SB1879sam001 99TH GENERAL ASSEMBLY

Sen. Kimberly A. Lightford

Filed: 3/19/2015

09900SB1879sam001 LRB099 10946 MLM 33017 a

AMENDMENT TO SENATE BILL 1879

AMENDMENT NO. ______. Amend Senate Bill 1879 by replacing everything after the enacting clause with the following:

"Section 5. The Illinois Power Agency Act is amended by changing Sections 1-10, 1-56, and 1-75 as follows:

(20 ILCS 3855/1-10)

Sec. 1-10. Definitions.

"Agency" means the Illinois Power Agency.

"Agency loan agreement" means any agreement pursuant to which the Illinois Finance Authority agrees to loan the proceeds of revenue bonds issued with respect to a project to the Agency upon terms providing for loan repayment installments at least sufficient to pay when due all principal of, interest and premium, if any, on those revenue bonds, and providing for maintenance, insurance, and other matters in respect of the project.

"Authority" means the Illinois Finance Authority.

"Brownfield site project" means photovoltaics located at a site that is:

(1) located in an area that, on April 5, 2004, was in non-attainment for the National Ambient Air Quality Standard 1997 PM2.5 Standard;

(2) interconnected at the distribution system level of either an electric utility as defined in this Section, a municipal utility, or an electric cooperative as defined in Section 3-119 of the Public Utilities Act; and

(3) regulated by any of the following entities under the following programs:

(i) the United States Environmental Protection Agency under the federal Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended;

(ii) the United States Environmental Protection Agency under the Corrective Action Program of the federal Resource Conservation and Recovery Act, as amended; or

(iii) the Illinois Environmental Protection Agency under the Illinois Site Remediation Program.

"Clean coal facility" means an electric generating facility that uses primarily coal as a feedstock and that captures and sequesters carbon dioxide emissions at the following levels: at least 50% of the total carbon dioxide emissions that the facility would otherwise emit if, at the time construction commences, the facility is scheduled to commence operation before 2016, at least 70% of the total carbon dioxide emissions that the facility would otherwise emit if, at the time construction commences, the facility is scheduled to commence operation during 2016 or 2017, and at least 90% of the total carbon dioxide emissions that the facility would otherwise emit if, at the time construction commences, the facility is scheduled to commence operation after 2017. The power block of the clean coal facility shall not exceed allowable emission rates for sulfur dioxide, nitrogen oxides, carbon monoxide, particulates and mercury for a natural gas-fired combined-cycle facility the same size as and in the same location as the clean coal facility at the time the clean coal facility obtains an approved air permit. All coal used by a clean coal facility shall have high volatile bituminous rank and greater than 1.7 pounds of sulfur per million btu content, unless the clean coal facility does not use gasification technology and was operating as a conventional coal-fired electric generating facility on June 1, 2009 (the effective date of Public Act 95-1027).

"Clean coal SNG brownfield facility" means a facility that (1) has commenced construction by July 1, 2015 on an urban brownfield site in a municipality with at least 1,000,000 residents; (2) uses a gasification process to produce substitute natural gas; (3) uses coal as at least 50% of the total feedstock over the term of any sourcing agreement with a utility and the remainder of the feedstock may be either petroleum coke or coal, with all such coal having a high bituminous rank and greater than 1.7 pounds of sulfur per million Btu content unless the facility reasonably determines that it is necessary to use additional petroleum coke to deliver additional consumer savings, in which case the facility shall use coal for at least 35% of the total feedstock over the term of any sourcing agreement; and (4) captures and sequesters at least 85% of the total carbon dioxide emissions that the facility would otherwise emit.

"Clean coal SNG facility" means a facility that uses a gasification process to produce substitute natural gas, that sequesters at least 90% of the total carbon dioxide emissions that the facility would otherwise emit, that uses at least 90% coal as a feedstock, with all such coal having a high bituminous rank and greater than 1.7 pounds of sulfur per million btu content, and that has a valid and effective permit to construct emission sources and air pollution control equipment and approval with respect to the federal regulations for Prevention of Significant Deterioration of Air Quality (PSD) for the plant pursuant to the federal Clean Air Act; provided, however, a clean coal SNG brownfield facility shall not be a clean coal SNG facility.

"Commission" means the Illinois Commerce Commission.

"Costs incurred in connection with the development and construction of a facility" means:

(1) the cost of acquisition of all real property, fixtures, and improvements in connection therewith and equipment, personal property, and other property, rights, and easements acquired that are deemed necessary for the operation and maintenance of the facility;

(2) financing costs with respect to bonds, notes, and other evidences of indebtedness of the Agency;

(3) all origination, commitment, utilization, facility, placement, underwriting, syndication, credit enhancement, and rating agency fees;

(4) engineering, design, procurement, consulting, legal, accounting, title insurance, survey, appraisal, escrow, trustee, collateral agency, interest rate hedging, interest rate swap, capitalized interest, contingency, as required by lenders, and other financing costs, and other expenses for professional services; and

(5) the costs of plans, specifications, site study and investigation, installation, surveys, other Agency costs and estimates of costs, and other expenses necessary or incidental to determining the feasibility of any project, together with such other expenses as may be necessary or incidental to the financing, insuring, acquisition, and construction of a specific project and starting up, commissioning, and placing that project in operation.

"Department" means the Department of Commerce and Economic Opportunity.

"Director" means the Director of the Illinois Power Agency.

"Demand-response" means measures that decrease peak electricity demand or shift demand from peak to off-peak periods.

"Distributed renewable energy generation device" means a device that is:

(1) powered by wind, solar thermal energy, photovoltaic cells and panels, biodiesel, crops and untreated and unadulterated organic waste biomass, tree waste, and hydropower that does not involve new construction or significant expansion of hydropower dams;

(2) interconnected at the distribution system level of either an electric utility as defined in this Section, an alternative retail electric supplier as defined in Section 16-102 of the Public Utilities Act, a municipal utility as defined in Section 3-105 of the Public Utilities Act, or a rural electric cooperative as defined in Section 3-119 of the Public Utilities Act;

(3) located on the customer side of the customer's electric meter and is primarily used to offset that customer's electricity load; and

(4) limited in nameplate capacity to no more than 2,000 kilowatts.

"Energy efficiency" means measures that reduce the amount of electricity or natural gas required to achieve a given end use. "Energy efficiency" includes voltage optimization measures, which are measures that optimize the voltage at points on the electric distribution voltage system to conserve energy consumption by electric customers. "Energy efficiency" also includes measures that reduce the total Btus of electricity, and natural gas, and other fuels needed to meet the end use or uses.

"Electric utility" has the same definition as found in Section 16-102 of the Public Utilities Act.

"Facility" means an electric generating unit or a co-generating unit that produces electricity along with related equipment necessary to connect the facility to an electric transmission or distribution system.

"Governmental aggregator" means one or more units of local government that individually or collectively procure electricity to serve residential retail electrical loads located within its or their jurisdiction.

"Local government" means a unit of local government as defined in Section 1 of Article VII of the Illinois Constitution.

"Municipality" means a city, village, or incorporated town.

"Person" means any natural person, firm, partnership, corporation, either domestic or foreign, company, association, limited liability company, joint stock company, or association and includes any trustee, receiver, assignee, or personal representative thereof.

"Project" means the planning, bidding, and construction of a facility.

"Public utility" has the same definition as found in Section 3-105 of the Public Utilities Act.

"Real property" means any interest in land together with all structures, fixtures, and improvements thereon, including lands under water and riparian rights, any easements, covenants, licenses, leases, rights-of-way, uses, and other interests, together with any liens, judgments, mortgages, or other claims or security interests related to real property.

"Renewable energy credit" means a tradable credit that represents the environmental attributes of a certain amount of energy produced from a renewable energy resource.

"Renewable energy resources" includes energy and its associated renewable energy credit or renewable energy credits from wind, solar thermal energy, photovoltaic cells and panels, biodiesel, anaerobic digestion, crops and untreated and unadulterated organic waste biomass, tree waste, hydropower that does not involve new construction or significant expansion of hydropower dams, and other alternative sources of environmentally preferable energy. For purposes of this Act, landfill gas produced in the State is considered a renewable energy resource. "Renewable energy resources" does not include the incineration or burning of tires, garbage, general household, institutional, and commercial waste, industrial lunchroom or office waste, landscape waste other than tree waste, railroad crossties, utility poles, or construction or demolition debris, other than untreated and unadulterated waste wood.

"Revenue bond" means any bond, note, or other evidence of indebtedness issued by the Authority, the principal and interest of which is payable solely from revenues or income derived from any project or activity of the Agency.

"Sequester" means permanent storage of carbon dioxide by injecting it into a saline aquifer, a depleted gas reservoir, or an oil reservoir, directly or through an enhanced oil recovery process that may involve intermediate storage, regardless of whether these activities are conducted by a clean coal facility, a clean coal SNG facility, a clean coal SNG brownfield facility, or a party with which a clean coal facility, clean coal SNG facility, or clean coal SNG brownfield facility has contracted for such purposes.

"Sourcing agreement" means (i) in the case of an electric utility, an agreement between the owner of a clean coal facility and such electric utility, which agreement shall have terms and conditions meeting the requirements of paragraph (3) of subsection (d) of Section 1-75, (ii) in the case of an alternative retail electric supplier, an agreement between the owner of a clean coal facility and such alternative retail electric supplier, which agreement shall have terms and conditions meeting the requirements of Section 16-115(d)(5) of the Public Utilities Act, and (iii) in case of a gas utility, an agreement between the owner of a clean coal SNG brownfield facility and the gas utility, which agreement shall have the terms and conditions meeting the requirements of subsection (h-1) of Section 9-220 of the Public Utilities Act.

"Substitute natural gas" or "SNG" means a gas manufactured by gasification of hydrocarbon feedstock, which is substantially interchangeable in use and distribution with conventional natural gas.

"Total resource cost test" or "TRC test" means a standard that is met if, for an investment in energy efficiency or demand-response measures, the benefit-cost ratio is greater than one. The benefit-cost ratio is the ratio of the net present value of the total benefits of the program to the net present value of the total costs as calculated over the lifetime of the measures. A total resource cost test compares the sum of avoided electric utility costs, representing the benefits that accrue to the system and the participant in the delivery of those efficiency measures, as well as other quantifiable societal benefits, including avoided natural gas utility costs associated with natural gas or other fuels, to the sum of all incremental costs of end-use measures that are implemented due to the program (including both utility and participant contributions), plus costs to administer, deliver, and evaluate each demand-side program, to quantify the net savings obtained by substituting the demand-side program for supply resources. In calculating avoided costs of power and energy that an electric utility would otherwise have had to acquire, reasonable estimates shall be included of financial costs likely to be imposed by future regulations and legislation on emissions of greenhouse gases. Notwithstanding anything to the contrary, the benefits identified in this definition shall only be included in the TRC test if they are measurable and quantifiable, and the TRC test shall not include or take into account a calculation of market price suppression effects or demand reduction induced price effects. The changes made to this definition by this amendatory Act of the 99th General Assembly are intended to be a restatement and clarification of existing law.

(Source: P.A. 97-96, eff. 7-13-11; 97-239, eff. 8-2-11; 97-491, eff. 8-22-11; 97-616, eff. 10-26-11; 97-813, eff. 7-13-12; 98-90, eff. 7-15-13.)

(20 ILCS 3855/1-56)

Sec. 1-56. Illinois Power Agency Renewable Energy Resources Fund.

(a) The Illinois Power Agency Renewable Energy Resources Fund is created as a special fund in the State treasury.

(b) The Illinois Power Agency Renewable Energy Resources Fund shall be administered by the Agency to procure renewable energy credits resources. Renewable energy credits Prior to June 1, 2011, resources procured pursuant to this Section shall be procured from facilities located in Illinois, provided the resources are available from those facilities. If resources are not available in Illinois, then they shall be procured in states that adjoin Illinois. If resources are not available in Illinois or in states that adjoin Illinois, then they may be purchased elsewhere. Beginning June 1, 2011, resources procured pursuant to this Section shall be procured from facilities located in Illinois or states that adjoin Illinois. If renewable energy credits resources are not available in Illinois or in states that adjoin Illinois, then they may be procured elsewhere. To the extent available, at least 75% of these renewable energy credits resources shall come from wind generation. Of the renewable energy credits resources procured pursuant to this Section at least the following specified percentages shall come from photovoltaics on the following schedule: 0.5% by June 1, 2012; 1.5% by June 1, 2013; 3% by June 1, 2014; and 6% by June 1, 2015 and thereafter. Of the renewable energy credits 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 credits resources procured from distributed renewable energy generation shall come from devices of less than 25 kilowatts in nameplate capacity. Renewable energy credits resources procured from distributed generation devices may also count towards the required percentages for wind and solar photovoltaics. Procurement of renewable energy credits 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. Of the renewable energy credits from photovoltaics that are not distributed renewable energy generation devices procured pursuant to this Section, at least one-half shall come from brownfield site projects, if available. The Agency shall create application requirements for brownfield site projects that shall include, as appropriate, credit requirements for suppliers, demonstrated site control, bid bond requirements, construction completion deadlines, or other appropriate conditions to ensure confidence that selected bids will result in successful projects. Beginning June 1, 2018, each renewable energy resources plan shall specify how the moneys available in the Illinois Power Agency Renewable Energy Resources Fund for a given planning year shall be allocated to satisfy the photovoltaic requirements of this subsection (b) and subsection (j) of this Section.

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

(c) Pursuant to a renewable energy resources plan approved by the Commission under Section 16-111.5 of the Public Utilities Act, the The Agency shall procure renewable energy credits using moneys in the Illinois Power Agency Renewable Energy Resources Fund or moneys projected to be deposited into the Fund resources at least once each year in conjunction with a procurement event for electric utilities required to comply with Section 1-75 of the Act and shall, whenever possible, enter into long-term contracts on an annual basis for a portion of the incremental requirement for the given procurement year. Plans for the procurement of renewable energy credits through long-term contracts shall recognize the possible impacts of customer migration between alternative retail electric suppliers and electric utility electric supply service and shall be designed to limit the potential that eligible retail customers may be required to pay for curtailed credits in excess of those required to meet the minimum for attainment of the goals set forth in paragraph (1) of subsection (c) of Section 1-75 of this Act.

In the event of any curtailment required in order to comply with the rate impact limits of paragraph (2) of subsection (c) of Section 1-75 of this Act with respect to a contract for purchase of certain renewable energy resources held by an electric utility, as single credits or in a bundle with other credits or other resources, the Agency shall offer to purchase from the supplier any renewable energy credits associated with such renewable energy resources that would have been purchased by the electric utility but for the curtailment; however, the offer shall not include renewable energy credits that have been purchased by any other means. Purchases of curtailed renewable energy credits by the Agency shall be made at (i) the contract price for each renewable energy credit if a price is explicitly stated in the original contract or (ii) the imputed price of the renewable energy credit, if purchased under a bundled contract and where no price for a renewable energy credit is explicitly stated in the original bundled contract, as determined by the Agency and approved by the Commission. Purchases of curtailed renewable energy credits shall be made using moneys from the Illinois Power Agency Renewable Energy Resources Fund. The Agency's use of moneys from the Illinois Power Agency Renewable Energy Resources Fund shall not exceed the total amount of moneys on deposit in the Fund or projected to be deposited into the Fund. Except as provided in this subsection (c), the Agency's purchase of renewable energy credits pursuant to a curtailment shall be made in accordance with all other terms of the original contract between the supplier and the electric utility and shall not include an obligation for physical deliveries of electricity. The Agency shall not purchase, nor enter into contracts for, any other renewable energy resources using moneys in the Illinois Power Agency Renewable Energy Resources Fund, unless either (i) all of the renewable energy credits subject to curtailment have been contracted for purchase or (ii) the supplier has declined the Agency's offer to purchase the renewable energy credits subject to curtailment.

(d) The price paid to procure renewable energy credits using monies from the Illinois Power Agency Renewable Energy Resources Fund shall not exceed market-based benchmarks established by the procurement administrator in consultation with the Commission staff, Agency staff, and the procurement monitor the winning bid prices paid for like resources procured for electric utilities required to comply with Section 1-75 of this Act. This subsection (d) does not apply to purchases of curtailed renewable energy credits made pursuant to the second paragraph of subsection (c) of this Section.

(e) All renewable energy credits procured using monies from the Illinois Power Agency Renewable Energy Resources Fund shall be permanently retired.

(f) The procurement process described in this Section is exempt from the requirements of the Illinois Procurement Code, pursuant to Section 20-10 of that Code.

(g) All disbursements from the Illinois Power Agency Renewable Energy Resources Fund shall be made only upon warrants of the Comptroller drawn upon the Treasurer as custodian of the Fund upon vouchers signed by the Director or by the person or persons designated by the Director for that purpose. The Comptroller is authorized to draw the warrant upon vouchers so signed. The Treasurer shall accept all warrants so signed and shall be released from liability for all payments made on those warrants.

(h) The Illinois Power Agency Renewable Energy Resources Fund shall not be subject to sweeps, administrative charges, or chargebacks, including, but not limited to, those authorized under Section 8h of the State Finance Act, that would in any way result in the transfer of any funds from this Fund to any other fund of this State or in having any such funds utilized for any purpose other than the express purposes set forth in this Section.

(h-5) The Agency may assess fees to each bidder to recover the costs incurred in connection with a procurement process held pursuant to this Section.

(i) Supplemental procurement process.

(1) Within 90 days after the effective date of this amendatory Act of the 98th General Assembly, the Agency shall develop a one-time supplemental procurement plan limited to the procurement of renewable energy credits, if available, from new or existing photovoltaics, including, but not limited to, distributed photovoltaic generation. Nothing in this subsection (i) requires procurement of wind generation through the supplemental procurement.

Renewable energy credits procured from new photovoltaics, including, but not limited to, distributed photovoltaic generation, under this subsection (i) must be procured from devices installed by a qualified person. In its supplemental procurement plan, the Agency shall establish contractually enforceable mechanisms for ensuring that the installation of new photovoltaics is performed by a qualified person.

For the purposes of this paragraph (1), "qualified person" means a person who performs installations of photovoltaics, including, but not limited to, distributed photovoltaic generation, and who: (A) has completed an apprenticeship as a journeyman electrician from a United States Department of Labor registered electrical apprenticeship and training program and received a certification of satisfactory completion; or (B) does not currently meet the criteria under clause (A) of this paragraph (1), but is enrolled in a United States Department of Labor registered electrical apprenticeship program, provided that the person is directly supervised by a person who meets the criteria under clause (A) of this paragraph (1); or (C) has obtained one of the following credentials in addition to attesting to satisfactory completion of at least 5 years or 8,000 hours of documented hands-on electrical experience: (i) a North American Board of Certified Energy Practitioners (NABCEP) Installer Certificate for Solar PV; (ii) an Underwriters Laboratories (UL) PV Systems Installer Certificate; (iii) an Electronics Technicians Association, International (ETAI) Level 3 PV Installer Certificate; or (iv) an Associate in Applied Science degree from an Illinois Community College Board approved community college program in renewable energy or a distributed generation technology.

For the purposes of this paragraph (1), "directly supervised" means that there is a qualified person who meets the qualifications under clause (A) of this paragraph (1) and who is available for supervision and consultation regarding the work performed by persons under clause (B) of this paragraph (1), including a final inspection of the installation work that has been directly supervised to ensure safety and conformity with applicable codes.

For the purposes of this paragraph (1), "install" means the major activities and actions required to connect, in accordance with applicable building and electrical codes, the conductors, connectors, and all associated fittings, devices, power outlets, or apparatuses mounted at the premises that are directly involved in delivering energy to the premises' electrical wiring from the photovoltaics, including, but not limited to, to distributed photovoltaic generation.

The renewable energy credits procured pursuant to the supplemental procurement plan shall be procured using up to $30,000,000 from the Illinois Power Agency Renewable Energy Resources Fund. The Agency shall not plan to use funds from the Illinois Power Agency Renewable Energy Resources Fund in excess of the monies on deposit in such fund or projected to be deposited into such fund. The supplemental procurement plan shall ensure adequate, reliable, affordable, efficient, and environmentally sustainable renewable energy resources (including credits) at the lowest total cost over time, taking into account any benefits of price stability.

To the extent available, 50% of the renewable energy credits procured from distributed renewable energy generation shall come from devices of less than 25 kilowatts in nameplate capacity. Procurement of renewable energy credits from distributed renewable energy generation devices shall be done through multi-year contracts of no less than 5 years. The Agency shall create credit requirements for counterparties. In order to minimize the administrative burden on contracting entities, the Agency shall solicit the use of third parties to aggregate distributed renewable energy. These third parties shall enter into and administer contracts with individual distributed renewable energy generation device owners. An individual distributed renewable energy generation device owner shall have the ability to measure the output of his or her distributed renewable energy generation device.

In developing the supplemental procurement plan, the Agency shall hold at least one workshop open to the public within 90 days after the effective date of this amendatory Act of the 98th General Assembly and shall consider any comments made by stakeholders or the public. Upon development of the supplemental procurement plan within this 90-day period, copies of the supplemental procurement plan shall be posted and made publicly available on the Agency's and Commission's websites. All interested parties shall have 14 days following the date of posting to provide comment to the Agency on the supplemental procurement plan. All comments submitted to the Agency shall be specific, supported by data or other detailed analyses, and, if objecting to all or a portion of the supplemental procurement plan, accompanied by specific alternative wording or proposals. All comments shall be posted on the Agency's and Commission's websites. Within 14 days following the end of the 14-day review period, the Agency shall revise the supplemental procurement plan as necessary based on the comments received and file its revised supplemental procurement plan with the Commission for approval.

(2) Within 5 days after the filing of the supplemental procurement plan at the Commission, any person objecting to the supplemental procurement plan shall file an objection with the Commission. Within 10 days after the filing, the Commission shall determine whether a hearing is necessary. The Commission shall enter its order confirming or modifying the supplemental procurement plan within 90 days after the filing of the supplemental procurement plan by the Agency.

(3) The Commission shall approve the supplemental procurement plan of renewable energy credits to be procured from new or existing photovoltaics, including, but not limited to, distributed photovoltaic generation, if the Commission determines that it will ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service in the form of renewable energy credits at the lowest total cost over time, taking into account any benefits of price stability.

