SB2939sam003 99TH GENERAL ASSEMBLY

Sen. James F. Clayborne, Jr.

Filed: 5/27/2016

09900SB2939sam003 LRB099 19038 EGJ 49324 a

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 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 sector, including managing supply risk;

(D) expertise in wholesale electricity market rules, including those established by the Federal Energy Regulatory Commission and regional transmission organizations;

(E) expertise in credit protocols and familiarity with contract protocols;

(F) adequate resources to perform and fulfill the required functions and responsibilities; and

(G) the absence of a conflict of interest and inappropriate bias for or against potential bidders or the affected electric utilities.

(2) The Agency shall each year, as needed, issue a request for qualifications for a procurement administrator to conduct the competitive procurement processes in accordance with Section 16-111.5 of the Public Utilities Act. In order to qualify an expert or expert consulting firm must have:

(A) direct previous experience administering a large-scale competitive procurement process;

(B) an advanced degree in economics, mathematics, engineering, or a related area of study;

(C) 10 years of experience in the electricity sector, including risk management experience;

(D) expertise in wholesale electricity market rules, including those established by the Federal Energy Regulatory Commission and regional transmission organizations;

(E) expertise in credit and contract protocols;

(F) adequate resources to perform and fulfill the required functions and responsibilities; and

(G) the absence of a conflict of interest and inappropriate bias for or against potential bidders or the affected electric utilities.

(3) The Agency shall provide affected utilities and other interested parties with the lists of qualified experts or expert consulting firms identified through the request for qualifications processes that are under consideration to develop the procurement plans and to serve as the procurement administrator. The Agency shall also provide each qualified expert's or expert consulting firm's response to the request for qualifications. All information provided under this subparagraph shall also be provided to the Commission. The Agency may provide by rule for fees associated with supplying the information to utilities and other interested parties. These parties shall, within 5 business days, notify the Agency in writing if they object to any experts or expert consulting firms on the lists. Objections shall be based on:

(A) failure to satisfy qualification criteria;

(B) identification of a conflict of interest; or

(C) evidence of inappropriate bias for or against potential bidders or the affected utilities.

The Agency shall remove experts or expert consulting firms from the lists within 10 days if there is a reasonable basis for an objection and provide the updated lists to the affected utilities and other interested parties. If the Agency fails to remove an expert or expert consulting firm from a list, an objecting party may seek review by the Commission within 5 days thereafter by filing a petition, and the Commission shall render a ruling on the petition within 10 days. There is no right of appeal of the Commission's ruling.

(4) The Agency shall issue requests for proposals to the qualified experts or expert consulting firms to develop a procurement plan for the affected utilities and to serve as procurement administrator.

(5) The Agency shall select an expert or expert consulting firm to develop procurement plans based on the proposals submitted and shall award contracts of up to 5 years to those selected.

(6) The Agency shall select an expert or expert consulting firm, with approval of the Commission, to serve as procurement administrator based on the proposals submitted. If the Commission rejects, within 5 days, the Agency's selection, the Agency shall submit another recommendation within 3 days based on the proposals submitted. The Agency shall award a 5-year contract to the expert or expert consulting firm so selected with Commission approval.

(b) The experts or expert consulting firms retained by the Agency shall, as appropriate, prepare procurement plans, and conduct a competitive procurement process as prescribed in Section 16-111.5 of the Public Utilities Act, to ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time, taking into account any benefits of price stability, for eligible retail customers of electric utilities that on December 31, 2005 provided electric service to at least 100,000 customers in the State of Illinois, and for eligible Illinois retail customers of small multi-jurisdictional electric utilities that (i) on December 31, 2005 served less than 100,000 customers in Illinois and (ii) request a procurement plan for their Illinois jurisdictional load.

(c) Renewable portfolio standard.

