SB1585sam002 99TH GENERAL ASSEMBLY

Sen. Donne E. Trotter

Filed: 5/5/2016

09900SB1585sam002 LRB099 09533 EGJ 48253 a

AMENDMENT TO SENATE BILL 1585

AMENDMENT NO. ______. Amend Senate Bill 1585, AS AMENDED, by replacing everything after the enacting clause with the following:

"Section 1. Findings.

(a) In 2011, the General Assembly encouraged and enabled the State's largest electric utilities to undertake substantial investment to refurbish, rebuild, modernize, and expand Illinois' century-old electric grid. Among those investments were the deployment of a smart grid and advanced metering infrastructure platform that would be accessible to all retail customers through new, digital smart meters. This investment, now well underway, not only allows utilities to continue to provide safe, reliable, and affordable service to the State's current and future utility customers, but also empowers the citizens of this State to directly access and participate in the rapidly emerging clean energy economy while also presenting them with unprecedented choices in their source of energy supply and pricing.

To ensure that the State and its citizens, including low-income citizens, are equipped to enjoy the opportunities and benefits of the smart grid and evolving clean energy marketplace, the General Assembly finds and declares that Illinois should continue in its efforts to build the grid of the future using the smart grid and advanced metering infrastructure platform, as well as maximize the impact of the State's existing energy efficiency and renewable energy portfolio standards. Specifically, the Generally Assembly finds that:

(1) the State should encourage the adoption and deployment of cost-effective distributed energy resource technologies and devices, such as photovoltaics, which can encourage private investment in renewable energy resources, stimulate economic growth, enhance the continued diversification of Illinois' energy resource mix, and protect the Illinois environment;

(2) the State's existing energy efficiency standard should be updated to ensure that customers continue to realize increased value, to incorporate and optimize measures enabled by the smart grid, including voltage optimization measures, and to provide incentives for electric utilities to achieve the energy savings goals; and

(3) the State's electric utilities should initiate programs to study the benefits of smart-grid enabled technologies, including, but not limited to, deploying microgrids and electric vehicle charging stations. Such programs are not required to be cost effective so long as a goal of the program is to analyze cost effectiveness. The costs to implement, manage, and analyze such programs shall be recovered through delivery service rates.

(b) The General Assembly further finds that the expansion of distributed generation technologies and devices across the State necessarily disrupts existing electricity generation and distribution models and frameworks, including related rate and tariff schedules, which can lead to inequitable charges, especially for low-income customers who often encounter the most substantial obstacles to adopting costly distributed generation technologies and devices. As a result, the General Assembly finds that low-income customers should be included within the State's efforts to expand the use of distributed generation technologies and devices. To address these issues, electric utilities should also be permitted to file revised tariffs related to implementing low-income programs, demand-based delivery services charges, and unbundling supply-related charges. These changes should be designed to ensure both an equitable allocation of costs so that no customers have to pay more than their fair share of these costs and that all costs are recovered, thus ensuring better and more equitable access to distributed generation and other energy options.

Section 1.5. Zero emission standard legislative findings. The General Assembly finds and declares:

(1) Reducing emissions of carbon dioxide and other air pollutants, such as sulfur oxides, nitrogen oxides, and particulate matter, is critical to improving air quality in Illinois for Illinois residents.

(2) Sulfur oxides, nitrogen oxides, and particulate emissions have significant adverse health effects on persons exposed to them, and carbon dioxide emissions result in climate change trends that could significantly adversely impact Illinois.

(3) The existing renewable portfolio standard has been successful in promoting the growth of renewable energy generation to reduce air pollution in Illinois. However, to achieve its environmental goals, Illinois must expand its commitment to zero emission energy generation and value the environmental attributes of zero emission generation that currently falls outside the scope of the existing renewable portfolio standard, including, but not limited to, nuclear power.