(4) The supplemental procurement process under this subsection (i) shall include each of the following components:

(A) Procurement administrator. The Agency may retain a procurement administrator in the manner set forth in item (2) of subsection (a) of Section 1-75 of this Act to conduct the supplemental procurement or may elect to use the same procurement administrator administering the Agency's annual procurement under Section 1-75.

(B) Procurement monitor. The procurement monitor retained by the Commission pursuant to Section 16-111.5 of the Public Utilities Act shall:

(i) monitor interactions among the procurement administrator and bidders and suppliers;

(ii) monitor and report to the Commission on the progress of the supplemental procurement process;

(iii) provide an independent confidential report to the Commission regarding the results of the procurement events;

(iv) assess compliance with the procurement plan approved by the Commission for the supplemental procurement process;

(v) preserve the confidentiality of supplier and bidding information in a manner consistent with all applicable laws, rules, regulations, and tariffs;

(vi) provide expert advice to the Commission and consult with the procurement administrator regarding issues related to procurement process design, rules, protocols, and policy-related matters;

(vii) consult with the procurement administrator regarding the development and use of benchmark criteria, standard form contracts, credit policies, and bid documents; and

(viii) perform, with respect to the supplemental procurement process, any other procurement monitor duties specifically delineated within subsection (i) of this Section.

(C) Solicitation, pre-qualification, and registration of bidders. The procurement administrator shall disseminate information to potential bidders to promote a procurement event, notify potential bidders that the procurement administrator may enter into a post-bid price negotiation with bidders that meet the applicable benchmarks, provide supply requirements, and otherwise explain the competitive procurement process. In addition to such other publication as the procurement administrator determines is appropriate, this information shall be posted on the Agency's and the Commission's websites. The procurement administrator shall also administer the prequalification process, including evaluation of credit worthiness, compliance with procurement rules, and agreement to the standard form contract developed pursuant to item (D) of this paragraph (4). The procurement administrator shall then identify and register bidders to participate in the procurement event.

(D) Standard contract forms and credit terms and instruments. The procurement administrator, in consultation with the Agency, the Commission, and other interested parties and subject to Commission oversight, shall develop and provide standard contract forms for the supplier contracts that meet generally accepted industry practices as well as include any applicable State of Illinois terms and conditions that are required for contracts entered into by an agency of the State of Illinois. Standard credit terms and instruments that meet generally accepted industry practices shall be similarly developed. Contracts for new photovoltaics shall include a provision attesting that the supplier will use a qualified person for the installation of the device pursuant to paragraph (1) of subsection (i) of this Section. The procurement administrator shall make available to the Commission all written comments it receives on the contract forms, credit terms, or instruments. If the procurement administrator cannot reach agreement with the parties as to the contract terms and conditions, the procurement administrator must notify the Commission of any disputed terms and the Commission shall resolve the dispute. The terms of the contracts shall not be subject to negotiation by winning bidders, and the bidders must agree to the terms of the contract in advance so that winning bids are selected solely on the basis of price.

(E) Requests for proposals; competitive procurement process. The procurement administrator shall design and issue requests for proposals to supply renewable energy credits in accordance with the supplemental procurement plan, as approved by the Commission. The requests for proposals shall set forth a procedure for sealed, binding commitment bidding with pay-as-bid settlement, and provision for selection of bids on the basis of price, provided, however, that no bid shall be accepted if it exceeds the benchmark developed pursuant to item (F) of this paragraph (4).

(F) Benchmarks. Benchmarks for each product to be procured shall be developed by the procurement administrator in consultation with Commission staff, the Agency, and the procurement monitor for use in this supplemental procurement.

(G) A plan for implementing contingencies in the event of supplier default, Commission rejection of results, or any other cause.

(5) Within 2 business days after opening the sealed bids, the procurement administrator shall submit a confidential report to the Commission. The report shall contain the results of the bidding for each of the products along with the procurement administrator's recommendation for the acceptance and rejection of bids based on the price benchmark criteria and other factors observed in the process. The procurement monitor also shall submit a confidential report to the Commission within 2 business days after opening the sealed bids. The report shall contain the procurement monitor's assessment of bidder behavior in the process as well as an assessment of the procurement administrator's compliance with the procurement process and rules. The Commission shall review the confidential reports submitted by the procurement administrator and procurement monitor and shall accept or reject the recommendations of the procurement administrator within 2 business days after receipt of the reports.

(6) Within 3 business days after the Commission decision approving the results of a procurement event, the Agency shall enter into binding contractual arrangements with the winning suppliers using the standard form contracts.

(7) The names of the successful bidders and the average of the winning bid prices for each contract type and for each contract term shall be made available to the public within 2 days after the supplemental procurement event. The Commission, the procurement monitor, the procurement administrator, the Agency, and all participants in the procurement process shall maintain the confidentiality of all other supplier and bidding information in a manner consistent with all applicable laws, rules, regulations, and tariffs. Confidential information, including the confidential reports submitted by the procurement administrator and procurement monitor pursuant to this Section, shall not be made publicly available and shall not be discoverable by any party in any proceeding, absent a compelling demonstration of need, nor shall those reports be admissible in any proceeding other than one for law enforcement purposes.

(8) The supplemental procurement provided in this subsection (i) shall not be subject to the requirements and limitations of subsections (c) and (d) of this Section.

(9) Expenses incurred in connection with the procurement process held pursuant to this Section, including, but not limited to, the cost of developing the supplemental procurement plan, the procurement administrator, procurement monitor, and the cost of the retirement of renewable energy credits purchased pursuant to the supplemental procurement shall be paid for from the Illinois Power Agency Renewable Energy Resources Fund. The Agency shall enter into an interagency agreement with the Commission to reimburse the Commission for its costs associated with the procurement monitor for the supplemental procurement process.

(j) Beginning June 1, 2018, the moneys available in the Illinois Power Agency Renewable Energy Resources Fund for a given planning year that are not required to be used for purchasing (i) the minimum amounts of renewable energy credits specified in subsection (b) of this Section, other than credits from photovoltaics, and (ii) curtailed credits pursuant to subsection (c) of this Section, shall be used to purchase renewable energy credits from photovoltaic projects as specified in this subsection (j) and subsection (b) of this Section and for other photovoltaic project costs as described in this subsection (j). Of the amount available for photovoltaic projects described in this subsection (j), at least one-half shall be used for low-income community photovoltaic projects approved by the Agency, to the extent available. The Agency shall specify in each renewable energy resources plan how the moneys available in the Illinois Power Agency Renewable Energy Resources Fund for a given planning year shall be allocated to satisfy the photovoltaic requirements of this subsection (j) and subsection (b) of this Section.

Consistent with the provisions of this subsection (j), the administrative costs incurred by the Agency and electric utilities associated with the photovoltaic projects and procurement pursuant to this subsection (j) shall be recovered from the Illinois Power Agency Renewable Energy Resources Fund. The Agency shall maintain a reserve of 10% of the moneys available in the Illinois Power Agency Renewable Energy Resources Fund to ensure the payment of these administrative costs. Electric utilities shall submit invoices to the Agency for reimbursement of the costs the utilities incur under this subsection (j) associated with photovoltaic projects and community photovoltaic projects, including low-income community photovoltaic projects, and the Agency shall reimburse the utilities using moneys from the Illinois Power Agency Renewable Energy Resources Fund within 30 days. Such costs shall include, but are not limited to, the costs the utility incurs to bill participants of photovoltaic projects. The administrative costs that the Agency may incur shall include third-party administrator and aggregator costs and such other administrative costs that the Agency deems (and the Commission finds) appropriate to initiate, administer, install, and operate community photovoltaic projects, including low-income community photovoltaic projects. The Agency shall establish an application process and eligibility criteria applicable to the approval of community photovoltaic projects. The criteria shall be consistent with the criteria set forth in subsection (j) of Section 16-107.6 of the Public Utilities Act, and include, but not be limited to, a maximum nameplate capacity of 2 megawatts per project, a minimum participant share requirement of 2 kilowatts, and a requirement that the participant's address at which it receives electric service from the electric utility shall be located within 5 miles of the location of the community photovoltaic project, provided that such project is also located within the utility's service territory. No project approved pursuant to this subsection (j) shall require an electric utility to exceed the limitations imposed by subsection (h) of Section 16-107.6 of the Public Utilities Act.

The Agency shall have authority to retain, by contract, such administrators as are necessary and appropriate to initiate, administer, aggregate, operate, maintain, and evaluate community photovoltaic projects that are otherwise consistent with the provisions of this Section. Such administrators shall be retained in the same manner, to the extent reasonably practicable, as the Agency retains others to administer provisions of this Act including, but not limited to, the procurement administrator. The Agency shall undertake to retain the necessary administrators for at least 2 low-income community photovoltaic projects by January 1, 2018.

If the moneys available in the Illinois Power Agency Renewable Energy Resources Fund are not sufficient to reimburse the electric utility for its costs as provided by this subsection (j) or the Agency fails to reimburse the utility for such costs within 30 days, the utility may recover such costs from its retail customers through a filing made pursuant to Article IX or Section 16-108.5 of the Public Utilities Act.

(Source: P.A. 97-616, eff. 10-26-11; 98-672, eff. 6-30-14.)

(20 ILCS 3855/1-75)

Sec. 1-75. Planning and Procurement Bureau. The Planning and Procurement Bureau has the following duties and responsibilities:

(a) The Planning and Procurement Bureau shall each year, beginning in 2008, develop procurement plans and conduct competitive procurement processes in accordance with the requirements of Section 16-111.5 of the Public Utilities Act for the eligible retail customers of electric utilities that on December 31, 2005 provided electric service to at least 100,000 customers in Illinois. 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. Of the renewable energy resources from photovoltaics that are not distributed renewable energy generation devices procured pursuant to this Section, at least one-half shall come from brownfield site projects, if available. The Agency shall create application requirements for brownfield site projects that shall include, as appropriate, credit requirements for suppliers, demonstrated site control, bid bond requirements, construction completion deadlines, or other appropriate conditions to ensure confidence that selected bids will result in successful projects.

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.

(1.5) If, as a result of customer migration between alternative retail electric suppliers and electric utility electric supply service, the Agency has insufficient moneys available in the Illinois Power Agency Renewable Energy Resources Fund to cover the contract cost of renewable energy credits procured pursuant to Section 1-56 of this Act, the Commission, pursuant to an approved renewable energy resources plan, shall direct the applicable utility to offer to purchase those renewable energy credits that (i) are assigned to its service territory pursuant to a Commission-approved renewable energy resources plan; (ii) the Agency is unable to purchase due to insufficient moneys available in the Illinois Power Agency Renewable Energy Resources Fund as a consequence of such customer migration; and (iii) are subject to curtailment; however, such direction to offer to purchase such renewable energy credits shall in no event include renewable energy credits that have been purchased by any other means. Any curtailed renewable energy credits purchased by the assigned electric utility in accordance with this provision shall count toward the minimum percentages of renewable energy resources required by this Section. Nothing in this Section shall require a supplier to sell its renewable energy credits in this manner.

Purchases of curtailed renewable energy credits originally contracted for by the Agency shall be made at the contract price for each renewable energy credit. Except as provided in this subsection (c), an electric utility's purchase of curtailed renewable energy credits shall be made in accordance with all other terms of the original contract between the supplier and the Agency and shall not include an obligation for physical deliveries of electricity. An electric utility shall not purchase, nor enter into contracts for, any other renewable energy resources pursuant to this subsection (c), unless either (i) all of the renewable energy credits subject to curtailment have been contracted for purchase or (ii) the supplier has declined the applicable utility's offer to purchase the renewable energy credits subject to curtailment. Nothing in this paragraph alters the limitations imposed by paragraph (2) of this subsection (c) or requires renewable energy credit purchases in excess of the amount required to meet the renewable goals set forth in this subsection (c).

(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.

In the event of a curtailment as specified in subsection (c) of Section 1-56, the Commission, pursuant to an approved renewable energy resources plan, shall direct the applicable utility to offer to purchase, using the accumulated amounts collected pursuant to this paragraph (5), renewable energy credits subject to curtailment in accordance with the terms specified in subsection (c) of Section 1-56; however, the offer to purchase the renewable energy credits shall in no event include renewable energy credits that have been purchased by any other means.

If, as a result of customer migration between alternative retail electric suppliers and electric utility electric supply service, the Agency has insufficient moneys available in the Illinois Power Agency Renewable Energy Resources Fund to cover the contract cost of renewable energy credits procured pursuant to Section 1-56 of this Act, the Commission, pursuant to an approved renewable energy resources plan, shall direct the applicable utility to offer to purchase, using the accumulated amounts collected by the utility under the alternative compliance payment required by this paragraph (5), renewable energy credits that (i) are assigned to its service territory pursuant to a Commission-approved renewable energy resources plan; (ii) the Agency is unable to purchase due to insufficient moneys available in the Illinois Power Agency Renewable Energy Resources Fund as a consequence of such customer migration; and (iii) are subject to curtailment; however, such direction to offer to purchase such renewable energy credits shall in no event include renewable energy credits that have been purchased by any other means. Nothing in this subsection (c) shall require a supplier to sell its renewable energy credits in this manner.

Purchases of curtailed renewable energy credits originally contracted for by the Agency shall be made at the contract price for each renewable energy credit. Except as provided in this subsection (c), an electric utility's purchase of curtailed renewable energy credits shall be made in accordance with all other terms of the original contract between the supplier and the Agency and shall not include an obligation for physical deliveries of electricity. An electric utility shall not purchase, nor enter into contracts for, any other renewable energy resources pursuant to this subsection (c), unless either (i) all of the renewable energy credits subject to curtailment have been contracted for purchase or (ii) the supplier has declined the applicable utility's offer to purchase the renewable energy credits subject to curtailment. Nothing in this paragraph alters the limitations imposed by paragraph (2) of this subsection or requires renewable energy credit purchases in excess of the amount required to meet the renewable goals set forth in this subsection (c).

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.

(6) Beginning with the planning year commencing June 1, 2016, the procurement plan shall include a renewable energy resources plan for the procurement of renewable energy credits in accordance with the requirements of Section 1-56 of this Act and renewable energy resources in accordance with the requirements of this Section. The renewable energy resources plan shall ensure adequate, reliable, affordable, efficient, and environmentally sustainable renewable energy resources at the lowest total cost over time, taking into account any benefits of price stability. The renewable energy resources plan shall also include the items set forth in subparagraphs (i) through (v) of paragraph (5) of subsection (b) of Section 16-111.5 of the Public Utilities Act.

Nothing in this paragraph (6) is intended to alter any of the limitations or conditions otherwise imposed on the purchase of renewable energy credits or renewable energy resources by any other Section of this Act.

(d) Clean coal portfolio standard.

(1) The procurement plans shall include electricity generated using clean coal. Each utility shall enter into one or more sourcing agreements with the initial clean coal facility, as provided in paragraph (3) of this subsection (d), covering electricity generated by the initial clean coal facility representing at least 5% of each utility's total supply to serve the load of eligible retail customers in 2015 and each year thereafter, as described in paragraph (3) of this subsection (d), subject to the limits specified in paragraph (2) of this subsection (d). It is the goal of the State that by January 1, 2025, 25% of the electricity used in the State shall be generated by cost-effective clean coal facilities. For purposes of this subsection (d), "cost-effective" means that the expenditures pursuant to such sourcing agreements do not cause the limit stated in paragraph (2) of this subsection (d) to be exceeded and do not exceed cost-based benchmarks, which shall be developed to assess all expenditures pursuant to such sourcing agreements covering electricity generated by clean coal facilities, other than the initial clean coal facility, by the procurement administrator, in consultation with the Commission staff, Agency staff, and the procurement monitor and shall be subject to Commission review and approval.

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

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

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

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

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

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

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

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

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

(E) thereafter, the total amount paid under sourcing agreements with clean coal facilities pursuant to the procurement plan for any single year shall be reduced by an amount necessary to limit the estimated average net increase due to the cost of these resources included in the amounts paid by eligible retail customers in connection with electric service to no more than the greater of (i) 2.015% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009 or (ii) the incremental amount per kilowatthour paid for these resources in 2013. These requirements may be altered only as provided by statute.

No later than June 30, 2015, the Commission shall review the limitation on the total amount paid under sourcing agreements, if any, with clean coal facilities pursuant to this subsection (d) and report to the General Assembly its findings as to whether that limitation unduly constrains the amount of electricity generated by cost-effective clean coal facilities that is covered by sourcing agreements.

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

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

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

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

(B) power purchase provisions, which shall:

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

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

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

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

(C) contract for differences provisions, which shall:

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

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

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

(D) general provisions, which shall:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

The facility cost report shall be prepared as follows:

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

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

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

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

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

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

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

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

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

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

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

(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 8-103, 8-103A, 8-104, 16-107, 16-107.5, 16-111.5, 16-111.5B, and 16-115D and by adding Sections 9-105, 9-106, 16-103.3, 16-103.4, 16-107.6, 16-108.9, 16-108.10, 16-108.11, and 16-108.12 as follows:

(220 ILCS 5/8-103)

Sec. 8-103. Energy efficiency and demand-response measures.

(a) It is the policy of the State that electric utilities are required to use cost-effective energy efficiency and demand-response measures to reduce delivery load. Requiring investment in cost-effective energy efficiency and demand-response measures will reduce direct and indirect costs to consumers by decreasing environmental impacts and by avoiding or delaying the need for new generation, transmission, and distribution infrastructure. It serves the public interest to allow electric utilities to recover costs for reasonably and prudently incurred expenses for energy efficiency and demand-response measures. As used in this Section, "cost-effective" means that the measures satisfy the total resource cost test. The low-income measures described in subsection (e-5) and paragraph (4) of subsection (g) subsection (f)(4) of this Section shall not be required to meet the total resource cost test. For purposes of this Section, the terms "energy-efficiency", "demand-response", "electric utility", and "total resource cost test" shall have the meanings set forth in the Illinois Power Agency Act. For purposes of this Section, the amount per kilowatthour means the total amount paid for electric service expressed on a per kilowatthour basis. For purposes of this Section, the total amount paid for electric service includes without limitation estimated amounts paid for supply, transmission, distribution, surcharges, and add-on-taxes.

(b) Electric utilities shall implement cost-effective energy efficiency measures to meet the following incremental annual energy savings goals:

(1) 0.2% of energy delivered in the year commencing June 1, 2008;

(2) 0.4% of energy delivered in the year commencing June 1, 2009;

(3) 0.6% of energy delivered in the year commencing June 1, 2010;

(4) 0.8% of energy delivered in the year commencing June 1, 2011;

(5) 1% of energy delivered in the year commencing June 1, 2012;

(6) 1.4% of energy delivered in the year commencing June 1, 2013;

(7) 1.8% of energy delivered in the year commencing June 1, 2014; and

(8) 2% of energy delivered in the year commencing June 1, 2015 and June 1, 2016; and each year thereafter.

(9) 2% of energy delivered in the year commencing January 1, 2018 and in each year thereafter.

Electric utilities may comply with this subsection (b) by meeting the annual incremental savings goal in the applicable year or by showing that the total cumulative annual savings within a multi-year 3-year planning period associated with measures implemented after May 31, 2014 was equal to the sum of each annual incremental savings requirement from the first day of the multi-year planning period May 31, 2014 through the last day of the multi-year planning period end of the applicable year.

(b-5) Energy efficiency measures shall include cost-effective voltage optimization measures. Notwithstanding the limitations set forth in subsection (d) of this Section, costs incurred by an electric utility to implement cost-effective voltage optimization measures pursuant to Section 16-108.11 of this Act shall be recoverable pursuant to the provisions of Article IX or Section 16-108.5 of this Act, and the associated energy savings shall be included under and applied to achievement of the energy savings goals set forth in subsection (b) of this Section. Beginning with those multi-year plans commencing after December 31, 2017, each electric utility shall address cost-effective voltage optimization measures in its assessments submitted pursuant to paragraph (8) of subsection (g) of this Section, and the costs incurred by a utility to implement such measures pursuant to a Commission-approved plan shall be recovered pursuant to the provisions of Article IX or Section 16-108.5 of this Act.

In the event an electric utility jointly offers an energy efficiency measure or program with a gas utility pursuant to plans approved under this Section and Section 8-104 of this Act, the electric utility may continue offering the program, including the gas energy efficiency measures, in the event the gas utility is unable to continue funding the program. In that event, up to 30% of the annual savings goal calculated pursuant to subsection (b) of this Section, as modified pursuant to subsection (d) of this Section, if applicable, may be met through savings of fuels other than electricity, and the savings value associated with such other fuels shall be converted to electric energy savings on an equivalent site Btu basis. An electric utility may recover the costs of offering the gas energy efficiency measures pursuant to this subsection.

(c) Electric utilities shall implement cost-effective demand-response measures to reduce peak demand by 0.1% over the prior year for eligible retail customers, as defined in Section 16-111.5 of this Act, and for customers that elect hourly service from the utility pursuant to Section 16-107 of this Act, provided those customers have not been declared competitive. Notwithstanding any law, rule, regulation, or order to the contrary, this This requirement commences June 1, 2008 and continues until December 31, 2017 for 10 years.

(d) Notwithstanding the requirements of subsections (b) and (c) of this Section, an electric utility shall reduce the amount of energy efficiency and demand-response measures implemented for any single 12-month plan year by an amount necessary to limit the estimated average net increase due to the cost of these measures included in the amounts paid by retail customers in connection with electric service to no more than the incremental amount per kilowatthour paid for these measures in 2011. The changes made in this subsection (d) by this amendatory Act of the 99th General Assembly are intended to be a restatement and clarification of existing law. over a 3-year planning period by an amount necessary to limit the estimated average annual increase in the amounts paid by retail customers in connection with electric service due to the cost of those measures to:

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

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

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

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

(5) thereafter, the amount of energy efficiency and demand-response measures implemented for any single year shall be reduced by an amount necessary to limit the estimated average net increase due to the cost of these measures included in the amounts paid by eligible retail customers in connection with electric service to no more than the greater of 2.015% of the amount paid per kilowatthour by those customers during the year ending May 31, 2007 or the incremental amount per kilowatthour paid for these measures in 2011.

No later than June 30, 2011, the Commission shall review the limitation on the amount of energy efficiency and demand-response measures implemented pursuant to this Section and report to the General Assembly its findings as to whether that limitation unduly constrains the procurement of energy efficiency and demand-response measures.

