HB2607 99TH GENERAL ASSEMBLY

LRB099 06217 AMC 30868 b

99TH GENERAL ASSEMBLY
State of Illinois
2015 and 2016
HB2607

Introduced , by Rep. Elaine Nekritz

SYNOPSIS AS INTRODUCED:

See Index

Amends the Illinois Power Agency Act. Requires the Planning and Procurement Bureau to establish a long-term renewable resources procurement plan that includes all renewable energy credits necessary to meet specified goals (replacing the current renewable portfolio standards). Sets forth guidelines for what shall be included in the procurement plan. Makes changes to provisions concerning definitions, the powers of the Agency, the Illinois Power Agency Renewable Energy Resources Fund, and the duties of the Planning and Procurement Bureau. Amends the Public Utilities Act. Makes changes concerning nondiscrimination, energy efficiency and demand-response measures, natural gas efficiency programs, real-time pricing, infrastructure investment and modernization, the Illinois Smart Grid test bed, and on-bill financing programs for electric and gas utilities. Adds provisions related to renewable energy credit procurement. Amends the Environmental Protection Act. Provides that upon promulgation by the U.S. Environmental Protection Agency of a final rule regulating carbon dioxide emissions from existing electric generating units, the Illinois Environmental Protection Agency shall be authorized to implement a cap and invest program or similar market mechanism to regulate carbon dioxide emissions. Makes other changes. Effective immediately.

FISCAL NOTE ACT MAY APPLY

A BILL FOR

AN ACT concerning regulation.

Be it enacted by the People of the State of Illinois, represented in the General Assembly:

Section 5. The Illinois Power Agency Act is amended by changing Sections 1-5, 1-10, 1-20, 1-56, and 1-75 as follows:

(20 ILCS 3855/1-5)

Sec. 1-5. Legislative declarations and findings. The General Assembly finds and declares:

(1) The health, welfare, and prosperity of all Illinois citizens require the provision of adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time, taking into account any benefits of price stability.

(2) The transition to retail competition is not complete. Some customers, especially residential and small commercial customers, have failed to benefit from lower electricity costs from retail and wholesale competition.

(3) Escalating prices for electricity in Illinois pose a serious threat to the economic well-being, health, and safety of the residents of and the commerce and industry of the State.

(4) To protect against this threat to economic well-being, health, and safety it is necessary to improve the process of procuring electricity to serve Illinois residents, to promote investment in energy efficiency and demand-response measures, and to support development of clean coal technologies and renewable resources.

(5) Procuring a diverse electricity supply portfolio will ensure the lowest total cost over time for adequate, reliable, efficient, and environmentally sustainable electric service.

(6) Including cost-effective renewable resources in that portfolio will reduce long-term direct and indirect costs to consumers by decreasing environmental impacts and by avoiding or delaying the need for new generation, transmission, and distribution infrastructure.

(7) Energy efficiency, demand-response measures, and renewable energy are resources currently underused in Illinois. These and other demand-side resources should be used when cost-effective to reduce costs to consumers and encourage job creation.

(8) The State should encourage the use of advanced clean coal technologies that capture and sequester carbon dioxide emissions to advance environmental protection goals and to demonstrate the viability of coal and coal-derived fuels in a carbon-constrained economy.

(9) The General Assembly enacted Public Act 96-0795 to reform the State's purchasing processes, recognizing that government procurement is susceptible to abuse if structural and procedural safeguards are not in place to ensure independence, insulation, oversight, and transparency.

(10) The principles that underlie the procurement reform legislation apply also in the context of power purchasing.

The General Assembly therefore finds that it is necessary to create the Illinois Power Agency and that the goals and objectives of that Agency are to accomplish each of the following:

(A) Develop electricity procurement plans to ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time, taking into account any benefits of price stability, for electric utilities that on December 31, 2005 provided electric service to at least 100,000 customers in Illinois and for small multi-jurisdictional electric utilities that (i) on December 31, 2005 served less than 100,000 customers in Illinois and (ii) request a procurement plan for their Illinois jurisdictional load. The procurement plan shall be updated on an annual basis and shall include renewable energy resources sufficient to achieve the standards specified in this Act.

(B) Conduct competitive procurement processes to procure the supply resources identified in the procurement plan.

(C) Develop electric generation and co-generation facilities that use indigenous coal or renewable resources, or both, financed with bonds issued by the Illinois Finance Authority.

(D) Supply electricity from the Agency's facilities at cost to one or more of the following: municipal electric systems, governmental aggregators, or rural electric cooperatives in Illinois.

(E) Ensure that the process of power procurement is conducted in an ethical and transparent fashion, immune from improper influence.

(F) Continue to review its policies and practices to determine how best to meet its mission of providing the lowest cost power to the greatest number of people, at any given point in time, in accordance with applicable law.

(G) Operate in a structurally insulated, independent, and transparent fashion so that nothing impedes the Agency's mission to secure power at the best prices the market will bear, provided that the Agency meets all applicable legal requirements.

(Source: P.A. 97-325, eff. 8-12-11; 97-618, eff. 10-26-11; 97-813, eff. 7-13-12.)

(20 ILCS 3855/1-10)

Sec. 1-10. Definitions.

"Agency" means the Illinois Power Agency.

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

"Authority" means the Illinois Finance Authority.

"Brownfield solar project" means an electric generating facility that:

(1) generates electricity using photovoltaic cells;

(2) is interconnected at the distribution system level of either an electric utility as defined in this Section, 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; and

(3) is located on a site that is 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;

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

(iv) the Illinois Environmental Protection Agency under the Illinois Solid Waste Program.

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

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

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

"Commission" means the Illinois Commerce Commission.

"Community solar project" means an electric generating facility that:

(1) generates electricity using photovoltaic cells;

(2) is interconnected at the distribution system level of an electric utility as defined in this Section;

(3) credits the value of electricity generated by the facility to the subscribers of the facility; and

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

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

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

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

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

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

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

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

"Delivery year" means the year beginning June 1 of the year referenced and ending May 31 of the following year.

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

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

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

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

(1) powered by wind, solar thermal energy, photovoltaic cells 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" also includes measures that reduce the total Btus of electricity and natural gas 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.

"Nameplate capacity" means the aggregate inverter nameplate capacity in kilowatts AC.

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

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

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

"Renewable energy credit" means a tradable credit that represents the environmental attributes of one megawatt hour a certain amount of energy produced from a renewable energy generating facility 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.

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

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

"Standard wholesale product" means any type of product that is routinely traded in a liquid regional wholesale market, including, but not limited to, energy or demand-side resources.

"Subscriber" means any customer that takes delivery service from an electric utility who owns one or more subscriptions to a community solar project and who has identified an individual billing meter within the same electric utility service territory as the community solar project is located to which each subscription shall be attributed. Each subscriber to a single community solar project must have a separate legal or corporate identity, and no subscriber's subscriptions may total more than 40% of an individual community solar project.

"Subscription" means a percentage interest in a community solar project. Each subscription shall represent a percentage of the community solar project's generating capacity, provided that the subscription is intended to primarily offset part or all of the subscriber's electricity usage.

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

"Total resource cost test" or "TRC test" means a standard that is met if, for an investment in energy efficiency or demand-response measures, the benefit-cost ratio is greater than one. The benefit-cost ratio is the ratio of the net present value of the total benefits of the program to the net present value of the total costs as calculated over the lifetime of the measures. A total resource cost test compares the sum of avoided electric utility costs, representing the benefits that accrue to the system and the participant in the delivery of those efficiency measures, including avoided energy costs, avoided generating capacity costs, avoided transmission and distribution system investments and price suppression effects, as well as other quantifiable societal benefits, including avoided natural gas utility costs, other avoided energy costs, and reasonable estimates of non-energy benefits, such as the health, safety, comfort, operation and maintenance, business productivity, and financial security benefits to low-income and moderate-income customers of efficiency investments, to the sum of all incremental costs of end-use measures that are implemented due to the program (including both utility and participant contributions), plus costs to administer, deliver, and evaluate each demand-side program, to quantify the net savings obtained by substituting the demand-side program for supply resources. In calculating avoided costs of power and energy that an electric utility would otherwise have had to acquire, reasonable estimates shall be included of financial costs likely to be imposed by future regulations and legislation on emissions of greenhouse gases. In discounting future costs and benefits for the purpose of computing net present values, a societal discount rate based on real, long-term Treasury bond yields or other appropriate indictors should be used.

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

(20 ILCS 3855/1-20)

Sec. 1-20. General powers of the Agency.

(a) The Agency is authorized to do each of the following:

(1) Develop electricity procurement plans to ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time, taking into account any benefits of price stability, for electric utilities that on December 31, 2005 provided electric service to at least 100,000 customers in Illinois and for small multi-jurisdictional electric utilities that (A) on December 31, 2005 served less than 100,000 customers in Illinois and (B) request a procurement plan for their Illinois jurisdictional load. The electricity procurement plans shall be updated on an annual basis and shall, until May 31, 2016, include electricity generated from renewable resources sufficient to achieve the standards specified in this Act and shall include energy efficiency and demand response resources identified under Sections 16-108.5, 16-111.5, and 16-111.5B of the Public Utilities Act.

(1.5) Beginning with the planning process for the plan or plans to be implemented in the 2016 delivery year, develop a long-term renewable resources procurement plan in accordance with subdivision (c) of Section 1-75 of this Act for renewable energy credits in amounts sufficient to achieve the standards specified in this Act for all customers taking delivery service from an electric utility.

(2) Conduct competitive procurement processes to procure the supply resources identified in the electricity procurement plan, pursuant to Section 16-111.5 of the Public Utilities Act.

Beginning with the 2016 delivery year, conduct competitive procurement processes and implement programs to procure renewable energy credits identified in the long-term renewable resources procurement plan developed pursuant to subdivision (c) of Section 1-75 of this Act and procured pursuant to Section 16-111.5C of the Public Utilities Act.

(3) Develop electric generation and co-generation facilities that use indigenous coal or renewable resources, or both, financed with bonds issued by the Illinois Finance Authority.

(4) Supply electricity from the Agency's facilities at cost to one or more of the following: municipal electric systems, governmental aggregators, or rural electric cooperatives in Illinois.

(b) Except as otherwise limited by this Act, the Agency has all of the powers necessary or convenient to carry out the purposes and provisions of this Act, including without limitation, each of the following:

(1) To have a corporate seal, and to alter that seal at pleasure, and to use it by causing it or a facsimile to be affixed or impressed or reproduced in any other manner.

(2) To use the services of the Illinois Finance Authority necessary to carry out the Agency's purposes.

(3) To negotiate and enter into loan agreements and other agreements with the Illinois Finance Authority.

(4) To obtain and employ personnel and hire consultants that are necessary to fulfill the Agency's purposes, and to make expenditures for that purpose within the appropriations for that purpose.

(5) To purchase, receive, take by grant, gift, devise, bequest, or otherwise, lease, or otherwise acquire, own, hold, improve, employ, use, and otherwise deal in and with, real or personal property whether tangible or intangible, or any interest therein, within the State.

(6) To acquire real or personal property, whether tangible or intangible, including without limitation property rights, interests in property, franchises, obligations, contracts, and debt and equity securities, and to do so by the exercise of the power of eminent domain in accordance with Section 1-21; except that any real property acquired by the exercise of the power of eminent domain must be located within the State.

(7) To sell, convey, lease, exchange, transfer, abandon, or otherwise dispose of, or mortgage, pledge, or create a security interest in, any of its assets, properties, or any interest therein, wherever situated.

(8) To purchase, take, receive, subscribe for, or otherwise acquire, hold, make a tender offer for, vote, employ, sell, lend, lease, exchange, transfer, or otherwise dispose of, mortgage, pledge, or grant a security interest in, use, and otherwise deal in and with, bonds and other obligations, shares, or other securities (or interests therein) issued by others, whether engaged in a similar or different business or activity.

(9) To make and execute agreements, contracts, and other instruments necessary or convenient in the exercise of the powers and functions of the Agency under this Act, including contracts with any person, including personal service contracts, or with any local government, State agency, or other entity; and all State agencies and all local governments are authorized to enter into and do all things necessary to perform any such agreement, contract, or other instrument with the Agency. No such agreement, contract, or other instrument shall exceed 40 years.

(10) To lend money, invest and reinvest its funds in accordance with the Public Funds Investment Act, and take and hold real and personal property as security for the payment of funds loaned or invested.

(11) To borrow money at such rate or rates of interest as the Agency may determine, issue its notes, bonds, or other obligations to evidence that indebtedness, and secure any of its obligations by mortgage or pledge of its real or personal property, machinery, equipment, structures, fixtures, inventories, revenues, grants, and other funds as provided or any interest therein, wherever situated.

(12) To enter into agreements with the Illinois Finance Authority to issue bonds whether or not the income therefrom is exempt from federal taxation.

(13) To procure insurance against any loss in connection with its properties or operations in such amount or amounts and from such insurers, including the federal government, as it may deem necessary or desirable, and to pay any premiums therefor.

(14) To negotiate and enter into agreements with trustees or receivers appointed by United States bankruptcy courts or federal district courts or in other proceedings involving adjustment of debts and authorize proceedings involving adjustment of debts and authorize legal counsel for the Agency to appear in any such proceedings.

(15) To file a petition under Chapter 9 of Title 11 of the United States Bankruptcy Code or take other similar action for the adjustment of its debts.

(16) To enter into management agreements for the operation of any of the property or facilities owned by the Agency.

(17) To enter into an agreement to transfer and to transfer any land, facilities, fixtures, or equipment of the Agency to one or more municipal electric systems, governmental aggregators, or rural electric agencies or cooperatives, for such consideration and upon such terms as the Agency may determine to be in the best interest of the citizens of Illinois.

(18) To enter upon any lands and within any building whenever in its judgment it may be necessary for the purpose of making surveys and examinations to accomplish any purpose authorized by this Act.

(19) To maintain an office or offices at such place or places in the State as it may determine.

(20) To request information, and to make any inquiry, investigation, survey, or study that the Agency may deem necessary to enable it effectively to carry out the provisions of this Act.

(21) To accept and expend appropriations.

(22) To engage in any activity or operation that is incidental to and in furtherance of efficient operation to accomplish the Agency's purposes, including hiring employees that the Director deems essential for the operations of the Agency.

(23) To adopt, revise, amend, and repeal rules with respect to its operations, properties, and facilities as may be necessary or convenient to carry out the purposes of this Act, subject to the provisions of the Illinois Administrative Procedure Act and Sections 1-22 and 1-35 of this Act.

(24) To establish and collect charges and fees as described in this Act.

(25) To conduct competitive gasification feedstock procurement processes to procure the feedstocks for the clean coal SNG brownfield facility in accordance with the requirements of Section 1-78 of this Act.

(26) To review, revise, and approve sourcing agreements and mediate and resolve disputes between gas utilities and the clean coal SNG brownfield facility pursuant to subsection (h-1) of Section 9-220 of the Public Utilities Act or to fulfill its responsibilities for developing energy efficiency potential studies as required under subsection (f) of Section 8-103 of the Public Utilities Act.

(Source: P.A. 96-784, eff. 8-28-09; 96-1000, eff. 7-2-10; 97-96, eff. 7-13-11; 97-325, eff. 8-12-11; 97-618, eff. 10-26-11; 97-813, eff. 7-13-12.)

(20 ILCS 3855/1-56)

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 for the following purposes:

(1) to purchase renewable energy credits according to any approved procurement plan developed by the Agency prior to June 1, 2016; and

(2) to purchase renewable energy credits and pay for other applicable expenses as part of a low-income solar program; the Agency shall create a low-income solar program with the objective of bringing solar photovoltaics to low-income communities in a manner that maximizes the development of new renewable energy generating facilities, provides workforce development opportunities within low-income communities, creates a long-term, low-income solar marketplace throughout Illinois, and minimizes administrative costs; the Agency shall include the low-income solar program as part of the long-term renewable resources procurement plan authorized by subdivision (c) of Section 1-75 of this Act, and the program shall be designed to grow the low-income solar market over at least 10 years; for this program, the Agency shall purchase renewable energy credits from either (i) photovoltaic distributed renewable energy generation devices or (ii) community solar projects. The electricity generated by each distributed generation device or community solar project must primarily be used to offset the electricity usage of (i) lower-income households, (ii) properties where the majority of occupants are lower-income households, (iii) public sector buildings that primarily serve lower-income households, or (iv) not-for-profit corporations that primarily serve lower-income households.

As used in this subsection (b), "lower-income households" means persons and families whose income does not exceed 80% of area median income, adjusted for family size and revised every 5 years.

Administrative costs associated with the low-income solar program, including, but not limited to, the Agency's general administrative expenses associated with developing and operating the program, costs associated with the program manager referenced in this Section, and costs related to the evaluation of the low-income solar program, may be paid for using the Illinois Power Agency Renewable Energy Resources Fund, but the Agency and program manager shall strive to minimize administrative expenses in the implementation of the program.

The Agency shall purchase renewable energy credits through an upfront payment per kilowatt of installed nameplate capacity paid once the device is energized. The payment shall be in exchange for an assignment of all renewable energy credits generated by the system during the first 15 years of operation and shall be structured to overcome barriers to participation in the solar market by the low-income community. The Agency shall retire any renewable energy credits purchased from this program and shall use the renewable energy credits to reduce the obligation under subdivision (c) of Section 1-75 of this Act for the electric utility to which the project is interconnected.

The Agency shall establish the low-income solar program terms, conditions, and requirements, including the initial purchase price of renewable energy credits, through the development, review, and approval of the Agency's long-term renewable resources procurement plan described in subdivision (c) of Section 1-75 of this Act. The Agency may review and adjust the program terms, conditions, and requirements, including the price offered to new systems, to ensure the long-term viability and success of the program. The Commission shall review and approve any modifications to the program through the periodic plan revision process described in Section 16-111.5C of the Public Utilities Act.