(4) Preserving existing zero emission energy generation and promoting new zero emission energy generation is vital to placing the State on a glide path to achieving its environmental goals and ensuring that air quality in Illinois continues to improve.

(5) The Illinois Commerce Commission, the Illinois Power Agency, the Illinois Environmental Protection Agency, and the Department of Commerce and Economic Opportunity issued a report dated January 5, 2015 titled "Potential Nuclear Power Plant Closings in Illinois" (the Report), which addressed the issues identified by Illinois House Resolution 1146 of the 98th General Assembly, which, among other things, urged the Illinois Environmental Protection Agency to prepare a report showing how the premature closure of existing nuclear power plants in Illinois will affect the societal cost of increased greenhouse gas emissions based upon the Environmental Protection Agency's published societal cost of greenhouse gases.

(6) The Report also identified significant adverse consequences for electric reliability in Illinois, including significant voltage and thermal violations in the interstate transmission network, in the event that Illinois' existing nuclear facilities close prematurely. The Report also found that nuclear power plants are among the most reliable sources of energy, which means that electricity from nuclear power plants is available on the electric grid all hours of the day and when needed, thereby always reducing carbon emissions.

(7) Illinois House Resolution 1146 further urged that the Report make findings concerning potential market-based solutions that will ensure that the premature closure of these nuclear power plants does not occur and that the associated dire consequences to the environment, electric reliability, and the regional economy are averted.

(8) The Report identified potential market-based solutions that will ensure that the premature closure of these nuclear power plants does not occur and that the associated dire consequences to the environment, electric reliability, and the regional economy are averted.

The General Assembly therefore finds that it is necessary to establish and implement a zero emission standard, which will increase the State's reliance on zero emission energy through the procurement of zero emission energy credits from zero emission resources, in order to achieve the State's environmental objectives and reduce the adverse impact of emitted air pollutants on the health and welfare of the State's citizens.

Section 5. The Illinois Power Agency Act is amended by changing Sections 1-5, 1-10, 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) (Blank). 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) (Blank). 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) It 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 maintain and support development of clean coal technologies, generation resources that operate at all hours of the day and under all weather conditions, zero emission resources, 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 and zero emission credits from zero emission 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, zero emission energy, and renewable energy are resources currently underused in Illinois.

(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 and, beginning with the planning year commencing June 1, 2017, zero emission credits from zero emission 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 site project" means photovoltaics located at a site that is:

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

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

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

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

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

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

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

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

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

"Commission" means the Illinois Commerce Commission.

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

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

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

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

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

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

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

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

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

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

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

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

(3) located on the customer side of the customer's electric meter and is primarily used to offset that customer's electricity load or used in a community solar project; and

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

For an electric utility that services 3,000,000 or less customers in the State, "energy "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.

For an electric utility that services more than 3,000,000 customers in the State, "energy efficiency" means measures that reduce the amount of electricity or natural gas required to achieve a given end use. "Energy efficiency" includes voltage optimization measures that optimize the voltage at points on the electric distribution voltage system and thereby conserve energy consumption by electric customers. "Energy efficiency" also includes measures that reduce the total Btus of electricity, natural gas, and other fuels needed to meet the end use or uses.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

For an electric utility that serves 3,000,000 or less customers in the State, "total "Total resource cost test" or "TRC test" means a standard that is met if, for an investment in energy efficiency or demand-response measures, the benefit-cost ratio is greater than one. The benefit-cost ratio is the ratio of the net present value of the total benefits of the program to the net present value of the total costs as calculated over the lifetime of the measures. A total resource cost test compares the sum of avoided electric utility costs, representing the benefits that accrue to the system and the participant in the delivery of those efficiency measures, as well as other quantifiable societal benefits, including avoided natural gas utility costs, 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.