(1) The procurement plans shall include cost-effective renewable energy resources. A minimum percentage of each utility's total supply to serve the load of eligible retail customers, as defined in Section 16-111.5(a) of the Public Utilities Act, procured for each of the following years shall be generated from cost-effective renewable energy resources: at least 2% by June 1, 2008; at least 4% by June 1, 2009; at least 5% by June 1, 2010; at least 6% by June 1, 2011; at least 7% by June 1, 2012; at least 8% by June 1, 2013; at least 9% by June 1, 2014; at least 10% by June 1, 2015; and increasing by at least 1.5% each year thereafter to at least 25% by June 1, 2025. To the extent that it is available, at least 75% of the renewable energy resources used to meet these standards shall come from wind generation and, beginning on June 1, 2011, at least the following percentages of the renewable energy resources used to meet these standards shall come from photovoltaics on the following schedule: 0.5% by June 1, 2012, 1.5% by June 1, 2013; 3% by June 1, 2014; and 6% by June 1, 2015 and thereafter. Of the renewable energy resources procured pursuant to this Section, at least the following percentages shall come from distributed renewable energy generation devices: 0.5% by June 1, 2013, 0.75% by June 1, 2014, and 1% by June 1, 2015 and thereafter. To the extent available, half of the renewable energy resources procured from distributed renewable energy generation shall come from devices of less than 25 kilowatts in nameplate capacity. Renewable energy resources procured from distributed generation devices may also count towards the required percentages for wind and solar photovoltaics. Procurement of renewable energy resources from distributed renewable energy generation devices shall be done on an annual basis through multi-year contracts of no less than 5 years, and shall consist solely of renewable energy credits.

The Agency shall create credit requirements for suppliers of distributed renewable energy. In order to minimize the administrative burden on contracting entities, the Agency shall solicit the use of third-party organizations to aggregate distributed renewable energy into groups of no less than one megawatt in installed capacity. These third-party organizations shall administer contracts with individual distributed renewable energy generation device owners. An individual distributed renewable energy generation device owner shall have the ability to measure the output of his or her distributed renewable energy generation device.

For purposes of this subsection (c), "cost-effective" means that the costs of procuring renewable energy resources do not cause the limit stated in paragraph (2) of this subsection (c) to be exceeded and do not exceed benchmarks based on market prices for renewable energy resources in the region, which shall be developed by the procurement administrator, in consultation with the Commission staff, Agency staff, and the procurement monitor and shall be subject to Commission review and approval.

(2) For purposes of this subsection (c), the required procurement of cost-effective renewable energy resources for a particular year shall be measured as a percentage of the actual amount of electricity (megawatt-hours) supplied by the electric utility to eligible retail customers in the planning year ending immediately prior to the procurement. For purposes of this subsection (c), the amount paid per kilowatthour means the total amount paid for electric service expressed on a per kilowatthour basis. For purposes of this subsection (c), the total amount paid for electric service includes without limitation amounts paid for supply, transmission, distribution, surcharges, and add-on taxes.

Notwithstanding the requirements of this subsection (c), the total of renewable energy resources procured pursuant to the procurement plan for any single year shall be reduced by an amount necessary to limit the annual estimated average net increase due to the costs of these resources included in the amounts paid by eligible retail customers in connection with electric service to:

(A) in 2008, no more than 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2007;

(B) in 2009, the greater of an additional 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2008 or 1% of the amount paid per kilowatthour by those customers during the year ending May 31, 2007;

(C) in 2010, the greater of an additional 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009 or 1.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2007;

(D) in 2011, the greater of an additional 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2010 or 2% of the amount paid per kilowatthour by those customers during the year ending May 31, 2007; and

(E) thereafter, the amount of renewable energy resources procured pursuant to the procurement plan for any single year shall be reduced by an amount necessary to limit the estimated average net increase due to the cost of these resources included in the amounts paid by eligible retail customers in connection with electric service to no more than the greater of 2.015% of the amount paid per kilowatthour by those customers during the year ending May 31, 2007 or the incremental amount per kilowatthour paid for these resources in 2011.

No later than June 30, 2011, the Commission shall review the limitation on the amount of renewable energy resources procured pursuant to this subsection (c) and report to the General Assembly its findings as to whether that limitation unduly constrains the procurement of cost-effective renewable energy resources.

(3) 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 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 (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 total supply to serve the load of eligible retail customers in 2015 and each year thereafter, as described in paragraph (3) of this subsection (d), subject to the limits specified in paragraph (2) of this subsection (d). It is the goal of the State that by January 1, 2025, 25% of the electricity used in the State shall be generated by cost-effective clean coal facilities. For purposes of this subsection (d), "cost-effective" means that the expenditures pursuant to such sourcing agreements do not cause the limit stated in paragraph (2) of this subsection (d) to be exceeded and do not exceed cost-based benchmarks, which shall be developed to assess all expenditures pursuant to such sourcing agreements covering electricity generated by clean coal facilities, other than the initial clean coal facility, by the procurement administrator, in consultation with the Commission staff, Agency staff, and the procurement monitor and shall be subject to Commission review and approval.