The Agency shall issue a request for qualifications for a third-party program manager to administer the low-income solar program. The third-party program manager may be a government entity or a not-for-profit corporation and shall be chosen through a competitive bid process based on selection criteria and requirements developed by the Agency. In selecting a program manager, the Agency shall consider a bidder's experience in (i) administering low-income energy programs with evidence of strong consumer protection, (ii) providing low-income job training opportunities, and (iii) providing or overseeing solar installation or energy efficiency services. At least every 2 years, the Commission shall select an independent evaluator to review and report on the low-income solar program and the performance of the third-party program manager of the low-income solar program. The report shall include the number of projects installed, the total installed capacity in kilowatts, the average cost per kilowatt of installed capacity, the total number of jobs or job training opportunities, and other economic, social and environmental benefits created, and the total administrative costs expended by the Agency and program manager to implement and evaluate the program. The report shall be delivered to the Commission and posted on the Agency's website and used, as needed, to revise the low-income solar program.

The low-income solar program manager shall administer the low-income solar program, which shall include the development of standard contract forms, the development and implementation of a marketing and outreach program for eligible low-income customers, and providing solar installation services, including subcontractor solicitations when necessary. The low-income solar program shall also include energy efficiency referral and education services, solar job training and workforce development opportunities, and consumer protection provisions.

(b-5) Upon the submission of all payments required by Section 16-115D of the Public Utilities Act, no funds shall be deposited into the Illinois Power Agency Renewable Energy Resources Fund unless directed by order of the Commission.

(b-10) Upon the balance of the Illinois Power Agency Renewable Energy Resources Fund falling below $5,000, the Fund shall be terminated, and any remaining funds shall be transferred to the Low Income Home Energy Assistance Program, as authorized by the Energy Assistance Act.

to procure renewable energy resources. Prior to June 1, 2011, resources procured pursuant to this Section shall be procured from facilities located in Illinois, provided the resources are available from those facilities. If resources are not available in Illinois, then they shall be procured in states that adjoin Illinois. If resources are not available in Illinois or in states that adjoin Illinois, then they may be purchased elsewhere. Beginning June 1, 2011, resources procured pursuant to this Section shall be procured from facilities located in Illinois or states that adjoin Illinois. If resources are not available in Illinois or in states that adjoin Illinois, then they may be procured elsewhere. To the extent available, at least 75% of these renewable energy resources shall come from wind generation. Of the renewable energy resources procured pursuant to this Section at least the following specified percentages shall come from photovoltaics on the following schedule: 0.5% by June 1, 2012; 1.5% by June 1, 2013; 3% by June 1, 2014; and 6% by June 1, 2015 and thereafter. Of the renewable energy resources procured pursuant to this Section, at least the following percentages shall come from distributed renewable energy generation devices: 0.5% by June 1, 2013, 0.75% by June 1, 2014, and 1% by June 1, 2015 and thereafter. To the extent available, half of the renewable energy resources procured from distributed renewable energy generation shall come from devices of less than 25 kilowatts in nameplate capacity. Renewable energy resources procured from distributed generation devices may also count towards the required percentages for wind and solar photovoltaics. Procurement of renewable energy resources from distributed renewable energy generation devices shall be done on an annual basis through multi-year contracts of no less than 5 years, and shall consist solely of renewable energy credits.

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

(c) (Blank). The Agency shall procure renewable energy resources at least once each year in conjunction with a procurement event for electric utilities required to comply with Section 1-75 of the Act and shall, whenever possible, enter into long-term contracts on an annual basis for a portion of the incremental requirement for the given procurement year.

(d) (Blank). The price paid to procure renewable energy credits using monies from the Illinois Power Agency Renewable Energy Resources Fund shall not exceed the winning bid prices paid for like resources procured for electric utilities required to comply with Section 1-75 of this Act.

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

(f) The selection of the third-party program manager, the selection of the independent evaluator, and the procurement process described in this Section are exempt from the requirements of Section 20-10 of the Illinois Procurement Code. The procurement process described in this Section is exempt from the requirements of the Illinois Procurement Code, pursuant to Section 20-10 of that Code.

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

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

(i) Supplemental procurement process.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

(20 ILCS 3855/1-75)

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

(a) The Planning and Procurement Bureau shall each year, beginning in 2008, develop procurement plans and conduct competitive procurement processes in accordance with the requirements of Section 16-111.5 of the Public Utilities Act for the eligible retail customers of electric utilities that on December 31, 2005 provided electric service to at least 100,000 customers in Illinois. 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.

Notwithstanding the requirements of this subdivision (a), beginning with the planning process for the plan or plans to be implemented in the 2016 delivery year, the Agency shall no longer include the procurement of renewable energy resources in the procurement plans required by this subdivision (a) and shall instead develop a long-term renewable resources procurement plan in accordance with subdivision (c) of this Section.

(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 Planning and Procurement Bureau shall develop a long-term renewable resources procurement plan that includes all renewable energy credits necessary to meet the goals set forth in this subdivision (c). The long-term renewable resources procurement plan shall include long-term programs and competitive procurement events designed to meet the renewable resources goals in this subdivision (c) from the date of the plan through the 2030 delivery year. The initial long-term renewable resources procurement plan shall be released for comment no later than 120 days after the effective date of this amendatory Act of the 99th General Assembly. The Agency shall review and revise the long-term renewable resources procurement plan at least every 2 years. The initial long-term renewable resources procurement plan and each revised plan shall be subject to review and approval by the Commission pursuant to Section 16-111.5C of the Public Utilities Act.

(1.5) The Agency shall continue to implement all procurements of renewable energy credits included in all prior procurement plans filed with the Commission prior to June 1, 2016. Any renewable energy credits procured as a result of these prior procurements, including renewable energy credits as part of bundled renewable energy resources, shall be used to meet the goals set forth in this subdivision (c) and shall be included as resources in the long-term renewable resources plan required in paragraph (1) of this subdivision (c). Any costs associated with the procurement of renewable energy credits as a result of these prior procurements, including the cost of renewable energy credits included in the cost of bundled renewable energy resources, but not including any renewable energy credits procured as a result of procurements authorized by subsection (i) of Section 1-56 of this Act or paid for using funds collected as a result of paragraph (5) of this subdivision (c), shall be included in the total cost of renewable energy credits procured pursuant to the long-term procurement plan, as limited in paragraph (1.15) of this subdivision (c).

As used in this subdivision (c):

"Bundled renewable energy resources" means electricity generated by a renewable energy system and its associated renewable energy credit.

"Cost of renewable energy credits included in the cost of bundled renewable energy resources" means the difference between the contract price for the bundled renewable energy resources and the day-ahead locational marginal price at the load zone at which the contract is settled multiplied by the megawatt hours of electricity generated in each hour.

(1.10) The cost of any renewable energy credits procured through a competitive procurement event pursuant to an approved plan shall not exceed benchmarks established by the procurement administrator, in consultation with the Commission staff, Agency staff, and the procurement monitor. The benchmarks shall be based on price data for similar products for the same delivery period and same utility delivery hub or other utility 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 the Commission and shall be subject to Commission review and approval prior to a procurement event.

(1.15) Notwithstanding the requirements of this subdivision (c), the total amount of renewable energy credits procured pursuant to the long-term renewable resources procurement plan shall be reduced by an amount necessary to limit the annual estimated average net increase due to the costs of these credits included in the amounts paid by all customers taking delivery service from an electric utility to no more than 2.015% of the amount paid per kilowatthour by eligible retail customers during the year ending May 31, 2007. For purposes of this subdivision (c), the amount paid per kilowatthour means the total amount paid for electric service expressed on a per kilowatthour basis, including without limitation amounts paid for supply, transmission, distribution, surcharges, and add-on taxes.

(1.20) The long-term renewable resources procurement plan shall include the procurement of renewable energy credits in amounts equal to at least the following percentages measured as a percentage of the projected amount of electricity in kilowatthours to be delivered by the electric utilities to all customers taking delivery service from an electric utility: 11.5% by the 2016 delivery year, and increasing by at least 1.5% each delivery year thereafter to at least 25% by the 2025 delivery year; and increasing at least 2% each delivery year thereafter to at least 35% by the 2030 delivery year, continuing at that percentage for each delivery year thereafter.

(A) By the end of the 2020 delivery year:

(i) 75% of the total renewable energy credits procured shall come from wind generation, of which at least 25% shall come from new wind projects; and

(ii) 5% of the total renewable energy credits procured or the equivalent amount of renewable energy credits from 1,000 megawatts of solar photovoltaic nameplate capacity, whichever is larger, shall come from new photovoltaic projects; of that amount, to the extent possible, the Agency shall procure 75% from photovoltaic projects using the program outlined in paragraph (1.25) of this subdivision (c) from distributed renewable energy devices or community solar projects and shall give preference to brownfield solar projects that are not community solar projects for the remaining 25%.

(B) By the end of the 2025 delivery year:

(i) 75% of the total renewable energy credits procured shall come from wind generation, of which at least 25% shall come from new wind projects; and

(ii) 6% of the total renewable energy credits procured or the equivalent amount of renewable energy credits from 1,500 megawatts of solar photovoltaic nameplate capacity, whichever is larger, shall come from new photovoltaic projects; of that amount, to the extent possible the Agency shall procure 75% from photovoltaic projects using the program outlined in paragraph (1.25) of this subdivision (c) from distributed renewable energy devices or community solar projects and shall give preference to brownfield solar projects that are not community solar projects for the remaining 25%.

(C) By the end of the 2030 delivery year:

(i) 75% of the total renewable energy credits procured shall come from wind generation, of which at least 25% shall come from new wind projects; and

(ii) 7% of the total renewable energy credits procured or the equivalent amount of renewable energy credits from 2,000 megawatts of solar photovoltaic nameplate capacity, whichever is larger, shall come from new photovoltaic projects; of that amount, to the extent possible the Agency shall procure 75% from photovoltaic projects using the program outlined in paragraph (1.25) of this subdivision (c) from distributed renewable energy devices or community solar projects and shall give preference to brownfield solar projects that are not community solar projects for the remaining 25%.

Renewable energy credits are eligible to be counted toward the renewable energy requirements of this subsection (c) if the renewable energy facility is located in Illinois, if the facility has a generator interconnection agreement with PJM or MISO, or if the renewable energy facility is located in the United States and the output of the facility is delivered to a transmission asset that is controlled by PJM or MISO, where "delivered" means the generated output of the facility has been demonstrated to have a distribution factor of 25% or greater on the transmission asset of PJM or MISO, and where "distribution factor" means a measurement of the sensitivity of the flow of electricity from a renewable energy generator to a consuming load on a transmission asset under the control of MISO or PJM. In procuring renewable energy credits, the Agency may consider bid selection criteria that include public interest factors, such as the potential to increase fuel and resource diversity in Illinois, enhance system reliability and resiliency, and contribute to a cleaner and healthier environment for the citizens of Illinois. In its long-term plan, the Agency shall develop the method for incorporating these public interest factors, in addition to bid price, into its bid selection process. The Agency's method may include, but may not be limited to, quantitatively scoring the evaluation of individual bids under public interest criteria or the establishment of procurement minimums for project categories informed by the public interest factors described in this paragraph (1.15).

In the event that the rate impact cap in paragraph (1.15) of this subdivision (c) prevents the Agency from meeting all of the percentage goals in this subdivision (c), the Agency shall prioritize compliance with the goals for new wind and photovoltaic projects.

As used in this paragraph (1.20):

"New wind projects" means wind renewable energy projects (i) that begin energy delivery no earlier than 3 years prior to the procurement date and (ii) for projects located within Illinois, for which the owner of the project has certified that not less than the prevailing wage was or will be paid to employees who are engaged in construction activities associated with the project.

"New photovoltaic projects" means photovoltaic renewable energy projects (i) that are interconnected at the distribution system level of either an electric utility, 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, (ii) that are energized after January 1, 2016 for the first procurement year or within one year of the procurement date for subsequent procurement years, and (iii) for projects over 1,000 kilowatts in nameplate capacity, for which the owner of the project has certified that not less than the prevailing wage was or will be paid to employees who are engaged in construction activities associated with the project.

"Prevailing wage" has the same definition as in subsection (F) of Section 5.5(a)(3) of the Enterprise Zone Act.

(1.25) The long-term renewable resources procurement plan developed by the Agency in accordance with this subdivision (c) shall include a declining block program for the procurement of renewable energy credits from photovoltaic projects that are distributed renewable energy generation devices or community solar projects. The declining block program shall be designed to provide a transparent schedule of prices and capacity to enable the photovoltaic market to scale up and for renewable energy credit prices to fall at a predictable, sustainable rate over time. The declining block program shall include for each category of eligible projects: (i) a schedule of standard, declining block purchase prices to be offered, (ii) a series of steps, with associated nameplate capacity and purchase prices that decline from step to step, and (iii) automatic opening of the next step as soon as the nameplate capacity and available purchase prices for an open step are fully committed or reserved. Only projects energized on or after January 1, 2016, shall be eligible for the declining block program. For each block group the Agency shall determine the number of blocks, the amount of generation capacity in each block, and the purchase price for each block, provided that the purchase price provided and the total amount of generation in all blocks for all block groups shall be sufficient to meet the goals in paragraph (1.20) of this subdivision (c). The Agency may periodically review the purchase prices and may redistribute available funds as necessary and appropriate, subject to Commission approval as part of the periodic plan revision process described in Section 16-111.5C of the Public Utilities Act.

The declining block program shall include at least the following block groups, which may be adjusted upon review by the Agency and approval of the Commission:

(A) Distributed renewable energy generation devices with a nameplate capacity of no more than 10 kilowatts.

(B) Distributed renewable energy generation devices with a nameplate capacity of more than 10 kilowatts and no more than 100 kilowatts.

(C) Distributed renewable energy generation devices with a nameplate capacity of more than 100 kilowatts and no more than 500 kilowatts.

(D) Distributed renewable energy generation devices with a nameplate capacity of more than 500 kilowatts and no more than 2,000 kilowatts.

(E) Distributed renewable energy generation devices with a nameplate capacity of no more than 2,000 kilowatts that are owned by a municipality, a school district, a unit of local government, a public university, or a not-for-profit corporation, and primarily used to offset their own electricity load.

(F) Community solar projects.

For projects that qualify under paragraph (A) of this paragraph (1.25), the renewable energy credit purchase price shall be paid as an upfront payment per installed kilowatt of nameplate capacity paid once the device is energized. The electric utility shall receive all renewable energy credits generated by the project for the first 15 years of operation. For projects that qualify under items (B) through (F) of this paragraph (1.25) and any additional categories included in the long-term renewable resources plan and approved by the Commission, the renewable energy credit purchase price shall be in exchange for an assignment of all renewable energy credits generated by the project for the first 15 years of operation. The Agency shall pay for those credits over the first 5 years of operation of the system through a partial payment made after the system is first energized and additional payments over the first 4 years of operation based on actual energy produced. The electric utility shall receive all renewable energy credits generated by the project for the first 15 years of operation.

The Agency shall issue a request for qualifications for a third-party program manager to administer the declining block program. The third-party program manager shall be chosen through a competitive bid process based on selection criteria and requirements developed by the Agency, including consideration of prior experience in administering an incentive program for energy efficiency, renewable energy, or other similar resources. The third-party program manager shall be the counterparty to the contract to purchase renewable energy credits from individual systems. The utility shall transfer funds needed to cover the cost of purchasing renewable energy credits and administering the declining block program to the third-party program manager at the order of the Commission. The utility's obligation under this paragraph (1.25) shall be considered met upon transfer of funds to the third-party program manager and retirement of associated renewable energy credits. At least every 2 years, the Agency shall select an independent evaluator to review and report on the declining block program and the performance of the declining block program manager. The report should include the number of projects installed, the total installed capacity in kilowatts, the average cost per kilowatt of installed capacity, the total number of jobs, and other economic, social, and environmental benefits created. The report shall be posted on the Agency's website and used, as needed, to revise the declining block program. Upon order of the Commission, the utility shall provide payment for the independent evaluation of the declining block program. Costs associated with evaluation of the declining block program shall not be included in paragraph (1.15) of this subdivision (c), however these costs shall be recoverable as a utility cost of service under the Public Utilities Act. The selection of the third-party program manager, the selection of the independent evaluator, and the procurement process described in this paragraph (1.25) are exempt from the requirements of Section 20-10 of the Illinois Procurement Code.

(1.30) The long-term renewable resources procurement plan required by the subdivision (c) shall include a Community Solar Program. The Agency shall develop the Community Solar Program to purchase renewable energy credits from community solar projects with a goal to expand renewable energy generating facility access to a broader group of energy consumers, including those who cannot install renewable energy on their own properties, while prioritizing those persons most sensitive to market barriers.

The Agency shall establish the terms, conditions, and program requirements for community solar projects as part of the long-term renewable resources plan required by this Section. Any plan approved by the Commission must reasonably allow for the creation, financing, and accessibility of community solar projects and shall allow subscriptions to community solar projects to be portable and transferrable. Electric utilities shall establish a tariff to provide bill credits to subscribers of community solar projects, as specified in an approved long-term renewable resources plan. The community solar bill credits shall account for the fair value of the distributed solar energy and its delivery, generation capacity, transmission capacity, transmission and distribution line losses, and environmental value. The Agency may provide an enhanced bill credit for community solar projects that are located within brownfield sites or within strategic zones identified by the utility with approval by the Commission to provide the greatest benefits to the electric distribution system. If the electrical capacity of a community solar project is not fully subscribed during the first full year of operation, the electric utility shall purchase the energy associated with the unsubscribed capacity at the electric utility's avoided cost of electricity supply over the month period or as otherwise specified by the terms of a power purchase agreement negotiated by the community solar owners or subscribers and the electricity provider. After the first full year of operation, if the electrical capacity of a community solar project is not fully subscribed, the electric utility shall purchase the energy associated with the unsubscribed capacity at the electric utility's avoided cost of electricity supply over the month period unless excess capacity is otherwise provided for in a power purchase agreement. The Agency shall purchase renewable energy credits from subscribed shares of community solar projects through the declining block program described in paragraph (6) of this subdivision (c) or through the low income solar program described in Section 1-56 of this Act. The owners of and any subscribers to a community solar project shall not be considered public utilities or alternative retail electricity suppliers under the Public Utilities Act solely as a result of their interest in or subscription to a community solar project and shall not be required to become an alternative retail electric supplier by participating in a community solar project with a public utility.