(e) The following provisions apply to those multi-year plans that commence prior to January 1, 2018: Electric utilities shall be responsible for overseeing the design, development, and filing of energy efficiency and demand-response plans with the Commission. (i) electric Electric utilities shall implement 100% of the demand-response measures in the plans; . (ii) electric Electric utilities shall implement 75% of the energy efficiency measures approved by the Commission, and may, as part of that implementation, outsource various aspects of program development and implementation; and (iii) the . The remaining 25% of those energy efficiency measures approved by the Commission shall be implemented by the Department of Commerce and Economic Opportunity, and must be designed in conjunction with the utility and the filing process. The Department may outsource development and implementation of energy efficiency measures. A minimum of 10% of the entire portfolio of cost-effective energy efficiency measures shall be procured from units of local government, municipal corporations, school districts, and community college districts. The Department shall coordinate the implementation of these measures.

The apportionment of the dollars to cover the costs to implement the Department's share of the portfolio of energy efficiency measures shall be made to the Department once the Department has executed rebate agreements, grants, or contracts for energy efficiency measures and provided supporting documentation for those rebate agreements, grants, and contracts to the utility. The Department is authorized to adopt any rules necessary and prescribe procedures in order to ensure compliance by applicants in carrying out the purposes of rebate agreements for energy efficiency measures implemented by the Department made under this Section.

The details of the measures implemented by the Department shall be submitted by the Department to the Commission in connection with the utility's filing regarding the energy efficiency and demand-response measures that the utility implements.

The portfolio of measures administered by both the utilities and the Department shall, in combination, be designed to achieve the annual savings targets described in subsections (b) and (c) of this Section, as modified by subsection (d) of this Section.

The utility and the Department shall agree upon a reasonable portfolio of measures and determine the measurable corresponding percentage of the savings goals associated with measures implemented by the utility or Department.

No utility shall be assessed a penalty under subsection (g) of this Section for failure to make a timely filing if that failure is the result of a lack of agreement with the Department with respect to the allocation of responsibilities or related costs or target assignments. In that case, the Department and the utility shall file their respective plans with the Commission and the Commission shall determine an appropriate division of measures and programs that meets the requirements of this Section.

(e-5) For those multi-year plans that commence after December 31, 2017, electric utilities shall be responsible for overseeing the design, development, and filing of energy efficiency plans with the Commission, and may, as part of that implementation, outsource various aspects of program development and implementation. A minimum of 10% of the entire portfolio of cost-effective energy efficiency measures shall be procured from units of local government, municipal corporations, school districts, and community college districts. The utilities shall also implement energy efficiency measures targeted at households at or below 80% of area median income. The funding for these measures shall be proportionate to the total annual utility revenues in Illinois from households at or below 80% of area median income.

(f) A utility providing approved energy efficiency and demand-response measures in the State shall be permitted to recover costs of those measures through an automatic adjustment clause tariff filed with and approved by the Commission. The tariff shall be established outside the context of a general rate case. Each year the Commission shall initiate a review to reconcile any amounts collected with the actual costs and to determine the required adjustment to the annual tariff factor to match annual expenditures. Beginning January 1, 2016, the utility may amortize over a 5-year period the full amount of its operating expenses incurred pursuant to this Section for each annual period, provided that such expenses do not include those costs associated with voltage optimization measures that are described in subsection (b-5) of this Section and Section 16-108.11 of this Act that are being recovered pursuant to Article IX or Section 16-108.5 of this Act. A utility that recovers operating expenses through an automatic adjustment clause tariff shall reflect any unamortized balance as of December 31 for a given year in a regulatory asset. The utility shall also earn a return on that balance, less any related deferred taxes, at an annual rate equal to the utility's weighted average cost of capital as approved by the Commission in its most recent order applicable to that utility under Article IX or Section 16-108.5 of this Act, including a revenue conversion factor calculated to recover or refund all additional income taxes that may be payable or receivable as a result of that return. An electric utility's election to amortize its operating expenses pursuant to this subsection (f) shall have no effect on the calculations performed under subsection (d) of this Section, and such calculations shall not limit the utility's ability to recover all of its amortized costs.

Prior to January 1, 2018, each Each utility shall include, in its recovery of costs, the costs estimated for both the utility's and the Department's implementation of energy efficiency and demand-response measures. Costs collected by the utility for measures implemented by the Department shall be submitted to the Department pursuant to Section 605-323 of the Civil Administrative Code of Illinois, shall be deposited into the Energy Efficiency Portfolio Standards Fund, and shall be used by the Department solely for the purpose of implementing these measures. A utility shall not be required to advance any moneys to the Department but only to forward such funds as it has collected. The Department shall report to the Commission on an annual basis regarding the costs actually incurred by the Department in the implementation of the measures. Any changes to the costs of energy efficiency measures as a result of plan modifications shall be appropriately reflected in amounts recovered by the utility and turned over to the Department.

The portfolio of measures, administered by both the utilities and the Department, shall, in combination, be designed to achieve the annual savings targets described in subsections (b) and (c) of this Section, as modified by subsection (d) of this Section.

The utility and the Department shall agree upon a reasonable portfolio of measures and determine the measurable corresponding percentage of the savings goals associated with measures implemented by the utility or Department.

No utility shall be assessed a penalty under subsection (f) of this Section for failure to make a timely filing if that failure is the result of a lack of agreement with the Department with respect to the allocation of responsibilities or related costs or target assignments. In that case, the Department and the utility shall file their respective plans with the Commission and the Commission shall determine an appropriate division of measures and programs that meets the requirements of this Section.

If the Department is unable to meet incremental annual performance goals for the portion of the portfolio implemented by the Department, then the utility and the Department shall jointly submit a modified filing to the Commission explaining the performance shortfall and recommending an appropriate course going forward, including any program modifications that may be appropriate in light of the evaluations conducted under item (7) of subsection (f) of this Section. In this case, the utility obligation to collect the Department's costs and turn over those funds to the Department under this subsection (e) shall continue only if the Commission approves the modifications to the plan proposed by the Department.

(g) (f) No later than November 15, 2007, each electric utility shall file an energy efficiency and demand-response plan with the Commission to meet the energy efficiency and demand-response standards for 2008 through 2010. No later than October 1, 2010, each electric utility shall file an energy efficiency and demand-response plan with the Commission to meet the energy efficiency and demand-response standards for 2011 through 2013. No later Every 3 years thereafter, each electric utility shall file, no later than September 1, 2013, each electric utility shall file an energy efficiency and demand-response plan with the Commission to meet the energy efficiency and demand-response standards for 2014 through 2017. Beginning March 1, 2017 and every 4 years thereafter, each electric utility shall file an energy efficiency plan with the Commission to meet the energy efficiency standards for the applicable 4-year period. If a utility does not file such a plan by March September 1 of an applicable year, it shall face a penalty of $100,000 per day until the plan is filed. Each utility's plan shall set forth the utility's proposals to meet the utility's portion of the energy efficiency standards identified in subsection (b), as modified by subsections (d) and (e) of this Section, and, for multi-year plans that commence prior to January 1, 2018, the demand-response standards identified in subsection (c) of this Section as modified by subsections (d) and (e), taking into account the unique circumstances of the utility's service territory. The Commission shall seek public comment on the utility's plan and shall issue an order approving or disapproving each plan within 6 5 months after its submission. If the Commission disapproves a plan, the Commission shall, within 30 days, describe in detail the reasons for the disapproval and describe a path by which the utility may file a revised draft of the plan to address the Commission's concerns satisfactorily. If the utility does not refile with the Commission within 60 days, the utility shall be subject to penalties at a rate of $100,000 per day until the plan is filed. This process shall continue, and penalties shall accrue, until the utility has successfully filed a portfolio of energy efficiency and demand-response measures. Penalties shall be deposited into the Energy Efficiency Trust Fund. In submitting proposed energy efficiency and demand-response plans and funding levels to meet the savings goals adopted by this Act the utility shall:

(1) Demonstrate that its proposed energy efficiency measures and, if applicable, demand-response measures will achieve the requirements that are identified in subsections (b) and (c) of this Section, as modified by subsections (d) and (e).

(2) Present specific proposals to implement new building and appliance standards that have been placed into effect.

(3) Present estimates of the total amount paid for electric service expressed on a per kilowatthour basis associated with the proposed portfolio of measures designed to meet the requirements that are identified in subsections (b) and (c) of this Section, as modified by subsections (d) and (e).

(4) For those multi-year plans that commence prior to January 1, 2018, coordinate Coordinate with the Department to present a portfolio of energy efficiency measures proportionate to the share of total annual utility revenues in Illinois from households at or below 150% of the poverty level. The energy efficiency programs shall be targeted to households with incomes at or below 80% of area median income.

(5) Demonstrate that its overall portfolio of energy efficiency and demand-response measures, not including low-income programs described in covered by item (4) of this subsection (g) and subsection (e-5) of this Section (f), are cost-effective using the total resource cost test and represent a diverse cross-section of opportunities for customers of all rate classes to participate in the programs.

(6) Include a proposed cost-recovery tariff mechanism to fund the proposed energy efficiency and demand-response measures and to ensure the recovery of the prudently and reasonably incurred costs of Commission-approved programs.

(7) Provide for an annual independent evaluation of the performance of the cost-effectiveness of the utility's portfolio of measures and, prior to January 1, 2018, the Department's portfolio of measures, as well as a full review of the multi-year plan 3-year results of the broader net program impacts and, to the extent practical, for adjustment of the measures on a going-forward basis as a result of the evaluations. The resources dedicated to evaluation shall not exceed 3% of portfolio resources in any given year.

(8) For those multi-year plans commencing after December 31, 2017 where the requirements of subsection (b) of this Section will require modification by subsection (d) of this Section, present an assessment of additional cost-effective energy efficiency programs or measures that could be included in the multi-year plan. The assessment shall include:

(A) the most recent analysis submitted pursuant to Section 8-103A of this Act; and

(B) an analysis showing that the new or expanded cost-effective energy efficiency programs or measures would lead to a reduction in the overall cost of electric service.

Notwithstanding the limitations imposed by subsection (d) of this Section, the Commission may approve cost-effective energy efficiency programs or measures identified in the assessment that are designed to achieve no more than the unmet portion of the utility's energy savings goals calculated pursuant to subsection (b) of this Section for the applicable multi-year planning period. For purposes of this Section, the "unmet portion" shall be calculated as the difference between the utility's energy savings goals calculated pursuant to subsection (b) of this Act for the applicable multi-year planning period and the utility's energy savings goals as modified by subsection (d) of this Section for the same planning period. Notwithstanding the limitations set forth in subsection (d) of this Section, the utility shall recover all of its costs incurred to implement any energy efficiency programs or measures approved by the Commission pursuant to this paragraph (8) through the cost recovery mechanism specified in subsection (f) of this Section.

(h) (g) No more than 3% of energy efficiency and demand-response program revenue may be allocated for demonstration of breakthrough equipment and devices.

(i) Electric utilities' 3-year energy efficiency and demand-response plans approved by the Commission on or before the effective date of this amendatory Act of the 99th General Assembly for the period June 1, 2014 through May 31, 2017 shall continue to be in force and effect through December 31, 2017 so that the energy efficiency programs set forth in those plans continue to be offered during the period June 1, 2017 through December 31, 2017. Each utility is authorized to increase, on a pro-rata basis, the energy savings goals and budgets approved in its plan to reflect the additional 7 months of the plan's operation.

(j) (h) This Section does not apply to an electric utility that on December 31, 2005 provided electric service to fewer than 100,000 customers in Illinois.

(i) If, after 2 years, an electric utility fails to meet the efficiency standard specified in subsection (b) of this Section, as modified by subsections (d) and (e), it shall make a contribution to the Low-Income Home Energy Assistance Program. The combined total liability for failure to meet the goal shall be $1,000,000, which shall be assessed as follows: a large electric utility shall pay $665,000, and a medium electric utility shall pay $335,000. If, after 3 years, an electric utility fails to meet the efficiency standard specified in subsection (b) of this Section, as modified by subsections (d) and (e), it shall make a contribution to the Low-Income Home Energy Assistance Program. The combined total liability for failure to meet the goal shall be $1,000,000, which shall be assessed as follows: a large electric utility shall pay $665,000, and a medium electric utility shall pay $335,000. In addition, the responsibility for implementing the energy efficiency measures of the utility making the payment shall be transferred to the Illinois Power Agency if, after 3 years, or in any subsequent 3-year period, the utility fails to meet the efficiency standard specified in subsection (b) of this Section, as modified by subsections (d) and (e). The Agency shall implement a competitive procurement program to procure resources necessary to meet the standards specified in this Section as modified by subsections (d) and (e), with costs for those resources to be recovered in the same manner as products purchased through the procurement plan as provided in Section 16-111.5. The Director shall implement this requirement in connection with the procurement plan as provided in Section 16-111.5.

For purposes of this Section, (i) a "large electric utility" is an electric utility that, on December 31, 2005, served more than 2,000,000 electric customers in Illinois; (ii) a "medium electric utility" is an electric utility that, on December 31, 2005, served 2,000,000 or fewer but more than 100,000 electric customers in Illinois; and (iii) Illinois electric utilities that are affiliated by virtue of a common parent company are considered a single electric utility.

(k) (j) If, after 3 years, or any subsequent 3-year period through December 31, 2017, the Department fails to implement the Department's share of energy efficiency measures required by the standards in subsection (b), then the Illinois Power Agency may assume responsibility for and control of the Department's share of the required energy efficiency measures. The Agency shall implement a competitive procurement program to procure resources necessary to meet the standards specified in this Section, with the costs of these resources to be recovered in the same manner as provided for the Department in this Section.

(l) (k) No electric utility shall be deemed to have failed to meet the energy efficiency standards to the extent any such failure is due to a failure of the Department or the Agency.

(Source: P.A. 97-616, eff. 10-26-11; 97-841, eff. 7-20-12; 98-90, eff. 7-15-13.)

(220 ILCS 5/8-103A)

Sec. 8-103A. Energy efficiency analysis. An Beginning in 2013, an electric utility subject to the requirements of Section 8-103 of this Act shall include in its energy efficiency and demand-response plan submitted pursuant to subsection (g) (f) of Section 8-103 an analysis of additional cost-effective energy efficiency measures that could be implemented, by customer class, absent the limitations set forth in subsection (d) of Section 8-103. In seeking public comment on the electric utility's plan pursuant to subsection (g) (f) of Section 8-103, the Commission shall include, beginning in 2013, the assessment of additional cost-effective energy efficiency measures submitted pursuant to this Section. For purposes of this Section, the term "energy efficiency" shall have the meaning set forth in Section 1-10 of the Illinois Power Agency Act, and the term "cost-effective" shall have the meaning set forth in subsection (a) of Section 8-103 of this Act.

(Source: P.A. 97-616, eff. 10-26-11.)

(220 ILCS 5/8-104)

Sec. 8-104. Natural gas energy efficiency programs.

(a) It is the policy of the State that natural gas utilities and the Department of Commerce and Economic Opportunity are required to use cost-effective energy efficiency to reduce direct and indirect costs to consumers. It serves the public interest to allow natural gas utilities to recover costs for reasonably and prudently incurred expenses for cost-effective energy efficiency measures.

(b) For purposes of this Section, "energy efficiency" means measures that reduce the amount of energy required to achieve a given end use. "Energy efficiency" also includes measures that reduce the total Btus of electricity and natural gas needed to meet the end use or uses. "Cost-effective" means that the measures satisfy the total resource cost test which, for purposes of this Section, means a standard that is met if, for an investment in energy efficiency, the benefit-cost ratio is greater than one. The benefit-cost ratio is the ratio of the net present value of the total benefits of the measures to the net present value of the total costs as calculated over the lifetime of the measures. The total resource cost test compares the sum of avoided natural gas utility costs, representing the benefits that accrue to the system and the participant in the delivery of those efficiency measures, as well as other quantifiable societal benefits, including avoided electric utility costs, to the sum of all incremental costs of end use measures (including both utility and participant contributions), plus costs to administer, deliver, and evaluate each demand-side measure, to quantify the net savings obtained by substituting demand-side measures for supply resources. In calculating avoided costs, reasonable estimates shall be included for financial costs likely to be imposed by future regulation of emissions of greenhouse gases. The low-income programs described in item (4) of subsection (f) of this Section shall not be required to meet the total resource cost test.

(c) Natural gas utilities shall implement cost-effective energy efficiency measures to meet at least the following natural gas savings requirements, which shall be based upon the total amount of gas delivered to retail customers, other than the customers described in subsection (m) of this Section, during calendar year 2009 multiplied by the applicable percentage. Natural gas utilities may comply with this Section by meeting the annual incremental savings goal in the applicable year or by showing that total cumulative annual savings within a multi-year 3-year planning period associated with measures implemented after May 31, 2011 were equal to the sum of each annual incremental savings requirement from the first day of the multi-year planning period May 31, 2011 through the last day of the multi-year planning period end of the applicable year:

(1) 0.2% by May 31, 2012;

(2) an additional 0.4% by May 31, 2013, increasing total savings to .6%;

(3) an additional 0.6% by May 31, 2014, increasing total savings to 1.2%;

(4) an additional 0.8% by May 31, 2015, increasing total savings to 2.0%;

(5) an additional 1% by May 31, 2016, increasing total savings to 3.0%;

(6) an additional 1.2% by May 31, 2017, increasing total savings to 4.2%;

(7) an additional 1.4% in the year commencing January 1, 2018 by May 31, 2018, increasing total savings to 5.6%;

(8) an additional 1.5% in the year commencing January 1, 2019 by May 31, 2019, increasing total savings to 7.1%; and

(9) an additional 1.5% in each 12-month period thereafter.

(d) Notwithstanding the requirements of subsection (c) of this Section, a natural gas utility shall limit the amount of energy efficiency implemented in any multi-year 3-year reporting period established by subsection (f) of Section 8-104 of this Act, by an amount necessary to limit the estimated average increase in the amounts paid by retail customers in connection with natural gas service to no more than 2% in the applicable multi-year 3-year reporting period. The energy savings requirements in subsection (c) of this Section may be reduced by the Commission for the subject plan, if the utility demonstrates by substantial evidence that it is highly unlikely that the requirements could be achieved without exceeding the applicable spending limits in any multi-year 3-year reporting period. No later than September 1, 2013, the Commission shall review the limitation on the amount of energy efficiency measures implemented pursuant to this Section and report to the General Assembly, in the report required by subsection (k) of this Section, its findings as to whether that limitation unduly constrains the procurement of energy efficiency measures.

(e) Natural gas utilities shall be responsible for overseeing the design, development, and filing of their efficiency plans with the Commission. The utility shall utilize 75% of the available funding associated with energy efficiency programs approved by the Commission, and may outsource various aspects of program development and implementation. The remaining 25% of available funding shall be used by the Department of Commerce and Economic Opportunity to implement energy efficiency measures that achieve no less than 20% of the requirements of subsection (c) of this Section. Such measures shall be designed in conjunction with the utility and approved by the Commission. The Department may outsource development and implementation of energy efficiency measures. A minimum of 10% of the entire portfolio of cost-effective energy efficiency measures shall be procured from local government, municipal corporations, school districts, and community college districts. Five percent of the entire portfolio of cost-effective energy efficiency measures may be granted to local government and municipal corporations for market transformation initiatives. The Department shall coordinate the implementation of these measures and, until December 31, 2017, shall integrate delivery of natural gas efficiency programs with electric efficiency programs delivered pursuant to Section 8-103 of this Act, unless the Department can show that integration is not feasible.

The apportionment of the dollars to cover the costs to implement the Department's share of the portfolio of energy efficiency measures shall be made to the Department once the Department has executed rebate agreements, grants, or contracts for energy efficiency measures and provided supporting documentation for those rebate agreements, grants, and contracts to the utility. The Department is authorized to adopt any rules necessary and prescribe procedures in order to ensure compliance by applicants in carrying out the purposes of rebate agreements for energy efficiency measures implemented by the Department made under this Section.

The details of the measures implemented by the Department shall be submitted by the Department to the Commission in connection with the utility's filing regarding the energy efficiency measures that the utility implements.

A utility providing approved energy efficiency measures in this State shall be permitted to recover costs of those measures through an automatic adjustment clause tariff filed with and approved by the Commission. The tariff shall be established outside the context of a general rate case and shall be applicable to the utility's customers other than the customers described in subsection (m) of this Section. Each year the Commission shall initiate a review to reconcile any amounts collected with the actual costs and to determine the required adjustment to the annual tariff factor to match annual expenditures.

Each utility shall include, in its recovery of costs, the costs estimated for both the utility's and the Department's implementation of energy efficiency measures. Costs collected by the utility for measures implemented by the Department shall be submitted to the Department pursuant to Section 605-323 of the Civil Administrative Code of Illinois, shall be deposited into the Energy Efficiency Portfolio Standards Fund, and shall be used by the Department solely for the purpose of implementing these measures. A utility shall not be required to advance any moneys to the Department but only to forward such funds as it has collected. The Department shall report to the Commission on an annual basis regarding the costs actually incurred by the Department in the implementation of the measures. Any changes to the costs of energy efficiency measures as a result of plan modifications shall be appropriately reflected in amounts recovered by the utility and turned over to the Department.

The portfolio of measures, administered by both the utilities and the Department, shall, in combination, be designed to achieve the annual energy savings requirements set forth in subsection (c) of this Section, as modified by subsection (d) of this Section.

The utility and the Department shall agree upon a reasonable portfolio of measures and determine the measurable corresponding percentage of the savings goals associated with measures implemented by the Department.

No utility shall be assessed a penalty under subsection (f) of this Section for failure to make a timely filing if that failure is the result of a lack of agreement with the Department with respect to the allocation of responsibilities or related costs or target assignments. In that case, the Department and the utility shall file their respective plans with the Commission and the Commission shall determine an appropriate division of measures and programs that meets the requirements of this Section.

If the Department is unable to meet performance requirements for the portion of the portfolio implemented by the Department, then the utility and the Department shall jointly submit a modified filing to the Commission explaining the performance shortfall and recommending an appropriate course going forward, including any program modifications that may be appropriate in light of the evaluations conducted under item (8) of subsection (f) of this Section. In this case, the utility obligation to collect the Department's costs and turn over those funds to the Department under this subsection (e) shall continue only if the Commission approves the modifications to the plan proposed by the Department.

