Bill Amendment: IL SB2939 | 2015-2016 | 99th General Assembly

NOTE: For additional amemendments please see the Bill Drafting List

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Bill Title: ENERGY EFFICIENCY MEASURES

Status: 2016-07-31 - Pursuant to Senate Rule 3-9(b) / Referred to Assignments [SB2939 Detail]

Download: Illinois-2015-SB2939-Senate_Amendment_003.html

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Sen. James F. Clayborne, Jr.

Filed: 5/27/2016

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AMENDMENT TO SENATE BILL 2939
AMENDMENT NO. ______. Amend Senate Bill 2939 by replacing
everything after the enacting clause with the following:
"Section 5. The Illinois Power Agency Act is amended by
changing Section 1-75 as follows:
(20 ILCS 3855/1-75)
Sec. 1-75. Planning and Procurement Bureau. The Planning
and Procurement Bureau has the following duties and
responsibilities:
(a) The Planning and Procurement Bureau shall each year,
beginning in 2008, develop procurement plans and conduct
competitive procurement processes in accordance with the
requirements of Section 16-111.5 of the Public Utilities Act
for the eligible retail customers of electric utilities that on
December 31, 2005 provided electric service to at least 100,000
customers in Illinois. The Planning and Procurement Bureau

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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.
(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

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

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

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

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expert or expert consulting firm so selected with
Commission approval.
(b) The experts or expert consulting firms retained by the
Agency shall, as appropriate, prepare procurement plans, and
conduct a competitive procurement process as prescribed in
Section 16-111.5 of the Public Utilities Act, to ensure
adequate, reliable, affordable, efficient, and environmentally
sustainable electric service at the lowest total cost over
time, taking into account any benefits of price stability, for
eligible retail customers of electric utilities that on
December 31, 2005 provided electric service to at least 100,000
customers in the State of Illinois, and for eligible Illinois
retail customers of small multi-jurisdictional electric
utilities that (i) on December 31, 2005 served less than
100,000 customers in Illinois and (ii) request a procurement
plan for their Illinois jurisdictional load.
(c) Renewable portfolio standard.
(1) The procurement plans shall include cost-effective
renewable energy resources. A minimum percentage of each
utility's total supply to serve the load of eligible retail
customers, as defined in Section 16-111.5(a) of the Public
Utilities Act, procured for each of the following years
shall be generated from cost-effective renewable energy
resources: at least 2% by June 1, 2008; at least 4% by June
1, 2009; at least 5% by June 1, 2010; at least 6% by June 1,
2011; at least 7% by June 1, 2012; at least 8% by June 1,

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2013; at least 9% by June 1, 2014; at least 10% by June 1,
2015; and increasing by at least 1.5% each year thereafter
to at least 25% by June 1, 2025. To the extent that it is
available, at least 75% of the renewable energy resources
used to meet these standards shall come from wind
generation and, beginning on June 1, 2011, at least the
following percentages of the renewable energy resources
used to meet these standards shall come from photovoltaics
on the following schedule: 0.5% by June 1, 2012, 1.5% by
June 1, 2013; 3% by June 1, 2014; and 6% by June 1, 2015 and
thereafter. Of the renewable energy resources procured
pursuant to this Section, at least the following
percentages shall come from distributed renewable energy
generation devices: 0.5% by June 1, 2013, 0.75% by June 1,
2014, and 1% by June 1, 2015 and thereafter. To the extent
available, half of the renewable energy resources procured
from distributed renewable energy generation shall come
from devices of less than 25 kilowatts in nameplate
capacity. Renewable energy resources procured from
distributed generation devices may also count towards the
required percentages for wind and solar photovoltaics.
Procurement of renewable energy resources from distributed
renewable energy generation devices shall be done on an
annual basis through multi-year contracts of no less than 5
years, and shall consist solely of renewable energy
credits.

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The Agency shall create credit requirements for
suppliers of distributed renewable energy. In order to
minimize the administrative burden on contracting
entities, the Agency shall solicit the use of third-party
organizations to aggregate distributed renewable energy
into groups of no less than one megawatt in installed
capacity. These third-party organizations shall administer
contracts with individual distributed renewable energy
generation device owners. An individual distributed
renewable energy generation device owner shall have the
ability to measure the output of his or her distributed
renewable energy generation device.
For purposes of this subsection (c), "cost-effective"
means that the costs of procuring renewable energy
resources do not cause the limit stated in paragraph (2) of
this subsection (c) to be exceeded and do not exceed
benchmarks based on market prices for renewable energy
resources in the region, which shall be developed by the
procurement administrator, in consultation with the
Commission staff, Agency staff, and the procurement
monitor and shall be subject to Commission review and
approval.
(2) For purposes of this subsection (c), the required
procurement of cost-effective renewable energy resources
for a particular year shall be measured as a percentage of
the actual amount of electricity (megawatt-hours) supplied

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by the electric utility to eligible retail customers in the
planning year ending immediately prior to the procurement.
For purposes of this subsection (c), the amount paid per
kilowatthour means the total amount paid for electric
service expressed on a per kilowatthour basis. For purposes
of this subsection (c), the total amount paid for electric
service includes without limitation amounts paid for
supply, transmission, distribution, surcharges, and add-on
taxes.
Notwithstanding the requirements of this subsection
(c), the total of renewable energy resources procured
pursuant to the procurement plan for any single year shall
be reduced by an amount necessary to limit the annual
estimated average net increase due to the costs of these
resources included in the amounts paid by eligible retail
customers in connection with electric service to:
(A) in 2008, no more than 0.5% of the amount paid
per kilowatthour by those customers during the year
ending May 31, 2007;
(B) in 2009, the greater of an additional 0.5% of
the amount paid per kilowatthour by those customers
during the year ending May 31, 2008 or 1% of the amount
paid per kilowatthour by those customers during the
year ending May 31, 2007;
(C) in 2010, the greater of an additional 0.5% of
the amount paid per kilowatthour by those customers

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during the year ending May 31, 2009 or 1.5% of the
amount paid per kilowatthour by those customers during
the year ending May 31, 2007;
(D) in 2011, the greater of an additional 0.5% of
the amount paid per kilowatthour by those customers
during the year ending May 31, 2010 or 2% of the amount
paid per kilowatthour by those customers during the
year ending May 31, 2007; and
(E) thereafter, the amount of renewable energy
resources procured pursuant to the procurement plan
for any single year shall be reduced by an amount
necessary to limit the estimated average net increase
due to the cost of these resources included in the
amounts paid by eligible retail customers in
connection with electric service to no more than the
greater of 2.015% of the amount paid per kilowatthour
by those customers during the year ending May 31, 2007
or the incremental amount per kilowatthour paid for
these resources in 2011.
No later than June 30, 2011, the Commission shall
review the limitation on the amount of renewable energy
resources procured pursuant to this subsection (c) and
report to the General Assembly its findings as to
whether that limitation unduly constrains the
procurement of cost-effective renewable energy
resources.