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

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

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

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

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

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

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

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

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

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

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

(3) (Blank). Through June 1, 2011, renewable energy resources shall be counted for the purpose of meeting the renewable energy standards set forth in paragraph (1) of this subsection (c) only if they are generated from facilities located in the State, provided that cost-effective renewable energy resources are available from those facilities. If those cost-effective resources are not available in Illinois, they shall be procured in states that adjoin Illinois and may be counted towards compliance. If those cost-effective resources are not available in Illinois or in states that adjoin Illinois, they shall be purchased elsewhere and shall be counted towards compliance. After June 1, 2011, cost-effective renewable energy resources located in Illinois and in states that adjoin Illinois may be counted towards compliance with the standards set forth in paragraph (1) of this subsection (c). If those cost-effective resources are not available in Illinois or in states that adjoin Illinois, they shall be purchased elsewhere and shall be counted towards compliance.

(4) The electric utility shall retire all renewable energy credits used to comply with the standard.

(5) Beginning with the 2010 delivery year and ending after the 2016 delivery year year commencing June 1, 2010, an electric utility subject to this subsection (c) shall apply the lesser of the maximum alternative compliance payment rate or the most recent estimated alternative compliance payment rate for its service territory for the corresponding compliance period, established pursuant to subsection (d) of Section 16-115D of the Public Utilities Act to its retail customers that take service pursuant to the electric utility's hourly pricing tariff or tariffs. The electric utility shall retain all amounts collected as a result of the application of the alternative compliance payment rate or rates to such customers, and, beginning in 2011, the utility shall include in the information provided under item (1) of subsection (d) of Section 16-111.5 of the Public Utilities Act the amounts collected under the alternative compliance payment rate or rates for the prior year ending May 31. Notwithstanding any limitation on the procurement of renewable energy resources imposed by item (2) of this subsection (c), the Agency shall increase its spending on the purchase of renewable energy resources to be procured by the electric utility for the next plan year by an amount equal to the amounts collected by the utility under the alternative compliance payment rate or rates in the prior year ending May 31. Beginning April 1, 2012, and each year thereafter, the Agency shall prepare a public report for the General Assembly and Illinois Commerce Commission that shall include, but not necessarily be limited to:

(A) a comparison of the costs associated with the Agency's procurement of renewable energy resources to (1) the Agency's costs associated with electricity generated by other types of generation facilities and (2) the benefits associated with the Agency's procurement of renewable energy resources; and

(B) an analysis of the rate impacts associated with the Illinois Power Agency's procurement of renewable resources, including, but not limited to, any long-term contracts, on the eligible retail customers of electric utilities.

The analysis shall include the Agency's estimate of the total dollar impact that the Agency's procurement of renewable resources has had on the annual electricity bills of the customer classes that comprise each eligible retail customer class taking service from an electric utility. The Agency's report shall also analyze how the operation of the alternative compliance payment mechanism, any long-term contracts, or other aspects of the applicable renewable portfolio standards impacts the rates of customers of alternative retail electric suppliers.

(6) Costs of procuring renewable energy credits pursuant to plans approved under Section 16-111.5C of the Public Utilities Act and associated reasonable expenses for implementing the procurement programs, including the costs of administering and evaluating the declining block program, shall be recoverable as a utility cost of service under the Public Utilities Act.

(7) In meeting the renewable energy requirements of this subdivision (c), to the extent feasible and consistent with State and federal law, the renewable energy credit procurements, declining block solar program, and community solar program shall provide employment opportunities for all segments of the population and workforce, including minority-owned and female-owned business enterprises, and shall not, consistent with State and federal law, discriminate based on race or socioeconomic status.

(d) Clean coal portfolio standard.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

(B) power purchase provisions, which shall:

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

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

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

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

(C) contract for differences provisions, which shall:

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

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

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

(D) general provisions, which shall:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

The facility cost report shall be prepared as follows:

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

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

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

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

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

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

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

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

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

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

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

(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 8-101, 8-103, 8-104, 16-107, 16-108.5, 16-108.8, 16-111.5, 16-111.5B, 16-111.7, 16-115D, and 19-140 and by adding Section 16-111.5C as follows:

(220 ILCS 5/8-101) (from Ch. 111 2/3, par. 8-101)

Sec. 8-101. Duties of public utilities; nondiscrimination. A public utility shall furnish, provide, and maintain such service instrumentalities, equipment, and facilities as shall promote the safety, health, comfort, and convenience of its patrons, employees, and public and as shall be in all respects adequate, efficient, just, and reasonable.

All rules and regulations made by a public utility affecting or pertaining to its charges or service to the public shall be just and reasonable.

A public utility shall, upon reasonable notice, furnish to all persons who may apply therefor and be reasonably entitled thereto, suitable facilities and service, without discrimination and without delay.

Nothing in this Section shall be construed to prevent a public utility from accepting payment electronically or by the use of a customer-preferred financially accredited credit or debit methodology.

A public utility shall not discriminate against technologies, regardless of generator, prime mover, or inverter, when presented with an application for interconnection of a distributed generation facility, including without limitation a battery or energy storage facility, that operates in parallel with the electric distribution system.

(Source: P.A. 92-22, eff. 6-30-01.)

(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, by reducing electricity prices in the regional power market, and by avoiding or delaying the need for new generation, transmission, and distribution infrastructure. It serves the public interest to allow electric utilities to recover costs for reasonably and prudently incurred expenses for energy efficiency and demand-response measures. As used in this Section, "cost-effective" means that the measures satisfy the total resource cost test. The low-income measures described in subsection (f)(4) of this Section shall not be required to meet the total resource cost test. For purposes of this Section, the terms "energy-efficiency", "demand-response", "electric utility", and "total resource cost test" shall have the meanings set forth in the Illinois Power Agency Act. For purposes of this Section, the amount per kilowatthour means the total amount paid for electric service expressed on a per kilowatthour basis. For purposes of this Section, the total amount paid for electric service includes without limitation estimated amounts paid for supply, transmission, distribution, surcharges, and add-on-taxes.

(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 each the year commencing June 1, 2015 and ending on December 31, 2017; and each year thereafter.

(9) beginning in January 2018, an amount to be determined by the Illinois Commerce Commission through the process described in subsection (f) of this Section in order to achieve a cumulative annual persisting reduction in electric energy demand from efficiency measures implemented as a result of utility programs from 2012 through 2025 of 20%, relative to average annual electricity sales from 2014 through 2016, by the year ending December 31 2025; cumulative persisting annual reductions are the reductions realized in a given year from measures installed in either the that year or in previous years that are still operational and providing savings in that year because they have not yet reached the end of their useful life; and

After 2025, the incremental annual energy goal shall be an amount to be determined by the Illinois Commerce Commission in order to fully capture the cost-effective potential for electricity savings as assessed by the Illinois Power Agency under subsection (j-10) of this Section.

Electric utilities may comply with this subsection (b) by meeting the annual incremental savings goal in the applicable year or by showing that the total cumulative annual savings within a 3-year planning period associated with measures implemented after May 31, 2014 was equal to the sum of each annual incremental savings requirement from May 31, 2014 through the end of the applicable year. Beginning January 1, 2018, electric utilities may comply by showing that the total cumulative annual savings persisting the last year of the applicable 4-year planning period was equal to the cumulative persisting annual savings required in that year by the Illinois Commerce Commission pursuant to the plans approved under subsection (f) of this Section. Annually, beginning on March 1, 2019, each participating utility shall file third-party evaluations of the savings achieved in the preceding year. Within 5 days after the filing, any person objecting to the filing shall file an objection. 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 savings estimates within 90 days after the filing date.

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

(d) Notwithstanding the requirements of subsections (b) and (c) of this Section, an electric utility shall reduce the amount of energy efficiency and demand-response measures implemented over a 3-year planning period by an amount necessary to limit the estimated average annual increase in the amounts paid by retail customers in connection with electric service due to the cost of those measures to:

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

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

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

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

(5) in 2012 and in each subsequent year through 2017 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.

For utility efficiency programs offered on or after January 2018, the amount of savings shall be limited only to the extent necessary to ensure that the measures installed will, in the aggregate, result in net benefits to customers when the full costs of the efficiency programs are compared with the full benefits, as defined in the total resource cost test.

(e) Electric utilities shall be responsible for overseeing the design, development, and filing of energy efficiency and demand-response plans with the Commission. Electric utilities shall implement 100% of the demand-response measures in the plans. Electric utilities shall implement 75% of the energy efficiency measures approved by the Commission, and may, as part of that implementation, outsource various aspects of program development and implementation. The remaining 25% of those energy efficiency measures approved by the Commission shall be implemented by the Department of Commerce and Economic Opportunity, and must be designed in conjunction with the utility and the filing process. The Department may outsource development and implementation of energy efficiency measures. A minimum of 10% of the entire portfolio of cost-effective energy efficiency measures shall be procured from units of local government, municipal corporations, school districts, and community college districts. A minimum of 12.5% of the entire portfolio of cost-effective energy efficiency measures shall be allocated to programs that serve low-income residential customers. The Department shall coordinate the implementation of these measures. As much as half of the minimum low-income requirement may be met through energy efficiency measures that result in savings related to fuels other than electricity if necessary:

(1) to comprehensively capture treatment of efficiency opportunities for low-income residential customers;

(2) to enable effective administration of low-income programs; or

(3) to address limitations on availability of other funding sources for efficiency measures to improve the efficiency of use of natural gas, fuel oil, or other fuels used by low-income residential customers. The Department shall coordinate the implementation of these measures.

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

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

A utility providing approved energy efficiency and demand-response measures in the State before December 31, 2017 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, 2018, a participating utility providing approved energy efficiency and demand-response measures in the State that has elected to be subject to Section 16-108.5 of the Public Utilities Act may recover the costs of those measures as part of its cost of service in its performance-based formula rate as provided in paragraph (1) of subsection (c) of Section 16-108.5.

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

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

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

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

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

(f) No later than November 15, 2007, each electric utility shall file an energy efficiency and demand-response plan with the Commission to meet the energy efficiency and demand-response standards for 2008 through 2010. No later than October 1, 2010, each electric utility shall file an energy efficiency and demand-response plan with the Commission to meet the energy efficiency and demand-response standards for 2011 through 2013. By September 1, 2013, each electric utility shall file an energy efficiency and demand-response plan for 2014 through 2017. By January 1, 2016, the Illinois Power Agency shall publish a draft statewide energy efficiency potential study that assesses the technical, economic, and maximum cost-effective achievable potential for energy efficiency for each electric utility service territory from 2018 through 2021 and from 2022 through 2025. The Agency shall seek input from stakeholders in advance of conducting the study. After the draft study is published, the Agency shall accept public comments on the study through March 1, 2016 and shall transmit a final proposed study to the Commission by April 15, 2017. The Commission shall approve the study or approve with modifications by June 1, 2016. By January 1, 2017, each electric utility and the Department shall file an energy efficiency plan for the period beginning January 1, 2018 through December 31, 2021 that seeks to achieve a cumulative persisting annual reduction in electricity demand in 2021, from efficiency measures installed as a result of its programs from 2012 through 2021, of at least 12% compared to average annual electricity sales from 2014 through 2016, unless such levels have been clearly shown by the Illinois Power Agency's potential study to not be cost-effective or achievable, in which case the plans should be designed to capture all of the cost-effective potential for energy savings identified as achievable in the potential study completed by the Illinois Power Agency. By January 1, 2020 and every 4 years thereafter, the Illinois Power Agency shall publish a second draft statewide energy efficiency potential study updating its assessment of the cost-effective achievable potential for energy efficiency for each electric utility service territory from 2022 through 2025. The agency shall seek input from stakeholders in advance of conducting the study. The agency will accept public comments on the draft study through March 1, 2020 and shall transmit a final proposed study to the Commission by April 15, 2020. The Commission shall approve the study or approve with modifications by June 1, 2020. By January 1, 2021, each electric utility and the Department shall file an energy efficiency plan for the period beginning January 1, 2022 through December 31, 2025 that seeks to achieve a cumulative persisting annual reduction in electricity demand in 2025, from efficiency measures installed as a result of its programs from 2012 through 2025, of at least 20% compared to average annual electricity sales from 2014 through 2016, unless such levels have been clearly shown by the Illinois Power Agency's study to not be cost-effective or achievable, in which case the plans should be designed to capture all of the cost-effective potential for energy savings identified in the potential study completed by the Illinois Power Agency. On January 1, 2024 and every 4 years thereafter, each electric utility and the Department shall file an energy efficiency plan covering a 4-year period beginning January 1 of the following year. Every 3 years thereafter, each electric utility shall file, no later than September 1, an energy efficiency and demand-response plan with the Commission. If a utility does not file such a plan by the deadlines described in this Section September 1 of an applicable year, it shall face a penalty of $100,000 per day until the plan is filed. Each utility's plan shall set forth the utility's proposals to meet the utility's portion of the energy efficiency standards identified in subsection (b) and the demand-response standards identified in subsection (c) of this Section as modified by subsections (d) and (e), taking into account the unique circumstances of the utility's service territory. The Commission shall seek public comment on the utility's plan and shall issue an order approving or disapproving each plan within 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 and demand-response measures will achieve the requirements that are identified in subsections (b) and (c) of this Section, as modified by subsections (d) and (e).

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

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

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

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

(5.5) Include meaningful opportunities for third-party energy efficiency businesses to deliver energy savings.

(5.10) Ensure that the portfolio as a whole, including the portion administered by the Department of Commerce and Economic Opportunity and programs offered by third-party energy service providers, include opportunities for a diverse set of building types, including both program offering tailored to the needs of specific building types and opportunities to source energy efficiency savings from building, including, but not limited to, hospitals, health care facilities, long-term care facilities, units of local government, school districts, park districts, cultural institutions, museums, facilities licensed under the Child Care Act of 1969, preschools, churches and houses of worship, public universities, private colleges, community college districts, and wastewater and drinking water treatment plant agencies and operators.

(5.15) Demonstrate that the utility consulted with interested stakeholders, including customer groups, environmental advocates, Commission staff, the Illinois Commission on Environmental Justice, and other entities who have participated in Commission proceedings to consider the approval of past energy efficiency plans under this Section and that those entities concerns and input have been taken into consideration during the development of the proposed plan.

(5.20) Ensure that the portfolio maximizes the use of cost-effective measures with measure lives of 10 years or greater.

(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. Beginning in 2018, a participating utility, as defined in Section 16-108.5, providing approved energy efficiency and demand-response measures in the State shall recover the costs of those measures as part of its performance-based formula rate as provided in paragraph (1) of subsection (c) of Section 16-108.5.

(7) Provide for an annual independent evaluation of the performance of the cost-effectiveness of the utility's portfolio of measures and the Department's portfolio of measures, as well as a full review of the full multi-year portfolio 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. The evaluations shall be performed by independent experts that are retained for this purpose by the Illinois Commerce Commission.

(g) No more than 3% of energy efficiency and demand-response program revenue may be allocated for research, development, or pilot deployment of new equipment or measures demonstration of breakthrough equipment and devices.

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

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

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

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

(j-5) By June 1, 2016 and every 4 years thereafter, the Department of Commerce and Economic Opportunity shall perform and make publicly available a study assessing the job creation impact of implementation of energy efficiency programs and policies in Illinois. The Department shall seek input from stakeholders in advance of conducting the study.

(j-10) For the purposes of conducting the energy efficiency potential studies required in subsection (f) of this Section, the Illinois Power Agency shall:

(1) base estimates of the portion of economic potential that could be achieved on document experience of the most successful programs in other jurisdictions in each of the specific efficiency markets being analyzed;

(2) include impacts from emergence of new technologies that can reasonably be expected to emerge after the study is conducted but during the period covered by the study;

(3) account for potential for measure costs to decline as volumes of sales increase;

(4) account for economies that could be achieved through joint electric-gas program delivery or coordination;

(5) include estimates of potential from behavioral changes and process improvements (in addition to technologies);

(6) include estimates of impacts from fuel-switching measures; and

(7) include estimates of impacts from either supporting adoption of stricter building codes or equipment standards or better compliance with existing codes and standards.

(j-15) The Commission shall issue an order extending the programs approved under subsection (f) of this Section for the period beginning June 1, 2014 and ending May 31, 2017 so that these programs continue to be offered until December 31, 2017. The savings goals and budgets associated with these approved programs shall be modified to ensure that the programs will continue to operate and acquire additional savings during this period and under the same cost-effectiveness requirements applicable when the programs were approved.

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

(l) In meeting the energy efficiency requirements of this Section, to the extent feasible and consistent with State and federal law, the energy efficiency credit procurements, declining block solar program, and community solar program should provide employment opportunities for all segments of the population and workforce, including minority-owned and female-owned business enterprises, and shall not, consistent with State and federal law, discriminate based on race or socioeconomic status.

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

(220 ILCS 5/8-104)

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, has the meaning given to that term in Section 1-10 of the Illinois Power Agency Act. 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 3-year planning period associated with measures implemented after May 31, 2011 were equal to the sum of each annual incremental savings requirement from May 31, 2011 through the 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% by May 31, 2018, increasing total savings to 5.6%;

(8) an additional 1.5% 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 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 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 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 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. Every 3 years thereafter, each utility shall file, no later than October 1, an energy efficiency plan with the Commission, except that for plans covering 2018 through 2025, each gas utility shall file plans on the same schedule as is required for the electric utilities under subsection (f) of Section 8-103 of this Act. If a utility does not file such a plan by the statutory deadline described in this Section 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. 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 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 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 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.

(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 5/16-107)

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

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

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

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

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

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

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

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

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

(220 ILCS 5/16-108.5)

Sec. 16-108.5. Infrastructure investment and modernization; regulatory reform.

(a) (Blank).