A utility party to a sourcing agreement shall immediately retire any emission credits that it receives in connection with the electricity covered by such agreement.

Utilities shall maintain adequate records documenting the purchases under the sourcing agreement to comply with this subsection (d) and shall file an accounting with the load forecast that must be filed with the Agency by July 15 of each year, in accordance with subsection (d) of Section 16-111.5 of the Public Utilities Act.

A utility shall be deemed to have complied with the clean coal portfolio standard specified in this subsection (d) if the utility enters into a sourcing agreement as required by this subsection (d).

(2) For purposes of this subsection (d), the required execution of sourcing agreements with the initial clean coal facility for a particular year shall be measured as a percentage of the actual amount of electricity (megawatt-hours) supplied by the electric utility to eligible retail customers in the planning year ending immediately prior to the agreement's execution. For purposes of this subsection (d), the amount paid per kilowatthour means the total amount paid for electric service expressed on a per kilowatthour basis. For purposes of this subsection (d), the total amount paid for electric service includes without limitation amounts paid for supply, transmission, distribution, surcharges and add-on taxes.

Notwithstanding the requirements of this subsection (d), the total amount paid under sourcing agreements with clean coal facilities pursuant to the procurement plan for any given year shall be reduced by an amount necessary to limit the annual estimated average net increase due to the costs of these resources included in the amounts paid by eligible retail customers in connection with electric service to:

(A) in 2010, no more than 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009;

(B) in 2011, the greater of an additional 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2010 or 1% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009;

(C) in 2012, the greater of an additional 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2011 or 1.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009;

(D) in 2013, the greater of an additional 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2012 or 2% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009; and

(E) thereafter, the total amount paid under sourcing agreements with clean coal facilities pursuant to the procurement plan for any single year shall be reduced by an amount necessary to limit the estimated average net increase due to the cost of these resources included in the amounts paid by eligible retail customers in connection with electric service to no more than the greater of (i) 2.015% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009 or (ii) the incremental amount per kilowatthour paid for these resources in 2013, 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 amendatory Act of the 95th General Assembly, and that will meet the definition of clean coal facility in Section 1-10 of this Act when commercial operation commences. The sourcing agreements with this initial clean coal facility shall be subject to both approval of the initial clean coal facility by the General Assembly and satisfaction of the requirements of paragraph (4) of this subsection (d) and shall be executed within 90 days after any such approval by the General Assembly. The Agency and the Commission shall have authority to inspect all books and records associated with the initial clean coal facility during the term of such a sourcing agreement. A utility's sourcing agreement for electricity produced by the initial clean coal facility shall include:

(A) a formula contractual price (the "contract price") approved pursuant to paragraph (4) of this subsection (d), which shall:

(i) be determined using a cost of service methodology employing either a level or deferred capital recovery component, based on a capital structure consisting of 45% equity and 55% debt, and a return on equity as may be approved by the Federal Energy Regulatory Commission, which in any case may not exceed the lower of 11.5% or the rate of return approved by the General Assembly pursuant to paragraph (4) of this subsection (d); and

(ii) provide that all miscellaneous net revenue, including but not limited to net revenue from the sale of emission allowances, if any, substitute natural gas, if any, grants or other support provided by the State of Illinois or the United States Government, firm transmission rights, if any, by-products produced by the facility, energy or capacity derived from the facility and not covered by a sourcing agreement pursuant to paragraph (3) of this subsection (d) or item (5) of subsection (d) of Section 16-115 of the Public Utilities Act, whether generated from the synthesis gas derived from coal, from SNG, or from natural gas, shall be credited against the revenue requirement for this initial clean coal facility;

(B) power purchase provisions, which shall:

(i) provide that the utility party to such sourcing agreement shall pay the contract price for electricity delivered under such sourcing agreement;

(ii) require delivery of electricity to the regional transmission organization market of the utility that is party to such sourcing agreement;

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

(iv) be considered pre-existing contracts in such utility's procurement plans for eligible retail customers;

(C) contract for differences provisions, which shall:

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

(ii) provide that the utility's payment obligation in respect of the quantity of electricity determined pursuant to the preceding clause (i) shall be limited to an amount equal to (1) the difference between the contract price determined pursuant to subparagraph (A) of paragraph (3) of this subsection (d) and the day-ahead price for electricity delivered to the regional transmission organization market of the utility that is party to such sourcing agreement (or any successor delivery point at which such utility's supply obligations are financially settled on an hourly basis) (the "reference price") on the day preceding the day on which the electricity is delivered to the initial clean coal facility busbar, multiplied by (2) the quantity of electricity determined pursuant to the preceding clause (i); and

(iii) not require the utility to take physical delivery of the electricity produced by the facility;

(D) general provisions, which shall:

(i) specify a term of no more than 30 years, commencing on the commercial operation date of the facility;

(ii) provide that utilities shall maintain adequate records documenting purchases under the sourcing agreements entered into to comply with this subsection (d) and shall file an accounting with the load forecast that must be filed with the Agency by July 15 of each year, in accordance with subsection (d) of Section 16-111.5 of the Public Utilities Act;

(iii) provide that all costs associated with the initial clean coal facility will be periodically reported to the Federal Energy Regulatory Commission and to purchasers in accordance with applicable laws governing cost-based wholesale power contracts;

(iv) permit the Illinois Power Agency to assume ownership of the initial clean coal facility, without monetary consideration and otherwise on reasonable terms acceptable to the Agency, if the Agency so requests no less than 3 years prior to the end of the stated contract term;

(v) require the owner of the initial clean coal facility to provide documentation to the Commission each year, starting in the facility's first year of commercial operation, accurately reporting the quantity of carbon emissions from the facility that have been captured and sequestered and report any quantities of carbon released from the site or sites at which carbon emissions were sequestered in prior years, based on continuous monitoring of such sites. If, in any year after the first year of commercial operation, the owner of the facility fails to demonstrate that the initial clean coal facility captured and sequestered at least 50% of the total carbon emissions that the facility would otherwise emit or that sequestration of emissions from prior years has failed, resulting in the release of carbon dioxide into the atmosphere, the owner of the facility must offset excess emissions. Any such carbon offsets must be permanent, additional, verifiable, real, located within the State of Illinois, and legally and practicably enforceable. The cost of such offsets for the facility that are not recoverable shall not exceed $15 million in any given year. No costs of any such purchases of carbon offsets may be recovered from a utility or its customers. All carbon offsets purchased for this purpose and any carbon emission credits associated with sequestration of carbon from the facility must be permanently retired. The initial clean coal facility shall not forfeit its designation as a clean coal facility if the facility fails to fully comply with the applicable carbon sequestration requirements in any given year, provided the requisite offsets are purchased. However, the Attorney General, on behalf of the People of the State of Illinois, may specifically enforce the facility's sequestration requirement and the other terms of this contract provision. Compliance with the sequestration requirements and offset purchase requirements specified in paragraph (3) of this subsection (d) shall be reviewed annually by an independent expert retained by the owner of the initial clean coal facility, with the advance written approval of the Attorney General. The Commission may, in the course of the review specified in item (vii), reduce the allowable return on equity for the facility if the facility wilfully fails to comply with the carbon capture and sequestration requirements set forth in this item (v);

(vi) include limits on, and accordingly provide for modification of, the amount the utility is required to source under the sourcing agreement consistent with paragraph (2) of this subsection (d);

(vii) require Commission review: (1) to determine the justness, reasonableness, and prudence of the inputs to the formula referenced in subparagraphs (A)(i) through (A)(iii) of paragraph (3) of this subsection (d), prior to an adjustment in those inputs including, without limitation, the capital structure and return on equity, fuel costs, and other operations and maintenance costs and (2) to approve the costs to be passed through to customers under the sourcing agreement by which the utility satisfies its statutory obligations. Commission review shall occur no less than every 3 years, regardless of whether any adjustments have been proposed, and shall be completed within 9 months;

(viii) limit the utility's obligation to such amount as the utility is allowed to recover through tariffs filed with the Commission, provided that neither the clean coal facility nor the utility waives any right to assert federal pre-emption or any other argument in response to a purported disallowance of recovery costs;

(ix) limit the utility's or alternative retail electric supplier's obligation to incur any liability until such time as the facility is in commercial operation and generating power and energy and such power and energy is being delivered to the facility busbar;

(x) provide that the owner or owners of the initial clean coal facility, which is the counterparty to such sourcing agreement, shall have the right from time to time to elect whether the obligations of the utility party thereto shall be governed by the power purchase provisions or the contract for differences provisions;

(xi) append documentation showing that the formula rate and contract, insofar as they relate to the power purchase provisions, have been approved by the Federal Energy Regulatory Commission pursuant to Section 205 of the Federal Power Act;

(xii) provide that any changes to the terms of the contract, insofar as such changes relate to the power purchase provisions, are subject to review under the public interest standard applied by the Federal Energy Regulatory Commission pursuant to Sections 205 and 206 of the Federal Power Act; and

(xiii) conform with customary lender requirements in power purchase agreements used as the basis for financing non-utility generators.