(f) No later than October 1, 2010, each gas utility shall file an energy efficiency plan with the Commission to meet the energy efficiency standards through May 31, 2014. No later than October 1, 2013, each gas utility shall file an energy efficiency plan with the Commission to meet the energy efficiency standards through May 31, 2017. Beginning March 1, 2017 and every 4 Every 3 years thereafter, each utility shall file, no later than October 1, an energy efficiency plan with the Commission to meet the energy efficiency standards for the applicable 4-year period. If a utility does not file such a plan by March October 1 of the applicable year, then it shall face a penalty of $100,000 per day until the plan is filed. Each utility's plan shall set forth the utility's proposals to meet the utility's portion of the energy efficiency standards identified in subsection (c) of this Section, as modified by subsection (d) of this Section, taking into account the unique circumstances of the utility's service territory. The Commission shall seek public comment on the utility's plan and shall issue an order approving or disapproving each plan within 6 months after its submission. If the Commission disapproves a plan, the Commission shall, within 30 days, describe in detail the reasons for the disapproval and describe a path by which the utility may file a revised draft of the plan to address the Commission's concerns satisfactorily. If the utility does not refile with the Commission within 60 days after the disapproval, the utility shall be subject to penalties at a rate of $100,000 per day until the plan is filed. This process shall continue, and penalties shall accrue, until the utility has successfully filed a portfolio of energy efficiency measures. Penalties shall be deposited into the Energy Efficiency Trust Fund and the cost of any such penalties may not be recovered from ratepayers. In submitting proposed energy efficiency plans and funding levels to meet the savings goals adopted by this Act the utility shall:

(1) Demonstrate that its proposed energy efficiency measures will achieve the requirements that are identified in subsection (c) of this Section, as modified by subsection (d) of this Section.

(2) Present specific proposals to implement new building and appliance standards that have been placed into effect.

(3) Present estimates of the total amount paid for gas service expressed on a per therm basis associated with the proposed portfolio of measures designed to meet the requirements that are identified in subsection (c) of this Section, as modified by subsection (d) of this Section.

(4) Coordinate with the Department to present a portfolio of energy efficiency measures proportionate to the share of total annual utility revenues in Illinois from households at or below 150% of the poverty level. Such programs shall be targeted to households with incomes at or below 80% of area median income.

(5) Demonstrate that its overall portfolio of energy efficiency measures, not including programs covered by item (4) of this subsection (f), are cost-effective using the total resource cost test and represent a diverse cross section of opportunities for customers of all rate classes to participate in the programs.

(6) Demonstrate that a gas utility affiliated with an electric utility that is required to comply with Section 8-103 of this Act has integrated gas and electric efficiency measures into a single program that reduces program or participant costs and appropriately allocates costs to gas and electric ratepayers. The Department shall integrate all gas and electric programs it delivers in any such utilities' service territories, unless the Department can show that integration is not feasible or appropriate.

(7) Include a proposed cost recovery tariff mechanism to fund the proposed energy efficiency measures and to ensure the recovery of the prudently and reasonably incurred costs of Commission-approved programs.

(8) Provide for quarterly status reports tracking implementation of and expenditures for the utility's portfolio of measures and the Department's portfolio of measures, an annual independent review, and a full independent evaluation of the multi-year 3-year results of the performance and the cost-effectiveness of the utility's and Department's portfolios of measures and broader net program impacts and, to the extent practical, for adjustment of the measures on a going forward basis as a result of the evaluations. The resources dedicated to evaluation shall not exceed 3% of portfolio resources in any given multi-year 3-year period.

(g) No more than 3% of expenditures on energy efficiency measures may be allocated for demonstration of breakthrough equipment and devices.

(h) Illinois natural gas utilities that are affiliated by virtue of a common parent company may, at the utilities' request, be considered a single natural gas utility for purposes of complying with this Section.

(i) If, after 3 years, a gas utility fails to meet the efficiency standard specified in subsection (c) of this Section as modified by subsection (d), then it shall make a contribution to the Low-Income Home Energy Assistance Program. The total liability for failure to meet the goal shall be assessed as follows:

(1) a large gas utility shall pay $600,000;

(2) a medium gas utility shall pay $400,000; and

(3) a small gas utility shall pay $200,000.

For purposes of this Section, (i) a "large gas utility" is a gas utility that on December 31, 2008, served more than 1,500,000 gas customers in Illinois; (ii) a "medium gas utility" is a gas utility that on December 31, 2008, served fewer than 1,500,000, but more than 500,000 gas customers in Illinois; and (iii) a "small gas utility" is a gas utility that on December 31, 2008, served fewer than 500,000 and more than 100,000 gas customers in Illinois. The costs of this contribution may not be recovered from ratepayers.

If a gas utility fails to meet the efficiency standard specified in subsection (c) of this Section, as modified by subsection (d) of this Section, in any 2 consecutive 3-year planning periods, then the responsibility for implementing the utility's energy efficiency measures shall be transferred to an independent program administrator selected by the Commission. Reasonable and prudent costs incurred by the independent program administrator to meet the efficiency standard specified in subsection (c) of this Section, as modified by subsection (d) of this Section, may be recovered from the customers of the affected gas utilities, other than customers described in subsection (m) of this Section. The utility shall provide the independent program administrator with all information and assistance necessary to perform the program administrator's duties including but not limited to customer, account, and energy usage data, and shall allow the program administrator to include inserts in customer bills. The utility may recover reasonable costs associated with any such assistance.

(j) No utility shall be deemed to have failed to meet the energy efficiency standards to the extent any such failure is due to a failure of the Department.

(k) Not later than January 1, 2012, the Commission shall develop and solicit public comment on a plan to foster statewide coordination and consistency between statutorily mandated natural gas and electric energy efficiency programs to reduce program or participant costs or to improve program performance. Not later than September 1, 2013, the Commission shall issue a report to the General Assembly containing its findings and recommendations.

(l) This Section does not apply to a gas utility that on January 1, 2009, provided gas service to fewer than 100,000 customers in Illinois.

(m) Subsections (a) through (k) of this Section do not apply to customers of a natural gas utility that have a North American Industry Classification System code number that is 22111 or any such code number beginning with the digits 31, 32, or 33 and (i) annual usage in the aggregate of 4 million therms or more within the service territory of the affected gas utility or with aggregate usage of 8 million therms or more in this State and complying with the provisions of item (l) of this subsection (m); or (ii) using natural gas as feedstock and meeting the usage requirements described in item (i) of this subsection (m), to the extent such annual feedstock usage is greater than 60% of the customer's total annual usage of natural gas.

(1) Customers described in this subsection (m) of this Section shall apply, on a form approved on or before October 1, 2009 by the Department, to the Department to be designated as a self-directing customer ("SDC") or as an exempt customer using natural gas as a feedstock from which other products are made, including, but not limited to, feedstock for a hydrogen plant, on or before the 1st day of February, 2010. Thereafter, application may be made not less than 6 months before the filing date of the gas utility energy efficiency plan described in subsection (f) of this Section; however, a new customer that commences taking service from a natural gas utility after February 1, 2010 may apply to become a SDC or exempt customer up to 30 days after beginning service. Customers described in this subsection (m) that have not already been approved by the Department may apply to be designated a self-directing customer or exempt customer, on a form approved by the Department, between September 1, 2013 and September 30, 2013. Customer applications that are approved by the Department under this amendatory Act of the 98th General Assembly shall be considered to be a self-directing customer or exempt customer, as applicable, for the current 3-year planning period effective December 1, 2013. Such application shall contain the following:

(A) the customer's certification that, at the time of its application, it qualifies to be a SDC or exempt customer described in this subsection (m) of this Section;

(B) in the case of a SDC, the customer's certification that it has established or will establish by the beginning of the utility's 3-year planning period commencing subsequent to the application, and will maintain for accounting purposes, an energy efficiency reserve account and that the customer will accrue funds in said account to be held for the purpose of funding, in whole or in part, energy efficiency measures of the customer's choosing, which may include, but are not limited to, projects involving combined heat and power systems that use the same energy source both for the generation of electrical or mechanical power and the production of steam or another form of useful thermal energy or the use of combustible gas produced from biomass, or both;

(C) in the case of a SDC, the customer's certification that annual funding levels for the energy efficiency reserve account will be equal to 2% of the customer's cost of natural gas, composed of the customer's commodity cost and the delivery service charges paid to the gas utility, or $150,000, whichever is less;

(D) in the case of a SDC, the customer's certification that the required reserve account balance will be capped at 3 years' worth of accruals and that the customer may, at its option, make further deposits to the account to the extent such deposit would increase the reserve account balance above the designated cap level;

(E) in the case of a SDC, the customer's certification that by October 1 of each year, beginning no sooner than October 1, 2012, the customer will report to the Department information, for the 12-month period ending May 31 of the same year, on all deposits and reductions, if any, to the reserve account during the reporting year, and to the extent deposits to the reserve account in any year are in an amount less than $150,000, the basis for such reduced deposits; reserve account balances by month; a description of energy efficiency measures undertaken by the customer and paid for in whole or in part with funds from the reserve account; an estimate of the energy saved, or to be saved, by the measure; and that the report shall include a verification by an officer or plant manager of the customer or by a registered professional engineer or certified energy efficiency trade professional that the funds withdrawn from the reserve account were used for the energy efficiency measures;

(F) in the case of an exempt customer, the customer's certification of the level of gas usage as feedstock in the customer's operation in a typical year and that it will provide information establishing this level, upon request of the Department;

(G) in the case of either an exempt customer or a SDC, the customer's certification that it has provided the gas utility or utilities serving the customer with a copy of the application as filed with the Department;

(H) in the case of either an exempt customer or a SDC, certification of the natural gas utility or utilities serving the customer in Illinois including the natural gas utility accounts that are the subject of the application; and

(I) in the case of either an exempt customer or a SDC, a verification signed by a plant manager or an authorized corporate officer attesting to the truthfulness and accuracy of the information contained in the application.

(2) The Department shall review the application to determine that it contains the information described in provisions (A) through (I) of item (1) of this subsection (m), as applicable. The review shall be completed within 30 days after the date the application is filed with the Department. Absent a determination by the Department within the 30-day period, the applicant shall be considered to be a SDC or exempt customer, as applicable, for all subsequent multi-year 3-year planning periods, as of the date of filing the application described in this subsection (m). If the Department determines that the application does not contain the applicable information described in provisions (A) through (I) of item (1) of this subsection (m), it shall notify the customer, in writing, of its determination that the application does not contain the required information and identify the information that is missing, and the customer shall provide the missing information within 15 working days after the date of receipt of the Department's notification.

(3) The Department shall have the right to audit the information provided in the customer's application and annual reports to ensure continued compliance with the requirements of this subsection. Based on the audit, if the Department determines the customer is no longer in compliance with the requirements of items (A) through (I) of item (1) of this subsection (m), as applicable, the Department shall notify the customer in writing of the noncompliance. The customer shall have 30 days to establish its compliance, and failing to do so, may have its status as a SDC or exempt customer revoked by the Department. The Department shall treat all information provided by any customer seeking SDC status or exemption from the provisions of this Section as strictly confidential.

(4) Upon request, or on its own motion, the Commission may open an investigation, no more than once every 3 years and not before October 1, 2014, to evaluate the effectiveness of the self-directing program described in this subsection (m).

Customers described in this subsection (m) that applied to the Department on January 3, 2013, were approved by the Department on February 13, 2013 to be a self-directing customer or exempt customer, and receive natural gas from a utility that provides gas service to at least 500,000 retail customers in Illinois and electric service to at least 1,000,000 retail customers in Illinois shall be considered to be a self-directing customer or exempt customer, as applicable, for the current 3-year planning period effective December 1, 2013.

(n) The applicability of this Section to customers described in subsection (m) of this Section is conditioned on the existence of the SDC program. In no event will any provision of this Section apply to such customers after January 1, 2020.

(o) Utilities' 3-year energy efficiency plans approved by the Commission on or before the effective date of this amendatory Act of the 99th General Assembly for the period June 1, 2014 through May 31, 2017 shall continue to be in force and effect through December 31, 2017 so that the energy efficiency programs set forth in those plans continue to be offered during the period June 1, 2017 through December 31, 2017. Each utility is authorized to increase, on a pro-rata basis, the energy savings goals and budgets approved in its plan to reflect the additional 7 months of the plan's operation.

(Source: P.A. 97-813, eff. 7-13-12; 97-841, eff. 7-20-12; 98-90, eff. 7-15-13; 98-225, eff. 8-9-13; 98-604, eff. 12-17-13.)

(220 ILCS 5/9-105 new)

Sec. 9-105. Demand-based delivery services charge. Beginning with the January 2018 monthly billing period, an electric utility that serves more than 3,000,000 retail customers in the State may recover its costs of providing delivery services to retail customers as follows:

(1) the categories of costs being recovered through a fixed charge on the effective date of this amendatory Act of the 99th General Assembly shall continue to be recovered through a fixed charge;

(2) costs being recovered through riders on the effective date of this amendatory Act of the 99th General Assembly and add-on taxes and other separately-stated charges or adjustments shall continue to be recovered in the manner they are being collected, provided that nothing in this paragraph (2) shall prohibit addition or elimination of a rider or preclude the utility from revising those riders, pursuant to this Article IX and any applicable provisions of this Act, regardless of whether such riders assess charges on a kilowatt-hour or kilowatt basis;

(3) taxes incurred pursuant to the Public Utilities Revenue Act shall continue to be recovered on a kilowatt-hour basis; and

(4) all remaining costs of providing delivery services to retail customers shall be recovered through a charge based on kilowatts of demand.

A utility shall file tariffs implementing the provisions of this Section pursuant to Section 9-201 of this Act, provided that a participating utility as defined in Section 16-108.5 of this Act shall file such tariffs pursuant to subsection (e) of Section 16-108.5.

An electric utility may estimate retail customers' kilowatt demands if the interval data necessary to determine such customers' kilowatt demands is not available.

(220 ILCS 5/9-106 new)

Sec. 9-106. Electric utility line extensions; distribution capacity expansion.

(a) The General Assembly finds that it is a goal of this State to encourage the establishment of new businesses and expansion of existing businesses in Illinois and further finds that start-up costs may be a significant obstacle, and at times a deterrent, to undertaking new investment in Illinois. In light of the economy's increasing reliance on electricity to fuel business, technology, and innovation, the General Assembly finds that it is appropriate for the State's electric utilities to now undertake a review of their tariffs that impact such start-up costs.

(b) Each electric utility serving more than 200,000 customers in Illinois on the effective date of this amendatory Act of the 99th General Assembly shall review its tariffs relating to line extensions and distribution capacity expansion. Following such a review, the utility may file tariff changes with the Commission that are consistent with the objectives described in subsection (a) of this Section. Such tariffs shall be submitted to the Commission under Section 9-201 of this Act, except that the Commission shall approve, or modify and approve, such tariffs within 120 days after the date on which they are filed. The Commission shall review its rules relating to utility line extensions and distribution capacity expansion to be consistent with any tariffs approved pursuant to this Section.

(220 ILCS 5/16-103.3 new)

Sec. 16-103.3. Unbundling of charges related to electricity supply and regional transmission organization services. Beginning with the January 2018 monthly billing period, an electric utility that provides electric service to more than 3,000,000 retail customers in the State shall restructure its retail electricity supply charges applicable to eligible retail customers, as defined by Section 16-111.5 of this Act, for whom the electric utility procures electric power and energy pursuant to Section 1-75 of the Illinois Power Agency Act and Section 16-111.5 of this Act. The restructuring shall separately recover the costs of electric capacity and other services incurred by the electric utility related to providing electricity supply where such costs are not primarily incurred based upon the number of kilowatt-hours consumed. Charges that recover the costs shall appear as 2 separate line items on the eligible retail customers' electric service bills. The costs shall not be included in the costs of determining the kilowatt-hour based electricity supply charges for electric power and energy and shall be recovered through separate kilowatt-based charges applicable to customers' kilowatt demands.

In addition to the costs of electric capacity, an electric utility shall also recover the costs of services it procures from the regional transmission organization of which it is a member, including, but not limited to, the transmission and ancillary transmission services costs that are not primarily incurred on a kilowatt-hour basis, from eligible retail customers through kilowatt-based charges applicable to the customers' kilowatt demands and not through kilowatt-hour based charges.

An electric utility may estimate eligible retail customers' kilowatt demands if the interval data necessary to determine such customers' kilowatt demands is not available.

It is the intent of this Section that eligible retail customers taking electricity supply service from such electric utility pay kilowatt-based charges for the electricity supply and regional transmission organization-related services costs that are not primarily incurred on a kilowatt-hour basis.

(220 ILCS 5/16-103.4 new)

Sec. 16-103.4. Demand-response facilitation service.

(a) It is a policy of this State to promote investment in demand-response resources. The General Assembly has previously found that including cost-effective demand-response resources in a diverse electricity supply portfolio will reduce long-term direct and indirect costs to consumers by decreasing environmental impacts and by avoiding or delaying the need for new generation, transmission, and distribution infrastructure. The General Assembly finds, however, that recent legal developments affecting the regional transmission organizations that serve Illinois have altered the way in which demand-response resources can be procured and present new obstacles to the continued procurement of cost-effective demand-response resources.

The General Assembly further finds that on January 14, 2015, PJM Interconnection, the regional transmission organization serving most of the State's retail customers, filed a tariff with the Federal Energy Regulatory Commission that would provide an alternative path by which states could continue to procure demand-response resources.

To ensure that the State's policy regarding procurement of demand-response resources continues to be implemented, an electric utility providing service to more than 3,000,000 customers in the State may participate in an auction as authorized by the tariff, provided that the tariff is lawfully placed into effect. A utility that elects to participate may recover its costs as specified in this Section.

(b) In the event the tariff described in subsection (a) of this Section is lawfully placed into effect, an electric utility serving more than 3,000,000 retail customers in the State may facilitate the continued procurement of demand-response resources from its retail customers. As part of such procurement, the electric utility may contract with curtailment service providers and load serving entities to procure demand-response resources from the utility's retail customers, which the utility may use to submit demand-response bids through the utility's account into the Reliability Pricing Model auction. All of the costs the electric utility incurs to implement this program, including compensating the curtailment service providers and load serving entities for the demand-response bids that clear the auction and for which the utility is obligated, shall be recovered from all of its retail customers through a non-bypassable charge applied to their electric bills. The electric utility shall recover such costs through an automatic adjustment clause tariff, which may be filed and established outside the context of a general rate case filing or a filing under subsections (c) or (d) of Section 16-108.5 of this Act. The Commission shall review and, after notice and hearing, by order approve or approve with modification the proposed tariff no later than 180 days after the filing of the tariff. A tariff approved and placed into effect pursuant to this Section shall remain in effect at the discretion of the utility, and the utility may withdraw the tariff at any time. Each year the Commission shall initiate a proceeding to review and reconcile any amounts collected with the actual costs.

(220 ILCS 5/16-107)

Sec. 16-107. Real-time pricing.

(a) Each electric utility shall file, on or before May 1, 1998, a tariff or tariffs which allow nonresidential retail customers in the electric utility's service area to elect real-time pricing beginning October 1, 1998.

(b) Each electric utility shall file, on or before May 1, 2000, a tariff or tariffs which allow residential retail customers in the electric utility's service area to elect real-time pricing beginning October 1, 2000.

(b-5) Each electric utility shall file a tariff or tariffs allowing residential retail customers in the electric utility's service area to elect real-time pricing beginning January 2, 2007. The Commission may, after notice and hearing, approve the tariff or tariffs. A customer who elects real-time pricing shall remain on such rate for a minimum of 12 months. The Commission may, after notice and hearing, approve the tariff or tariffs, provided that the Commission finds that the potential for demand reductions will result in net economic benefits to all residential customers of the electric utility. In examining economic benefits from demand reductions, the Commission shall, at a minimum, consider the following: improvements to system reliability and power quality, reduction in wholesale market prices and price volatility, electric utility cost avoidance and reductions, market power mitigation, and other benefits of demand reductions, but only to the extent that the effects of reduced demand can be demonstrated to lower the cost of electricity delivered to residential customers. A tariff or tariffs approved pursuant to this subsection (b-5) shall, at a minimum, describe (i) the methodology for determining the market price of energy to be reflected in the real-time rate and (ii) the manner in which customers who elect real-time pricing will be provided with ready access to hourly market prices, including, but not limited to, day-ahead hourly energy prices. A customer who elects real-time pricing pursuant to a tariff approved under this Section and thereafter terminates the election shall not return to taking service under the tariff for a period of 12 months following the date on which the customer terminated real-time pricing.

A proceeding under this subsection (b-5) may not exceed 120 days in length.

(b-10) Each electric utility providing real-time pricing pursuant to subsection (b-5) shall install a meter capable of recording hourly interval energy use at the service location of each customer that elects real-time pricing pursuant to this subsection.

(b-15) If the Commission issues an order pursuant to subsection (b-5), the affected electric utility shall contract with an entity not affiliated with the electric utility to serve as a program administrator to develop and implement a program to provide consumer outreach, enrollment, and education concerning real-time pricing and to establish and administer an information system and technical and other customer assistance that is necessary to enable customers to manage electricity use. The program administrator: (i) shall be selected and compensated by the electric utility, subject to Commission approval; (ii) shall have demonstrated technical and managerial competence in the development and administration of demand management programs; and (iii) may develop and implement risk management, energy efficiency, and other services related to energy use management for which the program administrator shall be compensated by participants in the program receiving such services. The electric utility shall provide the program administrator with all information and assistance necessary to perform the program administrator's duties, including, but not limited to, customer, account, and energy use data. The electric utility shall permit the program administrator to include inserts in residential customer bills 2 times per year to assist with customer outreach and enrollment.

The program administrator shall submit an annual report to the electric utility no later than April 1 of each year describing the operation and results of the program, including information concerning the number and types of customers using real-time pricing, changes in customers' energy use patterns, an assessment of the value of the program to both participants and non-participants, and recommendations concerning modification of the program and the tariff or tariffs filed under subsection (b-5). This report shall be filed by the electric utility with the Commission within 30 days of receipt and shall be available to the public on the Commission's web site.

(b-20) The Commission shall monitor the performance of programs established pursuant to subsection (b-15) and shall order the termination or modification of a program if it determines that the program is not, after a reasonable period of time for development not to exceed 4 years after the effective date of this amendatory Act of the 99th General Assembly, resulting in net benefits to the residential customers of the electric utility.