(b) For purposes of this Section, "participating utility" means an electric utility or a combination utility serving more than 1,000,000 customers in Illinois that voluntarily elects and commits to undertake (i) the infrastructure investment program consisting of the commitments and obligations described in this subsection (b) and (ii) the customer assistance program consisting of the commitments and obligations described in subsection (b-10) of this Section, notwithstanding any other provisions of this Act and without obtaining any approvals from the Commission or any other agency other than as set forth in this Section, regardless of whether any such approval would otherwise be required. "Combination utility" means a utility that, as of January 1, 2011, provided electric service to at least one million retail customers in Illinois and gas service to at least 500,000 retail customers in Illinois. A participating utility shall recover the expenditures made under the infrastructure investment program through the ratemaking process, including, but not limited to, the performance-based formula rate and process set forth in this Section.

During the infrastructure investment program's peak program year, a participating utility other than a combination utility shall create 2,000 full-time equivalent jobs in Illinois, and a participating utility that is a combination utility shall create 450 full-time equivalent jobs in Illinois related to the provision of electric service. These jobs shall include direct jobs, contractor positions, and induced jobs, but shall not include any portion of a job commitment, not specifically contingent on an amendatory Act of the 97th General Assembly becoming law, between a participating utility and a labor union that existed on the effective date of this amendatory Act of the 97th General Assembly and that has not yet been fulfilled. A portion of the full-time equivalent jobs created by each participating utility shall include incremental personnel hired subsequent to the effective date of this amendatory Act of the 97th General Assembly. For purposes of this Section, "peak program year" means the consecutive 12-month period with the highest number of full-time equivalent jobs that occurs between the beginning of investment year 2 and the end of investment year 4.

A participating utility shall meet one of the following commitments, as applicable:

(1) Beginning no later than 180 days after a participating utility other than a combination utility files a performance-based formula rate tariff pursuant to subsection (c) of this Section, or, beginning no later than January 1, 2012 if such utility files such performance-based formula rate tariff within 14 days of the effective date of this amendatory Act of the 97th General Assembly, the participating utility shall, except as provided in subsection (b-5):

(A) over a 5-year period, invest an estimated $1,300,000,000 in electric system upgrades, modernization projects, and training facilities, including, but not limited to:

(i) distribution infrastructure improvements totaling an estimated $1,000,000,000, including underground residential distribution cable injection and replacement and mainline cable system refurbishment and replacement projects;

(ii) training facility construction or upgrade projects totaling an estimated $10,000,000, provided that, at a minimum, one such facility shall be located in a municipality having a population of more than 2 million residents and one such facility shall be located in a municipality having a population of more than 150,000 residents but fewer than 170,000 residents; any such new facility located in a municipality having a population of more than 2 million residents must be designed for the purpose of obtaining, and the owner of the facility shall apply for, certification under the United States Green Building Council's Leadership in Energy Efficiency Design Green Building Rating System;

(iii) wood pole inspection, treatment, and replacement programs;

(iv) an estimated $200,000,000 for reducing the susceptibility of certain circuits to storm-related damage, including, but not limited to, high winds, thunderstorms, and ice storms; improvements may include, but are not limited to, overhead to underground conversion and other engineered outcomes for circuits; the participating utility shall prioritize the selection of circuits based on each circuit's historical susceptibility to storm-related damage and the ability to provide the greatest customer benefit upon completion of the improvements; to be eligible for improvement, the participating utility's ability to maintain proper tree clearances surrounding the overhead circuit must not have been impeded by third parties; and

(B) over a 10-year period, invest an estimated $1,300,000,000 to upgrade and modernize its transmission and distribution infrastructure and in Smart Grid electric system upgrades, including, but not limited to:

(i) additional smart meters;

(ii) distribution automation;

(iii) associated cyber secure data communication network; and

(iv) substation micro-processor relay upgrades.

(2) Beginning no later than 180 days after a participating utility that is a combination utility files a performance-based formula rate tariff pursuant to subsection (c) of this Section, or, beginning no later than January 1, 2012 if such utility files such performance-based formula rate tariff within 14 days of the effective date of this amendatory Act of the 97th General Assembly, the participating utility shall, except as provided in subsection (b-5):

(A) over a 10-year period, invest an estimated $265,000,000 in electric system upgrades, modernization projects, and training facilities, including, but not limited to:

(i) distribution infrastructure improvements totaling an estimated $245,000,000, which may include bulk supply substations, transformers, reconductoring, and rebuilding overhead distribution and sub-transmission lines, underground residential distribution cable injection and replacement and mainline cable system refurbishment and replacement projects;

(ii) training facility construction or upgrade projects totaling an estimated $1,000,000; any such new facility must be designed for the purpose of obtaining, and the owner of the facility shall apply for, certification under the United States Green Building Council's Leadership in Energy Efficiency Design Green Building Rating System; and

(iii) wood pole inspection, treatment, and replacement programs; and

(B) over a 10-year period, invest an estimated $360,000,000 to upgrade and modernize its transmission and distribution infrastructure and in Smart Grid electric system upgrades, including, but not limited to:

(i) additional smart meters;

(ii) distribution automation;

(iii) associated cyber secure data communication network; and

(iv) substation micro-processor relay upgrades.

For purposes of this Section, "Smart Grid electric system upgrades" shall have the meaning set forth in subsection (a) of Section 16-108.6 of this Act.

The investments in the infrastructure investment program described in this subsection (b) shall be incremental to the participating utility's annual capital investment program, as defined by, for purposes of this subsection (b), the participating utility's average capital spend for calendar years 2008, 2009, and 2010 as reported in the applicable Federal Energy Regulatory Commission (FERC) Form 1; provided that where one or more utilities have merged, the average capital spend shall be determined using the aggregate of the merged utilities' capital spend reported in FERC Form 1 for the years 2008, 2009, and 2010. A participating utility may add reasonable construction ramp-up and ramp-down time to the investment periods specified in this subsection (b). For each such investment period, the ramp-up and ramp-down time shall not exceed a total of 6 months.

Within 60 days after filing a tariff under subsection (c) of this Section, a participating utility shall submit to the Commission its plan, including scope, schedule, and staffing, for satisfying its infrastructure investment program commitments pursuant to this subsection (b). The submitted plan shall include a schedule and staffing plan for the next calendar year. The plan shall also include a plan for the creation, operation, and administration of a Smart Grid test bed as described in subsection (c) of Section 16-108.8. The plan need not allocate the work equally over the respective periods, but should allocate material increments throughout such periods commensurate with the work to be undertaken. No later than April 1 of each subsequent year, the utility shall submit to the Commission a report that includes any updates to the plan, a schedule for the next calendar year, the expenditures made for the prior calendar year and cumulatively, and the number of full-time equivalent jobs created for the prior calendar year and cumulatively. If the utility is materially deficient in satisfying a schedule or staffing plan, then the report must also include a corrective action plan to address the deficiency. The fact that the plan, implementation of the plan, or a schedule changes shall not imply the imprudence or unreasonableness of the infrastructure investment program, plan, or schedule. Further, no later than 45 days following the last day of the first, second, and third quarters of each year of the plan, a participating utility shall submit to the Commission a verified quarterly report for the prior quarter that includes (i) the total number of full-time equivalent jobs created during the prior quarter, (ii) the total number of employees as of the last day of the prior quarter, (iii) the total number of full-time equivalent hours in each job classification or job title, (iv) the total number of incremental employees and contractors in support of the investments undertaken pursuant to this subsection (b) for the prior quarter, and (v) any other information that the Commission may require by rule.

With respect to the participating utility's peak job commitment, if, after considering the utility's corrective action plan and compliance thereunder, the Commission enters an order finding, after notice and hearing, that a participating utility did not satisfy its peak job commitment described in this subsection (b) for reasons that are reasonably within its control, then the Commission shall also determine, after consideration of the evidence, including, but not limited to, evidence submitted by the Department of Commerce and Economic Opportunity and the utility, the deficiency in the number of full-time equivalent jobs during the peak program year due to such failure. The Commission shall notify the Department of any proceeding that is initiated pursuant to this paragraph. For each full-time equivalent job deficiency during the peak program year that the Commission finds as set forth in this paragraph, the participating utility shall, within 30 days after the entry of the Commission's order, pay $6,000 to a fund for training grants administered under Section 605-800 of The Department of Commerce and Economic Opportunity Law, which shall not be a recoverable expense.

With respect to the participating utility's investment amount commitments, if, after considering the utility's corrective action plan and compliance thereunder, the Commission enters an order finding, after notice and hearing, that a participating utility is not satisfying its investment amount commitments described in this subsection (b), then the utility shall no longer be eligible to annually update the performance-based formula rate tariff pursuant to subsection (d) of this Section. In such event, the then current rates shall remain in effect until such time as new rates are set pursuant to Article IX of this Act, subject to retroactive adjustment, with interest, to reconcile rates charged with actual costs.

If the Commission finds that a participating utility is no longer eligible to update the performance-based formula rate tariff pursuant to subsection (d) of this Section, or the performance-based formula rate is otherwise terminated, then the participating utility's voluntary commitments and obligations under this subsection (b) shall immediately terminate, except for the utility's obligation to pay an amount already owed to the fund for training grants pursuant to a Commission order.

In meeting the obligations of this subsection (b), to the extent feasible and consistent with State and federal law, the investments under the infrastructure investment program should provide employment opportunities for all segments of the population and workforce, including minority-owned and female-owned business enterprises, and shall not, consistent with State and federal law, discriminate based on race or socioeconomic status.

(b-5) Nothing in this Section shall prohibit the Commission from investigating the prudence and reasonableness of the expenditures made under the infrastructure investment program during the annual review required by subsection (d) of this Section and shall, as part of such investigation, determine whether the utility's actual costs under the program are prudent and reasonable. The fact that a participating utility invests more than the minimum amounts specified in subsection (b) of this Section or its plan shall not imply imprudence or unreasonableness.

If the participating utility finds that it is implementing its plan for satisfying the infrastructure investment program commitments described in subsection (b) of this Section at a cost below the estimated amounts specified in subsection (b) of this Section, then the utility may file a petition with the Commission requesting that it be permitted to satisfy its commitments by spending less than the estimated amounts specified in subsection (b) of this Section. The Commission shall, after notice and hearing, enter its order approving, or approving as modified, or denying each such petition within 150 days after the filing of the petition.

In no event, absent General Assembly approval, shall the capital investment costs incurred by a participating utility other than a combination utility in satisfying its infrastructure investment program commitments described in subsection (b) of this Section exceed $3,000,000,000 or, for a participating utility that is a combination utility, $720,000,000. If the participating utility's updated cost estimates for satisfying its infrastructure investment program commitments described in subsection (b) of this Section exceed the limitation imposed by this subsection (b-5), then it shall submit a report to the Commission that identifies the increased costs and explains the reason or reasons for the increased costs no later than the year in which the utility estimates it will exceed the limitation. The Commission shall review the report and shall, within 90 days after the participating utility files the report, report to the General Assembly its findings regarding the participating utility's report. If the General Assembly does not amend the limitation imposed by this subsection (b-5), then the utility may modify its plan so as not to exceed the limitation imposed by this subsection (b-5) and may propose corresponding changes to the metrics established pursuant to subparagraphs (5) through (8) of subsection (f) of this Section, and the Commission may modify the metrics and incremental savings goals established pursuant to subsection (f) of this Section accordingly.

(b-10) All participating utilities shall make contributions for an energy low-income and support program in accordance with this subsection. Beginning no later than 180 days after a participating utility files a performance-based formula rate tariff pursuant to subsection (c) of this Section, or beginning no later than January 1, 2012 if such utility files such performance-based formula rate tariff within 14 days of the effective date of this amendatory Act of the 97th General Assembly, and without obtaining any approvals from the Commission or any other agency other than as set forth in this Section, regardless of whether any such approval would otherwise be required, a participating utility other than a combination utility shall pay $10,000,000 per year for 5 years and a participating utility that is a combination utility shall pay $1,000,000 per year for 10 years to the energy low-income and support program, which is intended to fund customer assistance programs with the primary purpose being avoidance of imminent disconnection. Such programs may include:

(1) a residential hardship program that may partner with community-based organizations, including senior citizen organizations, and provides grants to low-income 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 subsection (b-10) shall not be a recoverable expense. A participating utility may elect to fund either new or existing customer assistance programs, including, but not limited to, those that are administered by the utility.

Programs that use funds that are provided by a participating utility to reduce utility bills shall 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 effective date of this amendatory Act of the 97th General Assembly. The participating utilities whose customers benefit from the funds that are disbursed as contemplated in this Section shall file annual reports documenting the disbursement of those funds with the Commission. The Commission has the authority to audit disbursement of the funds to ensure they were disbursed consistently with this Section.

If the Commission finds that a participating utility is no longer eligible to update the performance-based formula rate tariff pursuant to subsection (d) of this Section, or the performance-based formula rate is otherwise terminated, then the participating utility's voluntary commitments and obligations under this subsection (b-10) shall immediately terminate.

(c) A participating utility shall may elect to recover its delivery services costs through a performance-based formula rate approved by the Commission, which shall specify the cost components that form the basis of the rate charged to customers with sufficient specificity to operate in a standardized manner and be updated annually with transparent information that reflects the utility's actual costs to be recovered during the applicable rate year, which is the period beginning with the first billing day of January and extending through the last billing day of the following December. In the event the utility recovers a portion of its costs through automatic adjustment clause tariffs on the effective date of this amendatory Act of the 97th General Assembly, the utility may elect to continue to recover these costs through such tariffs, but then these costs shall not be recovered through the performance-based formula rate. In the event the participating utility, prior to the effective date of this amendatory Act of the 97th General Assembly, filed electric delivery services tariffs with the Commission pursuant to Section 9-201 of this Act that are related to the recovery of its electric delivery services costs that are still pending on the effective date of this amendatory Act of the 97th General Assembly, the participating utility shall, at the time it files its performance-based formula rate tariff with the Commission, also file a notice of withdrawal with the Commission to withdraw the electric delivery services tariffs previously filed pursuant to Section 9-201 of this Act. Upon receipt of such notice, the Commission shall dismiss with prejudice any docket that had been initiated to investigate the electric delivery services tariffs filed pursuant to Section 9-201 of this Act, and such tariffs and the record related thereto shall not be the subject of any further hearing, investigation, or proceeding of any kind related to rates for electric delivery services.

The performance-based formula rate shall be implemented through a tariff filed with the Commission consistent with the provisions of this subsection (c) that shall be applicable to all delivery services customers. The Commission shall initiate and conduct an investigation of the tariff in a manner consistent with the provisions of this subsection (c) and the provisions of Article IX of this Act to the extent they do not conflict with this subsection (c). Except in the case where the Commission finds, after notice and hearing, that a participating utility is not satisfying its investment amount commitments under subsection (b) of this Section, the performance-based formula rate shall remain in effect at the discretion of the utility. The performance-based formula rate approved by the Commission shall do the following:

(1) Provide for the recovery of the utility's actual costs of delivery services that are prudently incurred and reasonable in amount consistent with Commission practice and law. The sole fact that a cost differs from that incurred in a prior calendar year or that an investment is different from that made in a prior calendar year shall not imply the imprudence or unreasonableness of that cost or investment.

(2) Reflect the utility's actual year-end capital structure for the applicable calendar year, excluding goodwill, subject to a determination of prudence and reasonableness consistent with Commission practice and law.

(3) Include a cost of equity, which shall be calculated as the sum of the following:

(A) the average for the applicable calendar year of the monthly average yields of 30-year U.S. Treasury bonds published by the Board of Governors of the Federal Reserve System in its weekly H.15 Statistical Release or successor publication; and

(B) 580 basis points.

At such time as the Board of Governors of the Federal Reserve System ceases to include the monthly average yields of 30-year U.S. Treasury bonds in its weekly H.15 Statistical Release or successor publication, the monthly average yields of the U.S. Treasury bonds then having the longest duration published by the Board of Governors in its weekly H.15 Statistical Release or successor publication shall instead be used for purposes of this paragraph (3).

(4) Permit and set forth protocols, subject to a determination of prudence and reasonableness consistent with Commission practice and law, for the following:

(A) recovery of incentive compensation expense that is based on the achievement of operational metrics, including metrics related to budget controls, outage duration and frequency, safety, customer service, efficiency and productivity, and environmental compliance. Incentive compensation expense that is based on net income or an affiliate's earnings per share shall not be recoverable under the performance-based formula rate;

(B) recovery of pension and other post-employment benefits expense, provided that such costs are supported by an actuarial study;

(C) recovery of severance costs, provided that if the amount is over $3,700,000 for a participating utility that is a combination utility or $10,000,000 for a participating utility that serves more than 3 million retail customers, then the full amount shall be amortized consistent with subparagraph (F) of this paragraph (4);

(D) investment return at a rate equal to the utility's weighted average cost of long-term debt, on the pension assets as, and in the amount, reported in Account 186 (or in such other Account or Accounts as such asset may subsequently be recorded) of the utility's most recently filed FERC Form 1, net of deferred tax benefits;

(E) recovery of the expenses related to the Commission proceeding under this subsection (c) to approve this performance-based formula rate and initial rates or to subsequent proceedings related to the formula, provided that the recovery shall be amortized over a 3-year period; recovery of expenses related to the annual Commission proceedings under subsection (d) of this Section to review the inputs to the performance-based formula rate shall be expensed and recovered through the performance-based formula rate;

(F) amortization over a 5-year period of the full amount of each charge or credit that exceeds $3,700,000 for a participating utility that is a combination utility or $10,000,000 for a participating utility that serves more than 3 million retail customers in the applicable calendar year and that relates to a workforce reduction program's severance costs, changes in accounting rules, changes in law, compliance with any Commission-initiated audit, or a single storm or other similar expense, provided that any unamortized balance shall be reflected in rate base. For purposes of this subparagraph (F), changes in law includes any enactment, repeal, or amendment in a law, ordinance, rule, regulation, interpretation, permit, license, consent, or order, including those relating to taxes, accounting, or to environmental matters, or in the interpretation or application thereof by any governmental authority occurring after the effective date of this amendatory Act of the 97th General Assembly;

(G) recovery of existing regulatory assets over the periods previously authorized by the Commission;

(H) historical weather normalized billing determinants; and

(I) allocation methods for common costs.