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(3) Through June 1, 2011, renewable energy resources
shall be counted for the purpose of meeting the renewable
energy standards set forth in paragraph (1) of this
subsection (c) only if they are generated from facilities
located in the State, provided that cost-effective
renewable energy resources are available from those
facilities. If those cost-effective resources are not
available in Illinois, they shall be procured in states
that adjoin Illinois and may be counted towards compliance.
If those cost-effective resources are not available in
Illinois or in states that adjoin Illinois, they shall be
purchased elsewhere and shall be counted towards
compliance. After June 1, 2011, cost-effective renewable
energy resources located in Illinois and in states that
adjoin Illinois may be counted towards compliance with the
standards set forth in paragraph (1) of this subsection
(c). If those cost-effective resources are not available in
Illinois or in states that adjoin Illinois, they shall be
purchased elsewhere and shall be counted towards
compliance.
(4) The electric utility shall retire all renewable
energy credits used to comply with the standard.
(5) Beginning with the year commencing June 1, 2010, an
electric utility subject to this subsection (c) shall apply
the lesser of the maximum alternative compliance payment
rate or the most recent estimated alternative compliance

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payment rate for its service territory for the
corresponding compliance period, established pursuant to
subsection (d) of Section 16-115D of the Public Utilities
Act to its retail customers that take service pursuant to
the electric utility's hourly pricing tariff or tariffs.
The electric utility shall retain all amounts collected as
a result of the application of the alternative compliance
payment rate or rates to such customers, and, beginning in
2011, the utility shall include in the information provided
under item (1) of subsection (d) of Section 16-111.5 of the
Public Utilities Act the amounts collected under the
alternative compliance payment rate or rates for the prior
year ending May 31. Notwithstanding any limitation on the
procurement of renewable energy resources imposed by item
(2) of this subsection (c), the Agency shall increase its
spending on the purchase of renewable energy resources to
be procured by the electric utility for the next plan year
by an amount equal to the amounts collected by the utility
under the alternative compliance payment rate or rates in
the prior year ending May 31. Beginning April 1, 2012, and
each year thereafter, the Agency shall prepare a public
report for the General Assembly and Illinois Commerce
Commission that shall include, but not necessarily be
limited to:
(A) a comparison of the costs associated with the
Agency's procurement of renewable energy resources to

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(1) the Agency's costs associated with electricity
generated by other types of generation facilities and
(2) the benefits associated with the Agency's
procurement of renewable energy resources; and
(B) an analysis of the rate impacts associated with
the Illinois Power Agency's procurement of renewable
resources, including, but not limited to, any
long-term contracts, on the eligible retail customers
of electric utilities.
The analysis shall include the Agency's estimate of the
total dollar impact that the Agency's procurement of
renewable resources has had on the annual electricity bills
of the customer classes that comprise each eligible retail
customer class taking service from an electric utility. The
Agency's report shall also analyze how the operation of the
alternative compliance payment mechanism, any long-term
contracts, or other aspects of the applicable renewable
portfolio standards impacts the rates of customers of
alternative retail electric suppliers.
(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

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

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

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

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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, in
each of cases (i) and (ii) reduced during the period
November 1, 2016 through the termination of the
transitional reliability capacity credit program
provided for in subsection (d-10) of this Section, by
0.114 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
500 MW when commercial operation commences, that has a
final Clean Air Act permit on the effective date of this

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amendatory Act of the 95th General Assembly, and that will
meet the definition of clean coal facility in Section 1-10
of this Act when commercial operation commences. The
sourcing agreements with this initial clean coal facility
shall be subject to both approval of the initial clean coal
facility by the General Assembly and satisfaction of the
requirements of paragraph (4) of this subsection (d) and
shall be executed within 90 days after any such approval by
the General Assembly. The Agency and the Commission shall
have authority to inspect all books and records associated
with the initial clean coal facility during the term of
such a sourcing agreement. A utility's sourcing agreement
for electricity produced by the initial clean coal facility
shall include:
(A) a formula contractual price (the "contract
price") approved pursuant to paragraph (4) of this
subsection (d), which shall:
(i) be determined using a cost of service
methodology employing either a level or deferred
capital recovery component, based on a capital
structure consisting of 45% equity and 55% debt,
and a return on equity as may be approved by the
Federal Energy Regulatory Commission, which in any
case may not exceed the lower of 11.5% or the rate
of return approved by the General Assembly
pursuant to paragraph (4) of this subsection (d);

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and
(ii) provide that all miscellaneous net
revenue, including but not limited to net revenue
from the sale of emission allowances, if any,
substitute natural gas, if any, grants or other
support provided by the State of Illinois or the
United States Government, firm transmission
rights, if any, by-products produced by the
facility, energy or capacity derived from the
facility and not covered by a sourcing agreement
pursuant to paragraph (3) of this subsection (d) or
item (5) of subsection (d) of Section 16-115 of the
Public Utilities Act, whether generated from the
synthesis gas derived from coal, from SNG, or from
natural gas, shall be credited against the revenue
requirement for this initial clean coal facility;
(B) power purchase provisions, which shall:
(i) provide that the utility party to such
sourcing agreement shall pay the contract price
for electricity delivered under such sourcing
agreement;
(ii) require delivery of electricity to the
regional transmission organization market of the
utility that is party to such sourcing agreement;
(iii) require the utility party to such
sourcing agreement to buy from the initial clean

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

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facility in each hour with respect to an amount of
energy equal to all clean coal energy made
available from the initial clean coal facility
during such hour times a fraction, the numerator of
which is such utility's retail market sales of
electricity (expressed in kilowatthours sold) in
the utility's service territory in the State
during the prior calendar month and the
denominator of which is the total retail market
sales of electricity (expressed in kilowatthours
sold) in the State by utilities during such prior
month and the sales of electricity (expressed in
kilowatthours sold) in the State by alternative
retail electric suppliers during such prior month
that are subject to the requirements of this
subsection (d) and paragraph (5) of subsection (d)
of Section 16-115 of the Public Utilities Act,
provided that the amount paid by the utility in any
year will be limited by paragraph (2) of this
subsection (d);
(ii) provide that the utility's payment
obligation in respect of the quantity of
electricity determined pursuant to the preceding
clause (i) shall be limited to an amount equal to
(1) the difference between the contract price
determined pursuant to subparagraph (A) of

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paragraph (3) of this subsection (d) and the
day-ahead price for electricity delivered to the
regional transmission organization market of the
utility that is party to such sourcing agreement
(or any successor delivery point at which such
utility's supply obligations are financially
settled on an hourly basis) (the "reference
price") on the day preceding the day on which the
electricity is delivered to the initial clean coal
facility busbar, multiplied by (2) the quantity of
electricity determined pursuant to the preceding
clause (i); and
(iii) not require the utility to take physical
delivery of the electricity produced by the
facility;
(D) general provisions, which shall:
(i) specify a term of no more than 30 years,
commencing on the commercial operation date of the
facility;
(ii) provide that utilities shall maintain
adequate records documenting purchases under the
sourcing agreements entered into to comply with
this subsection (d) and shall file an accounting
with the load forecast that must be filed with the
Agency by July 15 of each year, in accordance with
subsection (d) of Section 16-111.5 of the Public

09900SB2939sam003 - 23 - LRB099 19038 EGJ 49324 a
Utilities Act;
(iii) provide that all costs associated with
the initial clean coal facility will be
periodically reported to the Federal Energy
Regulatory Commission and to purchasers in
accordance with applicable laws governing
cost-based wholesale power contracts;
(iv) permit the Illinois Power Agency to
assume ownership of the initial clean coal
facility, without monetary consideration and
otherwise on reasonable terms acceptable to the
Agency, if the Agency so requests no less than 3
years prior to the end of the stated contract term;
(v) require the owner of the initial clean coal
facility to provide documentation to the
Commission each year, starting in the facility's
first year of commercial operation, accurately
reporting the quantity of carbon emissions from
the facility that have been captured and
sequestered and report any quantities of carbon
released from the site or sites at which carbon
emissions were sequestered in prior years, based
on continuous monitoring of such sites. If, in any
year after the first year of commercial operation,
the owner of the facility fails to demonstrate that
the initial clean coal facility captured and

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sequestered at least 50% of the total carbon
emissions that the facility would otherwise emit
or that sequestration of emissions from prior
years has failed, resulting in the release of
carbon dioxide into the atmosphere, the owner of
the facility must offset excess emissions. Any
such carbon offsets must be permanent, additional,
verifiable, real, located within the State of
Illinois, and legally and practicably enforceable.
The cost of such offsets for the facility that are
not recoverable shall not exceed $15 million in any
given year. No costs of any such purchases of
carbon offsets may be recovered from a utility or
its customers. All carbon offsets purchased for
this purpose and any carbon emission credits
associated with sequestration of carbon from the
facility must be permanently retired. The initial
clean coal facility shall not forfeit its
designation as a clean coal facility if the
facility fails to fully comply with the applicable
carbon sequestration requirements in any given
year, provided the requisite offsets are
purchased. However, the Attorney General, on
behalf of the People of the State of Illinois, may
specifically enforce the facility's sequestration
requirement and the other terms of this contract

