement administrator's compliance with the procurement
process and rules. The Commission shall review the confidential
reports submitted by the procurement administrator and
procurement monitor, and shall accept or reject the
recommendations of the procurement administrator within 2
business days after receipt of the reports.
(g) Within 3 business days after the Commission decision
approving the results of a procurement event, the utility shall
enter into binding contractual arrangements with the winning
suppliers using the standard form contracts; except that the
utility shall not be required either directly or indirectly to
execute the contracts if a tariff that is consistent with
subsection (l) of this Section has not been approved and placed

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into effect for that utility.
(h) The names of the successful bidders and the load
weighted average of the winning bid prices for each contract
type and for each contract term shall be made available to the
public at the time of Commission approval of a procurement
event. The Commission, the procurement monitor, the
procurement administrator, the Illinois Power Agency, and all
participants in the procurement process shall maintain the
confidentiality of all other supplier and bidding information
in a manner consistent with all applicable laws, rules,
regulations, and tariffs. Confidential information, including
the confidential reports submitted by the procurement
administrator and procurement monitor pursuant to subsection
(f) of this Section, shall not be made publicly available and
shall not be discoverable by any party in any proceeding,
absent a compelling demonstration of need, nor shall those
reports be admissible in any proceeding other than one for law
enforcement purposes.
(i) Within 2 business days after a Commission decision
approving the results of a procurement event or such other date
as may be required by the Commission from time to time, the
utility shall file for informational purposes with the
Commission its actual or estimated retail supply charges, as
applicable, by customer supply group reflecting the costs
associated with the procurement and computed in accordance with
the tariffs filed pursuant to subsection (l) of this Section

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and approved by the Commission.
(j) Within 60 days following August 28, 2007 (the effective
date of Public Act 95-481), each electric utility that on
December 31, 2005 provided electric service to at least 100,000
customers in Illinois shall prepare and file with the
Commission an initial procurement plan, which shall conform in
all material respects to the requirements of the procurement
plan set forth in subsection (b); provided, however, that the
Illinois Power Agency Act shall not apply to the initial
procurement plan prepared pursuant to this subsection. The
initial procurement plan shall identify the portfolio of power
and energy products to be procured and delivered for the period
June 2008 through May 2009, and shall identify the proposed
procurement administrator, who shall have the same experience
and expertise as is required of a procurement administrator
hired pursuant to Section 1-75 of the Illinois Power Agency
Act. Copies of the procurement plan shall be posted and made
publicly available on the Commission's website. The initial
procurement plan may include contracts for renewable resources
that extend beyond May 2009.
(i) Within 14 days following filing of the initial
procurement plan, any person may file a detailed objection
with the Commission contesting the procurement plan
submitted by the electric utility. All objections to the
electric utility's plan shall be specific, supported by
data or other detailed analyses. The electric utility may

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file a response to any objections to its procurement plan
within 7 days after the date objections are due to be
filed. Within 7 days after the date the utility's response
is due, the Commission shall determine whether a hearing is
necessary. If it determines that a hearing is necessary, it
shall require the hearing to be completed and issue an
order on the procurement plan within 60 days after the
filing of the procurement plan by the electric utility.
(ii) The order shall approve or modify the procurement
plan, approve an independent procurement administrator,
and approve or modify the electric utility's tariffs that
are proposed with the initial procurement plan. The
Commission shall approve the procurement plan if the
Commission determines that it will ensure adequate,
reliable, affordable, efficient, and environmentally
sustainable electric service at the lowest total cost over
time, taking into account any benefits of price stability.
(k) (Blank).
(k-5) (Blank).
(l) An electric utility shall recover its costs incurred
under this Section and subsection (c-5) of Section 1-75 of the
Illinois Power Agency Act, including, but not limited to, the
costs of procuring power and energy demand-response resources
under this Section and its costs for purchasing renewable
energy credits pursuant to subsection (c-5) of Section 1-75 of
the Illinois Power Agency Act. The utility shall file with the

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initial procurement plan its proposed tariffs through which its
costs of procuring power that are incurred pursuant to a
Commission-approved procurement plan and those other costs
identified in this subsection (l), will be recovered. The
tariffs shall include a formula rate or charge designed to pass
through both the costs incurred by the utility in procuring a
supply of electric power and energy for the applicable customer
classes with no mark-up or return on the price paid by the
utility for that supply, plus any just and reasonable costs
that the utility incurs in arranging and providing for the
supply of electric power and energy. The formula rate or charge
shall also contain provisions that ensure that its application
does not result in over or under recovery due to changes in
customer usage and demand patterns, and that provide for the
correction, on at least an annual basis, of any accounting
errors that may occur. A utility shall recover through the
tariff all reasonable costs incurred to implement or comply
with any procurement plan that is developed and put into effect
pursuant to Section 1-75 of the Illinois Power Agency Act and
this Section, and for the procurement of renewable energy
credits pursuant to subsection (c-5) of Section 1-75 of the
Illinois Power Agency Act, including any fees assessed by the
Illinois Power Agency, costs associated with load balancing,
and contingency plan costs. The electric utility shall also
recover its full costs of procuring electric supply for which
it contracted before the effective date of this Section in

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

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Section on an emergency basis immediately following August 28,
2007 (the effective date of Public Act 95-481).
(n) Notwithstanding any other provision of this Act, any
affiliated electric utilities that submit a single procurement
plan covering their combined needs may procure for those
combined needs in conjunction with that plan, and may enter
jointly into power supply contracts, purchases, and other
procurement arrangements, and allocate capacity and energy and
cost responsibility therefor among themselves in proportion to
their requirements.
(o) On or before June 1 of each year, the Commission shall
hold an informal hearing for the purpose of receiving comments
on the prior year's procurement process and any recommendations
for change.
(p) An electric utility subject to this Section may propose
to invest, lease, own, or operate an electric generation
facility as part of its procurement plan, provided the utility
demonstrates that such facility is the least-cost option to
provide electric service to those retail customers included in
the plan's electric supply service requirements. If the
facility is shown to be the least-cost option and is included
in a procurement plan prepared in accordance with Section 1-75
of the Illinois Power Agency Act and this Section, then the
electric utility shall make a filing pursuant to Section 8-406
of this Act, and may request of the Commission any statutory
relief required thereunder. If the Commission grants all of the

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

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

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serves less than 100,000 retail customers in the State, other
than the procurement of renewable energy credits for
distributed renewable energy generation devices.
(Source: P.A. 99-906, eff. 6-1-17.)
Article 99.
Section 99-99. Effective date. This Act takes effect upon
becoming law.".