(4) Effective date of sourcing agreements with the initial clean coal facility.

Any proposed sourcing agreement with the initial clean coal facility shall not become effective unless the following reports are prepared and submitted and authorizations and approvals obtained:

(i) Facility cost report. The owner of the initial clean coal facility shall submit to the Commission, the Agency, and the General Assembly a front-end engineering and design study, a facility cost report, method of financing (including but not limited to structure and associated costs), and an operating and maintenance cost quote for the facility (collectively "facility cost report"), which shall be prepared in accordance with the requirements of this paragraph (4) of subsection (d) of this Section, and shall provide the Commission and the Agency access to the work papers, relied upon documents, and any other backup documentation related to the facility cost report.

(ii) Commission report. Within 6 months following receipt of the facility cost report, the Commission, in consultation with the Agency, shall submit a report to the General Assembly setting forth its analysis of the facility cost report. Such report shall include, but not be limited to, a comparison of the costs associated with electricity generated by the initial clean coal facility to the costs associated with electricity generated by other types of generation facilities, an analysis of the rate impacts on residential and small business customers over the life of the sourcing agreements, and an analysis of the likelihood that the initial clean coal facility will commence commercial operation by and be delivering power to the facility's busbar by 2016. To assist in the preparation of its report, the Commission, in consultation with the Agency, may hire one or more experts or consultants, the costs of which shall be paid for by the owner of the initial clean coal facility. The Commission and Agency may begin the process of selecting such experts or consultants prior to receipt of the facility cost report.

(iii) General Assembly approval. The proposed sourcing agreements shall not take effect unless, based on the facility cost report and the Commission's report, the General Assembly enacts authorizing legislation approving (A) the projected price, stated in cents per kilowatthour, to be charged for electricity generated by the initial clean coal facility, (B) the projected impact on residential and small business customers' bills over the life of the sourcing agreements, and (C) the maximum allowable return on equity for the project; and

(iv) Commission review. If the General Assembly enacts authorizing legislation pursuant to subparagraph (iii) approving a sourcing agreement, the Commission shall, within 90 days of such enactment, complete a review of such sourcing agreement. During such time period, the Commission shall implement any directive of the General Assembly, resolve any disputes between the parties to the sourcing agreement concerning the terms of such agreement, approve the form of such agreement, and issue an order finding that the sourcing agreement is prudent and reasonable.

The facility cost report shall be prepared as follows:

(A) The facility cost report shall be prepared by duly licensed engineering and construction firms detailing the estimated capital costs payable to one or more contractors or suppliers for the engineering, procurement and construction of the components comprising the initial clean coal facility and the estimated costs of operation and maintenance of the facility. The facility cost report shall include:

(i) an estimate of the capital cost of the core plant based on one or more front end engineering and design studies for the gasification island and related facilities. The core plant shall include all civil, structural, mechanical, electrical, control, and safety systems.

(ii) an estimate of the capital cost of the balance of the plant, including any capital costs associated with sequestration of carbon dioxide emissions and all interconnects and interfaces required to operate the facility, such as transmission of electricity, construction or backfeed power supply, pipelines to transport substitute natural gas or carbon dioxide, potable water supply, natural gas supply, water supply, water discharge, landfill, access roads, and coal delivery.

The quoted construction costs shall be expressed in nominal dollars as of the date that the quote is prepared and shall include capitalized financing costs during construction, taxes, insurance, and other owner's costs, and an assumed escalation in materials and labor beyond the date as of which the construction cost quote is expressed.

(B) The front end engineering and design study for the gasification island and the cost study for the balance of plant shall include sufficient design work to permit quantification of major categories of materials, commodities and labor hours, and receipt of quotes from vendors of major equipment required to construct and operate the clean coal facility.