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provision. Compliance with the sequestration
requirements and offset purchase requirements
specified in paragraph (3) of this subsection (d)
shall be reviewed annually by an independent
expert retained by the owner of the initial clean
coal facility, with the advance written approval
of the Attorney General. The Commission may, in the
course of the review specified in item (vii),
reduce the allowable return on equity for the
facility if the facility wilfully fails to comply
with the carbon capture and sequestration
requirements set forth in this item (v);
(vi) include limits on, and accordingly
provide for modification of, the amount the
utility is required to source under the sourcing
agreement consistent with paragraph (2) of this
subsection (d);
(vii) require Commission review: (1) to
determine the justness, reasonableness, and
prudence of the inputs to the formula referenced in
subparagraphs (A)(i) through (A)(iii) of paragraph
(3) of this subsection (d), prior to an adjustment
in those inputs including, without limitation, the
capital structure and return on equity, fuel
costs, and other operations and maintenance costs
and (2) to approve the costs to be passed through

09900SB2939sam003 - 26 - LRB099 19038 EGJ 49324 a
to customers under the sourcing agreement by which
the utility satisfies its statutory obligations.
Commission review shall occur no less than every 3
years, regardless of whether any adjustments have
been proposed, and shall be completed within 9
months;
(viii) limit the utility's obligation to such
amount as the utility is allowed to recover through
tariffs filed with the Commission, provided that
neither the clean coal facility nor the utility
waives any right to assert federal pre-emption or
any other argument in response to a purported
disallowance of recovery costs;
(ix) limit the utility's or alternative retail
electric supplier's obligation to incur any
liability until such time as the facility is in
commercial operation and generating power and
energy and such power and energy is being delivered
to the facility busbar;
(x) provide that the owner or owners of the
initial clean coal facility, which is the
counterparty to such sourcing agreement, shall
have the right from time to time to elect whether
the obligations of the utility party thereto shall
be governed by the power purchase provisions or the
contract for differences provisions;

09900SB2939sam003 - 27 - LRB099 19038 EGJ 49324 a
(xi) append documentation showing that the
formula rate and contract, insofar as they relate
to the power purchase provisions, have been
approved by the Federal Energy Regulatory
Commission pursuant to Section 205 of the Federal
Power Act;
(xii) provide that any changes to the terms of
the contract, insofar as such changes relate to the
power purchase provisions, are subject to review
under the public interest standard applied by the
Federal Energy Regulatory Commission pursuant to
Sections 205 and 206 of the Federal Power Act; and
(xiii) conform with customary lender
requirements in power purchase agreements used as
the basis for financing non-utility generators.
(4) Effective date of sourcing agreements with the
initial clean coal facility.
Any proposed sourcing agreement with the initial clean
coal facility shall not become effective unless the
following reports are prepared and submitted and
authorizations and approvals obtained:
(i) Facility cost report. The owner of the initial
clean coal facility shall submit to the Commission, the
Agency, and the General Assembly a front-end
engineering and design study, a facility cost report,
method of financing (including but not limited to

09900SB2939sam003 - 28 - LRB099 19038 EGJ 49324 a
structure and associated costs), and an operating and
maintenance cost quote for the facility (collectively
"facility cost report"), which shall be prepared in
accordance with the requirements of this paragraph (4)
of subsection (d) of this Section, and shall provide
the Commission and the Agency access to the work
papers, relied upon documents, and any other backup
documentation related to the facility cost report.
(ii) Commission report. Within 6 months following
receipt of the facility cost report, the Commission, in
consultation with the Agency, shall submit a report to
the General Assembly setting forth its analysis of the
facility cost report. Such report shall include, but
not be limited to, a comparison of the costs associated
with electricity generated by the initial clean coal
facility to the costs associated with electricity
generated by other types of generation facilities, an
analysis of the rate impacts on residential and small
business customers over the life of the sourcing
agreements, and an analysis of the likelihood that the
initial clean coal facility will commence commercial
operation by and be delivering power to the facility's
busbar by 2016. To assist in the preparation of its
report, the Commission, in consultation with the
Agency, may hire one or more experts or consultants,
the costs of which shall be paid for by the owner of

09900SB2939sam003 - 29 - LRB099 19038 EGJ 49324 a
the initial clean coal facility. The Commission and
Agency may begin the process of selecting such experts
or consultants prior to receipt of the facility cost
report.
(iii) General Assembly approval. The proposed
sourcing agreements shall not take effect unless,
based on the facility cost report and the Commission's
report, the General Assembly enacts authorizing
legislation approving (A) the projected price, stated
in cents per kilowatthour, to be charged for
electricity generated by the initial clean coal
facility, (B) the projected impact on residential and
small business customers' bills over the life of the
sourcing agreements, and (C) the maximum allowable
return on equity for the project; and
(iv) Commission review. If the General Assembly
enacts authorizing legislation pursuant to
subparagraph (iii) approving a sourcing agreement, the
Commission shall, within 90 days of such enactment,
complete a review of such sourcing agreement. During
such time period, the Commission shall implement any
directive of the General Assembly, resolve any
disputes between the parties to the sourcing agreement
concerning the terms of such agreement, approve the
form of such agreement, and issue an order finding that
the sourcing agreement is prudent and reasonable.

09900SB2939sam003 - 30 - LRB099 19038 EGJ 49324 a
The facility cost report shall be prepared as follows:
(A) The facility cost report shall be prepared by
duly licensed engineering and construction firms
detailing the estimated capital costs payable to one or
more contractors or suppliers for the engineering,
procurement and construction of the components
comprising the initial clean coal facility and the
estimated costs of operation and maintenance of the
facility. The facility cost report shall include:
(i) an estimate of the capital cost of the core
plant based on one or more front end engineering
and design studies for the gasification island and
related facilities. The core plant shall include
all civil, structural, mechanical, electrical,
control, and safety systems.
(ii) an estimate of the capital cost of the
balance of the plant, including any capital costs
associated with sequestration of carbon dioxide
emissions and all interconnects and interfaces
required to operate the facility, such as
transmission of electricity, construction or
backfeed power supply, pipelines to transport
substitute natural gas or carbon dioxide, potable
water supply, natural gas supply, water supply,
water discharge, landfill, access roads, and coal
delivery.

09900SB2939sam003 - 31 - LRB099 19038 EGJ 49324 a
The quoted construction costs shall be expressed
in nominal dollars as of the date that the quote is
prepared and shall include capitalized financing costs
during construction, taxes, insurance, and other
owner's costs, and an assumed escalation in materials
and labor beyond the date as of which the construction
cost quote is expressed.
(B) The front end engineering and design study for
the gasification island and the cost study for the
balance of plant shall include sufficient design work
to permit quantification of major categories of
materials, commodities and labor hours, and receipt of
quotes from vendors of major equipment required to
construct and operate the clean coal facility.
(C) The facility cost report shall also include an
operating and maintenance cost quote that will provide
the estimated cost of delivered fuel, personnel,
maintenance contracts, chemicals, catalysts,
consumables, spares, and other fixed and variable
operations and maintenance costs. The delivered fuel
cost estimate will be provided by a recognized third
party expert or experts in the fuel and transportation
industries. The balance of the operating and
maintenance cost quote, excluding delivered fuel
costs, will be developed based on the inputs provided
by duly licensed engineering and construction firms

09900SB2939sam003 - 32 - LRB099 19038 EGJ 49324 a
performing the construction cost quote, potential
vendors under long-term service agreements and plant
operating agreements, or recognized third party plant
operator or operators.
The operating and maintenance cost quote
(including the cost of the front end engineering and
design study) shall be expressed in nominal dollars as
of the date that the quote is prepared and shall
include taxes, insurance, and other owner's costs, and
an assumed escalation in materials and labor beyond the
date as of which the operating and maintenance cost
quote is expressed.
(D) The facility cost report shall also include an
analysis of the initial clean coal facility's ability
to deliver power and energy into the applicable
regional transmission organization markets and an
analysis of the expected capacity factor for the
initial clean coal facility.
(E) Amounts paid to third parties unrelated to the
owner or owners of the initial clean coal facility to
prepare the core plant construction cost quote,
including the front end engineering and design study,
and the operating and maintenance cost quote will be
reimbursed through Coal Development Bonds.
(5) Re-powering and retrofitting coal-fired power
plants previously owned by Illinois utilities to qualify as