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

(6) Provide for an annual reconciliation, as described in subsection (d) of this Section, with interest, of the revenue requirement reflected in rates for each calendar year, beginning with the calendar year in which the utility files its performance-based formula rate tariff pursuant to subsection (c) of this Section, with what the revenue requirement would have been had the actual cost information for the applicable calendar year been available at the filing date.

The utility shall file, together with its tariff, final data based on its most recently filed FERC Form 1, plus projected plant additions and correspondingly updated depreciation reserve and expense for the calendar year in which the tariff and data are filed, that shall populate the performance-based formula rate and set the initial delivery services rates under the formula. For purposes of this Section, "FERC Form 1" means the Annual Report of Major Electric Utilities, Licensees and Others that electric utilities are required to file with the Federal Energy Regulatory Commission under the Federal Power Act, Sections 3, 4(a), 304 and 209, modified as necessary to be consistent with 83 Ill. Admin. Code Part 415 as of May 1, 2011. Nothing in this Section is intended to allow costs that are not otherwise recoverable to be recoverable by virtue of inclusion in FERC Form 1.

After the utility files its proposed performance-based formula rate structure and protocols and initial rates, the Commission shall initiate a docket to review the filing. The Commission shall enter an order approving, or approving as modified, the performance-based formula rate, including the initial rates, as just and reasonable within 270 days after the date on which the tariff was filed, or, if the tariff is filed within 14 days after the effective date of this amendatory Act of the 97th General Assembly, then by May 31, 2012. Such review shall be based on the same evidentiary standards, including, but not limited to, those concerning the prudence and reasonableness of the costs incurred by the utility, the Commission applies in a hearing to review a filing for a general increase in rates under Article IX of this Act. The initial rates shall take effect within 30 days after the Commission's order approving the performance-based formula rate tariff.

Until such time as the Commission approves a different rate design and cost allocation pursuant to subsection (e) of this Section, rate design and cost allocation across customer classes shall be consistent with the Commission's most recent order regarding the participating utility's request for a general increase in its delivery services rates.

Subsequent changes to the performance-based formula rate structure or protocols shall be made as set forth in Section 9-201 of this Act, but nothing in this subsection (c) is intended to limit the Commission's authority under Article IX and other provisions of this Act to initiate an investigation of a participating utility's performance-based formula rate tariff, provided that any such changes shall be consistent with paragraphs (1) through (6) of this subsection (c). Any change ordered by the Commission shall be made at the same time new rates take effect following the Commission's next order pursuant to subsection (d) of this Section, provided that the new rates take effect no less than 30 days after the date on which the Commission issues an order adopting the change.

A participating utility that files a tariff pursuant to this subsection (c) must submit a one-time $200,000 filing fee at the time the Chief Clerk of the Commission accepts the filing, which shall be a recoverable expense.

In the event the performance-based formula rate is terminated, the then current rates shall remain in effect until such time as new rates are set pursuant to Article IX of this Act, subject to retroactive rate adjustment, with interest, to reconcile rates charged with actual costs. At such time that the performance-based formula rate is terminated, the participating utility's voluntary commitments and obligations under subsection (b) of this Section shall immediately terminate, except for the utility's obligation to pay an amount already owed to the fund for training grants pursuant to a Commission order issued under subsection (b) of this Section.

(d) Subsequent to the Commission's issuance of an order approving the utility's performance-based formula rate structure and protocols, and initial rates under subsection (c) of this Section, the utility shall file, on or before May 1 of each year, with the Chief Clerk of the Commission its updated cost inputs to the performance-based formula rate for the applicable rate year and the corresponding new charges. Each such filing shall conform to the following requirements and include the following information:

(1) The inputs to the performance-based formula rate for the applicable rate year shall be based on final historical data reflected in the utility's most recently filed annual FERC Form 1 plus projected plant additions and correspondingly updated depreciation reserve and expense for the calendar year in which the inputs are filed. The filing shall also include a reconciliation of the revenue requirement that was in effect for the prior rate year (as set by the cost inputs for the prior rate year) with the actual revenue requirement for the prior rate year (determined using a year-end rate base) that uses amounts reflected in the applicable FERC Form 1 that reports the actual costs for the prior rate year. Any over-collection or under-collection indicated by such reconciliation shall be reflected as a credit against, or recovered as an additional charge to, respectively, with interest calculated at a rate equal to the utility's weighted average cost of capital approved by the Commission for the prior rate year, the charges for the applicable rate year. Provided, however, that the first such reconciliation shall be for the calendar year in which the utility files its performance-based formula rate tariff pursuant to subsection (c) of this Section and shall reconcile (i) the revenue requirement or requirements established by the rate order or orders in effect from time to time during such calendar year (weighted, as applicable) with (ii) the revenue requirement determined using a year-end rate base for that calendar year calculated pursuant to the performance-based formula rate using (A) actual costs for that year as reflected in the applicable FERC Form 1, and (B) for the first such reconciliation only, the cost of equity, which shall be calculated as the sum of 590 basis points plus the average for the applicable calendar year of the monthly average yields of 30-year U.S. Treasury bonds published by the Board of Governors of the Federal Reserve System in its weekly H.15 Statistical Release or successor publication. The first such reconciliation is not intended to provide for the recovery of costs previously excluded from rates based on a prior Commission order finding of imprudence or unreasonableness. Each reconciliation shall be certified by the participating utility in the same manner that FERC Form 1 is certified. The filing shall also include the charge or credit, if any, resulting from the calculation required by paragraph (6) of subsection (c) of this Section.

Notwithstanding anything that may be to the contrary, the intent of the reconciliation is to ultimately reconcile the revenue requirement reflected in rates for each calendar year, beginning with the calendar year in which the utility files its performance-based formula rate tariff pursuant to subsection (c) of this Section, with what the revenue requirement determined using a year-end rate base for the applicable calendar year would have been had the actual cost information for the applicable calendar year been available at the filing date.

(2) The new charges shall take effect beginning on the first billing day of the following January billing period and remain in effect through the last billing day of the next December billing period regardless of whether the Commission enters upon a hearing pursuant to this subsection (d).

(3) The filing shall include relevant and necessary data and documentation for the applicable rate year that is consistent with the Commission's rules applicable to a filing for a general increase in rates or any rules adopted by the Commission to implement this Section. Normalization adjustments shall not be required. Notwithstanding any other provision of this Section or Act or any rule or other requirement adopted by the Commission, a participating utility that is a combination utility with more than one rate zone shall not be required to file a separate set of such data and documentation for each rate zone and may combine such data and documentation into a single set of schedules.

Within 45 days after the utility files its annual update of cost inputs to the performance-based formula rate, the Commission shall have the authority, either upon complaint or its own initiative, but with reasonable notice, to enter upon a hearing concerning the prudence and reasonableness of the costs incurred by the utility to be recovered during the applicable rate year that are reflected in the inputs to the performance-based formula rate derived from the utility's FERC Form 1. During the course of the hearing, each objection shall be stated with particularity and evidence provided in support thereof, after which the utility shall have the opportunity to rebut the evidence. Discovery shall be allowed consistent with the Commission's Rules of Practice, which Rules shall be enforced by the Commission or the assigned hearing examiner. The Commission shall apply the same evidentiary standards, including, but not limited to, those concerning the prudence and reasonableness of the costs incurred by the utility, in the hearing as it would apply in a hearing to review a filing for a general increase in rates under Article IX of this Act. The Commission shall not, however, have the authority in a proceeding under this subsection (d) to consider or order any changes to the structure or protocols of the performance-based formula rate approved pursuant to subsection (c) of this Section. In a proceeding under this subsection (d), the Commission shall enter its order no later than the earlier of 240 days after the utility's filing of its annual update of cost inputs to the performance-based formula rate or December 31. The Commission's determinations of the prudence and reasonableness of the costs incurred for the applicable calendar year shall be final upon entry of the Commission's order and shall not be subject to reopening, reexamination, or collateral attack in any other Commission proceeding, case, docket, order, rule or regulation, provided, however, that nothing in this subsection (d) shall prohibit a party from petitioning the Commission to rehear or appeal to the courts the order pursuant to the provisions of this Act.

In the event the Commission does not, either upon complaint or its own initiative, enter upon a hearing within 45 days after the utility files the annual update of cost inputs to its performance-based formula rate, then the costs incurred for the applicable calendar year shall be deemed prudent and reasonable, and the filed charges shall not be subject to reopening, reexamination, or collateral attack in any other proceeding, case, docket, order, rule, or regulation.

A participating utility's first filing of the updated cost inputs, and any Commission investigation of such inputs pursuant to this subsection (d) shall proceed notwithstanding the fact that the Commission's investigation under subsection (c) of this Section is still pending and notwithstanding any other law, order, rule, or Commission practice to the contrary.

(e) Nothing in subsections (c) or (d) of this Section shall prohibit the Commission from investigating, or a participating utility from filing, revenue-neutral tariff changes related to rate design of a performance-based formula rate that has been placed into effect for the utility. Following approval of a participating utility's performance-based formula rate tariff pursuant to subsection (c) of this Section, the utility shall make a filing with the Commission within one year after the effective date of the performance-based formula rate tariff that proposes changes to the tariff to incorporate the findings of any final rate design orders of the Commission applicable to the participating utility and entered subsequent to the Commission's approval of the tariff. The Commission shall, after notice and hearing, enter its order approving, or approving with modification, the proposed changes to the performance-based formula rate tariff within 240 days after the utility's filing. Following such approval, the utility shall make a filing with the Commission during each subsequent 3-year period that either proposes revenue-neutral tariff changes or re-files the existing tariffs without change, which shall present the Commission with an opportunity to suspend the tariffs and consider revenue-neutral tariff changes related to rate design.

(f) Within 30 days after the filing of a tariff pursuant to subsection (c) of this Section, each participating utility shall develop and file with the Commission multi-year metrics designed to achieve, ratably (i.e., in equal segments) over a 10-year period, improvement over baseline performance values as follows:

(1) Twenty percent improvement in the System Average Interruption Frequency Index, using a baseline of the average of the data from 2001 through 2010.

(2) Fifteen percent improvement in the system Customer Average Interruption Duration Index, using a baseline of the average of the data from 2001 through 2010.

(3) For a participating utility other than a combination utility, 20% improvement in the System Average Interruption Frequency Index for its Southern Region, using a baseline of the average of the data from 2001 through 2010. For purposes of this paragraph (3), Southern Region shall have the meaning set forth in the participating utility's most recent report filed pursuant to Section 16-125 of this Act.

(3.5) For a participating utility other than a combination utility, 20% improvement in the System Average Interruption Frequency Index for its Northeastern Region, using a baseline of the average of the data from 2001 through 2010. For purposes of this paragraph (3.5), Northeastern Region shall have the meaning set forth in the participating utility's most recent report filed pursuant to Section 16-125 of this Act.

(4) Seventy-five percent improvement in the total number of customers who exceed the service reliability targets as set forth in subparagraphs (A) through (C) of paragraph (4) of subsection (b) of 83 Ill. Admin. Code Part 411.140 as of May 1, 2011, using 2010 as the baseline year.

(5) Reduction in issuance of estimated electric bills: 90% improvement for a participating utility other than a combination utility, and 56% improvement for a participating utility that is a combination utility, using a baseline of the average number of estimated bills for the years 2008 through 2010.

(6) Consumption on inactive meters: 90% improvement for a participating utility other than a combination utility, and 56% improvement for a participating utility that is a combination utility, using a baseline of the average unbilled kilowatthours for the years 2009 and 2010.

(7) Unaccounted for energy: 50% improvement for a participating utility other than a combination utility using a baseline of the non-technical line loss unaccounted for energy kilowatthours for the year 2009.

(8) Uncollectible expense: reduce uncollectible expense by at least $30,000,000 for a participating utility other than a combination utility and by at least $3,500,000 for a participating utility that is a combination utility, using a baseline of the average uncollectible expense for the years 2008 through 2010.

(9) Opportunities for minority-owned and female-owned business enterprises: design a performance metric regarding the creation of opportunities for minority-owned and female-owned business enterprises consistent with State and federal law using a base performance value of the percentage of the participating utility's capital expenditures that were paid to minority-owned and female-owned business enterprises in 2010.

(10) Achieving cost-effective energy efficiency savings consistent with Section 8-103 of this Act. By January 1, 2018, each participating utility shall file with the Commission a proposed set of performance metrics designed to align financial rewards with the utility's performance relative to the goal provided in Section 8-103 of this Act.

(11) Improve load shape by achieving a 20% reduction in peak load by January 1, 2025 as compared to the baseline year of 2009 through annual incremental reductions.

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

The metrics shall include incremental performance goals for each year of the 10-year period, which shall be designed to demonstrate that the utility is on track to achieve the performance goal in each category at the end of the 10-year period. The utility shall elect when the 10-year period shall commence for the metrics set forth in subparagraphs (1) through (4) and (9) of this subsection (f), provided that it begins no later than 14 months following the date on which the utility begins investing pursuant to subsection (b) of this Section, and when the 10-year period shall commence for the metrics set forth in subparagraphs (5) through (8) of this subsection (f), provided that it begins no later than 14 months following the date on which the Commission enters its order approving the utility's Advanced Metering Infrastructure Deployment Plan pursuant to subsection (c) of Section 16-108.6 of this Act.

The metrics and performance goals set forth in subparagraphs (5) through (8) of this subsection (f) are based on the assumptions that the participating utility may fully implement the technology described in subsection (b) of this Section, including utilizing the full functionality of such technology and that there is no requirement for personal on-site notification. If the utility is unable to meet the metrics and performance goals set forth in subparagraphs (5) through (8) of this subsection (f) for such reasons, and the Commission so finds after notice and hearing, then the utility shall be excused from compliance, but only to the limited extent achievement of the affected metrics and performance goals was hindered by the less than full implementation.

(f-5) The financial penalties applicable to the metrics described in subparagraphs (1) through (8) of subsection (f) of this Section, as applicable, shall be applied through an adjustment to the participating utility's return on equity of no more than a total of 30 basis points in each of the first 3 years, of no more than a total of 34 basis points in each of the 3 years thereafter, and of no more than a total of 38 basis points in each of the 4 years thereafter, as follows:

(1) With respect to each of the incremental annual performance goals established pursuant to paragraph (1) of subsection (f) of this Section,

(A) for each year that a participating utility other than a combination utility does not achieve the annual goal, the participating utility's return on equity shall be reduced as follows: during years 1 through 3, by 5 basis points; during years 4 through 6, by 6 basis points; and during years 7 through 10, by 7 basis points; and

(B) for each year that a participating utility that is a combination utility does not achieve the annual goal, the participating utility's return on equity shall be reduced as follows: during years 1 through 3, by 10 basis points; during years 4 through 6, by 12 basis points; and during years 7 through 10, by 14 basis points.

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

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

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

(5) With respect to each of the incremental annual performance goals established pursuant to subparagraph (5) of subsection (f) of this Section, for each year that the participating utility does not achieve at least 95% of each such goal, the participating utility's return on equity shall be reduced by 5 basis points for each such unachieved goal.

(6) With respect to each of the incremental annual performance goals established pursuant to paragraphs (6), (7), and (8) of subsection (f) of this Section, as applicable, which together measure non-operational customer savings and benefits relating to the implementation of the Advanced Metering Infrastructure Deployment Plan, as defined in Section 16-108.6 of this Act, the performance under each such goal shall be calculated in terms of the percentage of the goal achieved. The percentage of goal achieved for each of the goals shall be aggregated, and an average percentage value calculated, for each year of the 10-year period. If the utility does not achieve an average percentage value in a given year of at least 95%, the participating utility's return on equity shall be reduced by 5 basis points.

The financial penalties shall be applied as described in this subsection (f-5) for the 12-month period in which the deficiency occurred through a separate tariff mechanism, which shall be filed by the utility together with its metrics. In the event the formula rate tariff established pursuant to subsection (c) of this Section terminates, the utility's obligations under subsection (f) of this Section and this subsection (f-5) shall also terminate, provided, however, that the tariff mechanism established pursuant to subsection (f) of this Section and this subsection (f-5) shall remain in effect until any penalties due and owing at the time of such termination are applied.

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

(g) On or before July 31, 2014, each participating utility shall file a report with the Commission that sets forth the average annual increase in the average amount paid per kilowatthour for residential eligible retail customers, exclusive of the effects of energy efficiency programs, comparing the 12-month period ending May 31, 2012; the 12-month period ending May 31, 2013; and the 12-month period ending May 31, 2014. For a participating utility that is a combination utility with more than one rate zone, the weighted average aggregate increase shall be provided. The report shall be filed together with a statement from an independent auditor attesting to the accuracy of the report. The cost of the independent auditor shall be borne by the participating utility and shall not be a recoverable expense. "The average amount paid per kilowatthour" shall be based on the participating utility's tariffed rates actually in effect and shall not be calculated using any hypothetical rate or adjustments to actual charges (other than as specified for energy efficiency) as an input.

In the event that the average annual increase exceeds 2.5% as calculated pursuant to this subsection (g), then Sections 16-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act, other than this subsection, shall be inoperative as they relate to the utility and its service area as of the date of the report due to be submitted pursuant to this subsection and the utility shall no longer be eligible to annually update the performance-based formula rate tariff pursuant to subsection (d) of this Section. In such event, the then current rates shall remain in effect until such time as new rates are set pursuant to Article IX of this Act, subject to retroactive adjustment, with interest, to reconcile rates charged with actual costs, and the participating utility's voluntary commitments and obligations under subsection (b) of this Section shall immediately terminate, except for the utility's obligation to pay an amount already owed to the fund for training grants pursuant to a Commission order issued under subsection (b) of this Section.

In the event that the average annual increase is 2.5% or less as calculated pursuant to this subsection (g), then the performance-based formula rate shall remain in effect as set forth in this Section.