(b-25) An electric utility shall be entitled to recover reasonable costs incurred in complying with this Section, provided that recovery of the costs is fairly apportioned among its residential customers as provided in this subsection (b-25). The electric utility may apportion greater costs on the residential customers who elect real-time pricing, but may also impose some of the costs of real-time pricing on customers who do not elect real-time pricing, provided that the Commission determines that the cost savings resulting from real-time pricing will exceed the costs imposed on customers for maintaining the program.

(c) The electric utility's tariff or tariffs filed pursuant to this Section shall be subject to Article IX.

(d) This Section does not apply to any electric utility providing service to 100,000 or fewer customers.

(Source: P.A. 94-977, eff. 6-30-06.)

(220 ILCS 5/16-107.5)

Sec. 16-107.5. Net electricity metering.

(a) The Legislature finds and declares that a program to provide net electricity metering, as defined in this Section, for eligible customers can encourage private investment in renewable energy resources, stimulate economic growth, enhance the continued diversification of Illinois' energy resource mix, and protect the Illinois environment.

(b) As used in this Section, (i) "eligible customer" means a retail customer that owns or operates a solar, wind, or other eligible renewable electrical generating facility with a rated capacity of not more than 2,000 kilowatts that is located on the customer's premises and is intended primarily to offset the customer's own electrical requirements; (ii) "electricity provider" means an electric utility or alternative retail electric supplier; (iii) "eligible renewable electrical generating facility" means a generator powered by solar electric energy, wind, dedicated crops grown for electricity generation, agricultural residues, untreated and unadulterated wood waste, landscape trimmings, livestock manure, anaerobic digestion of livestock or food processing waste, fuel cells or microturbines powered by renewable fuels, or hydroelectric energy; and (iv) "net electricity metering" (or "net metering") means the measurement, during the billing period applicable to an eligible customer, of the net amount of electricity supplied by an electricity provider to the customer's premises or provided to the electricity provider by the customer.

(c) A net metering facility shall be equipped with metering equipment that can measure the flow of electricity in both directions at the same rate.

(1) For eligible customers whose electric service has not been declared competitive pursuant to Section 16-113 of this Act as of July 1, 2011 and whose electric delivery service is provided and measured on a kilowatt-hour basis and electric supply service is not provided based on hourly pricing, this shall typically be accomplished through use of a single, bi-directional meter. If the eligible customer's existing electric revenue meter does not meet this requirement, the electricity provider shall arrange for the local electric utility or a meter service provider to install and maintain a new revenue meter at the electricity provider's expense.

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

(3) For all other eligible customers, the electricity provider may arrange for the local electric utility or a meter service provider to install and maintain metering equipment capable of measuring the flow of electricity both into and out of the customer's facility at the same rate and ratio, typically through the use of a dual channel meter. If the eligible customer's existing electric revenue meter does not meet this requirement, then the costs of installing such equipment shall be paid for by the customer.

(d) An electricity provider shall measure and charge or credit for the net electricity supplied to eligible customers or provided by eligible customers whose electric service has not been declared competitive pursuant to Section 16-113 of the Act as of July 1, 2011 and whose electric delivery service is provided and measured on a kilowatt-hour basis and electric supply service is not provided based on hourly pricing in the following manner:

(1) If the amount of electricity used by the customer during the billing period exceeds the amount of electricity produced by the customer, the electricity provider shall charge the customer for the net electricity supplied to and used by the customer as provided in subsection (e-5) of this Section.

(2) If the amount of electricity produced by a customer during the billing period exceeds the amount of electricity used by the customer during that billing period, the electricity provider supplying that customer shall apply a 1:1 kilowatt-hour credit to a subsequent bill for service to the customer for the net electricity supplied to the electricity provider. The electricity provider shall continue to carry over any excess kilowatt-hour credits earned and apply those credits to subsequent billing periods to offset any customer-generator consumption in those billing periods until all credits are used or until the end of the annualized period.

(3) At the end of the year or annualized over the period that service is supplied by means of net metering, or in the event that the retail customer terminates service with the electricity provider prior to the end of the year or the annualized period, any remaining credits in the customer's account shall expire.

(d-5) An electricity provider shall measure and charge or credit for the net electricity supplied to eligible customers or provided by eligible customers whose electric service has not been declared competitive pursuant to Section 16-113 of this Act as of July 1, 2011 and whose electric delivery service is provided and measured on a kilowatt-hour basis and electric supply service is provided based on hourly pricing in the following manner:

(1) If the amount of electricity used by the customer during any hourly period exceeds the amount of electricity produced by the customer, the electricity provider shall charge the customer for the net electricity supplied to and used by the customer according to the terms of the contract or tariff to which the same customer would be assigned to or be eligible for if the customer was not a net metering customer.

(2) If the amount of electricity produced by a customer during any hourly period exceeds the amount of electricity used by the customer during that hourly period, the energy provider shall apply a credit for the net kilowatt-hours produced in such period. The credit shall consist of an energy credit and a delivery service credit. The energy credit shall be valued at the same price per kilowatt-hour as the electric service provider would charge for kilowatt-hour energy sales during that same hourly period. The delivery credit shall be equal to the net kilowatt-hours produced in such hourly period times a credit that reflects all kilowatt-hour based charges in the customer's electric service rate, excluding energy charges.

(e) An electricity provider shall measure and charge or credit for the net electricity supplied to eligible customers whose electric service has not been declared competitive pursuant to Section 16-113 of this Act as of July 1, 2011 and whose electric delivery service is provided and measured on a kilowatt demand basis and electric supply service is not provided based on hourly pricing in the following manner:

(1) If the amount of electricity used by the customer during the billing period exceeds the amount of electricity produced by the customer, then the electricity provider shall charge the customer for the net electricity supplied to and used by the customer as provided in subsection (e-5) of this Section. The customer shall remain responsible for all taxes, fees, and utility delivery charges that would otherwise be applicable to the net amount of electricity used by the customer.

(2) If the amount of electricity produced by a customer during the billing period exceeds the amount of electricity used by the customer during that billing period, then the electricity provider supplying that customer shall apply a 1:1 kilowatt-hour credit that reflects the kilowatt-hour based charges in the customer's electric service rate to a subsequent bill for service to the customer for the net electricity supplied to the electricity provider. The electricity provider shall continue to carry over any excess kilowatt-hour credits earned and apply those credits to subsequent billing periods to offset any customer-generator consumption in those billing periods until all credits are used or until the end of the annualized period.

(3) At the end of the year or annualized over the period that service is supplied by means of net metering, or in the event that the retail customer terminates service with the electricity provider prior to the end of the year or the annualized period, any remaining credits in the customer's account shall expire.

(e-5) An electricity provider shall provide electric service to eligible customers who utilize net metering at non-discriminatory rates that are identical, with respect to rate structure, retail rate components, and any monthly charges, to the rates that the customer would be charged if not a net metering customer. An electricity provider shall not charge net metering customers any fee or charge or require additional equipment, insurance, or any other requirements not specifically authorized by interconnection standards authorized by the Commission, unless the fee, charge, or other requirement would apply to other similarly situated customers who are not net metering customers. The customer will remain responsible for all taxes, fees, and utility delivery charges that would otherwise be applicable to the net amount of electricity used by the customer. Subsections (c) through (e) of this Section shall not be construed to prevent an arms-length agreement between an electricity provider and an eligible customer that sets forth different prices, terms, and conditions for the provision of net metering service, including, but not limited to, the provision of the appropriate metering equipment for non-residential customers.

(f) Notwithstanding the requirements of subsections (c) through (e-5) of this Section, an electricity provider must require dual-channel metering for customers operating eligible renewable electrical generating facilities with a nameplate rating up to 2,000 kilowatts and to whom the provisions of neither subsection (d), (d-5), nor (e) of this Section apply. In such cases, electricity charges and credits shall be determined as follows:

(1) The electricity provider shall assess and the customer remains responsible for all taxes, fees, and utility delivery charges that would otherwise be applicable to the gross amount of kilowatt-hours supplied to the eligible customer by the electricity provider.

(2) Each month that service is supplied by means of dual-channel metering, the electricity provider shall compensate the eligible customer for any excess kilowatt-hour credits at the electricity provider's avoided cost of electricity supply over the monthly period or as otherwise specified by the terms of a power-purchase agreement negotiated between the customer and electricity provider.

(3) For all eligible net metering customers taking service from an electricity provider under contracts or tariffs employing time of use rates, any monthly consumption of electricity shall be calculated according to the terms of the contract or tariff to which the same customer would be assigned to or be eligible for if the customer was not a net metering customer. When those same customer-generators are net generators during any discrete time of use period, the net kilowatt-hours produced shall be valued at the same price per kilowatt-hour as the electric service provider would charge for retail kilowatt-hour sales during that same time of use period.

(g) For purposes of federal and State laws providing renewable energy credits or greenhouse gas credits, the eligible customer shall be treated as owning and having title to the renewable energy attributes, renewable energy credits, and greenhouse gas emission credits related to any electricity produced by the qualified generating unit. The electricity provider may not condition participation in a net metering program on the signing over of a customer's renewable energy credits; provided, however, this subsection (g) shall not be construed to prevent an arms-length agreement between an electricity provider and an eligible customer that sets forth the ownership or title of the credits.

(h) Within 120 days after the effective date of this amendatory Act of the 95th General Assembly, the Commission shall establish standards for net metering and, if the Commission has not already acted on its own initiative, standards for the interconnection of eligible renewable generating equipment to the utility system. The interconnection standards shall address any procedural barriers, delays, and administrative costs associated with the interconnection of customer-generation while ensuring the safety and reliability of the units and the electric utility system. The Commission shall consider the Institute of Electrical and Electronics Engineers (IEEE) Standard 1547 and the issues of (i) reasonable and fair fees and costs, (ii) clear timelines for major milestones in the interconnection process, (iii) nondiscriminatory terms of agreement, and (iv) any best practices for interconnection of distributed generation.

(i) All electricity providers shall begin to offer net metering no later than April 1, 2008. However, after December 31, 2017, this Section shall not apply to an electric utility that serves more than 3,000,000 retail customers in the State.

(j) An electricity provider shall provide net metering to eligible customers until the load of its net metering customers equals 5% of the total peak demand supplied by that electricity provider during the previous year. Electricity providers are authorized to offer net metering beyond the 5% level if they so choose.

(k) Each electricity provider shall maintain records and report annually to the Commission the total number of net metering customers served by the provider, as well as the type, capacity, and energy sources of the generating systems used by the net metering customers. Nothing in this Section shall limit the ability of an electricity provider to request the redaction of information deemed by the Commission to be confidential business information. Each electricity provider shall notify the Commission when the total generating capacity of its net metering customers is equal to or in excess of the 5% cap specified in subsection (j) of this Section.

(l) Notwithstanding the definition of "eligible customer" in item (i) of subsection (b) of this Section, each electricity provider shall consider whether to allow meter aggregation for the purposes of net metering on:

(1) properties owned or leased by multiple customers that contribute to the operation of an eligible renewable electrical generating facility, such as a community-owned wind project, a community-owned biomass project, a community-owned solar project, or a community methane digester processing livestock waste from multiple sources; and

(2) individual units, apartments, or properties owned or leased by multiple customers and collectively served by a common eligible renewable electrical generating facility, such as an apartment building served by photovoltaic panels on the roof.

For the purposes of this subsection (l), "meter aggregation" means the combination of reading and billing on a pro rata basis for the types of eligible customers described in this Section.

(m) Nothing in this Section shall affect the right of an electricity provider to continue to provide, or the right of a retail customer to continue to receive service pursuant to a contract for electric service between the electricity provider and the retail customer in accordance with the prices, terms, and conditions provided for in that contract. Either the electricity provider or the customer may require compliance with the prices, terms, and conditions of the contract.

(Source: P.A. 97-616, eff. 10-26-11; 97-646, eff. 12-30-11; 97-824, eff. 7-18-12.)

(220 ILCS 5/16-107.6 new)

Sec. 16-107.6. Net electricity metering.

(a) Beginning January 1, 2018, this Section applies to electric utilities serving more than 3,000,000 retail customers in the State and the provisions of Section 16-107.5 shall no longer apply to those utilities.

(b) The General Assembly finds and declares that a program to provide net electricity metering, as defined in this Section, for eligible customers can encourage private investment in renewable energy resources, stimulate economic growth, enhance the continued diversification of Illinois' energy resource mix, and protect the Illinois environment.

(c) As used in this Section:

"Eligible customer" means a retail customer that owns or operates a solar, wind, or other eligible renewable electrical generating facility with a rated capacity of not more than 2,000 kilowatts that is located on the customer's premises and is intended primarily to offset the customer's own electrical requirements.

"Electricity provider" means an electric utility or alternative retail electric supplier.

"Eligible renewable electrical generating facility" means a generator powered by solar electric energy, wind, dedicated crops grown for electricity generation, agricultural residues, untreated and unadulterated wood waste, landscape trimmings, livestock manure, anaerobic digestion of livestock or food processing waste, fuel cells or microturbines powered by renewable fuels, or hydroelectric energy.

"Net electricity metering" or "net metering" means the measurement, during the billing period applicable to an eligible customer, of the net amount of electricity supplied by an electricity provider to the customer's premises or provided to the electricity provider by the customer.

(d) A net metering facility shall be equipped with metering equipment that can measure the flow of electricity in both directions at the same rate. The electricity provider may arrange for the local electric utility or a meter service provider to install and maintain metering equipment capable of measuring the flow of electricity both into and out of the eligible customer's facility at the same rate and ratio, typically through the use of a dual channel meter.

(e) An electricity provider shall measure and charge or credit for the net electricity supplied to eligible customers whose electric delivery service is provided and measured on a kilowatt-demand basis and electric supply service is not provided based on hourly pricing in the following manner:

(1) If the amount of electricity used by the customer during the billing period exceeds the amount of electricity produced by the customer, then the electricity provider shall charge the customer for the net electricity supplied to and used by the customer as provided in subsection (g) of this Section.

(2) If the amount of electricity produced by a customer during the billing period exceeds the amount of electricity used by the customer during that billing period, then the electricity provider supplying that customer shall apply a 1:1 kilowatt-hour credit that reflects the kilowatt-hour based charges in the customer's electric service rate to a subsequent bill for service to the customer for the net electricity supplied to the electricity provider. The electricity provider shall continue to carry over any excess kilowatt-hour credits earned and apply those credits to subsequent billing periods to offset any customer-generator consumption in those billing periods until all credits are used or until the end of the annualized period.

(3) At the end of the year or annualized over the period that service is supplied by means of net metering, or in the event that the retail customer terminates service with the electricity provider prior to the end of the year or the annualized period, any remaining credits in the customer's account shall expire.

(f) An electricity provider shall measure and charge or credit for the net electricity supplied to eligible customers whose electric delivery service is provided and measured on a kilowatt-demand basis and electric supply service is provided based on hourly or time of use pricing in the following manner:

(1) If the amount of electricity used by the customer during any hourly or time-of-use period exceeds the amount of electricity produced by the customer, then the electricity provider shall charge the customer for the net electricity supplied to and used by the customer as provided in subsection (g) of this Section.

(2) If the amount of electricity produced by a customer during any hourly or time of use period exceeds the amount of electricity used by the customer during that hourly or time of use period, the energy provider shall calculate an energy credit for the net kilowatt-hours produced in such period. The value of the energy credit shall be calculated using the same price per kilowatt-hour as the electric service provider would charge for kilowatt-hour energy sales during that same hourly or time of use period.

(g) An electricity provider shall provide electric service to eligible customers who utilize net metering at non-discriminatory rates that are identical, with respect to rate structure, retail rate components, and any monthly charges, to the rates that the customer would be charged if not a net metering customer. An electricity provider shall charge the customer for the net electricity supplied to and used by the customer according to the terms of the contract or tariff to which the same customer would be assigned or be eligible for if the customer was not a net metering customer. An electricity provider shall not charge net metering customers any fee or charge or require additional equipment, insurance, or any other requirements not specifically authorized by interconnection standards authorized by the Commission, unless the fee, charge, or other requirement would apply to other similarly situated customers who are not net metering customers. The customer will remain responsible for the gross amount of delivery services charges and all taxes and fees that would otherwise be applicable to the net amount of electricity used by the customer. Subsections (e) and (f) of this Section shall not be construed to prevent an arms-length agreement between an electricity provider and an eligible customer that sets forth different prices, terms, and conditions for the provision of net metering service, including, but not limited to, the provision of the appropriate metering equipment for non-residential customers.

(h) For purposes of federal and State laws providing renewable energy credits or greenhouse gas credits, the eligible customer shall be treated as owning and having title to the renewable energy attributes, renewable energy credits, and greenhouse gas emission credits related to any electricity produced by the qualified generating unit. The electric utility may not condition participation in a net metering program on the signing over of a customer's renewable energy credits; provided, however, this subsection (h) shall not be construed to prevent an arms-length agreement between an electricity provider and an eligible customer that sets forth the ownership or title of the credits.

(i) An electricity provider shall provide net metering to eligible customers until the load of its net metering customers equals 5% of the total peak demand supplied by that electricity provider during the previous year. Electricity providers are authorized to offer net metering beyond the 5% level if they so choose.

(j) Each electricity provider shall maintain records and report annually to the Commission the total number of net metering customers served by the provider, as well as the type, capacity, and energy sources of the generating systems used by the net metering customers. Nothing in this Section shall limit the ability of an electricity provider to request the redaction of information deemed by the Commission to be confidential business information. Each electricity provider shall notify the Commission when the total generating capacity of its net metering customers is equal to or in excess of the 5% cap specified in subsection (i) of this Section.

(k) Notwithstanding the definition of "eligible customer" in subsection (c) of this Section, each electricity provider shall allow meter aggregation for the purposes of net metering on:

(1) properties owned or leased by multiple customers that contribute to the operation of an eligible renewable electrical generating facility through an ownership or leasehold interest of at least 2 kilowatts in such facility, such as a community-owned biomass project, a community-owned solar project, or a community methane digester processing livestock waste from multiple sources, provided that the address at which each such customer receives electric service from the electric utility must be located within 5 miles of the location of the facility and that the facility is also located within the utility's service territory; and

(2) individual units, apartments, or properties located in a single building that are owned or leased by multiple customers and collectively served by a common eligible renewable electrical generating facility, such as an office or apartment building, a shopping center or strip mall served by photovoltaic panels on the roof.

The aggregate demand of all meter aggregation pursuant to subparagraphs (1) and (2) of this subsection (k) shall be subject to, and counted toward, the 5% cap specified in subsection (i) of this Section. In addition, the demand of the properties, units, or apartments identified in subparagraphs (1) and (2) of this subsection (k) whose meters are aggregated shall not exceed 2 megawatts in nameplate capacity in total. For the purposes of this subsection (k), "meter aggregation" means the combination of reading and billing on a pro rata basis for the types of eligible customers described in this Section.

(l) Nothing in this Section shall affect the right of an electricity provider to continue to provide, or the right of a retail customer to continue to receive service pursuant to a contract for electric service between the electricity provider and the retail customer in accordance with the prices, terms, and conditions provided for in that contract. Either the electricity provider or the customer may require compliance with the prices, terms, and conditions of the contract.

(220 ILCS 5/16-108.9 new)

Sec. 16-108.9. Microgrid pilot.

(a) The General Assembly finds that the electric industry is undergoing rapid transformation, including fundamental changes regarding how electricity is generated, procured, and delivered and how customers are choosing to participate in the supply and delivery of electricity to and from the electric grid. Building upon the State's goals to increase the procurement of electricity from renewable energy resources and distributed generation, the General Assembly finds that it is now necessary to study how the electric grid could be enhanced through reliance on the diverse supply options being connected to the grid by traditional suppliers and new market participants, such as the utility's customers. Specifically, the General Assembly finds that these developments present unprecedented opportunities to strengthen the resilience and security of the electric grid, particularly with respect to the grid's support of the State's critical infrastructure dedicated to public safety and health purposes. The General Assembly therefore finds that it is beneficial to undertake the microgrid pilot described in this Section to explore a variety of objectives, including, but not limited to, (i) alternatives to upgrading the conventional electric grid, (ii) ways to improve electric grid resiliency, security, and outage management for critical facilities and customers and thus reduce the frequency, duration, and cost of major outages, and (iii) how to improve the safety and security of critical electric infrastructure, including cyber security, for the benefit of the public.

(b) (1) An electric utility serving more than 3,000,000 retail customers in Illinois that is also a participating utility as defined by Section 16-108.5 of this Act may invest an estimated $250,000,000 to develop, construct, and install up to 6 microgrids in its service territory over a 5-year period that commences upon the date of the Commission's approval of the plan submitted pursuant to subsection (d) of this Section. Notwithstanding such investment amount, a utility that elects to undertake the investment described in this subsection (b) shall also be authorized to study, operate, and maintain such microgrids.

For purposes of this Section, "microgrid" means a group of interconnected loads and distributed energy resources with clearly defined electrical boundaries that acts as a single controllable entity with respect to the grid and can connect and disconnect from the grid to enable it to operate in both grid-connected or island modes.

(2) The locations selected to be served by the microgrids shall include critical public health and safety facilities and critical infrastructure and transportation facilities that provide opportunities to study the operation and benefits of the microgrid. Facilities and locations may include, but are not limited to, the following: military; fire fighting; police; aviation; medical and health; HazMat; civil defense and public safety warning services; communications; radiological, chemical, and other special weapons defense; water pumping and treatment facilities; and energy delivery. Nothing in this Section shall be interpreted to limit the utility's ability to coordinate with governmental agencies regarding the selection of locations and facilities to be served. Consistent with the provisions of this paragraph (2), a utility that elects to undertake the investment described in this Section may develop, construct, operate, maintain, and study microgrids located at or within the following sites in its service territory:

(A) the Bronzeville community of Chicago, whose boundaries are approximately Pershing Road, 31st Street, King Drive, and the Dan Ryan Expressway;

(B) the Illinois Medical District as defined by Section 1 of the Illinois Medical District Act;

(C) an airport, as that term is defined by the Illinois Aeronautics Act, that is located in Winnebago County;

(D) the Chicago Air Route Traffic Control Center operated by the Federal Aviation Administration and located in the city of Aurora;

(E) the DuPage County Courthouse and Administration Building located in the city of Wheaton; and

(F) the water pumping and treatment facilities located in the city of Chicago Heights.

In the event one or more of the sites approved by the Commission pursuant to subsection (d) of this Section becomes unsuitable or unavailable to accommodate a microgrid project, the electric utility shall select an alternative site or sites consistent with the provisions of this subparagraph (2). The utility shall submit an informational filing to the Commission that identifies the alternative site or sites within 90 days after such selection.