09900SB2939sam003 - 33 - LRB099 19038 EGJ 49324 a
clean coal facilities. During the 2009 procurement
planning process and thereafter, the Agency and the
Commission shall consider sourcing agreements covering
electricity generated by power plants that were previously
owned by Illinois utilities and that have been or will be
converted into clean coal facilities, as defined by Section
1-10 of this Act. Pursuant to such procurement planning
process, the owners of such facilities may propose to the
Agency sourcing agreements with utilities and alternative
retail electric suppliers required to comply with
subsection (d) of this Section and item (5) of subsection
(d) of Section 16-115 of the Public Utilities Act, covering
electricity generated by such facilities. In the case of
sourcing agreements that are power purchase agreements,
the contract price for electricity sales shall be
established on a cost of service basis. In the case of
sourcing agreements that are contracts for differences,
the contract price from which the reference price is
subtracted shall be established on a cost of service basis.
The Agency and the Commission may approve any such utility
sourcing agreements that do not exceed cost-based
benchmarks developed by the procurement administrator, in
consultation with the Commission staff, Agency staff and
the procurement monitor, subject to Commission review and
approval. The Commission shall have authority to inspect
all books and records associated with these clean coal

09900SB2939sam003 - 34 - LRB099 19038 EGJ 49324 a
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-10) Transitional reliability capacity credit program.
(1) Beginning November 1, 2016 and ending upon the
termination of the transitional reliability capacity
credit program provided for in this subsection (d-10), each
electric utility subject to subsection (a) of this Section
shall impose a transitional electric generation
reliability support charge of 0.114 cents per kilowatthour
on each kilowatthour of electricity delivered to its
delivery services customers within its service territory.
The electric utility shall include this charge in its
delivery services tariff authorized by Section 16-108 of
the Public Utilities Act. The electric utility shall
maintain a reserve fund to hold all moneys collected
through application of the transitional electric
generation reliability support charge and not used for the
purchase of transitional reliability capacity credits in
accordance with subsection (d-10) of this Section until the
electric utility is authorized to refund the balance, if
any, of moneys in the reserve fund to its retail customers

09900SB2939sam003 - 35 - LRB099 19038 EGJ 49324 a
in accordance with subsection (d-10). The electric
utility's administrative costs of billing, collecting, and
accounting for the transitional electric generation
reliability support charge shall be deemed prudently
incurred and reasonable in amount and the electric utility
shall be entitled to full cost recovery pursuant to the
tariff filed with the Commission.
(2) Beginning December 1, 2016, and continuing until
the transitional reliability capacity credit program is
terminated in accordance with this subsection (d-10), each
electric utility subject to subsection (a) of this Section
shall purchase transitional reliability capacity credits
in accordance with this subsection (d-10), but not to
exceed the amount of transitional reliability capacity
credits that can be purchased with the revenues collected
by the electric utility through the transitional electric
generation reliability support charge, as provided in this
subsection (d-10). The electric utilities shall purchase
transitional reliability capacity credits in procurement
events conducted by the Agency as provided in this
subsection (d-10).
(3) A transitional reliability capacity credit shall
be equal to one megawatt of electric generating capacity of
an eligible electric generating unit, as determined in
accordance with paragraph (5) of this subsection (d-10),
for one day. The megawatts of electric generating capacity

09900SB2939sam003 - 36 - LRB099 19038 EGJ 49324 a
on which transitional reliability capacity credits are
based shall be referred to as reliability capacity. A
transitional reliability capacity credit shall represent
the reliability attributes of one megawatt-day of electric
generating capacity of a specified electric generating
unit, but shall not represent a right or entitlement to
utilize or receive the capacity or energy of the electric
generating unit. The electrical capacity of the megawatts
of reliability capacity of an electric generating unit
which is contracted to provide transitional reliability
capacity credits may be sold to an electric utility or to
another purchaser located within the geographic boundaries
of the regional transmission organization in which the
electric generating unit is located, or to an electric
utility subject to subsection (a) of this Section located
outside such boundaries. The electrical energy produced by
megawatts of reliability capacity of an electric
generating unit may be sold to any purchaser, regardless of
location. A megawatt-day of the reliability capacity of an
electric generating unit may be supplied and used only once
as a transitional reliability capacity credit.
(4) The total number of transitional reliability
capacity credits to be purchased, in the aggregate, by the
electric utilities subject to subsection (a) of this
Section in a month shall be 5,000 multiplied by the number
of days in the month; provided, that the total number of

09900SB2939sam003 - 37 - LRB099 19038 EGJ 49324 a
transitional reliability capacity credits to be purchased
in an annual period (or in a 6-month period in the case of
the initial procurement of transitional reliability
capacity credits) shall be reduced, to the extent
necessary, so that the total estimated dollar obligation of
each electric utility for transitional reliability
capacity credits for the period shall not exceed the moneys
projected to be available from collections of the
transitional electric generation reliability support
charge plus the balance in the electric utility's reserve
fund for transitional electric generation reliability
support charge collections, as provided in paragraph (8) of
this subsection (d-10). The price of each transitional
reliability capacity credit shall be $150 per megawatt-day
minus the clearing price in the most recent Midcontinent
Independent System Operator, Inc. Planning Resource
Auction. Each electric utility that is subject to
subsection (a) of this Section shall purchase a fraction of
the total reliability capacity credits to be purchased in
the month by all electric utilities (prior to taking into
account any reduction for an individual electric utility
due to a projected insufficiency of funds as hereinabove
provided), where such fraction is equal to the electric
utility's percentage of megawatt hour deliveries to retail
customers in its service area during the calendar year
ended December 31 preceding the procurement event to the

09900SB2939sam003 - 38 - LRB099 19038 EGJ 49324 a
total megawatt hour deliveries to retail customers by all
electric utilities subject to subsection (a) of this
Section in their respective service areas during the
calendar year ended December 31.
(5) To be eligible for selection as a source of
transitional reliability capacity credits in a procurement
event, an electric generating unit must meet each of the
following requirements, as determined by the Agency. Prior
to each procurement event, the Agency shall determine the
eligibility of each electric generating unit seeking to
participate in that procurement event.
(A) The electric generating unit is physically
located within the service area of an electric utility
that served more than 100,000 delivery services
customers in Illinois as of December 31, 2015.
(B) The electric generating unit utilizes a solid
fuel, and the owner of the generating unit commits to
maintain an inventory of the fuel equal to at least 20
days supply at the site of the generating unit during
the period that the generating unit is providing
transitional reliability capacity credits.
(C) For the 3 consecutive calendar years ending on
December 31 immediately prior to the procurement
event, the generating unit achieved an equivalent
availability factor of at least 75%.
(D) The owner of the electric generating unit

09900SB2939sam003 - 39 - LRB099 19038 EGJ 49324 a
certifies (i) that, if the electric generating unit is
selected as a supplier of transitional reliability
capacity credits, the owner will continue to operate
the electric generating unit during the period in which
the transitional reliability capacity credits are to
be provided, and (ii) that the owner has no reason to
believe that the generating unit will be unable to
achieve an equivalent availability factor of at least
75% for the period for which transitional reliability
capacity credits are to be provided.
(E) The owner and the operator (which may be
separate entities) of the electric generating unit is
or are registered with the North American Electric
Reliability Corporation as the generator owner and
generator operator for the generating unit and are
subject to the North American Electric Reliability
Corporation's mandatory reliability standards
applicable to generator owners and generator
operators, adopted in accordance with Section 215(d)
of the Federal Power Act, for the electric generating
unit.
(F) The electric generating unit is connected to
the bulk electric system at an interconnection voltage
of at least 100 kilovolts.
(G) On and after June 1, 2017, the electric
generating unit is located within the geographic