(C) The facility cost report shall also include an operating and maintenance cost quote that will provide the estimated cost of delivered fuel, personnel, maintenance contracts, chemicals, catalysts, consumables, spares, and other fixed and variable operations and maintenance costs. The delivered fuel cost estimate will be provided by a recognized third party expert or experts in the fuel and transportation industries. The balance of the operating and maintenance cost quote, excluding delivered fuel costs, will be developed based on the inputs provided by duly licensed engineering and construction firms performing the construction cost quote, potential vendors under long-term service agreements and plant operating agreements, or recognized third party plant operator or operators.

The operating and maintenance cost quote (including the cost of the front end engineering and design study) shall be expressed in nominal dollars as of the date that the quote is prepared and shall include taxes, insurance, and other owner's costs, and an assumed escalation in materials and labor beyond the date as of which the operating and maintenance cost quote is expressed.

(D) The facility cost report shall also include an analysis of the initial clean coal facility's ability to deliver power and energy into the applicable regional transmission organization markets and an analysis of the expected capacity factor for the initial clean coal facility.

(E) Amounts paid to third parties unrelated to the owner or owners of the initial clean coal facility to prepare the core plant construction cost quote, including the front end engineering and design study, and the operating and maintenance cost quote will be reimbursed through Coal Development Bonds.

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

(6) Costs incurred under this subsection (d) or pursuant to a contract entered into under this subsection (d) shall be deemed prudently incurred and reasonable in amount and the electric utility shall be entitled to full cost recovery pursuant to the tariffs filed with the Commission.

(d-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 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 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 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 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 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 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 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 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;

(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 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 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 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 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 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 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 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 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 approving as modified, the delivery services tariff no later than 30 days prior to the date on which the electric utility must commence offering such services. The Commission may subsequently modify such tariff pursuant to this Act.

(c) The electric utility's tariffs shall define the classes of its customers for purposes of delivery services charges. Delivery services shall be priced and made available to all retail customers electing delivery services in each such class on a nondiscriminatory basis regardless of whether the retail customer chooses the electric utility, an affiliate of the electric utility, or another entity as its supplier of electric power and energy. Charges for delivery services shall be cost based, and shall allow the electric utility to recover the costs of providing delivery services through its charges to its delivery service customers that use the facilities and services associated with such costs. Such costs shall include the costs of owning, operating and maintaining transmission and distribution facilities. The Commission shall also be authorized to consider whether, and if so to what extent, the following costs are appropriately included in the electric utility's delivery services rates: (i) the costs of that portion of generation facilities used for the production and absorption of reactive power in order that retail customers located in the electric utility's service area can receive electric power and energy from suppliers other than the electric utility, and (ii) the costs associated with the use and redispatch of generation facilities to mitigate constraints on the transmission or distribution system in order that retail customers located in the electric utility's service area can receive electric power and energy from suppliers other than the electric utility. Nothing in this subsection shall be construed as directing the Commission to allocate any of the costs described in (i) or (ii) that are found to be appropriately included in the electric utility's delivery services rates to any particular customer group or geographic area in setting delivery services rates.

(d) The Commission shall establish charges, terms and conditions for delivery services that are just and reasonable and shall take into account customer impacts when establishing such charges. In establishing charges, terms and conditions for delivery services, the Commission shall take into account voltage level differences. A retail customer shall have the option to request to purchase electric service at any delivery service voltage reasonably and technically feasible from the electric facilities serving that customer's premises provided that there are no significant adverse impacts upon system reliability or system efficiency. A retail customer shall also have the option to request to purchase electric service at any point of delivery that is reasonably and technically feasible provided that there are no significant adverse impacts on system reliability or efficiency. Such requests shall not be unreasonably denied.

(e) Electric utilities shall recover the costs of installing, operating or maintaining facilities for the particular benefit of one or more delivery services customers, including without limitation any costs incurred in complying with a customer's request to be served at a different voltage level, directly from the retail customer or customers for whose benefit the costs were incurred, to the extent such costs are not recovered through the charges referred to in subsections (c) and (d) of this Section.