(3) Notwithstanding any law, rule, regulation, or order to the contrary, an electric utility that undertakes the investment authorized by this subsection (b):

(A) shall study electric generating plants and facilities and electric storage plants and facilities as part of a microgrid project, which shall include the construction, installation, leasing, or ownership of at least 3 of the following: (i) solar photovoltaic facilities; (ii) fuel cells; (iii) natural gas generation, including generation that utilizes combined heat and power; (iv) an electricity storage plant and facilities; (v) geothermal technologies; and (vi) wind turbines;

(B) shall be permitted to use the plant or facilities described in subparagraph (A) of this paragraph (3) as follows: (i) for distribution system purposes, (ii) as a source of power, energy, and ancillary services for retail customers located within the boundaries of the microgrid during interruptions of services on the distribution system serving the microgrid or such customers, provided that the use of the plant and facilities during these periods and the delivery of electric power and energy that they produce shall be considered and treated as a distribution system reliability function and not as a retail sale of power, and (iii) for sales of energy, power, heat, ancillary services, and other related products and services into any available markets, including, but not limited to, wholesale markets, provided that the utility shall not be required to make such sales and, if it elects not to do so, such election and the results thereof shall not be an unreasonable or imprudent decision;

(C) may upgrade the delivery facilities in and supporting the microgrid, including, but not limited to, constructing, installing, operating, and maintaining (i) multiple feeders to provide service within and to the microgrid, (ii) distribution automation and other smart grid facilities, which shall be incremental to the investment amounts set forth in Section 16-108.5 of this Act, and (iii) undergrounding distribution facilities within and providing service to the microgrid; and

(D) shall not be required to obtain any certificates of public convenience and necessity under Section 8-406 of this Act or any approvals under Sections 9-212, 9-213 or 16-111.5 of this Act.

(c) An electric utility that elects to undertake the investment described in subsection (b) of this Section may, at its election, recover the costs of such investment through an automatic adjustment clause tariff or through a delivery services charge. Regardless of which cost recovery mechanism the electric utility elects, the utility shall earn a return on the balance of the related plant investment as of December 31 for a given year, less any related accumulated depreciation and any related deferred taxes, at an annual rate equal to the utility's weighted average cost of capital as approved by the Commission in its most recent order applicable to that utility under Article IX or Section 16-108.5 of this Act, including a revenue conversion factor calculated to recover or refund all additional income taxes that may be payable or receivable as a result of that return. The weighted average cost of capital shall be increased for a period of 5 years following the date on which the utility begins recovering costs incurred pursuant to this Section, to add 50 basis points to the return on equity. The weighted average cost of capital calculated pursuant to this subsection (c) shall be updated from time to time to reflect the weighted average cost of capital most recently approved by the Commission for the utility.

In the event the utility elects to file an automatic adjustment clause tariff, such tariff may be filed and established outside the context of a general rate case filing or a filing under subsection (c) or (d) of Section 16-108.5 of this Act. The Commission shall review and, after notice and hearing, by order approve or approve with modification the proposed tariff no later than 90 days after the filing of the tariff. A utility may reflect the charges recovered through the tariff as a separate line item on customers' bills, but shall not be required to do so. A tariff approved and placed into effect pursuant to this Section shall remain in effect at the discretion of the utility, and the utility may withdraw the tariff at any time. At such time as the tariff ceases to be in effect, the utility shall recover its costs incurred pursuant to this Section through a delivery services charge regardless of how the assets are categorized or reflected on the utility's books and records of account.

An electric utility that elects to undertake the investment described in subsection (b) of this Section shall also recover the costs it incurs to study, operate, and maintain the microgrid projects pursuant to this Section, and may, at its election, recover such costs through an automatic adjustment clause tariff placed into effect pursuant to this Section, if applicable, or through its delivery services charges.

(d) If an electric utility elects to undertake the investment authorized by subsection (b) of this Section, then the utility shall submit to the Commission within 120 days after the effective date of this amendatory Act of the 99th General Assembly the utility's plan for developing, constructing, operating, and analyzing microgrids in its service territory for the 5-year period commencing upon the plan's approval. Such plan shall describe:

(1) the utility's current projections for scope, microgrid locations and boundaries, schedule, expenditures, and staffing;

(2) whether the utility intends to sell into wholesale markets any portion of the power generated pursuant to the plant or facilities described in subparagraph (A) of paragraph (3) of subsection (b) of this Section and, if so, how such sales will be executed and revenues applied to offset the costs of the microgrid pilot; and

(3) the criteria, including specific performance metrics, for evaluating the extent to which the microgrids developed under this Section achieved the objectives set out in subsection (a) of this Section.

Within 90 days after the utility files its plan pursuant to this subsection (d), the Commission shall review and, after notice and hearing, enter an order approving the plan if it finds that the plan conforms to the requirements of this Section or, if the Commission finds that the plan does not conform to the requirements of this Section, the Commission must enter an order describing in detail the reasons for not approving the plan. The utility may resubmit its plan to address the Commission's concerns, and the Commission shall expeditiously review and by order approve the revised plan if it finds that the plan conforms to the requirements of this Section, provided that such order shall be entered no later than 90 days after the utility resubmits its plan.

No later than 90 days after the close of each plan year, the utility shall submit a report to the Commission that includes any updates to the plan, a schedule for the next plan year, the expenditures made for the prior plan year and cumulatively, an evaluation of the extent to which the objectives of this microgrid pilot are being achieved, and the number of full-time equivalent jobs created for the prior plan year and cumulatively. Within 60 days after the utility files its annual report, the Commission may enter into an investigation of the report. If the Commission commences an investigation, it must, after notice and hearing, enter an order approving the report or approving the report with modification necessary to bring it into compliance with this Section no later than 180 days after the utility files such report. If the Commission does not initiate an investigation within 60 days after the utility files its annual report, then the filing shall be deemed accepted by the Commission.

The utility may continue operating, maintaining, and studying the microgrids developed and constructed pursuant to this Section following the end of the 5-year plan period, and the costs incurred by the utility regarding such continued operation and maintenance and to comply with the requirements of this Section shall continue to be recoverable following the end of the 5-year plan period. However, any generating or storage facility that becomes inoperable after the initial 5-year period may not be replaced without the approval of the Commission unless the facility will be used solely for the purposes described in subparagraph (B) of paragraph (3) of subsection (b) of this Section.

To the extent feasible and consistent with State and federal law, the investments made pursuant to this Section should provide employment opportunities for all segments of the population and workforce, including minority-owned and female-owned business enterprises, and shall not, consistent with State and federal law, discriminate based on race or socioeconomic status.

(e) No later than 365 days following the end of the 5-year plan period, the electric utility shall submit its final report to the Commission evaluating the extent to which the objectives of this microgrid pilot have been achieved, reporting on its performance under the metrics established in the plan, and proposing any additional study or action required to continue the further development of microgrids in the electric utility's service territory. In addition, the electric utility shall demonstrate that it created an average of 50 full-time equivalent jobs in Illinois, per microgrid project, during the construction and operation of the microgrids. The jobs shall include direct jobs, contractor positions, and induced jobs. If the Commission enters an order finding, after notice and hearing, that the utility did not satisfy its job commitment described in this subsection (e) for reasons that are reasonably within its control, then the Commission shall also determine, after consideration of the evidence, including, but not limited to, evidence submitted by the Department of Commerce and Economic Opportunity and the utility, the deficiency in the number of full-time equivalent jobs due to such failure. The Commission shall notify the Department of any proceeding that is initiated pursuant to this subsection (e). For each full-time equivalent job deficiency that the Commission finds as set forth in this subsection (e), the utility shall, within 30 days after the entry of the Commission's order, pay $6,000 to a fund for training grants administered under Section 605-800 of the Department of Commerce and Economic Opportunity Law, which shall not be a recoverable expense.

No later than 365 days following the date on which the utility submits its final report pursuant to this subsection (e), the Commission shall submit a report to the General Assembly evaluating the extent to which the objectives of the microgrid pilot have been achieved, reporting on the utility's performance under the metrics established in its plan, and proposing any additional study or action required to continue the further development of microgrids in the utility's service territory.

(f) In no event, absent General Assembly approval, shall the capital investment costs incurred by an electric utility pursuant to this Section exceed $300,000,000. If the utility's updated cost estimates for implementing its plan exceed the limitation imposed by this subsection (f), then it shall submit a report to the Commission that identifies the increased costs and explains the reason or reasons for the increased costs no later than the year in which the utility estimates it will exceed the limitation. The Commission shall review the report and shall, within 90 days after the utility files the report, report to the General Assembly its findings regarding the utility's report. If the General Assembly does not amend the limitation imposed by this subsection (f), then the utility may modify its plan so as not to exceed the limitation imposed by this subsection (f) and may propose corresponding changes in its plan, and the Commission may modify the metrics established pursuant to this Section accordingly.

(g) All facilities and equipment installed pursuant to this Section shall be considered and treated as distribution system facilities.

(220 ILCS 5/16-108.10 new)

Sec. 16-108.10. Electric vehicle charging station pilot.

(a) The General Assembly finds that substantial opportunities exist to expand the purchase and use of electric vehicles in Illinois and thereby reduce the State's reliance on conventional vehicles that use petroleum as their sole source of fuel. The General Assembly further finds that increased usage of electric vehicles in Illinois will improve the State's air quality by reducing greenhouse gas emissions and other environmental pollutants. These benefits will be realized by all citizens of the State, including low-income households. While the General Assembly has previously enacted legislation to address the installation of electric vehicle charging stations, the General Assembly finds that electric vehicles are substantially underutilized in Illinois, and the market remains nascent. The General Assembly further finds that the insufficient number of electric vehicle charging stations in the State has contributed to Illinoisans' reluctance to purchase electric vehicles. The General Assembly therefore finds that it is now necessary for electric utilities to undertake substantial investment in the development, construction, and installation of electric vehicle charging stations as described in this Section.

(b)(1) An electric utility that serves more than 3,000,000 retail customers in the State may invest a maximum of $100,000,000 to develop, construct, and install up to 5,000 publicly-accessible electric vehicle charging stations in its service territory over a 5-year period that commences upon the date of the Commission's approval of the plan submitted pursuant to subsection (d) of this Section. Notwithstanding such maximum investment amount, a utility that elects to undertake the investment described in this subsection (b) shall also be authorized to operate and maintain such stations. For purposes of this Section, "electric vehicle charging station" shall have the meaning set forth in Section 16-128A of this Act.

(2) The deployment of electric vehicle charging stations shall be focused primarily on the following priority areas:

(A) publicly accessible parking areas, including rights-of-way and parking facilities, to support residents of multi-unit dwelling buildings with respect to such use;

(B) workplace locations accessible to employees and visitors, provided that electric vehicle charging stations designated for use by an employer's fleet of vehicles shall not be installed pursuant to this Section unless the charging station is used by both the employer's fleet and the public;

(C) municipal parking lots;

(D) other locations designated for long-term or overnight public parking; and

(E) economically disadvantaged locations.

(3) Notwithstanding any law, rule, regulation, or order to the contrary:

(A) users of electric vehicle charging stations deployed by an electric utility pursuant to this Section shall be deemed to be retail customers of the electric utility as defined by Section 16-102 of this Act;

(B) electric utilities may market, advertise, and promote the use of the electric vehicle charging stations installed pursuant to this Section, including, but not limited to, the sale of electric power and energy from such stations;

(C) electric utilities may construct, install, own, operate, and maintain solar photovoltaic generating stations to supply the electric vehicle charging station facilities deployed pursuant to this Section and to use the energy output of such generating stations to serve the needs of the electric vehicle charging station facilities; the costs of constructing and installing such facilities shall be included within and subject to the maximum investment amount set forth in paragraph (1) of this subsection (b);

(D) the power, energy, and ancillary services required to serve the needs of the electric vehicle charging stations shall be included in the electric utility's load forecasts for its eligible retail customers submitted pursuant to Section 16-111.5 of this Act; however, the costs of the power, energy, and ancillary services shall not be recovered pursuant to that Section, and the utility shall instead recover such costs pursuant to this Section as specified in the plan submitted pursuant to subsection (d) of this Section; and

(E) electric utilities that construct, operate, and maintain facilities described in this subsection (b) shall not be required to obtain any certificates of public convenience and necessity under Section 8-406 of this Act or any approvals under Sections 9-212, 9-213, or 16-111.5 of this Act and shall not be subject to the certification requirements set forth in Section 16-128A of this Act.

(c) An electric utility that elects to undertake the investment in electric vehicle charging station facilities described in subsection (b) of this Section may, at its election, recover the costs of such investment through an automatic adjustment clause tariff or through a delivery services charge, provided that the cost recovery of such investment shall not include the energy charges associated with the electric vehicle charging stations, which shall be separately recovered as an operating expense as described in the plan submitted pursuant to subsection (d) of this Section. Regardless of which cost recovery mechanism the electric utility elects, the utility shall earn a return on the balance of the related plant investment as of December 31 for a given year, less any related accumulated depreciation and any related deferred taxes, at an annual rate equal to the utility's weighted average cost of capital as approved by the Commission in its most recent order applicable to that utility under Article IX or Section 16-108.5 of this Act, including a revenue conversion factor calculated to recover or refund all additional income taxes that may be payable or receivable as a result of that return. The weighted average cost of capital shall be increased for a period of 5 years following the date on which the utility begins recovering costs incurred pursuant to this Section, to add 50 basis points to the return on equity. The weighted average cost of capital calculated pursuant to this subsection (c) shall be updated from time to time to reflect the weighted average cost of capital most recently approved by the Commission for the utility.

If the utility elects to file an automatic adjustment clause tariff, the tariff may be filed and established outside the context of a general rate case filing or a filing under subsection (c) or (d) of Section 16-108.5 of this Act and shall be filed no later than 120 days after the effective date of this amendatory Act of the 99th General Assembly. The Commission shall review and, after notice and hearing, by order approve or approve with modification the proposed tariff no later than 180 days after the filing of the tariff. A tariff approved and placed into effect pursuant to this Section shall remain in effect at the discretion of the utility, and the utility may withdraw the tariff at any time. At such time as the tariff ceases to be in effect, the utility shall recover its costs incurred pursuant to this Section through a delivery services charge regardless of how the assets are categorized or reflected on the utility's books and records of account.

An electric utility that elects to undertake the investment in electric vehicle charging station facilities described in subsection (b) of this Section shall also recover the costs it incurs to operate and maintain such facilities installed pursuant to this Section and may, at its election, recover those costs through an automatic adjustment clause tariff placed into effect pursuant to this Section, if applicable, or through its delivery services charges.

(d) If an electric utility elects to undertake the investment authorized by subsection (b) of this Section, then the utility shall submit its plan to the Commission within 120 days after the effective date of this amendatory Act of the 99th General Assembly. The utility shall consult with the Illinois Electric Vehicle Advisory Council and Chicago Area Clean Cities Coalition prior to filing the plan. Such plan must include (i) the criteria and a description of the process for selecting the sites described in paragraph (2) of subsection (b) of this Section, (ii) a description of the process by which sites that fall within paragraph (2) of subsection (b) of this Section may submit applications for installation of an electric vehicle charging station at a particular location, (iii) a description of the pricing proposals the utility intends to pilot during the plan's 5-year period to recover the costs of the energy used at the electric vehicle charging stations, including, but not limited, to demand-response pricing, and (iv) a preliminary list of the recommended locations of the electric vehicle charging stations planned to be installed during the first annual period of investment under this Section, which shall commence upon the date of the Commission's approval of the plan.

Within 90 days after the utility files its plan pursuant to this subsection (d), the Commission shall review and, after notice and hearing, enter an order approving the plan if it finds that the plan conforms to the requirements of this Section or, if the Commission finds that the plan does not conform to the requirements of this Section, the Commission shall enter an order describing in detail the reasons for not approving the plan. The utility may resubmit its plan to address the Commission's concerns, and the Commission shall expeditiously review and by order approve the revised plan if it finds that the plan conforms to the requirements of this Section, provided that such order shall be entered no later than 90 days after the utility resubmits its plan. No later than 90 days after the close of each plan year, the utility shall submit a report to the Commission that includes any updates to the plan, a schedule for the next plan year, the expenditures made for the prior plan year and cumulatively, and the number of full-time equivalent jobs created for the prior plan year and cumulatively.

The utility may continue operating and maintaining the electric vehicle charging stations deployed pursuant to this Section following the end of the 5-year plan period, and the costs incurred by the utility regarding such continued operation and maintenance and to comply with the requirements of this Section shall continue to be recoverable following the end of the 5-year plan period. If the utility finds that the market for electric vehicles remains nascent following the first 2 years of deployment under the plan, then the utility may file a petition with the Commission requesting approval to terminate the pilot program described in, and plan approved pursuant to, this Section. If the Commission approves such termination and the utility is recovering its costs incurred pursuant to this Section through an automatic adjustment clause tariff authorized by subsection (c) of this Section, then the utility shall begin recovering such costs through its delivery services charges established in the next general rate case under Section 9-201 of this Act or in the next formula rate update proceeding under subsection (d) of Section 16-108.5 of this Act, as applicable. At such time as the utility begins recovering its costs incurred under this Section through delivery services charges, the automatic adjustment clause tariff shall terminate.

To the extent feasible and consistent with State and federal law, the investments made pursuant to this Section should provide employment opportunities for all segments of the population and workforce, including minority-owned and female-owned business enterprises, and shall not, consistent with State and federal law, discriminate based on race or socioeconomic status.

(e) No later than 365 days following the end of the 5-year plan period, the electric utility shall submit its final report to the Commission evaluating the development, construction, installation, operation, and maintenance of electric vehicle charging stations and solar photovoltaic generating stations and the extent to which the objectives stated in subsection (a) of this Section have been achieved. In addition, during the 5-year plan period, the electric utility shall create 50 full-time equivalent jobs in Illinois through the development, construction, installation, operation, and maintenance of electric vehicle charging stations and solar photovoltaic generating stations. The jobs shall include direct jobs, contractor positions, and induced jobs. If the Commission enters an order finding, after notice and hearing, that the utility did not satisfy its job commitment described in this subsection (e) for reasons that are reasonably within its control, then the Commission shall also determine, after consideration of the evidence, including, but not limited to, evidence submitted by the Department of Commerce and Economic Opportunity and the utility, the deficiency in the number of full-time equivalent jobs due to such failure. The Commission shall notify the Department of any proceeding that is initiated pursuant to this subsection (e). For each full-time equivalent job deficiency that the Commission finds as set forth in this subsection (e), the utility shall, within 30 days after the entry of the Commission's order, pay $6,000 to a fund for training grants administered under Section 605-800 of the Department of Commerce and Economic Opportunity Law, which shall not be a recoverable expense.

(f) All facilities and equipment installed pursuant to this Section shall be considered and treated as distribution system facilities.

(220 ILCS 5/16-108.11 new)

Sec. 16-108.11. Voltage optimization implementation.

(a) The General Assembly finds that electric utilities' energy efficiency and demand-response plans approved pursuant to Section 8-103 of this Act have already implemented many of the lowest-cost energy efficiency measures available in the market, and further finds that it is necessary to continue to research and identify new energy efficiency measures that are cost effective. The General Assembly finds that voltage optimization is an energy efficiency measure that can deliver cost-effective energy savings for all retail customers, including low-income customers. For purposes of this Section, "cost-effective" shall have the meaning set forth in Section 8-103 of this Act.

(b) A participating utility may file a plan with the Commission to begin implementing cost-effective voltage optimization on identified elements of its electric delivery system. The plan shall be submitted with a recent voltage optimization study identifying suitable facilities and potential benefits and costs of voltage optimization. The plan shall cover a period that does not extend beyond December 31, 2017, and its scope shall be limited to achieving no more than the unmet portion of the utility's statutory energy savings goals calculated pursuant to subsections (b) and (i) of Section 8-103 of this Act for the multi-year planning period ending on December 31, 2017. For purposes of this Section, such "unmet portion c" shall be calculated as the difference between the following:

(1) the utility's statutory energy savings goals calculated pursuant to subsections (b) and (i) of Section 8-103 of this Act for the multi-year planning period ending on December 31, 2017; and

(2) the amount of energy savings projected to be achieved during the multi-year planning period ending on December 31, 2017, which shall be determined using the energy efficiency energy savings goals set forth in the utility's most recent 3-year energy efficiency and demand-response plan approved by the Commission, as modified by subsection (i) of Section 8-103 of this Act, and the energy savings projected to be achieved through the energy efficiency measures to be implemented during the period June 1, 2014 through December 31, 2017 as approved by the Commission pursuant to Section 16-111.5B of this Act.

The Commission shall review the plan to determine if it is consistent with the scope and calculations set forth in this subsection (b) and that it is cost effective. The Commission shall, after notice and hearing, by order approve such plan if it is consistent with this subsection (b) and cost effective or approve it with modifications required to meet those requirements. Notwithstanding the limitations set forth in subsection (d) of Section 8-103 of this Act, the utility shall recover all of its costs incurred pursuant to a plan approved under this Section through the provisions of Article IX or Section 16-108.5 of this Act. Nothing in this Section is intended to prohibit or limit a utility from beginning to validate voltage optimization prior to the approval of its plan under this Section, and the costs of such validating shall be recovered through the provisions of Article IX or Section 16-108.5 of this Act.

(c) An electric utility that is implementing cost-effective voltage optimization pursuant to a plan approved by the Commission pursuant to this Section shall create 50 full-time equivalent jobs in Illinois related to such implementation during the plan period. The jobs shall include direct jobs, contractor positions, and induced jobs. If the Commission enters an order finding, after notice and hearing, that the utility did not satisfy its job commitment described in this subsection (c) for reasons that are reasonably within its control, then the Commission shall also determine, after consideration of the evidence, including, but not limited to, evidence submitted by the Department of Commerce and Economic Opportunity and the utility, the deficiency in the number of full-time equivalent jobs due to such failure. The Commission shall notify the Department of any proceeding that is initiated pursuant to this subsection (c). For each full-time equivalent job deficiency that the Commission finds as set forth in this subsection (c), the utility shall, within 30 days after the entry of the Commission's order, pay $6,000 to a fund for training grants administered under Section 605-800 of the Department of Commerce and Economic Opportunity Law, which shall not be a recoverable expense.