09900SB2939sam003 - 40 - LRB099 19038 EGJ 49324 a
boundaries of a regional transmission organization
that the Agency determines does not meet the criteria
specified in paragraph (9) of this subsection (d-10).
This requirement is not applicable to procurement
events to procure transitional reliability capacity
credits for periods beginning prior to June 1, 2017.
(H) For the period to be covered by the procurement
event, the electric generating unit has capacity that
has not been committed for sale to any purchaser or
purchasers located within the geographic boundaries of
a regional transmission organization other than the
regional transmission organization in which the
electric generating unit is located, other than an
electric utility subject to subsection (a) of this
Section. The owner of the electric generating unit
shall commit that if the electric generating unit is
selected to provide transitional reliability capacity
credits, then during the period covered by the
procurement event, the reliability capacity on which
the transitional reliability capacity credits are
based shall not be contracted for sale or committed to
any purchaser, other than an electric utility subject
to subsection (a) of this Section, that is located
within the geographic boundaries of a regional
transmission organization other than the regional
transmission organization in which the electric

09900SB2939sam003 - 41 - LRB099 19038 EGJ 49324 a
generating unit is physically located.
(I) The electric generating unit is not eligible to
sell or provide renewable energy credits or zero
emission credits.
(J) The electric generating unit is not owned by a
municipal utility, an electric cooperative, or a group
or consortium of municipal utilities or electric
cooperatives whose end user customers do not pay the
transitional electric generation reliability support
charge.
(K) The owner of the electric generating unit
commits to pay any fees assessed by the Agency to
recover the Agency's costs of conducting the
procurement event and related activities, as provided
in subparagraph (C) of paragraph (7) of this subsection
(d-10).
(6) On or before October 31, 2016, the Agency shall
conduct a procurement event for the procurement of
transitional reliability capacity credits by the electric
utilities for the period December 1, 2016 through May 31,
2017. On or before March 31, 2017 and on or before March 31
of each year thereafter until the termination of the
transitional reliability capacity credit program, the
Agency shall conduct a procurement event for the
procurement of transitional reliability capacity credits
by the electric utilities for the period beginning the

09900SB2939sam003 - 42 - LRB099 19038 EGJ 49324 a
following June 1 and ending on May 31 of the following
calendar year. The Agency is authorized to retain one or
more third-party consultants or contractors to assist the
Agency in conducting each procurement event and related
activities required by this subsection (d-10). At least 30
days prior to the date of each procurement event, the
Agency shall:
(A) announce the date of the procurement event and
the period for which transitional reliability capacity
credits will be procured;
(B) receive expressions of interest from owners of
electric generating units that their electric
generating units be selected as providers of
transitional reliability capacity credits in the
procurement event, which expressions of interest shall
include (i) a statement of the electric generating unit
or units and the amount of transitional reliability
capacity credits from each electric generating unit
that the owner intends to offer for selection in the
procurement event, and (ii) information demonstrating
that each electric generating unit meets the
eligibility requirements for selection specified in
paragraph (5) of this subsection (d-10), with the
information to be submitted to the Agency on such forms
and through such processes as established by the
Agency;

09900SB2939sam003 - 43 - LRB099 19038 EGJ 49324 a
(C) request and obtain from each electric utility
(i) a forecast of the electric utility's kilowatthour
deliveries of electricity to its retail customers in
its service area during the period to be covered by the
procurement event and (ii) the estimated balance in the
electric utility's reserve fund for transitional
electric generation reliability support charge
collections, as of the start of the period to be
covered by the procurement event; provided, that for
purposes of this subparagraph (C), the Agency may use
the load forecast of an electric utility for the period
to be covered by the procurement event that the Agency
obtained in connection with the preparation of a
procurement plan pursuant to subsection (a) of this
Section;
(D) announce an estimate of the number of
transitional reliability capacity credits to be
procured by each electric utility in the procurement
event, taking into account the electric utilities'
forecast of electricity deliveries, the amounts of the
transitional electric generation reliability support
charge estimated to be collected by each electric
utility during the period beginning one month prior to
the start of and ending one month prior to the end of
the period to be covered by the procurement event and
the estimated balance in the electric utility's

09900SB2939sam003 - 44 - LRB099 19038 EGJ 49324 a
reserve fund as of the start of the period to be
covered by the procurement event, with the total number
of transitional reliability capacity credits to be
procured for all electric utilities subject to
subsection (a) of this Section not to exceed the
transitional reliability capacity credits associated
with 5,000 megawatts of reliability capacity for the
period to be covered by the procurement event; and
(E) notify the owners of all electric generating
units seeking to be selected as providers of
transitional reliability capacity credits in the
procurement event, and the electric utilities, as to
which electric generating units the Agency has
determined are eligible to be selected as providers of
transitional reliability capacity credits in the
procurement event.
(7) The procurement events for transitional
reliability capacity credits shall be conducted as
follows:
(A) The owner of each electric generating unit that
the Agency has determined to be eligible to be selected
as a provider of transitional reliability capacity
credits shall specify the amount of transitional
reliability capacity credits per day that is being
offered from the electric generating unit for the
period to be covered by the procurement event. The same

09900SB2939sam003 - 45 - LRB099 19038 EGJ 49324 a
number of transitional reliability capacity credits
being offered from the electric generating unit shall
be offered for every day of the entire period to be
covered by the procurement event. The owner shall not
offer transitional reliability capacity credits from
an electric generating unit based on megawatts of
capacity of the electric generating unit that have been
sold or committed to one or more purchasers, other than
an electric utility subject to subsection (a) of this
Section, that is located within the geographic
boundaries of a regional transmission organization
other than the regional transmission organization in
which the electric generating unit is physically
located.
(B) If more transitional reliability capacity
credits are offered for purchase by an electric utility
than the amount which the Agency has determined should
be purchased for the period to be covered by the
procurement event, the Agency shall select the
electric generating units to provide the transitional
reliability capacity credits, and the associated
amount of reliability capacity of each electric
generating unit, based on the equivalent availability
factor achieved by each electric generating unit
during the 3 calendar years ended on December 31
preceding the procurement event, with the electric

09900SB2939sam003 - 46 - LRB099 19038 EGJ 49324 a
generating units achieving the highest equivalent
availability factor in the 3-year period selected
first, and so forth, until the required amount of
transitional reliability capacity credits is obtained.
(C) Costs incurred by the Agency to conduct a
procurement event, including the activities of the
Agency described in paragraphs (5), (6), and (7) of
this subsection (d-10), and including any costs
incurred by the Agency to retain consultants or
contractors to assist in conducting the procurement
event and related activities, shall be recovered by the
Agency through fees charged to the owners of electric
generating units that are selected in the procurement
event as the providers of transition reliability
capacity credits to the electric utilities. Any such
fees to recover the Agency's costs shall be charged to
the owners of the electric generating units on a
proportional basis based on the amounts of
transitional reliability capacity credits that are to
be supplied by each owner's electric generating unit or
units.
(8) The owner of each electric generating unit selected
by the Agency to provide transitional reliability capacity
credits to an electric utility, and the electric utility,
shall enter into binding contractual arrangements for the
provision of and payment for the transitional electric

09900SB2939sam003 - 47 - LRB099 19038 EGJ 49324 a
reliability credits, using forms developed by the Agency
with consideration of input provided by the electric
utilities and interested suppliers. The contractual
arrangements shall include the following provisions:
(A) The source of moneys to be used to pay for the
transitional reliability capacity credits for the
period covered by all contracts awarded pursuant to a
procurement event shall be (i) the electric utility's
collection of transitional electric generation
reliability support charges during the period
beginning one month prior to the start of, and ending
one month prior to the end of, the period covered by
the contracts, plus the balance in the electric
utility's reserve fund during the period covered by the
contracts; and the electric utility shall not be
obligated to pay for any transitional reliability
capacity credits for which there are insufficient
funds from such sources. In the event of a shortfall of
funding to pay for all of the contracted transitional
reliability capacity credits for an annual period (or
6-month period in the case of the original procurement
event), the number of transitional reliability
capacity credits for which the electric utility is
required to make payment shall be reduced pro rata for
each generating unit based on the number of
transitional reliability capacity credits contracted