(f) An electric utility shall be entitled but not required to implement transition charges in conjunction with the offering of delivery services pursuant to Section 16-104. If an electric utility implements transition charges, it shall implement such charges for all delivery services customers and for all customers described in subsection (h), but shall not implement transition charges for power and energy that a retail customer takes from cogeneration or self-generation facilities located on that retail customer's premises, if such facilities meet the following criteria:

(i) the cogeneration or self-generation facilities serve a single retail customer and are located on that retail customer's premises (for purposes of this subparagraph and subparagraph (ii), an industrial or manufacturing retail customer and a third party contractor that is served by such industrial or manufacturing customer through such retail customer's own electrical distribution facilities under the circumstances described in subsection (vi) of the definition of "alternative retail electric supplier" set forth in Section 16-102, shall be considered a single retail customer);

(ii) the cogeneration or self-generation facilities either (A) are sized pursuant to generally accepted engineering standards for the retail customer's electrical load at that premises (taking into account standby or other reliability considerations related to that retail customer's operations at that site) or (B) if the facility is a cogeneration facility located on the retail customer's premises, the retail customer is the thermal host for that facility and the facility has been designed to meet that retail customer's thermal energy requirements resulting in electrical output beyond that retail customer's electrical demand at that premises, comply with the operating and efficiency standards applicable to "qualifying facilities" specified in title 18 Code of Federal Regulations Section 292.205 as in effect on the effective date of this amendatory Act of 1999;

(iii) the retail customer on whose premises the facilities are located either has an exclusive right to receive, and corresponding obligation to pay for, all of the electrical capacity of the facility, or in the case of a cogeneration facility that has been designed to meet the retail customer's thermal energy requirements at that premises, an identified amount of the electrical capacity of the facility, over a minimum 5-year period; and

(iv) if the cogeneration facility is sized for the retail customer's thermal load at that premises but exceeds the electrical load, any sales of excess power or energy are made only at wholesale, are subject to the jurisdiction of the Federal Energy Regulatory Commission, and are not for the purpose of circumventing the provisions of this subsection (f).

If a generation facility located at a retail customer's premises does not meet the above criteria, an electric utility implementing transition charges shall implement a transition charge until December 31, 2006 for any power and energy taken by such retail customer from such facility as if such power and energy had been delivered by the electric utility. Provided, however, that an industrial retail customer that is taking power from a generation facility that does not meet the above criteria but that is located on such customer's premises will not be subject to a transition charge for the power and energy taken by such retail customer from such generation facility if the facility does not serve any other retail customer and either was installed on behalf of the customer and for its own use prior to January 1, 1997, or is both predominantly fueled by byproducts of such customer's manufacturing process at such premises and sells or offers an average of 300 megawatts or more of electricity produced from such generation facility into the wholesale market. Such charges shall be calculated as provided in Section 16-102, and shall be collected on each kilowatt-hour delivered under a delivery services tariff to a retail customer from the date the customer first takes delivery services until December 31, 2006 except as provided in subsection (h) of this Section. Provided, however, that an electric utility, other than an electric utility providing service to at least 1,000,000 customers in this State on January 1, 1999, shall be entitled to petition for entry of an order by the Commission authorizing the electric utility to implement transition charges for an additional period ending no later than December 31, 2008. The electric utility shall file its petition with supporting evidence no earlier than 16 months, and no later than 12 months, prior to December 31, 2006. The Commission shall hold a hearing on the electric utility's petition and shall enter its order no later than 8 months after the petition is filed. The Commission shall determine whether and to what extent the electric utility shall be authorized to implement transition charges for an additional period. The Commission may authorize the electric utility to implement transition charges for some or all of the additional period, and shall determine the mitigation factors to be used in implementing such transition charges; provided, that the Commission shall not authorize mitigation factors less than 110% of those in effect during the 12 months ended December 31, 2006. In making its determination, the Commission shall consider the following factors: the necessity to implement transition charges for an additional period in order to maintain the financial integrity of the electric utility; the prudence of the electric utility's actions in reducing its costs since the effective date of this amendatory Act of 1997; the ability of the electric utility to provide safe, adequate and reliable service to retail customers in its service area; and the impact on competition of allowing the electric utility to implement transition charges for the additional period.

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

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

(i) An electric utility shall be entitled to add to the bills of delivery services customers charges pursuant to Sections 9-221, 9-222 (except as provided in Section 9-222.1), and Section 16-114 of this Act, Section 5-5 of the Electricity Infrastructure Maintenance Fee Law, Section 6-5 of the Renewable Energy, Energy Efficiency, and Coal Resources Development Law of 1997, and Section 13 of the Energy Assistance Act. 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 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.)

(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 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, 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, 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:

(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 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 (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 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 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.

Section 99. Effective date. This Act takes effect upon becoming law.".