To the extent feasible and consistent with State and federal law, the investments made pursuant to this Section should provide employment opportunities for all segments of the population and workforce, including minority-owned and female-owned business enterprises, and shall not, consistent with State and federal law, discriminate based on race or socioeconomic status.

(d) A utility that is implementing voltage optimization pursuant to this Section shall address the continued implementation of voltage optimization in the assessment submitted pursuant to paragraph (8) of subsection (g) of Section 8-103 of this Act for its proposed energy efficiency plan filed on or before March 1, 2017 for the multi-year planning period commencing on January 1, 2018.

(220 ILCS 5/16-108.12 new)

Sec. 16-108.12. Energy low-income and support program.

(a) Beginning on January 1, 2017, without obtaining any approvals from the Commission or any other agency, regardless of whether any such approval would otherwise be required, a participating utility that is not a combination utility, as defined by Section 16-108.5 of this Act, shall contribute $10,000,000 per year for 5 years to the energy low-income and support program, which is intended to fund customer assistance programs with the primary purpose being avoidance of imminent disconnection. Such programs may include:

(1) a residential hardship program that may partner with community-based organizations, including senior citizen organizations, and provides grants to low-income residential customers, including low-income senior citizens, who demonstrate a hardship;

(2) a program that provides grants and other bill payment concessions to disabled veterans who demonstrate a hardship and members of the armed services or reserve forces of the United States or members of the Illinois National Guard who are on active duty pursuant to an executive order of the President of the United States, an act of the Congress of the United States, or an order of the Governor and who demonstrate a hardship;

(3) a budget assistance program that provides tools and education to low-income senior citizens to assist them with obtaining information regarding energy usage and effective means of managing energy costs;

(4) a non-residential special hardship program that provides grants to non-residential customers, such as small businesses and non-profit organizations, that demonstrate a hardship, including those providing services to senior citizen and low-income customers; and

(5) a performance-based assistance program that provides grants to encourage residential customers to make on-time payments by matching a portion of the customer's payments or providing credits towards arrearages.

The payments made by a participating utility pursuant to this Section shall not be a recoverable expense. A participating utility may elect to fund either new or existing customer assistance programs, including, but not limited to, those that are administered by the utility.

Programs that use funds that are provided by an electric utility to reduce utility bills may be implemented through tariffs that are filed with and reviewed by the Commission. If a utility elects to file tariffs with the Commission to implement all or a portion of the programs, those tariffs shall, regardless of the date actually filed, be deemed accepted and approved, and shall become effective on the date that they are filed. The electric utilities whose customers benefit from the funds that are disbursed as contemplated in this Section shall file annual reports documenting the disbursement of those funds with the Commission. The Commission may audit disbursement of the funds to ensure they were disbursed consistently with this Section.

If the Commission finds that a participating utility is no longer eligible to update the performance-based formula rate tariff pursuant to subsection (d) of Section 16-108.5 of this Act or the performance-based formula rate is otherwise terminated, then the participating utility's obligations under this Section shall immediately terminate.

(220 ILCS 5/16-111.5)

Sec. 16-111.5. Provisions relating to procurement.

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

(b) A procurement plan shall be prepared for each electric utility consistent with the applicable requirements of the Illinois Power Agency Act and this Section. For purposes of this Section, Illinois electric utilities that are affiliated by virtue of a common parent company are considered to be a single electric utility. Small multi-jurisdictional utilities may request a procurement plan for a portion of or all of its Illinois load. Each procurement plan shall analyze the projected balance of supply and demand for eligible retail customers over a 5-year period with the first planning year beginning on June 1 of the year following the year in which the plan is filed. The plan shall specifically identify the wholesale products to be procured following plan approval, and shall follow all the requirements set forth in the Public Utilities Act and all applicable State and federal laws, statutes, rules, or regulations, as well as Commission orders. Nothing in this Section precludes consideration of contracts longer than 5 years and related forecast data. Unless specified otherwise in this Section, in the procurement plan or in the implementing tariff, any procurement occurring in accordance with this plan shall be competitively bid through a request for proposals process. Approval and implementation of the procurement plan shall be subject to review and approval by the Commission according to the provisions set forth in this Section. A procurement plan shall include each of the following components:

(1) Hourly load analysis. This analysis shall include:

(i) multi-year historical analysis of hourly loads;

(ii) switching trends and competitive retail market analysis;

(iii) known or projected changes to future loads; and

(iv) growth forecasts by customer class.

(2) Analysis of the impact of any demand side and renewable energy initiatives. This analysis shall include:

(i) the impact of demand response programs and energy efficiency programs, both current and projected; for small multi-jurisdictional utilities, the impact of demand response and energy efficiency programs approved pursuant to Section 8-408 of this Act, both current and projected; and

(ii) supply side needs that are projected to be offset by purchases of renewable energy resources, if any.

(3) A plan for meeting the expected load requirements that will not be met through preexisting contracts. This plan shall include:

(i) definitions of the different Illinois retail customer classes for which supply is being purchased;

(ii) the proposed mix of demand-response products for which contracts will be executed during the next year. For small multi-jurisdictional electric utilities that on December 31, 2005 served fewer than 100,000 customers in Illinois, these shall be defined as demand-response products offered in an energy efficiency plan approved pursuant to Section 8-408 of this Act. The cost-effective demand-response measures shall be procured whenever the cost is lower than procuring comparable capacity products, provided that such products shall:

(A) be procured by a demand-response provider from eligible retail customers;

(B) at least satisfy the demand-response requirements of the regional transmission organization market in which the utility's service territory is located, including, but not limited to, any applicable capacity or dispatch requirements;

(C) provide for customers' participation in the stream of benefits produced by the demand-response products;

(D) provide for reimbursement by the demand-response provider of the utility for any costs incurred as a result of the failure of the supplier of such products to perform its obligations thereunder; and

(E) meet the same credit requirements as apply to suppliers of capacity, in the applicable regional transmission organization market;

(iii) monthly forecasted system supply requirements, including expected minimum, maximum, and average values for the planning period;

(iv) the proposed mix and selection of standard wholesale products for which contracts will be executed during the next year, separately or in combination, to meet that portion of its load requirements not met through pre-existing contracts, including but not limited to monthly 5 x 16 peak period block energy, monthly off-peak wrap energy, monthly 7 x 24 energy, annual 5 x 16 energy, annual off-peak wrap energy, annual 7 x 24 energy, monthly capacity, annual capacity, peak load capacity obligations, capacity purchase plan, and ancillary services;

(v) proposed term structures for each wholesale product type included in the proposed procurement plan portfolio of products; and

(vi) an assessment of the price risk, load uncertainty, and other factors that are associated with the proposed procurement plan; this assessment, to the extent possible, shall include an analysis of the following factors: contract terms, time frames for securing products or services, fuel costs, weather patterns, transmission costs, market conditions, and the governmental regulatory environment; the proposed procurement plan shall also identify alternatives for those portfolio measures that are identified as having significant price risk.

(4) Proposed procedures for balancing loads. The procurement plan shall include, for load requirements included in the procurement plan, the process for (i) hourly balancing of supply and demand and (ii) the criteria for portfolio re-balancing in the event of significant shifts in load.

(5) Renewable energy resources plan. The procurement plan shall include a renewable energy resources plan that shall ensure adequate, reliable, affordable, efficient, and environmentally sustainable renewable energy resources at the lowest total cost over time, taking into account any benefits of price stability. The renewable energy resources plan shall include:

(i) a description of the renewable energy resources, including renewable energy credits proposed to be procured pursuant to Section 1-56 and subsection (c) of Section 1-75 of the Illinois Power Agency Act;

(ii) a planning horizon and a comparison of the projected costs and benefits of procuring renewable resources for various contract terms based on market evidence;

(iii) an analysis of the possible impacts of customer migration between alternative retail electric suppliers and electric utility supply service and a description of how the plan has been designed to limit the potential that eligible retail customers may pay for curtailed credits in excess of those required to meet the minimum for attainment of the goals set forth in paragraph (1) of subsection (c) of Section 1-75 of this Act;

(iv) an assignment to a particular utility's service territory of the renewable energy credits proposed to be procured for purposes of addressing customer migration in accordance with paragraph (1) of subsection (c) of Section 1-75 of the Illinois Power Agency Act, taking into account the renewable goals of the Illinois Power Agency; and

(v) an explanation of how the Illinois Power Agency plans to utilize available funds for its planned renewable energy procurement, identifying specifically the source of funds to be used, including the Illinois Power Agency Renewable Energy Resources Fund, moneys accumulated by the electric utility in respect of service to customers under hourly pricing tariffs pursuant to paragraph (5) of subsection (c) of Section 1-75 of the Illinois Power Agency Act, and any other moneys to be collected by the electric utility for procurements conducted pursuant to paragraph (1) of subsection (c) of Section 1-75 of the Illinois Power Agency Act.

Planning of the procurement of renewable energy credits through long-term contracts by the Illinois Power Agency under subsection (c) of Section 1-56 of the Illinois Power Agency Act shall recognize the possible impacts of customer migration between alternative retail electric suppliers and electric utility electric supply service and shall be designed to limit the potential that eligible retail customers may be required to pay for curtailed credits in excess of the amounts required to meet the minimum for attainment of the goals set forth in paragraph (1) of subsection (c) of Section 1-75 of the Illinois Power Agency Act.

(c) The procurement process set forth in Section 1-75 of the Illinois Power Agency Act and subsection (e) of this Section shall be administered by a procurement administrator and monitored by a procurement monitor.

(1) The procurement administrator shall:

(i) design the final procurement process in accordance with Section 1-75 of the Illinois Power Agency Act and subsection (e) of this Section following Commission approval of the procurement plan;

(ii) develop benchmarks in accordance with subsection (e)(3) to be used to evaluate bids; these benchmarks shall be submitted to the Commission for review and approval on a confidential basis prior to the procurement event;

(iii) serve as the interface between the electric utility and suppliers;

(iv) manage the bidder pre-qualification and registration process;

(v) obtain the electric utilities' agreement to the final form of all supply contracts and credit collateral agreements;

(vi) administer the request for proposals process;

(vii) have the discretion to negotiate to determine whether bidders are willing to lower the price of bids that meet the benchmarks approved by the Commission; any post-bid negotiations with bidders shall be limited to price only and shall be completed within 24 hours after opening the sealed bids and shall be conducted in a fair and unbiased manner; in conducting the negotiations, there shall be no disclosure of any information derived from proposals submitted by competing bidders; if information is disclosed to any bidder, it shall be provided to all competing bidders;

(viii) maintain confidentiality of supplier and bidding information in a manner consistent with all applicable laws, rules, regulations, and tariffs;

(ix) submit a confidential report to the Commission recommending acceptance or rejection of bids;

(x) notify the utility of contract counterparties and contract specifics; and

(xi) administer related contingency procurement events.

(2) The procurement monitor, who shall be retained by the Commission, shall:

(i) monitor interactions among the procurement administrator, suppliers, and utility;

(ii) monitor and report to the Commission on the progress of the procurement process;

(iii) provide an independent confidential report to the Commission regarding the results of the procurement event;

(iv) assess compliance with the procurement plans approved by the Commission for each utility that on December 31, 2005 provided electric service to a least 100,000 customers in Illinois and for each small multi-jurisdictional utility that on December 31, 2005 served less than 100,000 customers in Illinois;

(v) preserve the confidentiality of supplier and bidding information in a manner consistent with all applicable laws, rules, regulations, and tariffs;

(vi) provide expert advice to the Commission and consult with the procurement administrator regarding issues related to procurement process design, rules, protocols, and policy-related matters; and

(vii) consult with the procurement administrator regarding the development and use of benchmark criteria, standard form contracts, credit policies, and bid documents.

(d) Except as provided in subsection (j), the planning process shall be conducted as follows:

(1) Beginning in 2008, each Illinois utility procuring power pursuant to this Section shall annually provide a range of load forecasts to the Illinois Power Agency by July 15 of each year, or such other date as may be required by the Commission or Agency. The load forecasts shall cover the 5-year procurement planning period for the next procurement plan and shall include hourly data representing a high-load, low-load and expected-load scenario for the load of the eligible retail customers. The utility shall provide supporting data and assumptions for each of the scenarios.

(2) Beginning in 2008, the Illinois Power Agency shall prepare a procurement plan by August 15th of each year, or such other date as may be required by the Commission. The procurement plan shall identify the portfolio of demand-response and power and energy products to be procured. Cost-effective demand-response measures shall be procured as set forth in item (iii) of subsection (b) of this Section. Copies of the procurement plan shall be posted and made publicly available on the Agency's and Commission's websites, and copies shall also be provided to each affected electric utility. An affected utility shall have 30 days following the date of posting to provide comment to the Agency on the procurement plan. Other interested entities also may comment on the procurement plan. All comments submitted to the Agency shall be specific, supported by data or other detailed analyses, and, if objecting to all or a portion of the procurement plan, accompanied by specific alternative wording or proposals. All comments shall be posted on the Agency's and Commission's websites. During this 30-day comment period, the Agency shall hold at least one public hearing within each utility's service area for the purpose of receiving public comment on the procurement plan. Within 14 days following the end of the 30-day review period, the Agency shall revise the procurement plan as necessary based on the comments received and file the procurement plan with the Commission and post the procurement plan on the websites.

(3) Within 5 days after the filing of the procurement plan, any person objecting to the procurement plan shall file an objection with the Commission. Within 10 days after the filing, the Commission shall determine whether a hearing is necessary. The Commission shall enter its order confirming or modifying the procurement plan within 90 days after the filing of the procurement plan by the Illinois Power Agency.

(4) The Commission shall approve the procurement plan, including expressly the forecast used in the procurement plan, if the Commission determines that it will ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time, taking into account any benefits of price stability.

(e) The procurement process shall include each of the following components:

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

(2) Standard contract forms and credit terms and instruments. The procurement administrator, in consultation with the utilities, the Commission, and other interested parties and subject to Commission oversight, shall develop and provide standard contract forms for the supplier contracts that meet generally accepted industry practices. Standard credit terms and instruments that meet generally accepted industry practices shall be similarly developed. The procurement administrator shall make available to the Commission all written comments it receives on the contract forms, credit terms, or instruments. If the procurement administrator cannot reach agreement with the applicable electric utility as to the contract terms and conditions, the procurement administrator must notify the Commission of any disputed terms and the Commission shall resolve the dispute. The terms of the contracts shall not be subject to negotiation by winning bidders, and the bidders must agree to the terms of the contract in advance so that winning bids are selected solely on the basis of price.

(3) Establishment of a market-based price benchmark. As part of the development of the procurement process, the procurement administrator, in consultation with the Commission staff, Agency staff, and the procurement monitor, shall establish benchmarks for evaluating the final prices in the contracts for each of the products that will be procured through the procurement process. The benchmarks shall be based on price data for similar products for the same delivery period and same delivery hub, or other delivery hubs after adjusting for that difference. The price benchmarks may also be adjusted to take into account differences between the information reflected in the underlying data sources and the specific products and procurement process being used to procure power for the Illinois utilities. The benchmarks shall be confidential but shall be provided to, and will be subject to Commission review and approval, prior to a procurement event.

(4) Request for proposals competitive procurement process. The procurement administrator shall design and issue a request for proposals to supply electricity in accordance with each utility's procurement plan, as approved by the Commission. The request for proposals shall set forth a procedure for sealed, binding commitment bidding with pay-as-bid settlement, and provision for selection of bids on the basis of price.

(5) A plan for implementing contingencies in the event of supplier default or failure of the procurement process to fully meet the expected load requirement due to insufficient supplier participation, Commission rejection of results, or any other cause.

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

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

(iii) In all cases where there is insufficient supply provided under contracts awarded through the procurement process to fully meet the electric utility's load requirement, the utility shall meet the load requirement by procuring power and energy from the applicable regional transmission organization market, including ancillary services, capacity, and day-ahead or real time energy or both; provided, however, that if a needed product is not available through the regional transmission organization market it shall be purchased from the wholesale market.

(6) The procurement process described in this subsection is exempt from the requirements of the Illinois Procurement Code, pursuant to Section 20-10 of that Code.

(f) Within 2 business days after opening the sealed bids, the procurement administrator shall submit a confidential report to the Commission. The report shall contain the results of the bidding for each of the products along with the procurement administrator's recommendation for the acceptance and rejection of bids based on the price benchmark criteria and other factors observed in the process. The procurement monitor also shall submit a confidential report to the Commission within 2 business days after opening the sealed bids. The report shall contain the procurement monitor's assessment of bidder behavior in the process as well as an assessment of the procurement administrator's compliance with the procurement process and rules. The Commission shall review the confidential reports submitted by the procurement administrator and procurement monitor, and shall accept or reject the recommendations of the procurement administrator within 2 business days after receipt of the reports.

(g) Within 3 business days after the Commission decision approving the results of a procurement event, the utility shall enter into binding contractual arrangements with the winning suppliers using the standard form contracts; except that the utility shall not be required either directly or indirectly to execute the contracts if a tariff that is consistent with subsection (l) of this Section has not been approved and placed into effect for that utility.

(h) The names of the successful bidders and the load weighted average of the winning bid prices for each contract type and for each contract term shall be made available to the public at the time of Commission approval of a procurement event. The Commission, the procurement monitor, the procurement administrator, the Illinois Power Agency, and all participants in the procurement process shall maintain the confidentiality of all other supplier and bidding information in a manner consistent with all applicable laws, rules, regulations, and tariffs. Confidential information, including the confidential reports submitted by the procurement administrator and procurement monitor pursuant to subsection (f) of this Section, shall not be made publicly available and shall not be discoverable by any party in any proceeding, absent a compelling demonstration of need, nor shall those reports be admissible in any proceeding other than one for law enforcement purposes.

(i) Within 2 business days after a Commission decision approving the results of a procurement event or such other date as may be required by the Commission from time to time, the utility shall file for informational purposes with the Commission its actual or estimated retail supply charges, as applicable, by customer supply group reflecting the costs associated with the procurement and computed in accordance with the tariffs filed pursuant to subsection (l) of this Section and approved by the Commission.

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

(i) Within 14 days following filing of the initial procurement plan, any person may file a detailed objection with the Commission contesting the procurement plan submitted by the electric utility. All objections to the electric utility's plan shall be specific, supported by data or other detailed analyses. The electric utility may file a response to any objections to its procurement plan within 7 days after the date objections are due to be filed. Within 7 days after the date the utility's response is due, the Commission shall determine whether a hearing is necessary. If it determines that a hearing is necessary, it shall require the hearing to be completed and issue an order on the procurement plan within 60 days after the filing of the procurement plan by the electric utility.

(ii) The order shall approve or modify the procurement plan, approve an independent procurement administrator, and approve or modify the electric utility's tariffs that are proposed with the initial procurement plan. The Commission shall approve the procurement plan if the Commission determines that it will ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time, taking into account any benefits of price stability.

(k) In order to promote price stability for residential and small commercial customers during the transition to competition in Illinois, and notwithstanding any other provision of this Act, each electric utility subject to this Section shall enter into one or more multi-year financial swap contracts that become effective on the effective date of this amendatory Act. These contracts may be executed with generators and power marketers, including affiliated interests of the electric utility. These contracts shall be for a term of no more than 5 years and shall, for each respective utility or for any Illinois electric utilities that are affiliated by virtue of a common parent company and that are thereby considered a single electric utility for purposes of this subsection (k), not exceed in the aggregate 3,000 megawatts for any hour of the year. The contracts shall be financial contracts and not energy sales contracts. The contracts shall be executed as transactions under a negotiated master agreement based on the form of master agreement for financial swap contracts sponsored by the International Swaps and Derivatives Association, Inc. and shall be considered pre-existing contracts in the utilities' procurement plans for residential and small commercial customers. Costs incurred pursuant to a contract authorized by this subsection (k) shall be deemed prudently incurred and reasonable in amount and the electric utility shall be entitled to full cost recovery pursuant to the tariffs filed with the Commission.

(k-5) In order to promote price stability for residential and small commercial customers during the infrastructure investment program described in subsection (b) of Section 16-108.5 of this Act, and notwithstanding any other provision of this Act or the Illinois Power Agency Act, for each electric utility that serves more than one million retail customers in Illinois, the Illinois Power Agency shall conduct a procurement event within 120 days after October 26, 2011 (the effective date of Public Act 97-616) and may procure contracts for energy and renewable energy credits for the period June 1, 2013 through December 31, 2017 that satisfy the requirements of this subsection (k-5), including the benchmarks described in this subsection. These contracts shall be entered into as the result of a competitive procurement event, and, to the extent that any provisions of this Section or the Illinois Power Agency Act do not conflict with this subsection (k-5), such provisions shall apply to the procurement event. The energy contracts shall be for 24 hour by 7 day supply over a term that runs from the first delivery year through December 31, 2017. For a utility that serves over 2 million customers, the energy contracts shall be multi-year with pricing escalating at 2.5% per annum. The energy contracts may be designed as financial swaps or may require physical delivery.

Within 30 days of October 26, 2011 (the effective date of Public Act 97-616), each such utility shall submit to the Agency updated load forecasts for the period June 1, 2013 through December 31, 2017. The megawatt volume of the contracts shall be based on the updated load forecasts of the minimum monthly on-peak or off-peak average load requirements shown in the forecasts, taking into account any existing energy contracts in effect as well as the expected migration of the utility's customers to alternative retail electric suppliers. The renewable energy credit volume shall be based on the number of credits that would satisfy the requirements of subsection (c) of Section 1-75 of the Illinois Power Agency Act, subject to the rate impact caps and other provisions of subsection (c) of Section 1-75 of the Illinois Power Agency Act. The evaluation of contract bids in the competitive procurement events for energy and for renewable energy credits shall incorporate price benchmarks set collaboratively by the Agency, the procurement administrator, the staff of the Commission, and the procurement monitor. If the contracts are swap contracts, then they shall be executed as transactions under a negotiated master agreement based on the form of master agreement for financial swap contracts sponsored by the International Swaps and Derivatives Association, Inc. Costs incurred pursuant to a contract authorized by this subsection (k-5) shall be deemed prudently incurred and reasonable in amount and the electric utility shall be entitled to full cost recovery pursuant to the tariffs filed with the Commission.

The cost of administering the procurement event described in this subsection (k-5) shall be paid by the winning supplier or suppliers to the procurement administrator through a supplier fee. In the event that there is no winning supplier for a particular utility, such utility will pay the procurement administrator for the costs associated with the procurement event, and those costs shall not be a recoverable expense. Nothing in this subsection (k-5) is intended to alter the recovery of costs for any other procurement event.