09900SB2939sam003 - 48 - LRB099 19038 EGJ 49324 a
for from the generating unit relative to the total
number of transitional reliability capacity credits
contracted by the electric utility for the period.
(B) On or before the 10th day of each month,
subject to the limitation set forth in subparagraph
(A), the electric utility shall pay the owner of the
generating unit for transitional reliability capacity
credits in the preceding month, based on the number of
days in the preceding month.
(9) The program for provision and purchase of
transitional reliability capacity credits provided for in
this subsection (d-10) and the obligation of electric
utilities to purchase transitional reliability capacity
credits shall terminate on May 31 next following the date
that the Agency determines that each electric utility that
on December 31, 2015 provided delivery services to at least
100,000 retail electric customers have become members of a
regional transmission organization meeting the following
criteria:
(A) The regional transmission organization
maintains a market for the provision and acquisition of
electric generation capacity resources that includes
an electric generation capacity auction process that
has the following characteristics: (i) a
downward-sloping demand curve for electric generation
capacity resources; (ii) buyer-side and supplier-side

09900SB2939sam003 - 49 - LRB099 19038 EGJ 49324 a
market power mitigation mechanisms sufficient to
prevent manipulation of the electric capacity market
by both buyers and sellers of electric generation
capacity, such as must-offer requirements for electric
generation capacity resources, mandatory participation
by load-serving entities for all load, structural
market power tests based on numbers of suppliers, and
minimum and maximum offer price requirements with
energy and ancillary services revenue offsets; (iii) a
forward term for the base electric generation capacity
auction of at least 3 years from the date of each base
electric generation capacity auction to the date when
the electric generation capacity acquired in the
auction is to be provided by the supplier; and (iv) an
explicit capacity performance product component
designed to drive improved generator reliability (A)
that provides incentives to generators to make
investments that help ensure that they perform
reliably during extreme weather events and (B) that
places value upon dependable fuel supplies; and
(B) At least 50% of the electric utilities that are
members of the regional transmission organization
primarily serve retail electricity customers located
in states offering retail electricity competition, or
the option to choose the customer's electricity
supplier, to a majority of the retail customers in the

09900SB2939sam003 - 50 - LRB099 19038 EGJ 49324 a
State.
Following the termination of the program provided for in
this subsection (d-10) and the completion of all contractual
arrangements for the provision of and payment for transitional
reliability capacity credits, any balance remaining in an
electric utility's reserve fund shall be refunded to the
electric utility's delivery services customers at the rate of
0.114 cents per kilowatthour until exhausted.
(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.
(Source: P.A. 97-325, eff. 8-12-11; 97-616, eff. 10-26-11;
97-618, eff. 10-26-11; 97-658, eff. 1-13-12; 97-813, eff.
7-13-12; 98-463, eff. 8-16-13.)
Section 10. The Public Utilities Act is amended by changing

09900SB2939sam003 - 51 - LRB099 19038 EGJ 49324 a
Sections 16-108 and 16-126.1 and by adding Section 16-126.2 as
follows:
(220 ILCS 5/16-108)
Sec. 16-108. Recovery of costs associated with the
provision of delivery services and certain other charges.
(a) An electric utility shall file a delivery services
tariff with the Commission at least 210 days prior to the date
that it is required to begin offering such services pursuant to
this Act. An electric utility shall provide the components of
delivery services that are subject to the jurisdiction of the
Federal Energy Regulatory Commission at the same prices, terms
and conditions set forth in its applicable tariff as approved
or allowed into effect by that Commission. The Commission shall
otherwise have the authority pursuant to Article IX to review,
approve, and modify the prices, terms and conditions of those
components of delivery services not subject to the jurisdiction
of the Federal Energy Regulatory Commission, including the
authority to determine the extent to which such delivery
services should be offered on an unbundled basis. In making any
such determination the Commission shall consider, at a minimum,
the effect of additional unbundling on (i) the objective of
just and reasonable rates, (ii) electric utility employees, and
(iii) the development of competitive markets for electric
energy services in Illinois.
(b) The Commission shall enter an order approving, or

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approving as modified, the delivery services tariff no later
than 30 days prior to the date on which the electric utility
must commence offering such services. The Commission may
subsequently modify such tariff pursuant to this Act.
(c) The electric utility's tariffs shall define the classes
of its customers for purposes of delivery services charges.
Delivery services shall be priced and made available to all
retail customers electing delivery services in each such class
on a nondiscriminatory basis regardless of whether the retail
customer chooses the electric utility, an affiliate of the
electric utility, or another entity as its supplier of electric
power and energy. Charges for delivery services shall be cost
based, and shall allow the electric utility to recover the
costs of providing delivery services through its charges to its
delivery service customers that use the facilities and services
associated with such costs. Such costs shall include the costs
of owning, operating and maintaining transmission and
distribution facilities. The Commission shall also be
authorized to consider whether, and if so to what extent, the
following costs are appropriately included in the electric
utility's delivery services rates: (i) the costs of that
portion of generation facilities used for the production and
absorption of reactive power in order that retail customers
located in the electric utility's service area can receive
electric power and energy from suppliers other than the
electric utility, and (ii) the costs associated with the use

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and redispatch of generation facilities to mitigate
constraints on the transmission or distribution system in order
that retail customers located in the electric utility's service
area can receive electric power and energy from suppliers other
than the electric utility. Nothing in this subsection shall be
construed as directing the Commission to allocate any of the
costs described in (i) or (ii) that are found to be
appropriately included in the electric utility's delivery
services rates to any particular customer group or geographic
area in setting delivery services rates.
(d) The Commission shall establish charges, terms and
conditions for delivery services that are just and reasonable
and shall take into account customer impacts when establishing
such charges. In establishing charges, terms and conditions for
delivery services, the Commission shall take into account
voltage level differences. A retail customer shall have the
option to request to purchase electric service at any delivery
service voltage reasonably and technically feasible from the
electric facilities serving that customer's premises provided
that there are no significant adverse impacts upon system
reliability or system efficiency. A retail customer shall also
have the option to request to purchase electric service at any
point of delivery that is reasonably and technically feasible
provided that there are no significant adverse impacts on
system reliability or efficiency. Such requests shall not be
unreasonably denied.

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(e) Electric utilities shall recover the costs of
installing, operating or maintaining facilities for the
particular benefit of one or more delivery services customers,
including without limitation any costs incurred in complying
with a customer's request to be served at a different voltage
level, directly from the retail customer or customers for whose
benefit the costs were incurred, to the extent such costs are
not recovered through the charges referred to in subsections
(c) and (d) of this Section.
(f) An electric utility shall be entitled but not required
to implement transition charges in conjunction with the
offering of delivery services pursuant to Section 16-104. If an
electric utility implements transition charges, it shall
implement such charges for all delivery services customers and
for all customers described in subsection (h), but shall not
implement transition charges for power and energy that a retail
customer takes from cogeneration or self-generation facilities
located on that retail customer's premises, if such facilities
meet the following criteria:
(i) the cogeneration or self-generation facilities
serve a single retail customer and are located on that
retail customer's premises (for purposes of this
subparagraph and subparagraph (ii), an industrial or
manufacturing retail customer and a third party contractor
that is served by such industrial or manufacturing customer
through such retail customer's own electrical distribution

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facilities under the circumstances described in subsection
(vi) of the definition of "alternative retail electric
supplier" set forth in Section 16-102, shall be considered
a single retail customer);
(ii) the cogeneration or self-generation facilities
either (A) are sized pursuant to generally accepted
engineering standards for the retail customer's electrical
load at that premises (taking into account standby or other
reliability considerations related to that retail
customer's operations at that site) or (B) if the facility
is a cogeneration facility located on the retail customer's
premises, the retail customer is the thermal host for that
facility and the facility has been designed to meet that
retail customer's thermal energy requirements resulting in
electrical output beyond that retail customer's electrical
demand at that premises, comply with the operating and
efficiency standards applicable to "qualifying facilities"
specified in title 18 Code of Federal Regulations Section
292.205 as in effect on the effective date of this
amendatory Act of 1999;
(iii) the retail customer on whose premises the
facilities are located either has an exclusive right to
receive, and corresponding obligation to pay for, all of
the electrical capacity of the facility, or in the case of
a cogeneration facility that has been designed to meet the
retail customer's thermal energy requirements at that