For an electric utility that serves more than 3,000,000 customers in the State, "total resource cost test" or "TRC test" means a standard that is met if, for an investment in energy efficiency or demand-response measures, the benefit-cost ratio is greater than one. The benefit-cost ratio is the ratio of the net present value of the total benefits of the program to the net present value of the total costs as calculated over the lifetime of the measures. A total resource cost test compares the sum of avoided electric utility costs, representing the benefits that accrue to the system and the participant in the delivery of those efficiency measures, as well as other quantifiable societal benefits, including avoided costs associated with natural gas or other fuels, to the sum of all incremental costs of end-use measures that are implemented due to the program (including both utility and participant contributions), plus costs to administer, deliver, and evaluate each demand-side program, to quantify the net savings obtained by substituting the demand-side program for supply resources. In calculating avoided costs of power and energy that an electric utility would otherwise have had to acquire, reasonable estimates shall be included of financial costs likely to be imposed by future regulations and legislation on emissions of greenhouse gases. In discounting future societal costs and benefits for the purpose of calculating net present values, a societal discount rate based on actual, long-term Treasury bond yields should be used. Notwithstanding anything to the contrary, the benefits identified in this definition shall only be included in the TRC test if they are measurable and quantifiable, and the TRC test shall not include or take into account a calculation of market price suppression effects or demand reduction induced price effects, which is intended to be a restatement and clarification of existing law by this amendatory Act of the 99th General Assembly.

"Zero emission credit" means a tradable credit that represents the environmental attributes of one megawatt hour of energy produced from a zero emission resource.

"Zero emission resource" means a facility that: (1) is fueled by nuclear power; (2) does not emit any air pollution, including sulfur dioxide, nitrogen oxide, or carbon dioxide, as reported in the Generation Attribute Tracking System; and (3) is located in PJM Interconnection, LLC or the Midcontinent Independent System Operator, Inc.

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

(20 ILCS 3855/1-56)

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

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

(b) Through May 31, 2018, the The Illinois Power Agency Renewable Energy Resources Fund shall be administered by the Agency to procure renewable energy credits in the percentages specified in this subsection (b) resources. Renewable energy credits Prior to June 1, 2011, resources procured pursuant to this Section shall be procured from facilities located in Illinois, provided the resources are available from those facilities. If resources are not available in Illinois, then they shall be procured in states that adjoin Illinois. If resources are not available in Illinois or in states that adjoin Illinois, then they may be purchased elsewhere. Beginning June 1, 2011, resources procured pursuant to this Section shall be procured from facilities located in Illinois or states that adjoin Illinois. If renewable energy credits resources are not available in Illinois or in states that adjoin Illinois, then they may be procured elsewhere. To the extent available, at least 75% of these renewable energy credits resources shall come from wind generation. Of the renewable energy credits resources procured pursuant to this Section at least the following specified percentages shall come from photovoltaics on the following schedule: 0.5% by June 1, 2012; 1.5% by June 1, 2013; 3% by June 1, 2014; and 6% by June 1, 2015 and thereafter. Of the renewable energy credits resources procured pursuant to this Section, at least the following percentages shall come from distributed renewable energy generation devices: 0.5% by June 1, 2013, 0.75% by June 1, 2014, and 1% by June 1, 2015 and thereafter. To the extent available, half of the renewable energy credits resources procured from distributed renewable energy generation shall come from devices of less than 25 kilowatts in nameplate capacity. Renewable energy credits resources procured from distributed generation devices may also count towards the required percentages for wind and solar photovoltaics. Procurement of renewable energy credits resources from distributed renewable energy generation devices shall be done on an annual basis through multi-year contracts of no less than 5 years, and shall consist solely of renewable energy credits. Of the renewable energy credits from photovoltaics that are not distributed renewable energy generation devices procured pursuant to this Section, at least one-half shall come from brownfield site projects, if available. The Agency shall create application requirements for brownfield site projects that shall include, as appropriate, credit requirements for suppliers, demonstrated site control, bid bond requirements, construction completion deadlines, or other appropriate conditions to ensure confidence that selected bids will result in successful projects.