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

(m) The Commission has the authority to adopt rules to carry out the provisions of this Section. For the public interest, safety, and welfare, the Commission also has authority to adopt rules to carry out the provisions of this Section on an emergency basis immediately following the effective date of this amendatory Act.

(n) Notwithstanding any other provision of this Act, any affiliated electric utilities that submit a single procurement plan covering their combined needs may procure for those combined needs in conjunction with that plan, and may enter jointly into power supply contracts, purchases, and other procurement arrangements, and allocate capacity and energy and cost responsibility therefor among themselves in proportion to their requirements.

(o) On or before June 1 of each year, the Commission shall hold an informal hearing for the purpose of receiving comments on the prior year's procurement process and any recommendations for change.

(p) An electric utility subject to this Section may propose to invest, lease, own, or operate an electric generation facility as part of its procurement plan, provided the utility demonstrates that such facility is the least-cost option to provide electric service to eligible retail customers. If the facility is shown to be the least-cost option and is included in a procurement plan prepared in accordance with Section 1-75 of the Illinois Power Agency Act and this Section, then the electric utility shall make a filing pursuant to Section 8-406 of this Act, and may request of the Commission any statutory relief required thereunder. If the Commission grants all of the necessary approvals for the proposed facility, such supply shall thereafter be considered as a pre-existing contract under subsection (b) of this Section. The Commission shall in any order approving a proposal under this subsection specify how the utility will recover the prudently incurred costs of investing in, leasing, owning, or operating such generation facility through just and reasonable rates charged to eligible retail customers. Cost recovery for facilities included in the utility's procurement plan pursuant to this subsection shall not be subject to review under or in any way limited by the provisions of Section 16-111(i) of this Act. Nothing in this Section is intended to prohibit a utility from filing for a fuel adjustment clause as is otherwise permitted under Section 9-220 of this Act.

(Source: P.A. 97-325, eff. 8-12-11; 97-616, eff. 10-26-11; 97-813, eff. 7-13-12.)

(220 ILCS 5/16-111.5B)

Sec. 16-111.5B. Provisions relating to energy efficiency procurement.

(a) Procurement Beginning in 2012, procurement plans prepared and filed pursuant to Section 16-111.5 of this Act during the years 2012 through 2014 shall be subject to the following additional requirements:

(1) The analysis included pursuant to paragraph (2) of subsection (b) of Section 16-111.5 shall also include the impact of energy efficiency building codes or appliance standards, both current and projected.

(2) The procurement plan components described in subsection (b) of Section 16-111.5 shall also include an assessment of opportunities to expand the programs promoting energy efficiency measures that have been offered under plans approved pursuant to Section 8-103 of this Act or to implement additional cost-effective energy efficiency programs or measures.

(3) In addition to the information provided pursuant to paragraph (1) of subsection (d) of Section 16-111.5 of this Act, each Illinois utility procuring power pursuant to that Section shall annually provide to the Illinois Power Agency by July 15 of each year, or such other date as may be required by the Commission or Agency, an assessment of cost-effective energy efficiency programs or measures that could be included in the procurement plan. The assessment shall include the following:

(A) A comprehensive energy efficiency potential study for the utility's service territory that was completed within the past 3 years.

(B) Beginning in 2014, the most recent analysis submitted pursuant to Section 8-103A of this Act and approved by the Commission under subsection (g) (f) of Section 8-103 of this Act.

(C) Identification of new or expanded cost-effective energy efficiency programs or measures that are incremental to those included in energy efficiency and demand-response plans approved by the Commission pursuant to Section 8-103 of this Act and that would be offered to all retail customers whose electric service has not been declared competitive under Section 16-113 of this Act and who are eligible to purchase power and energy from the utility under fixed-price bundled service tariffs, regardless of whether such customers actually do purchase such power and energy from the utility.

(D) Analysis showing that the new or expanded cost-effective energy efficiency programs or measures would lead to a reduction in the overall cost of electric service.

(E) Analysis of how the cost of procuring additional cost-effective energy efficiency measures compares over the life of the measures to the prevailing cost of comparable supply.

(F) An energy savings goal, expressed in megawatt-hours, for the year in which the measures will be implemented.

(G) For each expanded or new program, the estimated amount that the program may reduce the agency's need to procure supply.

In preparing such assessments, a utility shall conduct an annual solicitation process for purposes of requesting proposals from third-party vendors, the results of which shall be provided to the Agency as part of the assessment, including documentation of all bids received. The utility shall develop requests for proposals consistent with the manner in which it develops requests for proposals under plans approved pursuant to Section 8-103 of this Act, which considers input from the Agency and interested stakeholders.

(4) The Illinois Power Agency shall include in the procurement plan prepared pursuant to paragraph (2) of subsection (d) of Section 16-111.5 of this Act energy efficiency programs and measures it determines are cost-effective and the associated annual energy savings goal included in the annual solicitation process and assessment submitted pursuant to paragraph (3) of this subsection (a).

(5) Pursuant to paragraph (4) of subsection (d) of Section 16-111.5 of this Act, the Commission shall also approve the energy efficiency programs and measures included in the procurement plan, including the annual energy savings goal, if the Commission determines they fully capture the potential for all achievable cost-effective savings, to the extent practicable, and otherwise satisfy the requirements of Section 8-103 of this Act.

In the event the Commission approves the procurement of additional energy efficiency, it shall reduce the amount of power to be procured under the procurement plan to reflect the additional energy efficiency and shall direct the utility to undertake the procurement of such energy efficiency, which shall not be subject to the requirements of subsection (e) of Section 16-111.5 of this Act. The utility shall consider input from the Agency and interested stakeholders on the procurement and administration process. The requirements set forth in paragraphs (1) through (5) of this subsection (a) shall terminate after the filing of the procurement plan in 2014, and no energy efficiency shall be procured by the Agency thereafter. Energy efficiency programs approved previously pursuant to this Section shall terminate no later than December 31, 2017.

(6) An electric utility shall recover its costs incurred under this Section related to the implementation of energy efficiency programs and measures approved by the Commission in its order approving the procurement plan under Section 16-111.5 of this Act, including, but not limited to, all costs associated with complying with this Section and all start-up and administrative costs and the costs for any evaluation, measurement, and verification of the measures, from all retail customers whose electric service has not been declared competitive under Section 16-113 of this Act and who are eligible to purchase power and energy from the utility under fixed-price bundled service tariffs, regardless of whether such customers actually do purchase such power and energy from the utility through the automatic adjustment clause tariff established pursuant to Section 8-103 of this Act, provided, however, that the limitations described in subsection (d) of that Section shall not apply to the costs incurred pursuant to this Section or Section 16-111.7 of this Act.

(b) For purposes of this Section, the term "energy efficiency" shall have the meaning set forth in Section 1-10 of the Illinois Power Agency Act, and the term "cost-effective" shall have the meaning set forth in subsection (a) of Section 8-103 of this Act.

(Source: P.A. 97-616, eff. 10-26-11; 97-824, eff. 7-18-12.)

(220 ILCS 5/16-115D)

Sec. 16-115D. Renewable portfolio standard for alternative retail electric suppliers and electric utilities operating outside their service territories.

(a) An alternative retail electric supplier shall be responsible for procuring cost-effective renewable energy resources as required under item (5) of subsection (d) of Section 16-115 of this Act as outlined herein:

(1) The definition of renewable energy resources contained in Section 1-10 of the Illinois Power Agency Act applies to all renewable energy resources required to be procured by alternative retail electric suppliers.

(2) The quantity of renewable energy resources shall be measured as a percentage of the actual amount of metered electricity (megawatt-hours) delivered by the alternative retail electric supplier to Illinois retail customers during the 12-month period June 1 through May 31, commencing June 1, 2009, and the comparable 12-month period in each year thereafter except as provided in item (6) of this subsection (a).

(3) The quantity of renewable energy resources shall be in amounts at least equal to the annual percentages set forth in item (1) of subsection (c) of Section 1-75 of the Illinois Power Agency Act. At least 60% of the renewable energy resources procured pursuant to items (1) through (3) of subsection (b) of this Section shall come from wind generation and, starting June 1, 2015, at least 6% of the renewable energy resources procured pursuant to items (1) through (3) of subsection (b) of this Section shall come from solar photovoltaics. If, in any given year, an alternative retail electric supplier does not purchase at least these levels of renewable energy resources, then the alternative retail electric supplier shall make alternative compliance payments, as described in subsection (d) of this Section.

(4) The quantity and source of renewable energy resources shall be independently verified through the PJM Environmental Information System Generation Attribute Tracking System (PJM-GATS) or the Midwest Renewable Energy Tracking System (M-RETS), which shall document the location of generation, resource type, month, and year of generation for all qualifying renewable energy resources that an alternative retail electric supplier uses to comply with this Section. No later than June 1, 2009, the Illinois Power Agency shall provide PJM-GATS, M-RETS, and alternative retail electric suppliers with all information necessary to identify resources located in Illinois, within states that adjoin Illinois or within portions of the PJM and MISO footprint in the United States that qualify under the definition of renewable energy resources in Section 1-10 of the Illinois Power Agency Act for compliance with this Section 16-115D. Alternative retail electric suppliers shall not be subject to the requirements in item (3) of subsection (c) of Section 1-75 of the Illinois Power Agency Act.

(5) All renewable energy credits used to comply with this Section shall be permanently retired.

(6) The required procurement of renewable energy resources by an alternative retail electric supplier shall apply to all metered electricity delivered to Illinois retail customers by the alternative retail electric supplier pursuant to contracts executed or extended after March 15, 2009.

(b) Compliance obligations.

(1) (b) An alternative retail electric supplier shall comply with the renewable energy portfolio standards by making an alternative compliance payment, as described in subsection (d) of this Section, to cover:

(A) at least one-half of the alternative retail electric supplier's compliance obligation for the period prior to May 31, 2016; and

(B) beginning on June 1, 2016, at least 75% of the alternative retail electric suppliers' compliance obligation with respect to its metered electricity supplied to its Illinois retail customers in customer classes that, as of January 1, 2015, have not been declared competitive pursuant to Section 16-113 of this Act; however, for contracts with or on behalf of such retail customers, entered into or extended prior to the effective date of this amendatory Act of the 99th General Assembly, but in no event extended beyond May 31, 2017, the alternative retail electric supplier shall meet at least 50% of its compliance obligation with respect to such retail customers by making an alternative compliance payment.

(2) Beginning on June 1, 2016, an alternative retail electric supplier need not make any alternative compliance payment to meet any portion of its compliance obligation, as set forth in paragraph (3) of subsection (a) of this Section, with respect to its metered electricity supplied to its Illinois retail customers, but only with respect to those retail customer classes that, as of January 1, 2015, have been declared competitive pursuant to Section 16-113 of this Act, unless it chooses to meet its compliance obligation under paragraph (2) of this subsection through such payment.

(3) An alternative retail electric supplier shall use any one or combination of the following means to cover the remainder of the alternative retail electric supplier's compliance obligation, as set forth in paragraph (3) of subsection (a) of this Section, not covered by an alternative compliance payment made under paragraphs (1) and (2) of this subsection (b):

(A) (1) Generating electricity using renewable energy resources identified pursuant to item (4) of subsection (a) of this Section.

(B) (2) Purchasing electricity generated using renewable energy resources identified pursuant to item (4) of subsection (a) of this Section through an energy contract.

(C) (3) Purchasing renewable energy credits from renewable energy resources identified pursuant to item (4) of subsection (a) of this Section.

(D) (4) Making an alternative compliance payment as described in subsection (d) of this Section.

(c) Use of renewable energy credits.

(1) Renewable energy credits that are not used by an alternative retail electric supplier to comply with a renewable portfolio standard in a compliance year may be banked and carried forward up to 2 12-month compliance periods after the compliance period in which the credit was generated for the purpose of complying with a renewable portfolio standard in those 2 subsequent compliance periods. For the 2009-2010 and 2010-2011 compliance periods, an alternative retail electric supplier may use renewable credits generated after December 31, 2008 and before June 1, 2009 to comply with this Section.

(2) An alternative retail electric supplier is responsible for demonstrating that a renewable energy credit used to comply with a renewable portfolio standard is derived from a renewable energy resource and that the alternative retail electric supplier has not used, traded, sold, or otherwise transferred the credit.

(3) The same renewable energy credit may be used by an alternative retail electric supplier to comply with a federal renewable portfolio standard and a renewable portfolio standard established under this Act. An alternative retail electric supplier that uses a renewable energy credit to comply with a renewable portfolio standard imposed by any other state may not use the same credit to comply with a renewable portfolio standard established under this Act.

(d) Alternative compliance payments.

(1) The Commission shall establish and post on its website, within 5 business days after entering an order approving a procurement plan pursuant to Section 1-75 of the Illinois Power Agency Act, maximum alternative compliance payment rates, expressed on a per kilowatt-hour basis, that will be applicable in the first compliance period following the plan approval. A separate maximum alternative compliance payment rate shall be established for the service territory of each electric utility that is subject to subsection (c) of Section 1-75 of the Illinois Power Agency Act. Each maximum alternative compliance payment rate shall be equal to the maximum allowable annual estimated average net increase due to the costs of the utility's purchase of renewable energy resources included in the amounts paid by eligible retail customers in connection with electric service, as described in item (2) of subsection (c) of Section 1-75 of the Illinois Power Agency Act for the compliance period, and as established in the approved procurement plan. Following each procurement event through which renewable energy resources are purchased for one or more of these utilities for the compliance period, the Commission shall establish and post on its website estimates of the alternative compliance payment rates, expressed on a per kilowatt-hour basis, that shall apply for that compliance period. Posting of the estimates shall occur no later than 10 business days following the procurement event, however, the Commission shall not be required to establish and post such estimates more often than once per calendar month. By July 1 of each year, the Commission shall establish and post on its website the actual alternative compliance payment rates for the preceding compliance year. The Commission shall make available to alternative retail electric suppliers subject to this Section the average cost and quantity for the compliance year, the estimated average cost for each subsequent compliance year, and the anticipated quantity for each subsequent compliance year for the duration of such executed renewable energy contracts which will impact the alternative compliance payment. For compliance years beginning prior to June 1, 2014, each alternative compliance payment rate shall be equal to the total amount of dollars that the utility contracted to spend on renewable resources, excepting the additional incremental cost attributable to solar resources, for the compliance period divided by the forecasted load of eligible retail customers, at the customers' meters, as previously established in the Commission-approved procurement plan for that compliance year. For compliance years commencing on or after June 1, 2014, each alternative compliance payment rate shall be equal to the total amount of dollars that the utility contracted to spend on all renewable resources for the compliance period divided by the forecasted load of eligible retail customers, at the customers' meters, as previously established in the Commission-approved procurement plan for that compliance year. The actual alternative compliance payment rates may not exceed the maximum alternative compliance payment rates established for the compliance period. For purposes of this subsection (d), the term "eligible retail customers" has the same meaning as found in Section 16-111.5 of this Act.

(2) In any given compliance year, an alternative retail electric supplier may elect to use alternative compliance payments to comply with all or a part of the applicable renewable portfolio standard. In the event that an alternative retail electric supplier elects to make alternative compliance payments to comply with all or a part of the applicable renewable portfolio standard, such payments shall be made by September 1, 2010 for the period of June 1, 2009 to May 1, 2010 and by September 1 of each year thereafter for the subsequent compliance period, in the manner and form as determined by the Commission. Any election by an alternative retail electric supplier to use alternative compliance payments is subject to review by the Commission under subsection (e) of this Section.

(3) An alternative retail electric supplier's alternative compliance payments shall be computed separately for each electric utility's service territory within which the alternative retail electric supplier provided retail service during the compliance period, provided that the electric utility was subject to subsection (c) of Section 1-75 of the Illinois Power Agency Act. For each service territory, the alternative retail electric supplier's alternative compliance payment shall be equal to (i) the actual alternative compliance payment rate established in item (1) of this subsection (d), multiplied by (ii) the actual amount of metered electricity delivered by the alternative retail electric supplier to retail customers within the service territory during the compliance period, multiplied by (iii) the result of one minus the ratios of the quantity of renewable energy resources used by the alternative retail electric supplier to comply with the requirements of this Section within the service territory to the product of the percentage of renewable energy resources required under item (3) of subsection (a) of this Section and the actual amount of metered electricity delivered by the alternative retail electric supplier to retail customers within the service territory during the compliance period.

(4) All alternative compliance payments by alternative retail electric suppliers shall be deposited in the Illinois Power Agency Renewable Energy Resources Fund and used to purchase renewable energy credits, in accordance with Section 1-56 of the Illinois Power Agency Act. Beginning April 1, 2012 and by April 1 of each year thereafter, the Illinois Power Agency shall submit an annual report to the General Assembly, the Commission, and alternative retail electric suppliers that shall include, but not be limited to:

(A) the total amount of alternative compliance payments received in aggregate from alternative retail electric suppliers by planning year for all previous planning years in which the alternative compliance payment was in effect;

(B) the amount of those payments utilized to purchased renewable energy credits itemized by the date of each procurement in which the payments were utilized; and

(C) the unused and remaining balance in the Agency Renewable Energy Resources Fund attributable to those payments.

(5) The Commission, in consultation with the Illinois Power Agency, shall establish a process or proceeding to consider the impact of a federal renewable portfolio standard, if enacted, on the operation of the alternative compliance mechanism, which shall include, but not be limited to, developing, to the extent permitted by the applicable federal statute, an appropriate methodology to apportion renewable energy credits retired as a result of alternative compliance payments made in accordance with this Section. The Commission shall commence any such process or proceeding within 35 days after enactment of a federal renewable portfolio standard.

(e) Each alternative retail electric supplier shall, by September 1, 2010 and by September 1 of each year thereafter, prepare and submit to the Commission a report, in a format to be specified by the Commission on or before December 31, 2009, that provides information certifying:

(1) compliance by the alternative retail electric supplier with this Section, including copies of all PJM-GATS and M-RETS reports; , and

(2) documentation relating to banking, and retiring renewable energy credits; ,

(3) the type and the amounts of renewable energy credits the alternative retail electric supplier is using to satisfy the alternative retail electric supplier's compliance obligation for the applicable compliance year;

(4) the states in which the facilities supplying the renewable energy credits purchased by the alternative retail electric supplier to satisfy the alternative retail electric supplier's compliance obligation for the applicable compliance year are located;

(5) the vintage of all renewable energy credits purchased by the alternative retail electric supplier;

(6) the percent, if any, of the alternative retail electric supplier's compliance obligation that it intends to meet through making an alternative compliance payment pursuant to subsection (b) of this Section; and

(7) any other information that the Commission determines necessary to ensure compliance with this Section.

However, the information required by paragraphs (3) through (6) of this subsection (e) shall not be required to be included in reports submitted on or before September 1, 2017.

An alternative retail electric supplier may file commercially or financially sensitive information or trade secrets with the Commission as provided under the rules of the Commission. To be filed confidentially, the information shall be accompanied by an affidavit that sets forth both the reasons for the confidentiality and a public synopsis of the information.

The Commission shall provide an analysis of the information provided by the alternative retail electric suppliers pursuant to this subsection (e) and a description of the manner in which alternative retail electric suppliers have met their obligations. The information in the Commission's annual report shall be presented in a way that protects the confidentiality of the information provided by the alternative retail electric suppliers. The Commission's annual report shall be posted on its website and cover the period from June 1, 2016 through May 31, 2017 and each annual period thereafter.

(f) The Commission may initiate a contested case to review allegations that the alternative retail electric supplier has violated this Section, including an order issued or rule promulgated under this Section. In any such proceeding, the alternative retail electric supplier shall have the burden of proof. If the Commission finds, after notice and hearing, that an alternative retail electric supplier has violated this Section, then the Commission shall issue an order requiring the alternative retail electric supplier to:

(1) immediately comply with this Section; and

(2) if the violation involves a failure to procure the requisite quantity of renewable energy resources or pay the applicable alternative compliance payment by the annual deadline, the Commission shall require the alternative retail electric supplier to double the applicable alternative compliance payment that would otherwise be required to bring the alternative retail electric supplier into compliance with this Section.

If an alternative retail electric supplier fails to comply with the renewable energy resource portfolio requirement in this Section more than once in a 5-year period, then the Commission shall revoke the alternative electric supplier's certificate of service authority. The Commission shall not accept an application for a certificate of service authority from an alternative retail electric supplier that has lost certification under this subsection (f), or any corporate affiliate thereof, for at least one year after the date of revocation.

(g) All of the provisions of this Section apply to electric utilities operating outside their service area except under item (2) of subsection (a) of this Section the quantity of renewable energy resources shall be measured as a percentage of the actual amount of electricity (megawatt-hours) supplied in the State outside of the utility's service territory during the 12-month period June 1 through May 31, commencing June 1, 2009, and the comparable 12-month period in each year thereafter except as provided in item (6) of subsection (a) of this Section.

If any such utility fails to procure the requisite quantity of renewable energy resources by the annual deadline, then the Commission shall require the utility to double the alternative compliance payment that would otherwise be required to bring the utility into compliance with this Section.

If any such utility fails to comply with the renewable energy resource portfolio requirement in this Section more than once in a 5-year period, then the Commission shall order the utility to cease all sales outside of the utility's service territory for a period of at least one year.

(h) The provisions of this Section and the provisions of subsection (d) of Section 16-115 of this Act relating to procurement of renewable energy resources shall not apply to an alternative retail electric supplier that operates a combined heat and power system in this State or that has a corporate affiliate that operates such a combined heat and power system in this State that supplies electricity primarily to or for the benefit of: (i) facilities owned by the supplier, its subsidiary, or other corporate affiliate; (ii) facilities electrically integrated with the electrical system of facilities owned by the supplier, its subsidiary, or other corporate affiliate; or (iii) facilities that are adjacent to the site on which the combined heat and power system is located.

(Source: P.A. 96-33, eff. 7-10-09; 96-159, eff. 8-10-09; 96-1437, eff. 8-17-10; 97-658, eff. 1-13-12.)

Section 97. Severability. The provisions of this Act are severable under Section 1.31 of the Statute on Statutes.

Section 99. Effective date. This Act takes effect upon becoming law, except that Section 16-107.6 of the Public Utilities Act takes effect January 1, 2018.".