For purposes of this Section, the amount per kilowatthour means the total amount paid for electric service expressed on a per kilowatthour basis, and the total amount paid for electric service includes without limitation amounts paid for supply, transmission, distribution, surcharges, and add-on taxes exclusive of any increases in taxes or new taxes imposed after the effective date of this amendatory Act of the 97th General Assembly. For purposes of this Section, "eligible retail customers" shall have the meaning set forth in Section 16-111.5 of this Act.

The fact that this Section becomes inoperative as set forth in this subsection shall not be construed to mean that the Commission may reexamine or otherwise reopen prudence or reasonableness determinations already made.

(h) Sections 16-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act, other than this subsection, are inoperative after December 31, 2017 for every participating utility, after which time a participating utility shall no longer be eligible to annually update the performance-based formula rate tariff pursuant to subsection (d) of this Section. At such time, the then current rates shall remain in effect until such time as new rates are set pursuant to Article IX of this Act, subject to retroactive adjustment, with interest, to reconcile rates charged with actual costs.

By December 31, 2017, the Commission shall prepare and file with the General Assembly a report on the infrastructure program and the performance-based formula rate. The report shall include the change in the average amount per kilowatthour paid by residential customers between June 1, 2011 and May 31, 2017. If the change in the total average rate paid exceeds 2.5% compounded annually, the Commission shall include in the report an analysis that shows the portion of the change due to the delivery services component and the portion of the change due to the supply component of the rate. The report shall include separate sections for each participating utility.

In the event Sections 16-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act do not become inoperative after December 31, 2017, then these Sections are inoperative after December 31, 2022 for every participating utility, after which time a participating utility shall no longer be eligible to annually update the performance-based formula rate tariff pursuant to subsection (d) of this Section. At such time, the then current rates shall remain in effect until such time as new rates are set pursuant to Article IX of this Act, subject to retroactive adjustment, with interest, to reconcile rates charged with actual costs.

The fact that this Section becomes inoperative as set forth in this subsection shall not be construed to mean that the Commission may reexamine or otherwise reopen prudence or reasonableness determinations already made. The fact that this Section becomes inoperative, as set forth in this Section, shall not eliminate a utility's obligations under Section 8-103 of this Act.

(i) While a participating utility may use, develop, and maintain broadband systems and the delivery of broadband services, voice-over-internet-protocol services, telecommunications services, and cable and video programming services for use in providing delivery services and Smart Grid functionality or application to its retail customers, including, but not limited to, the installation, implementation and maintenance of Smart Grid electric system upgrades as defined in Section 16-108.6 of this Act, a participating utility is prohibited from offering to its retail customers broadband services or the delivery of broadband services, voice-over-internet-protocol services, telecommunications services, or cable or video programming services, unless they are part of a service directly related to delivery services or Smart Grid functionality or applications as defined in Section 16-108.6 of this Act, and from recovering the costs of such offerings from retail customers.

(j) Nothing in this Section is intended to legislatively overturn the opinion issued in Commonwealth Edison Co. v. Ill. Commerce Comm'n, Nos. 2-08-0959, 2-08-1037, 2-08-1137, 1-08-3008, 1-08-3030, 1-08-3054, 1-08-3313 cons. (Ill. App. Ct. 2d Dist. Sept. 30, 2010). This amendatory Act of the 97th General Assembly shall not be construed as creating a contract between the General Assembly and the participating utility, and shall not establish a property right in the participating utility.

(k) The changes made in subsections (c) and (d) of this Section by this amendatory Act of the 98th General Assembly are intended to be a restatement and clarification of existing law, and intended to give binding effect to the provisions of House Resolution 1157 adopted by the House of Representatives of the 97th General Assembly and Senate Resolution 821 adopted by the Senate of the 97th General Assembly that are reflected in paragraph (3) of this subsection. In addition, this amendatory Act of the 98th General Assembly preempts and supersedes any final Commission orders entered in Docket Nos. 11-0721, 12-0001, 12-0293, and 12-0321 to the extent inconsistent with the amendatory language added to subsections (c) and (d).

(1) No earlier than 5 business days after the effective date of this amendatory Act of the 98th General Assembly, each participating utility shall file any tariff changes necessary to implement the amendatory language set forth in subsections (c) and (d) of this Section by this amendatory Act of the 98th General Assembly and a revised revenue requirement under the participating utility's performance-based formula rate. The Commission shall enter a final order approving such tariff changes and revised revenue requirement within 21 days after the participating utility's filing.

(2) Notwithstanding anything that may be to the contrary, a participating utility may file a tariff to retroactively recover its previously unrecovered actual costs of delivery service that are no longer subject to recovery through a reconciliation adjustment under subsection (d) of this Section. This retroactive recovery shall include any derivative adjustments resulting from the changes to subsections (c) and (d) of this Section by this amendatory Act of the 98th General Assembly. Such tariff shall allow the utility to assess, on current customer bills over a period of 12 monthly billing periods, a charge or credit related to those unrecovered costs with interest at the utility's weighted average cost of capital during the period in which those costs were unrecovered. A participating utility may file a tariff that implements a retroactive charge or credit as described in this paragraph for amounts not otherwise included in the tariff filing provided for in paragraph (1) of this subsection (k). The Commission shall enter a final order approving such tariff within 21 days after the participating utility's filing.

(3) The tariff changes described in paragraphs (1) and (2) of this subsection (k) shall relate only to, and be consistent with, the following provisions of this amendatory Act of the 98th General Assembly: paragraph (2) of subsection (c) regarding year-end capital structure, subparagraph (D) of paragraph (4) of subsection (c) regarding pension assets, and subsection (d) regarding the reconciliation components related to year-end rate base and interest calculated at a rate equal to the utility's weighted average cost of capital.

(4) Nothing in this subsection is intended to effect a dismissal of or otherwise affect an appeal from any final Commission orders entered in Docket Nos. 11-0721, 12-0001, 12-0293, and 12-0321 other than to the extent of the amendatory language contained in subsections (c) and (d) of this amendatory Act of the 98th General Assembly.

(l) Each participating utility shall be deemed to have been in full compliance with all requirements of subsection (b) of this Section, subsection (c) of this Section, Section 16-108.6 of this Act, and all Commission orders entered pursuant to Sections 16-108.5 and 16-108.6 of this Act, up to and including the effective date of this amendatory Act of the 98th General Assembly. The Commission shall not undertake any investigation of such compliance and no penalty shall be assessed or adverse action taken against a participating utility for noncompliance with Commission orders associated with subsection (b) of this Section, subsection (c) of this Section, and Section 16-108.6 of this Act prior to such date. Each participating utility other than a combination utility shall be permitted, without penalty, a period of 12 months after such effective date to take actions required to ensure its infrastructure investment program is in compliance with subsection (b) of this Section and with Section 16-108.6 of this Act. Provided further:

(1) if this amendatory Act of the 98th General Assembly takes effect on or before June 15, 2013, the following subparagraphs shall apply to a participating utility other than a combination utility:

(A) if the Commission has initiated a proceeding pursuant to subsection (e) of Section 16-108.6 of this Act that is pending as of the effective date of this amendatory Act of the 98th General Assembly, then the order entered in such proceeding shall, after notice and hearing, accelerate the commencement of the meter deployment schedule approved in the final Commission order on rehearing entered in Docket No. 12-0298;

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

(C) if the Commission has not initiated a proceeding pursuant to subsection (e) of Section 16-108.6 of this Act prior to the effective date of this amendatory Act of the 98th General Assembly, then the utility shall file with the Commission, within 45 days after such effective date, a plan for accelerating the commencement of the utility's meter deployment schedule approved in the final Commission order on rehearing entered in Docket No. 12-0298 and the Commission shall, after notice and hearing, approve or approve as modified such plan within 90 days after the utility's filing;

(2) if this amendatory Act of the 98th General Assembly takes effect after June 15, 2013, then each participating utility other than a combination utility shall file with the Commission, within 45 days after such effective date, a plan for accelerating the commencement of the utility's meter deployment schedule approved in the final Commission order on rehearing entered in Docket No. 12-0298; the Commission shall reopen the most recent proceeding in which it entered an order pursuant to subsection (e) of Section 16-108.6 of this Act and within 90 days after the utility's filing shall, after notice and hearing, enter an amendatory order that approves or approves as modified such accelerated plan, provided that if there was no such prior proceeding the Commission shall open a new proceeding and within 90 days after the utility's filing shall, after notice and hearing, enter an order that approves or approves as modified such accelerated plan.

Any schedule for meter deployment approved by the Commission pursuant to subparagraphs (1) or (2) of this subsection (l) shall take into consideration procurement times for meters and other equipment and operational issues. Nothing in this amendatory Act of the 98th General Assembly shall shorten or extend the end dates for the 5-year or 10-year periods set forth in subsection (b) of this Section or Section 16-108.6 of this Act. Nothing in this subsection is intended to address whether a participating utility has, or has not, satisfied any or all of the metrics and performance goals established pursuant to subsection (f) of this Section.

(m) The provisions of this amendatory Act of the 98th General Assembly are severable under Section 1.31 of the Statute on Statutes.

(Source: P.A. 97-616, eff. 10-26-11; 97-646, eff. 12-30-11; 98-15, eff. 5-22-13.)

(220 ILCS 5/16-108.8)

Sec. 16-108.8. Illinois Smart Grid test bed.

(a) Within 180 days after the effective date of this amendatory Act of the 97th General Assembly, each participating utility, as defined by Section 16-108.5 of this Act, shall create or otherwise designate a Smart Grid test bed, which may be located at one or more places within the utility's system, for the purposes of allowing for the testing of Smart Grid technologies. The objectives of this test bed shall be to:

(1) provide an open, unbiased opportunity for testing programs, technologies, business models, and other Smart Grid-related activities;

(2) provide on-grid locations for the testing of potentially innovative Smart Grid-related technologies and services, including but not limited to those funded by the trust or foundation established pursuant to Section 16-108.7 of this Act;

(3) facilitate testing of business models or services that help integrate Smart Grid-related technologies into the electric grid, especially those business models that may help promote new products and services for retail customers;

(4) offer opportunities to test and showcase Smart Grid technologies and services, especially those likely to support the economic development goals of the State of Illinois.

(b) The test bed shall reside in one or more locations on the participating utility's network. Such locations shall be chosen by the utility to maximize the opportunity for real-time and real-world testing of Smart Grid technologies and services taking into account the safety and security of the participating utility's grid and grid operations.

(c) The participating utility, with input from the Smart Grid Advisory Council established pursuant to Section 16-108.6 of this Act, shall, as part of its filing under subsection (b) of Section 16-108.5, include a plan for the creation, operation, and administration of the test bed. This plan shall address the following:

(1) how the utility proposes to comply with each of the objectives set forth in subsection (a) of this Section;

(2) the proposed location or locations of the test bed;

(3) the process by which the utility will receive, review, and qualify proposals to use the test bed;

(4) the criteria by which the utility proposes to qualify proposals to use the test bed, including, but not limited to, safety, reliability, security, customer data security, privacy, and economic development considerations;

(5) the engineering and operations support that the utility will provide to test bed users, including provision of customer data; and

(6) the estimated costs to establish, administer and promote the availability of the test bed.

(d) The test bed should be open to all qualified entities wishing to test programs, technologies, business models, and other Smart Grid-related activities, provided that the utility retains control of its grid and operations and may reject any programs, technologies, business models, and other Smart Grid-related activities that threaten the reliability, safety, security, or operations of its network, or that would threaten the security of customer-identifiable data in the judgment of the utility. The number of technologies and entities participating in the test bed at any time may be limited by the utility based on its determination of its ability to maintain a secure, safe, and reliable grid.

(e) At a minimum, the test bed shall have the ability to receive live signals from PJM Interconnection LLC or other applicable regional transmission organization, the ability to test new applications in a utility scale environment (to include ramp rate regulations for distributed wind and solar resources), critical peak price response, and market-based power dispatch.

(f) At the end of the fourth year of operation the test bed shall be subject to an independent evaluation to determine if the test bed is meeting the objectives of this Section or is likely to meet the objectives in the future. The evaluation shall include the performance of the utility as test bed operator. Subject to the findings, the utility and the trust or foundation established pursuant to Section 16-108.7 of this Act may choose to continue operating the test bed.

(g) The utility shall be entitled to recover all prudently incurred and reasonable costs associated with evaluation of proposals, engineering, construction, operation, and administration of the test bed through the performance-based formula rate tariff established pursuant to Section 16-108.5 of this Act.

(h) The utility is authorized to charge fees to users of the test bed that shall recover the costs associated with the incremental direct costs to the utility associated with administration of the test bed, provided, however, that any such fees collected by the utility shall be used to offset the costs to be recovered pursuant to subsection (g) of this Section.

(i) On a quarterly basis, the utility shall provide the trust or foundation established pursuant to Section 16-108.7 of this Act with a report summarizing test bed activities, customers, discoveries, and other information as shall be mutually deemed relevant.

(j) To the extent practicable, the utility and trust or foundation established pursuant to Section 16-108.7 of this Act shall jointly pursue resources that enhance the capabilities and capacity of the test bed.

(k) If Section 16-108.5 of this Act becomes inoperative with respect to one or more participating utilities as set forth in subsection (g) or (h) of that Section, then Sections 16-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act shall become inoperative as to each affected utility and its service area on the same date as Section 16-108.5 become inoperative.

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

(220 ILCS 5/16-111.5)

Sec. 16-111.5. Provisions relating to electricity 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 an electricity 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 electricity 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 electricity 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) An electricity 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 an electricity a procurement plan for a portion of or all of its Illinois load. Each electricity 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 electricity 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 electricity procurement plan shall be subject to review and approval by the Commission according to the provisions set forth in this Section. An electricity 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 electricity procurement plan portfolio of products; and

(vi) an assessment of the price risk, load uncertainty, and other factors that are associated with the proposed electricity 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 electricity 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 electricity procurement plan shall include, for load requirements included in the electricity 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.

(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 electricity 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 electricity 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 electricity procurement planning period for the next electricity 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 an electricity a procurement plan by August 15th of each year, or such other date as may be required by the Commission. The electricity 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 electricity 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 electricity procurement plan. Other interested entities also may comment on the electricity 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 electricity 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 electricity procurement plan. Within 14 days following the end of the 30-day review period, the Agency shall revise the electricity procurement plan as necessary based on the comments received and file the electricity procurement plan with the Commission and post the electricity procurement plan on the websites.

(3) Within 5 days after the filing of the electricity procurement plan, any person objecting to the electricity 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 electricity procurement plan within 90 days after the filing of the electricity procurement plan by the Illinois Power Agency.

(4) The Commission shall approve the electricity procurement plan, including expressly the forecast used in the electricity 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 electricity 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 electricity procurement plan, which shall conform in all material respects to the requirements of the electricity procurement plan set forth in subsection (b); provided, however, that the Illinois Power Agency Act shall not apply to the initial electricity procurement plan prepared pursuant to this subsection. The initial electricity 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 electricity procurement plan shall be posted and made publicly available on the Commission's website. The initial electricity procurement plan may include contracts for renewable resources that extend beyond May 2009.

(i) Within 14 days following filing of the initial electricity procurement plan, any person may file a detailed objection with the Commission contesting the electricity 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 electricity 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 electricity procurement plan within 60 days after the filing of the electricity procurement plan by the electric utility.

(ii) The order shall approve or modify the electricity procurement plan, approve an independent procurement administrator, and approve or modify the electric utility's tariffs that are proposed with the initial electricity procurement plan. The Commission shall approve the electricity 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' electricity 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 electricity procurement plan its proposed tariffs through which its costs of procuring power that are incurred pursuant to a Commission-approved electricity 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 electricity 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 electricity 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 electricity 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 an electricity 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 electricity procurement plan pursuant to this subsection shall not be subject to review under or in any way limited by the provisions of Section 16-111(i) of this Act. Nothing in this Section is intended to prohibit a utility from filing for a fuel adjustment clause as is otherwise permitted under Section 9-220 of this Act.

(q) Notwithstanding any other provisions of this Section, beginning with the 2016 delivery year, the procurement of renewable energy credits in accordance with subdivision (c) of Section 1-75 of the Illinois Power Agency Act shall not be subject to this Section. For the purposes of this Section, "delivery year" has the same meaning as in Section 1-10 of the Illinois Power Agency 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) Beginning in 2012, procurement plans prepared pursuant to Section 16-111.5 of this Act shall be subject to the following additional requirements, except that beginning in 2018, any utility that has achieved the performance metrics under paragraph (10) of subsection (f) of Section 16-108.5 of this Act shall be exempt from this Section:

(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 (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.

(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 5/16-111.5C new)

Sec. 16-111.5C. Provisions related to renewable energy credit procurement.

(a) Beginning with the planning process to develop a plan or plans for implementation starting in the 2016 delivery year, a long-term renewable resources procurement plan for the procurement of renewable energy credits shall be prepared consistent with the applicable requirements of the Illinois Power Agency Act and this Section. The long-term renewable resources procurement plan and all subsequent revisions shall be subject to review and approval by the Commission according to the provisions set forth in this Section. For the purposes of this Section, "delivery year" has the same meaning as in Section 1-10 of the Illinois Power Agency Act.

(b) The long-term renewable resources planning process shall be conducted as follows:

(1) Electric utilities shall provide a range of load forecasts to the Illinois Power Agency within 30 days after the effective date of this amendatory Act of the 99th General Assembly and on July 15 of each year thereafter or upon such other date as may be required by the Commission or Agency. The load forecasts shall cover the procurement planning period through the 2030 delivery year and beyond and shall include a high-load, low-load, and expected-load scenario for the load of all customers taking delivery service from the electric utility. The utility shall provide supporting data and assumptions for each of the scenarios.