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premises, an identified amount of the electrical capacity
of the facility, over a minimum 5-year period; and
(iv) if the cogeneration facility is sized for the
retail customer's thermal load at that premises but exceeds
the electrical load, any sales of excess power or energy
are made only at wholesale, are subject to the jurisdiction
of the Federal Energy Regulatory Commission, and are not
for the purpose of circumventing the provisions of this
subsection (f).
If a generation facility located at a retail customer's
premises does not meet the above criteria, an electric utility
implementing transition charges shall implement a transition
charge until December 31, 2006 for any power and energy taken
by such retail customer from such facility as if such power and
energy had been delivered by the electric utility. Provided,
however, that an industrial retail customer that is taking
power from a generation facility that does not meet the above
criteria but that is located on such customer's premises will
not be subject to a transition charge for the power and energy
taken by such retail customer from such generation facility if
the facility does not serve any other retail customer and
either was installed on behalf of the customer and for its own
use prior to January 1, 1997, or is both predominantly fueled
by byproducts of such customer's manufacturing process at such
premises and sells or offers an average of 300 megawatts or
more of electricity produced from such generation facility into

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the wholesale market. Such charges shall be calculated as
provided in Section 16-102, and shall be collected on each
kilowatt-hour delivered under a delivery services tariff to a
retail customer from the date the customer first takes delivery
services until December 31, 2006 except as provided in
subsection (h) of this Section. Provided, however, that an
electric utility, other than an electric utility providing
service to at least 1,000,000 customers in this State on
January 1, 1999, shall be entitled to petition for entry of an
order by the Commission authorizing the electric utility to
implement transition charges for an additional period ending no
later than December 31, 2008. The electric utility shall file
its petition with supporting evidence no earlier than 16
months, and no later than 12 months, prior to December 31,
2006. The Commission shall hold a hearing on the electric
utility's petition and shall enter its order no later than 8
months after the petition is filed. The Commission shall
determine whether and to what extent the electric utility shall
be authorized to implement transition charges for an additional
period. The Commission may authorize the electric utility to
implement transition charges for some or all of the additional
period, and shall determine the mitigation factors to be used
in implementing such transition charges; provided, that the
Commission shall not authorize mitigation factors less than
110% of those in effect during the 12 months ended December 31,
2006. In making its determination, the Commission shall

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consider the following factors: the necessity to implement
transition charges for an additional period in order to
maintain the financial integrity of the electric utility; the
prudence of the electric utility's actions in reducing its
costs since the effective date of this amendatory Act of 1997;
the ability of the electric utility to provide safe, adequate
and reliable service to retail customers in its service area;
and the impact on competition of allowing the electric utility
to implement transition charges for the additional period.
(g) The electric utility shall file tariffs that establish
the transition charges to be paid by each class of customers to
the electric utility in conjunction with the provision of
delivery services. The electric utility's tariffs shall define
the classes of its customers for purposes of calculating
transition charges. The electric utility's tariffs shall
provide for the calculation of transition charges on a
customer-specific basis for any retail customer whose average
monthly maximum electrical demand on the electric utility's
system during the 6 months with the customer's highest monthly
maximum electrical demands equals or exceeds 3.0 megawatts for
electric utilities having more than 1,000,000 customers, and
for other electric utilities for any customer that has an
average monthly maximum electrical demand on the electric
utility's system of one megawatt or more, and (A) for which
there exists data on the customer's usage during the 3 years
preceding the date that the customer became eligible to take

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delivery services, or (B) for which there does not exist data
on the customer's usage during the 3 years preceding the date
that the customer became eligible to take delivery services, if
in the electric utility's reasonable judgment there exists
comparable usage information or a sufficient basis to develop
such information, and further provided that the electric
utility can require customers for which an individual
calculation is made to sign contracts that set forth the
transition charges to be paid by the customer to the electric
utility pursuant to the tariff.
(h) An electric utility shall also be entitled to file
tariffs that allow it to collect transition charges from retail
customers in the electric utility's service area that do not
take delivery services but that take electric power or energy
from an alternative retail electric supplier or from an
electric utility other than the electric utility in whose
service area the customer is located. Such charges shall be
calculated, in accordance with the definition of transition
charges in Section 16-102, for the period of time that the
customer would be obligated to pay transition charges if it
were taking delivery services, except that no deduction for
delivery services revenues shall be made in such calculation,
and usage data from the customer's class shall be used where
historical usage data is not available for the individual
customer. The customer shall be obligated to pay such charges
on a lump sum basis on or before the date on which the customer

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commences to take service from the alternative retail electric
supplier or other electric utility, provided, that the electric
utility in whose service area the customer is located shall
offer the customer the option of signing a contract pursuant to
which the customer pays such charges ratably over the period in
which the charges would otherwise have applied.
(i) An electric utility shall be entitled to add to the
bills of delivery services customers charges pursuant to
Sections 9-221, 9-222 (except as provided in Section 9-222.1),
and Section 16-114 of this Act, Section 5-5 of the Electricity
Infrastructure Maintenance Fee Law, Section 6-5 of the
Renewable Energy, Energy Efficiency, and Coal Resources
Development Law of 1997, and Section 13 of the Energy
Assistance Act. Beginning November 1, 2016, an electric utility
required to impose the transitional electric generation
reliability support charge provided for in subsection (d-10) of
Section 1-75 of the Illinois Power Agency Act shall add such
charge to the bills of its delivery services customers. The
electric utility shall use the collections from imposition of
the transitional electric generation reliability support
charge to pay for transitional reliability capacity credits in
accordance with subsection (d-10) of Section 1-75 of the
Illinois Power Agency Act, with any collections in excess of
current period payment obligations to be maintained in a
reserve fund until the electric utility is authorized to refund
the balance, if any, in the reserve fund to its delivery

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services customers in accordance with subsection (d-10) 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
Section 16-110.
(Source: P.A. 91-50, eff. 6-30-99; 92-690, eff. 7-18-02.)

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(220 ILCS 5/16-126.1)
Sec. 16-126.1. Regional transmission organization
memberships. The State shall not directly or indirectly
prohibit an electric utility that on December 31, 2005 provided
electric service to at least 100,000 customers in Illinois from
membership in a Federal Energy Regulatory Commission approved
regional transmission organization of its choosing. Nothing in
this Section limits any authority the Commission otherwise has
to regulate that electric utility. This Section ceases to be
effective on July 1, 2016 2022 unless extended by the General
Assembly by law.
(Source: P.A. 95-481, eff. 8-28-07.)
(220 ILCS 5/16-126.2 new)
Sec. 16-126.2. Regional transmission organization capacity
markets.
(a) The General Assembly finds that the electric generation
capacity market design of one or more regional transmission
organizations of which Illinois electric utilities are members
fails to adequately provide price signals that (i) incent the
development and availability of electric generation capacity
resources at times of high demand or unusual stress on the
electric generation and transmission system, and thereby fail
to promote the provision of adequate, reliable, and efficient
electric service to the citizens and businesses of the State of
Illinois, and (ii) provide adequate compensation to providers

09900SB2939sam003 - 63 - LRB099 19038 EGJ 49324 a
of electric generation capacity resources needed to maintain,
at all times of the day, week, and year and under all
conditions affecting the electric generation and transmission
resources and system, adequate, reliable, and efficient
electric service to the citizens and businesses of the State of
Illinois.
One of the regional transmission organizations of which
Illinois electric utilities are members has a membership that
overwhelmingly consists of vertically integrated utilities
that own generating facilities the costs of which are recovered
through cost-of-service-based rates that are charged to
captive retail customers and that serve customers in states
that, unlike Illinois, have elected not to enter into retail
electric competition; and the other regional transmission
organization has a membership that overwhelmingly consists of
utilities that do not own the generation facilities but rather
obtain their electric supply in competitive wholesale
generation markets and that serve customers in states that,
like Illinois, have adopted retail electric competition.
The State of Illinois has a direct interest and
responsibility in ensuring that the citizens and businesses of
the State of Illinois receive and obtain adequate, reliable,
and efficient electric service at all hours of the day, week,
and year and under all conditions affecting the electric
generation and transmission resources and system serving the
State of Illinois, and in thereby promoting the health,