(2) The Illinois Power Agency shall publish for comment the initial long-term renewable resources plan no later than 120 days after the effective date of this amendatory Act of the 99th General Assembly and shall make revisions to the plan at least every 2 years thereafter. The long-term renewable resources procurement plan shall identify the procurement programs and competitive procurement events consistent with the applicable requirements of the Illinois Power Agency Act and designed to achieve the goals set forth in subdivision (c) of Section 1-75 of that Act. Copies of the long-term renewable resources 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 and other interested parties shall have 30 days following the date of posting to provide comment to the Agency 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 long-term renewable resources procurement plan. Within 14 days following the end of the 30-day review period, the Agency shall revise the long-term renewable resources procurement plan as necessary based on the comments received and file the plan with the Commission for review and approval.

(3) Within 14 days after the filing of the long-term renewable resources procurement plan, any person objecting to the plan shall file an objection with the Commission. Within 21 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 120 days after the filing of the procurement plan by the Illinois Power Agency.

(4) The Commission shall approve the long-term renewable resources procurement plan if the Commission determines that the plan will reasonably and prudently fulfill the relevant requirements of Section 1-56 and subdivision (c) of Section 1-75 of the Illinois Power Agency Act.

(c) The Agency or third parties contracted by the Agency shall implement all programs authorized by the Commission in an approved long-term renewable resources procurement plan. For those renewable energy credits subject to procurement through a competitive bid process under the plan, the Agency shall follow the procurement process specified in the provisions relating to electricity procurement in subsections (e) through (i) of Section 16-111.5 of this Act.

(d) An electric utility shall recover its costs incurred under this Section, including, but not limited to, the costs of procuring renewable energy credits under this Section, as a utility cost of service under the Illinois Public Utilities Act.

(e) 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 of the 99th General Assembly.

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

(220 ILCS 5/16-111.7)

Sec. 16-111.7. On-bill financing program; electric utilities.

(a) The Illinois General Assembly finds that Illinois homes and businesses have the potential to save energy through conservation and cost-effective energy efficiency measures. Programs created pursuant to this Section will allow utility customers to purchase cost-effective energy efficiency measures, including measures set forth in a Commission-approved energy efficiency and demand-response plan under Section 8-103 of this Act, with no required initial upfront payment, and to pay the cost of those products and services over time on their utility bill.

(a-5) As used in this Section:

"Eligible electric energy efficiency measure" or "measure" means a product or service for which one or more of the following is true:

(1) a building energy assessment, performed by an energy auditor who is certified by the Building Performance Institute or who holds a similar certification, has recommended the product or service as likely to be cost-effective over the course of its installed life for the building in which the measure is to be installed;

(2) the projected electricity savings (determined by rates in effect at the time of purchase) are sufficient to cover the costs of implementing the measures, including finance charges and any program fees not recovered pursuant to subsection (g) of this Section;

(3) the product or service is included in a Commission-approved energy efficiency and demand-response plan under Section 8-103 of this Act and is cost-effective as that term is defined by that Section; or

(4) the product or service is necessary to safely or correctly install to code or industry standard an efficiency measure, including, but not limited to, installation work; changes needed to plumbing or electrical connections; upgrades to wiring or fixtures; removal of hazardous materials; correction of leaks; changes to thermostats, controls or similar devices; and changes to venting or exhaust necessitated by the measure.

"Small commercial customer" means, for an electric utility serving more than 3,000,000 retail customers, those customers having peak demand of less than 100 kilowatts, and, for an electric utility serving less than 3,000,000 retail customers, those customers having peak demand of less than 150 kilowatts; provided, however, that in the event the Commission, after August 27, 2013 (the effective date of Public Act 98-586), approves changes to a utility's tariffs that reflect new or revised demand criteria for the utility's customer rate classifications, then the utility may file a petition with the Commission to revise the applicable definition of a small commercial customer to reflect the new or revised demand criteria for the purposes of this Section. After notice and hearing, the Commission shall enter an order approving, or approving with modification, the revised definition within 60 days after the utility files the petition.

(b) Notwithstanding any other provision of this Act, an electric utility serving more than 100,000 customers on January 1, 2009 shall offer a Commission-approved on-bill financing program ("program") that allows its eligible retail customers, as that term is defined in Section 16-111.5 of this Act, who own a residential single family home, duplex, or other residential building with 4 or less units, or condominium at which the electric service is being provided (i) to borrow funds from a third party lender in order to purchase electric energy efficiency measures approved under the program for installation in such home or condominium without any required upfront payment and (ii) to pay back such funds over time through the electric utility's bill. Based upon the process described in subsection (b-5) of this Section, small commercial customers who own the premises at which electric service is being provided may be included in such program. After receiving a request from an electric utility for approval of a proposed program and tariffs pursuant to this Section, the Commission shall render its decision within 120 days. If no decision is rendered within 120 days, then the request shall be deemed to be approved.

Beginning no later than December 31, 2013, an electric utility subject to this subsection (b) shall also offer its program to eligible retail customers that own multifamily residential or mixed-use buildings with no more than 50 residential units, provided, however, that such customers must either be a residential customer or small commercial customer and may not use the program in such a way that repayment of the cost of energy efficiency measures is made through tenants' utility bills. An electric utility may impose a per site loan limit not to exceed $150,000. The program, and loans issued thereunder, shall only be offered to customers of the utility that meet the requirements of this Section and that also have an electric service account at the premises where the energy efficiency measures being financed shall be installed.

Beginning no later than December 31, 2015, an electric utility subject to this subsection (b) shall also offer its program to eligible retail customers that are Unit Owners' Associations, as defined in subsection (o) of Section 2 of the Condominium Property Act, or Master Associations, as defined in subsection (u) of Section 2 of the Condominium Property Act; however, such customers must either be residential customers or small commercial customers and may not use the program in such a way that repayment of the cost of energy efficiency measures is made through unit owners' utility bills. The program and loans issued under the program shall only be offered to customers of the utility that meet the requirements of this Section and that also have an electric service account at the premises where the energy efficiency measures being financed shall be installed.

For purposes of this Section, "small commercial customer" means, for an electric utility serving more than 3,000,000 retail customers, those customers having peak demand of less than 100 kilowatts, and, for an electric utility serving less than 3,000,000 retail customers, those customers having peak demand of less than 150 kilowatts; provided, however, that in the event the Commission, after the effective date of this amendatory Act of the 98th General Assembly, approves changes to a utility's tariffs that reflects new or revised demand criteria for the utility's customer rate classifications, then the utility may file a petition with the Commission to revise the applicable definition of a small commercial customer to reflect the new or revised demand criteria for the purposes of this Section. After notice and hearing, the Commission shall enter an order approving, or approving with modification, the revised definition within 60 days after the utility files the petition.

(b-5) Within 30 days after the effective date of this amendatory Act of the 96th General Assembly, the Commission shall convene a workshop process during which interested participants may discuss issues related to the program, including program design, eligible electric energy efficiency measures, vendor qualifications, and a methodology for ensuring ongoing compliance with such qualifications, financing, sample documents such as request for proposals, contracts and agreements, dispute resolution, pre-installment and post-installment verification, and evaluation. The workshop process shall be completed within 150 days after the effective date of this amendatory Act of the 96th General Assembly.

(c) Not later than 60 days following completion of the workshop process described in subsection (b-5) of this Section, each electric utility subject to subsection (b) of this Section shall submit a proposed program to the Commission that contains the following components:

(1) A description of how the program will determine if measures to be financed are eligible electric energy efficiency measures, as defined in subsection (b) of this Section. A list of recommended electric energy efficiency measures that will be eligible for on-bill financing. An eligible electric energy efficiency measure ("measure") shall be a product or service for which one or more of the following is true:

(A) (blank);

(B) the projected electricity savings (determined by rates in effect at the time of purchase) are sufficient to cover the costs of implementing the measures, including finance charges and any program fees not recovered pursuant to subsection (f) of this Section; or

(C) the product or service is included in a Commission-approved energy efficiency and demand-response plan under Section 8-103 of this Act.

(2) The electric utility shall issue a request for proposals ("RFP") to lenders for purposes of providing financing to participants to pay for approved measures. Lenders may be for-profit or not-for-profit institutions which can accept, manage, and lend utility funds consistent with applicable financial regulations. The RFP criteria shall include, but not be limited to, the interest rate, origination fees, and credit terms. The utility shall select the winning bidders based on its evaluation of these criteria, with a preference for those bids containing the rates, fees, and terms most favorable to participants;

(3) The utility shall work with the lenders selected pursuant to the RFP process, and with vendors, to establish the terms and processes pursuant to which a participant can purchase eligible electric energy efficiency measures using the financing obtained from the lender. The vendor shall explain and offer the approved financing packaging to those customers identified in subsection (b) of this Section and shall assist customers in applying for financing. As part of the process, vendors shall also provide to participants information about any other incentives that may be available for the measures.

(4) The lender shall determine loan eligibility by first examining customer utility bill payment history, unless untimely to do so, and then by conducting conduct credit checks or undertaking undertake other appropriate measures to limit credit risk, and shall review and approve or deny financing applications submitted by customers identified in subsection (b) of this Section. If a customer is not approved for financing as a result of a credit check, the lender shall determine whether to approve or deny financing by considering the customer's utility bill repayment history and the bill reductions likely from the energy efficiency measures to be financed and other appropriate measures. Following the lender's approval of financing and the participant's purchase of the measure or measures, the lender shall forward payment information to the electric utility, and the utility shall add as a separate line item on the participant's utility bill a charge showing the amount due under the program each month.

(5) A loan issued to a participant pursuant to the program shall be the sole responsibility of the participant, and any dispute that may arise concerning the loan's terms, conditions, or charges shall be resolved between the participant and lender. Upon transfer of the property title for the premises at which the participant receives electric service from the utility or the participant's request to terminate service at such premises, the participant shall pay in full its electric utility bill, including all amounts due under the program, provided that this obligation may be modified as provided in subsection (g) of this Section. Amounts due under the program shall be deemed amounts owed for residential and, as appropriate, small commercial electric service.

(6) The electric utility shall remit payment in full to the lender each month on behalf of the participant. In the event a participant defaults on payment of its electric utility bill, the electric utility shall continue to remit all payments due under the program to the lender, up to the larger of $10,000,000 or 50% of the total allowable outstanding amount financed under paragraph (7) of this subsection (c), and the utility shall be entitled to recover all costs related to a participant's nonpayment, up to the larger of $10,000,000 or 50% of the total allowable outstanding amount financed under paragraph (7) of this subsection (c), through the automatic adjustment clause tariff established pursuant to Section 16-111.8 of this Act. In addition, the electric utility shall retain a security interest in the measure or measures purchased under the program, and the utility retains its right to disconnect a participant that defaults on the payment of its utility bill.

(7) The total annual outstanding amount financed under the program in this subsection and subsection (c-5) of this Section shall not exceed $20,000,000 $2.5 million for an electric utility or electric utilities under a single holding company, provided that the electric utility or electric utilities may petition the Commission for an increase in such amount. A utility may meet the annual obligation using funds repaid through this program or through additional contributions.

(c-5) Within 120 days after the effective date of this amendatory Act of the 98th General Assembly, each electric utility subject to the requirements of this Section shall submit an informational filing to the Commission that describes its plan for implementing the provisions of this amendatory Act of the 98th General Assembly on or before December 31, 2013. Such filing shall also describe how the electric utility shall coordinate its program with any gas utility or utilities that provide gas service to buildings within the electric utility's service territory so that it is practical and feasible for the owner of a multifamily building to make a single application to access loans for both gas and electric energy efficiency measures in any individual building.

Within 60 days after the effective date of this amendatory Act of the 99th General Assembly, each electric utility subject to the requirements of this Section shall submit a filing to the Commission that describes its plan for implementing the provisions of this amendatory Act of the 99th General Assembly on or before December 31, 2015. The Commission shall seek public comment on the utility's plan and shall issue an order approving or disapproving each plan within 120 days of 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.

(d) A program approved by the Commission shall also include the following criteria and guidelines for such program:

(1) guidelines for financing of measures installed under a program, including, but not limited to, RFP criteria and limits on both individual loan amounts and the duration of the loans;

(2) criteria and standards for identifying and approving measures;

(3) qualifications of vendors that will market or install measures, as well as a methodology for ensuring ongoing compliance with such qualifications;

(4) sample contracts and agreements necessary to implement the measures and program; and

(5) the types of data and information that utilities and vendors participating in the program shall collect for purposes of preparing the reports required under subsection (g) of this Section.

(e) The proposed program submitted by each electric utility shall be consistent with the provisions of this Section that define operational, financial and billing arrangements between and among program participants, vendors, lenders, and the electric utility.

(f) An electric utility shall recover all of the prudently incurred costs of offering a program approved by the Commission pursuant to this Section, including, but not limited to, all start-up and administrative costs and the costs for program evaluation. All prudently incurred costs under this Section shall be recovered from the residential and small commercial retail customer classes eligible to participate in the program through the automatic adjustment clause tariff established pursuant to Section 8-103 of this Act.

(g) An independent evaluation of a program shall be conducted after 3 years of the program's operation. The electric utility shall retain an independent evaluator who shall evaluate the effects of the measures installed under the program and the overall operation of the program, including, but not limited to, customer eligibility criteria and whether the payment obligation for permanent electric energy efficiency measures that will continue to provide benefits of energy savings should attach to the meter location. As part of the evaluation process, the evaluator shall also solicit feedback from participants and interested stakeholders. The evaluator shall issue a report to the Commission on its findings no later than 4 years after the date on which the program commenced, and the Commission shall issue a report to the Governor and General Assembly including a summary of the information described in this Section as well as its recommendations as to whether the program should be discontinued, continued with modification or modifications or continued without modification, provided that any recommended modifications shall only apply prospectively and to measures not yet installed or financed. The Commission's report shall discuss changes to the program that were not considered in the independent evaluation, if any.

(h) An electric utility offering a Commission-approved program pursuant to this Section shall not be required to comply with any other statute, order, rule, or regulation of this State that may relate to the offering of such program, provided that nothing in this Section is intended to limit the electric utility's obligation to comply with this Act and the Commission's orders, rules, and regulations, including Part 280 of Title 83 of the Illinois Administrative Code.

(i) The source of a utility customer's electric supply shall not disqualify a customer from participation in the utility's on-bill financing program. Customers of alternative retail electric suppliers may participate in the program under the same terms and conditions applicable to the utility's supply customers.

(Source: P.A. 97-616, eff. 10-26-11; 98-586, eff. 8-27-13.)

(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) In conjunction with energy deliveries under contracts with customers for the period through May 31, 2016, an 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) For deliveries to customers through May 31, 2016, an 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 at least one-half of the alternative retail electric supplier's compliance obligation and any one or combination of the following means to cover the remainder of the alternative retail electric supplier's compliance obligation:

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

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

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

(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. 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 compliance by the alternative retail electric supplier with this Section, including copies of all PJM-GATS and M-RETS reports, and documentation relating to banking, retiring renewable energy credits, and any other information that the Commission determines necessary to ensure compliance with this Section. 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.

(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.

(i) The obligations specified in this Section of alternative retail electric suppliers and electric utilities operating outside their service territories to procure renewable energy resources, make alternative compliance payments, and file annual reports, and the obligations of the Commission to determine and post alternative compliance payment rates, shall terminate effective with the filing of reports and full payments made by alternative retail electric suppliers for energy deliveries to customers for the period ending May 31, 2016, provided that alternative retail electric suppliers and electric utilities operating outside their service territories shall be obligated to make all alternative compliance payments that they were obligated to pay for periods through and including May 31, 2016 but were not paid as of that date and to file all required reports for periods prior to June 1, 2016. The Commission shall continue to enforce the payment of unpaid alternative compliance payments after May 31, 2016 in accordance with subsections (f) and (g) of this Section. All alternative compliance payments made after May 31, 2016 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.

(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.)

(220 ILCS 5/19-140)

Sec. 19-140. On-bill financing program; gas utilities.

(a) The Illinois General Assembly finds that Illinois homes and businesses have the potential to save energy through conservation and cost-effective energy efficiency measures. Programs created pursuant to this Section will allow utility customers to purchase cost-effective energy efficiency measures, including measures set forth in a Commission-approved energy efficiency plan under Section 8-104 of this Act, with no required initial upfront payment, and to pay the cost of those products and services over time on their utility bill.

(a-5) As used in this Section:

"Eligible gas energy efficiency measure" or "measure" means a product or service for which one or more of the following is true:

(1) a building energy assessment, performed by an energy auditor who is certified by the Building Performance Institute or who holds a similar certification, has recommended the product or service as likely to be cost-effective over the course of its installed life for the building in which the measure is to be installed;

(2) the projected gas savings (determined by rates in effect at the time of purchase) are sufficient to cover the costs of implementing the measures, including finance charges and any program fees not recovered pursuant to subsection (f) of this Section;

(3) the product or service is included in a Commission-approved energy efficiency and demand-response plan under Section 8-104 of this Act and is cost-effective as that term is defined by that Section; or

(4) the product or service is necessary to safely or correctly install to code or industry standard an efficiency measure, including, but not limited to installation work, changes needed to plumbing or electrical connections, upgrades to wiring or fixtures, removal of hazardous materials, correction of leaks, changes to thermostats, controls, or similar devices, and changes to venting or exhaust necessitated by the measure.

"Small commercial customer" for a gas utility shall be defined in that gas utility's filing that is made under subsection (c-5) of this Section.

(b) Notwithstanding any other provision of this Act, a gas utility serving more than 100,000 customers on January 1, 2009 shall offer a Commission-approved on-bill financing program ("program") that allows its retail customers who own a residential single family home, duplex, or other residential building with 4 or less units, or condominium at which the gas service is being provided (i) to borrow funds from a third party lender in order to purchase gas energy efficiency measures approved under the program for installation in such home or condominium without any required upfront payment and (ii) to pay back such funds over time through the gas utility's bill. Based upon the process described in subsection (b-5) of this Section, small commercial customers who own the premises at which gas service is being provided may be included in such program. After receiving a request from a gas utility for approval of a proposed program and tariffs pursuant to this Section, the Commission shall render its decision within 120 days. If no decision is rendered within 120 days, then the request shall be deemed to be approved. Beginning no later than December 31, 2013, a gas utility subject to this subsection (b) shall also offer its program to eligible retail customers that own a multifamily residential or mixed-use building with no more than 50 residential units, provided, however, that such customer must either be a residential customer or small commercial customer and may not use the program in such a way that repayment of the cost of energy efficiency measures is made through tenants' utility bills. A gas utility may impose a per site loan limit not to exceed $150,000. The program, and loans issued thereunder, shall only be offered to customers of the utility that meet the requirements of this Section and that also have a gas service account at the premises where the energy efficiency measures being financed shall be installed.