09900SB2939sam003 - 64 - LRB099 19038 EGJ 49324 a
welfare, and safety of the citizens of this State.
It is in the public interest of the State of Illinois and
its citizens for the State to ensure that electric utilities
holding certificates of public convenience and necessity to
provide service in this State and providing electric service to
citizens and businesses in the State of Illinois participate in
regional transmission organizations with wholesale electricity
market structures and processes that provide price signals that
(i) incent the development and availability of electric
generation capacity resources at times of high demand or
unusual stress on the electric generation and transmission
system, and thereby promote the provision of adequate,
reliable, and efficient electric service to the citizens and
businesses of the State of Illinois, and (ii) provide adequate
compensation to providers of electric generation capacity
resources needed to maintain, at all times of the day, week,
and year and under all conditions affecting the electric
generation and transmission resources and system, adequate,
reliable, and efficient electric service to the citizens and
businesses of the State of Illinois, while (iii) maintaining
appropriate mechanisms to measure and protect against the
exercise of undue market power by both suppliers and buyers of
electric generation capacity resources.
The General Assembly has heretofore allowed electric
utilities serving customers in Illinois to exercise choice in
determining which regional transmission organization to join,

09900SB2939sam003 - 65 - LRB099 19038 EGJ 49324 a
in the interests of experimentation during the formative years
of regional transmission organizations and electric industry
restructuring, the General Assembly now finds, based on the
review of experience in Illinois, that having portions of the
State of Illinois located within different regional
transmission organizations is undesirable for numerous
reasons, including those stated in the other findings in this
subsection (a), and that it results in electric generating
capacity located within the different regional transmission
organizations receiving different compensation for providing
the same electric capacity, energy, and reliability services
and that absent overwhelming justification to the contrary, it
is in the public interest of the State of Illinois and its
citizens and businesses that all electric utilities in this
State serving more than 100,000 retail electric customers
should be members of the same regional transmission
organization.
(b) On or before September 1, 2016, the Illinois Commerce
Commission shall initiate a proceeding to evaluate the existing
regional transmission organization of which each electric
utility that on December 31, 2015 provided delivery services to
at least 100,000 retail electric customers in Illinois is a
member. No later than February 28, 2017, the Commission shall
make a determination as to whether each such regional
transmission organization met each of the following criteria as
of September 1, 2016:

09900SB2939sam003 - 66 - LRB099 19038 EGJ 49324 a
(1) The regional transmission organization maintains a
market for the provision and acquisition of electric
generation capacity resources including an electric
generation capacity auction process that has the following
characteristics:
(A) a downward-sloping demand curve for electric
generation capacity resources;
(B) buyer-side and supplier-side market power
mitigation mechanisms sufficient to prevent
manipulation of the electric capacity market by both
buyers and sellers of electric generation capacity,
such as must-offer requirements for electric
generation capacity resources, mandatory participation
by load-serving entities for all load, structural
market power tests based on numbers of suppliers, and
minimum and maximum offer price requirements with
energy and ancillary services revenue offsets;
(C) a forward term for the base electric generation
capacity auction of at least 3 years from the date of
each base electric generation capacity auction to the
date when the electric generation capacity acquired in
the auction is to be provided by the supplier; and
(D) an explicit capacity performance product
component designed to drive improved generator
reliability (i) that incents generators to make
investments that help ensure that they perform

09900SB2939sam003 - 67 - LRB099 19038 EGJ 49324 a
reliably during extreme weather events and (ii) that
places value upon dependable fuel supplies.
(2) At least 50% of the electric utilities that are
members of the regional transmission organization
primarily serve retail electricity customers located in
states offering retail electricity competition, or the
option to choose the customer's electricity supplier, to a
majority of the retail customers in the state.
(c) If the Commission determines in the proceeding
described in subsection (b) that an electric utility that on
December 31, 2015 provided delivery services to at least
100,000 retail electricity customers in Illinois is not a
member of a regional transmission organization meeting all of
the criteria specified in subsection (b) as of September 1,
2016, then the Commission shall issue an order in the
proceeding described in subsection (b) directing the electric
utility to initiate all actions necessary to become a member of
a regional transmission organization that the Commission has
found meets the criteria specified in subsection (b). The
actions that the Commission shall require of the electric
utility shall include initiating all actions necessary to
withdraw from membership in the regional transmission
organization of which the electric utility is a member and
applying for membership in a regional transmission
organization that the Commission has found meets the criteria
specified in subsection (b). For purposes of this subsection

09900SB2939sam003 - 68 - LRB099 19038 EGJ 49324 a
(c), "initiating all actions" shall include, without
limitation: (1) submitting any required notice of withdrawal of
membership to the regional transmission organization of which
the electric utility is a member, (2) submitting any required
application for membership to a regional transmission
organization that the Commission has found meets the criteria
specified in subsection (b), and (3) making any necessary
filings with the Federal Energy Regulatory Commission for
approval to withdraw from membership in one regional
transmission organization and to become a member of a regional
transmission organization meeting the criteria specified in
subsection (b).
(d) If an electric utility that is directed by the
Commission pursuant to subsection (c) to become a member of a
different regional transmission organization owns electric
transmission facilities in another state in addition to
Illinois, the electric utility is required to comply with the
Commission's order issued pursuant to subsection (c) only with
respect to its transmission facilities located within the State
of Illinois. Nothing in this subsection (d) shall preclude the
electric utility from transferring all of its electric
transmission facilities to a regional transmission
organization that meets the criteria specified in subsection
(b).
(e) If an electric utility that is required to withdraw
from membership in a regional transmission organization

09900SB2939sam003 - 69 - LRB099 19038 EGJ 49324 a
pursuant to subsection (c) is assessed exit fees or similar
charges, hereinafter referred to as "exit fees", by the
regional transmission organization, and the assessment and
amount of the exit fees is agreed to by the electric utility or
confirmed or approved by the Federal Energy Regulatory
Commission, the electric utility may file an application with
the Commission for authority to recover the amount of the exit
fees allocable to the electric utility's transmission
facilities or operations in the State of Illinois through
charges to the electric utility's delivery services customers
in Illinois. The Commission shall authorize the electric
utility to recover the amount of exit fees assessed by the
regional transmission organization and agreed to by the
electric utility or approved by the Federal Energy Regulatory
Commission that are allocable to Illinois, less any amount of
the exit fees that the electric utility is authorized to
recover or be reimbursed for through other means, as a cost of
service through the electric utility's delivery services
tariffs. The exit fees shall be recovered through a charge per
kilowatt-hour included in the electric utility's delivery
services tariff. The charge per kilowatt-hour shall be uniform
for all customer classes. The electric utility's tariff shall
provide for annual reconciliation filings with the Commission
to reconcile the amount collected with the amount authorized to
be collected and to provide for surcharges or refunds to
address any under-collections or over-collections. The

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Commission may direct that the amount of exit fees shall be
recovered through charges in the electric utility's delivery
services tariffs over a period longer than one year; provided,
that in such event, the Commission shall authorize the electric
utility to record carrying charges, at the rate of return
authorized in setting the electric utility's delivery services
rates, on the unrecovered balance of exit fees, and to include
the carrying charges in the amount of exit fees to be
recovered. The Commission shall issue its order granting the
electric utility authority to recover exit fees and approving a
tariff for this purpose, in accordance with this subsection
(e), within 120 days following the filing of the electric
utility's application.
(f) Nothing in this Section shall be construed as imposing
any requirements or obligations that are in conflict with
federal law.
(g) The Commission shall have authority, on its own motion
or on complaint, to investigate and determine an electric
utility's compliance with this Section, including, without
limiting the scope of the Commission's authority, to determine
the electric utility's compliance with this Section. Any
investigation or complaint proceeding before the Commission
shall be completed by the issuance of a final order within 6
months following the date that the Commission issued its order
initiating the investigation or that the complaint was filed.

09900SB2939sam003 - 71 - LRB099 19038 EGJ 49324 a
Section 99. Effective date. This Act takes effect upon
becoming law.".