Beginning no later than December 31, 2015, a gas utility subject to this subsection (b) shall also offer its program to eligible retail customers that are Unit Owners' Associations, as defined in subsection (o) of Section 2 of the Condominium Property Act, or Master Associations, as defined in subsection (u) of Section 2 of the Condominium Property Act; however, such customers must either be a residential customer or small commercial customer and may not use the program in such a way that repayment of the cost of energy efficiency measures is made through unit owners' utility bills. The program and loans issued under the program shall only be offered to customers of the utility that meet the requirements of this Section and that also have a gas service account at the premises where the energy efficiency measures being financed shall be installed.

For purposes of this Section, a small commercial customer for a gas utility shall be defined in that gas utility's informational filing that is made under subsection (c-5) of this Section.

(b-5) Within 30 days after the effective date of this amendatory Act of the 96th General Assembly, the Commission shall convene a workshop process during which interested participants may discuss issues related to the program, including program design, eligible gas energy efficiency measures, vendor qualifications, and a methodology for ensuring ongoing compliance with such qualifications, financing, sample documents such as request for proposals, contracts and agreements, dispute resolution, pre-installment and post-installment verification, and evaluation. The workshop process shall be completed within 150 days after the effective date of this amendatory Act of the 96th General Assembly.

(c) Not later than 60 days following completion of the workshop process described in subsection (b-5) of this Section, each gas utility subject to subsection (b) of this Section shall submit a proposed program to the Commission that contains the following components:

(1) A description of how the program will determine if measures to be financed are eligible electric energy efficiency measures, as defined in subsection (a-5) of this Section. A list of recommended gas energy efficiency measures that will be eligible for on-bill financing. An eligible gas energy efficiency measure ("measure") shall be a product or service for which one or more of the following is true:

(A) (blank);

(B) the projected gas savings (determined by rates in effect at the time of purchase) are sufficient to cover the costs of implementing the measures, including finance charges and any program fees not recovered pursuant to subsection (f) of this Section; or

(C) the product or service is included in a Commission-approved energy efficiency plan under Section 8-104 of this Act.

(2) The gas utility shall issue a request for proposals ("RFP") to lenders for purposes of providing financing to participants to pay for approved measures. The RFP criteria shall include, but not be limited to, the interest rate, origination fees, and credit terms. The utility shall select the winning bidders based on its evaluation of these criteria, with a preference for those bids containing the rates, fees, and terms most favorable to participants.

(3) The utility shall work with the lenders selected pursuant to the RFP process, and with vendors, to establish the terms and processes pursuant to which a participant can purchase eligible gas energy efficiency measures using the financing obtained from the lender. The vendor shall explain and offer the approved financing packaging to those customers identified in subsection (b) of this Section and shall assist customers in applying for financing. As part of such process, vendors shall also provide to participants information about any other incentives that may be available for the measures.

(4) The lender shall conduct credit checks or undertake other appropriate measures to limit credit risk, and shall review and approve or deny financing applications submitted by customers identified in subsection (b) of this Section. If a customer is not approved for financing as a result of a credit check, the lender shall determine whether to approve or deny financing by considering the customer's utility bill repayment history and the bill reductions likely from the energy efficiency measures to be financed and other appropriate measures. Following the lender's approval of financing and the participant's purchase of the measure or measures, the lender shall forward payment information to the gas utility, and the utility shall add as a separate line item on the participant's utility bill a charge showing the amount due under the program each month.

(5) A loan issued to a participant pursuant to the program shall be the sole responsibility of the participant, and any dispute that may arise concerning the loan's terms, conditions, or charges shall be resolved between the participant and lender. Upon transfer of the property title for the premises at which the participant receives gas service from the utility or the participant's request to terminate service at such premises, the participant shall pay in full its gas utility bill, including all amounts due under the program, provided that this obligation may be modified as provided in subsection (g) of this Section. Amounts due under the program shall be deemed amounts owed for residential and, as appropriate, small commercial gas service.

(6) The gas utility shall remit payment in full to the lender each month on behalf of the participant. In the event a participant defaults on payment of its gas utility bill, the gas utility shall continue to remit all payments due under the program to the lender, up to the larger of $10,000,000 or 50% of the total allowable outstanding amount financed under paragraph (7) of this subsection (c), and the utility shall be entitled to recover all costs related to a participant's nonpayment, up to the larger of $10,000,000 or 50% of the total allowable outstanding amount financed under paragraph (7) of this subsection (c), through the automatic adjustment clause tariff established pursuant to Section 19-145 of this Act. In addition, the gas utility shall retain a security interest in the measure or measures purchased under the program, and the utility retains its right to disconnect a participant that defaults on the payment of its utility bill.

(7) The total outstanding amount financed under the program in this subsection and subsection (c-5) of this Section shall not exceed $20,000,000 $2.5 million for a gas utility or gas utilities under a single holding company, provided that the gas utility or gas utilities may petition the Commission for an increase in such amount.

(c-5) Within 120 days after the effective date of this amendatory Act of the 98th General Assembly, each covered gas utility shall submit an informational filing to the Commission that describes its plan for implementing the provisions of this amendatory Act of the 98th General Assembly on or before December 31, 2013. A gas utility subject to this Section shall cooperate with any electric utility that provides electric service to buildings within the gas utility's service territory so that it is practical and feasible for the owner of a multifamily building to make a single application to access loans for both gas and electric energy efficiency measures in any individual building.

Within 60 days after the effective date of this amendatory Act of the 99th General Assembly, each electric utility subject to the requirements of this Section shall submit a filing to the Commission that describes its plan for implementing the provisions of this amendatory Act of the 99th General Assembly on or before December 31, 2015. The Commission shall seek public comment on the utility's plan and shall issue an order approving or disapproving each plan within 120 days of 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.

(d) A program approved by the Commission shall also include the following criteria and guidelines for such program:

(1) guidelines for financing of measures installed under a program, including, but not limited to, RFP criteria and limits on both individual loan amounts and the duration of the loans;

(2) criteria and standards for identifying and approving measures;

(3) qualifications of vendors that will market or install measures, as well as a methodology for ensuring ongoing compliance with such qualifications;

(4) sample contracts and agreements necessary to implement the measures and program; and

(5) the types of data and information that utilities and vendors participating in the program shall collect for purposes of preparing the reports required under subsection (g) of this Section.

(e) The proposed program submitted by each gas utility shall be consistent with the provisions of this Section that define operational, financial, and billing arrangements between and among program participants, vendors, lenders, and the gas utility.

(f) A gas utility shall recover all of the prudently incurred costs of offering a program approved by the Commission pursuant to this Section, including, but not limited to, all start-up and administrative costs and the costs for program evaluation. All prudently incurred costs under this Section shall be recovered from the residential and small commercial retail customer classes eligible to participate in the program through the automatic adjustment clause tariff established pursuant to Section 8-104 of this Act.

(g) An independent evaluation of a program shall be conducted after 3 years of the program's operation. The gas utility shall retain an independent evaluator who shall evaluate the effects of the measures installed under the program and the overall operation of the program, including, but not limited to, customer eligibility criteria and whether the payment obligation for permanent gas energy efficiency measures that will continue to provide benefits of energy savings should attach to the meter location. As part of the evaluation process, the evaluator shall also solicit feedback from participants and interested stakeholders. The evaluator shall issue a report to the Commission on its findings no later than 4 years after the date on which the program commenced, and the Commission shall issue a report to the Governor and General Assembly including a summary of the information described in this Section as well as its recommendations as to whether the program should be discontinued, continued with modification or modifications or continued without modification, provided that any recommended modifications shall only apply prospectively and to measures not yet installed or financed. The Commission's report shall discuss changes to the program that were not considered in the independent evaluation, if any.

(h) A gas utility offering a Commission-approved program pursuant to this Section shall not be required to comply with any other statute, order, rule, or regulation of this State that may relate to the offering of such program, provided that nothing in this Section is intended to limit the gas utility's obligation to comply with this Act and the Commission's orders, rules, and regulations, including Part 280 of Title 83 of the Illinois Administrative Code.

(i) The source of a utility customer's gas supply shall not disqualify a customer from participation in the utility's on-bill financing program. Customers of alternative gas suppliers may participate in the program under the same terms and conditions applicable to the utility's supply customers.

(Source: P.A. 98-586, eff. 8-27-13.)

Section 15. The Environmental Protection Act is amended by changing Section 9.1 as follows:

(415 ILCS 5/9.1) (from Ch. 111 1/2, par. 1009.1)

Sec. 9.1. (a) The General Assembly finds that the federal Clean Air Act, as amended, and regulations adopted pursuant thereto establish complex and detailed provisions for State-federal cooperation in the field of air pollution control, provide for a Prevention of Significant Deterioration program to regulate the issuance of preconstruction permits to insure that economic growth will occur in a manner consistent with the preservation of existing clean air resources, and also provide for plan requirements for nonattainment areas to regulate the construction, modification and operation of sources of air pollution to insure that economic growth will occur in a manner consistent with the goal of achieving the national ambient air quality standards, and that the General Assembly cannot conveniently or advantageously set forth in this Act all the requirements of such federal Act or all regulations which may be established thereunder.

It is the purpose of this Section to avoid the existence of duplicative, overlapping or conflicting State and federal regulatory systems.

(b) The provisions of Section 111 of the federal Clean Air Act (42 USC 7411), as amended, relating to standards of performance for new stationary sources, and Section 112 of the federal Clean Air Act (42 USC 7412), as amended, relating to the establishment of national emission standards for hazardous air pollutants are applicable in this State and are enforceable under this Act. Any such enforcement shall be stayed consistent with any stay granted in any federal judicial action to review such standards. Enforcement shall be consistent with the results of any such judicial review.

(b-5) (1) Upon the promulgation by the U.S. Environmental Protection Agency (USEPA) of a final rule regulating carbon dioxide emissions from existing electric generating units under 42 U.S.C. 7411(d) that allows for mass-based compliance and maintains state flexibility to achieve compliance using market-based tools (USEPA Rule), the Illinois Environmental Protection Agency shall develop a state implementation plan (Plan) to comply with the requirements of the USEPA rule by creating a market-based system to reduce carbon dioxide and create a revenue stream to be used by the State of Illinois consistent with paragraphs (2) through (4) of this subsection (b-5).

(2) The Illinois Environmental Protection Agency (Agency) is authorized to create and implement a cap and invest program or similar market mechanism (Program) to comply with the USEPA rule, after undertaking a robust and open stakeholder process and a comprehensive analysis and modeling of the impact of such a program on Illinois' energy system, ratepayers, and communities.

(A) The Illinois Environmental Protection Agency shall adopt rules to implement the Program consistent with this Act.

(B) A comprehensive market-based program shall, at a minimum, achieve the carbon emissions reductions required to meet Illinois' mass-based goal under its Plan and create a mechanism to achieve additional emissions reductions from the power sector when implemented in conjunction with other State policies, including Illinois' Renewable Energy Standard and Energy Efficiency Resource Standard.

(C) The Illinois Environmental Protection Agency is authorized to evaluate, establish, implement, and manage an annual cap on CO2 emissions and administer an auction program to sell power sector CO2 allowances in a market-based program consistent with this Act and the USEPA rule. The Program shall include a minimum emissions allowance price calibrated to ensure compliance with the State's obligations under the USEPA rule.

(D) The Agency shall make every effort to participate in a regional program and regional allowance auctions with other states if it results in greater carbon dioxide emission reductions at a lower cost for Illinois' residents over time. The Agency may conduct Illinois-only auctions if such auctions are found to be in the best interests of Illinois ratepayers, as determined by the Agency, and after consultation with the Illinois Commerce Commission, taking into account the impact on the State's goals under the USEPA rule, State residents' health, and ratepayers. Participation in a regional program does not relieve the Agency of its obligations to comply with the provisions of this Act.

(E) The Agency shall perform an environmental justice analysis of its Plan to ensure compliance with the USEPA rule and Federal Executive Order No. 12898, including a cumulative impacts assessment as part of its environmental impact assessment of the Program, following existing USEPA methodologies.

(F) The Agency shall develop, in coordination with the Illinois Environmental Justice Commission, through an open and inclusive stakeholder process, a list of Environmental Justice Communities, defined as distinct geographic areas of low-income and minority communities that are disproportionately impacted by power plant pollution and co-pollutant emissions.

(G) Any Program shall address and mitigate the displacement of Illinois carbon dioxide emissions to other states as well as establish appropriate spatial restrictions on allowance trading to avoid the creation of co-pollutant hotspots or areas with high concentrations of co-pollutants, defined in terms of cumulative impacts.

(H) After a Program is in place, the Agency shall require existing electric generating units located in low-income and minority communities to install and maintain monitors that provide detailed information on co-pollutant emissions tied to the purchase of allowances under the program. Information on these trading transactions and reports on emission levels shall be available to the public.

(I) The authority in this subsection (b-5) is restricted to verifiable carbon dioxide emissions allowances and credits within the power sector and does not permit inclusion of carbon emissions allowances, credits, or offsets from other sectors of the economy.

(3) The Illinois Environmental Protection Agency is authorized to invest the auction proceeds under this Act in strategies to meet the State's goal under the USEPA rule, create jobs in the State's renewable energy and energy efficiency industries (as defined in the Illinois Power Agency Act), enable workers' transition to renewable energy jobs, and mitigate adverse health and economic impacts of fossil fuel-fired power plants on minority and low-income communities, in a manner consistent with this Act.

(A) A minimum of 65% of the revenue the Agency receives from the Program (Revenue) shall be directed to the Illinois Power Agency to spend on new energy efficiency and renewable energy investments anywhere in the State. At least 20% of this portion must be invested to support energy efficiency and renewable energy investments in low-income communities and low-income households, where preference shall be given to investments in communities designated as Environmental Justice Communities, followed by investments in communities where power plants are or have been located. A portion of these funds shall support energy efficiency and renewable energy projects designed to assist public institutions, including, but not limited to, hospitals, health care facilities, long-term care facilities, schools, preschools, daycare facilities, and wastewater and drinking water treatment plant operators, with reducing their operating costs.

(B) A minimum of 5% of the Revenue shall be directed to the Low Income Home Energy Assistance Program for bill assistance.

(C) A minimum of 5% of the Revenue shall be directed to assist workers in the fossil fuel-fired power plant industry to transition to renewable energy and energy efficiency jobs.

(D) A minimum of 10% of the Revenue shall be directed to communities in which power plants are or have been located to mitigate the adverse health and economic impacts of power plants on those communities. Priority shall be given to areas that are designated non-attainment for any criteria pollutant under the Clean Air Act.

(E) A maximum of 5% of the Revenue shall be reserved for program administration, pollutant and co-pollutant monitoring as required under item (H) of paragraph (2) of this subsection (b-5), to invest in innovative strategies to reduce carbon emissions in the power sector, mitigate the impacts of climate change, and to increase public awareness of the impacts of climate change.

(4) In the development and operation of the Program, the Illinois Environmental Protection Agency is prohibited from doing the following:

(A) Implementing any program that leads to the degradation of air quality, or significantly hindering the attainment of other air quality standards under this Act.

(B) Allocating CO2 allowances to sources covered under the Program for free.

(C) Approving of any CO2 credits for emission reductions, allowances, or offsets from outside the scope of the Program.

(c) The Board may adopt regulations establishing permit programs meeting the requirements of Sections 165 and 173 of the Clean Air Act (42 USC 7475 and 42 USC 7503) as amended. The Agency may adopt procedures for the administration of such programs.

(d) No person shall:

(1) violate any provisions of Sections 111, 112, 165 or 173 of the Clean Air Act, as now or hereafter amended, or federal regulations adopted pursuant thereto; or

(2) construct, install, modify or operate any equipment, building, facility, source or installation which is subject to regulation under Sections 111, 112, 165 or 173 of the Clean Air Act, as now or hereafter amended, except in compliance with the requirements of such Sections and federal regulations adopted pursuant thereto, and no such action shall be undertaken (A) without a permit granted by the Agency whenever a permit is required pursuant to (i) this Act or Board regulations or (ii) Section 111, 112, 165, or 173 of the Clean Air Act or federal regulations adopted pursuant thereto or (B) in violation of any conditions imposed by such permit. Any denial of such a permit or any conditions imposed in such a permit shall be reviewable by the Board in accordance with Section 40 of this Act.

(e) The Board shall exempt from regulation under the State Implementation Plan for ozone the volatile organic compounds which have been determined by the U.S. Environmental Protection Agency to be exempt from regulation under state implementation plans for ozone due to negligible photochemical reactivity. In accordance with subsection (b) of Section 7.2, the Board shall adopt regulations identical in substance to the U.S. Environmental Protection Agency exemptions or deletion of exemptions published in policy statements on the control of volatile organic compounds in the Federal Register by amending the list of exemptions to the Board's definition of volatile organic material found at 35 Ill. Adm. Code Part 211. The provisions and requirements of Title VII of this Act shall not apply to regulations adopted under this subsection. Section 5-35 of the Illinois Administrative Procedure Act, relating to procedures for rulemaking, does not apply to regulations adopted under this subsection. However, the Board shall provide for notice, a hearing if required by the U.S. Environmental Protection Agency, and public comment before adopted rules are filed with the Secretary of State. The Board may consolidate into a single rulemaking under this subsection all such federal policy statements published in the Federal Register within a period of time not to exceed 6 months.

(f) (Blank).

(Source: P.A. 97-95, eff. 7-12-11; 98-284, eff. 8-9-13.)

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