The Agency shall create credit requirements for suppliers of distributed renewable energy. In order to minimize the administrative burden of 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.

(b-5) Beginning June 1, 2018, the Illinois Power Agency Renewable Energy Resources Fund shall be administered by the Agency to implement distributed generation programs, including low-income distributed generation programs and low-income community distributed generation programs, and to purchase renewable energy credits from the distributed generation projects developed by these programs. The Agency shall be authorized to retain one or more consultants to develop, administer, aggregate, operate, maintain, and evaluate distributed generation projects, and the Agency shall retain the consultant or consultants in the same manner, to the extent practicable, as the Agency retains others to administer provisions of this Act, including, but not limited to, the procurement administrator. The Agency may conduct a procurement process to procure one or more third parties to implement all or a portion of the programs offered under this subsection (b-5), and electric utilities and their affiliates shall not be precluded from participating in such procurement.

The Agency, together with any consultants the Agency has retained, shall coordinate with Local Administrative Agencies to determine eligibility criteria for low-income distributed generation projects, provided that eligible income shall be no more than 150% of the poverty level. The Agency, in connection with Local Administrative Agencies, shall further develop the application process and participation rules that will govern low-income customers' participation in the projects.

The costs incurred by the Agency associated with the distributed generation programs and projects implemented pursuant to this subsection (b-5) shall be recovered from the Illinois Power Agency Renewable Energy Resources Fund. Such costs shall include consultant, third-party, and aggregator costs and such other administrative costs that the Agency deems (and the Commission find) appropriate to develop, administer, install, and operate distributed generation projects.

The Agency shall specify in each renewable energy resources plan how the moneys available in the Illinois Power Agency Renewable Energy Resources Fund for a given planning year shall be allocated to satisfy the requirements of this subsection (b-5), provided that 75% of the funding shall be allocated to low-income distributed generation projects and programs that use photovoltaic technology, 12.5% of the funding shall be allocated to not-for-profit distributed generation programs that use photovoltaic technology, including, but not limited to community distributed generation projects, and 12.5% of the funding shall be allocated to public building distributed generation programs that use photovoltaic technology.

The distributed generation projects and programs implemented under this subsection (b-5) shall conform to the definition of "distributed renewable energy generation device" as set forth in Section 1-10 of this Act and shall otherwise comply with the criteria and billing requirements set forth in subsection (i) of Section 16-107.6 of the Public Utilities Act; however, the low-income community distributed generation projects described in this subsection (b-5) shall not be subject to the requirement that the participant's address must be located within 5 miles of the location of the project.

(b-10) 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-15) 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.

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

(c) Pursuant to a renewable energy resources plan approved by the Commission under Section 16-111.5 of the Public Utilities Act, the The Agency shall procure renewable energy credits using moneys in the Illinois Power Agency Renewable Energy Resources Fund or moneys projected to be deposited into the Fund resources at least once each year in conjunction with a procurement event for electric utilities required to comply with Section 1-75 of the Act and shall, whenever possible, enter into long-term contracts on an annual basis for a portion of the incremental requirement for the given procurement year.

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

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

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

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

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

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

(i) Supplemental procurement process.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

(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. Beginning with the planning year commencing on June 1, 2017, the Planning and Procurement Bureau shall include in such plans and processes the procurement of zero emission credits from zero emission resources pursuant to subsection (d-5) of this Section for all of the utilities' retail customers. For planning years beginning on or after June 1, 2018, the Planning and Procurement Bureau shall include in such plans and processes the procurement of renewable energy resources for all of the utilities' retail customers in the amounts set forth in subsection (c) of this Section. The Planning and Procurement Bureau shall also develop procurement plans and conduct competitive procurement processes in accordance with the requirements of Section 16-111.5 of the Public Utilities Act for the eligible retail customers of small multi-jurisdictional electric utilities that (i) on December 31, 2005 served less than 100,000 customers in Illinois and (ii) request a procurement plan for their Illinois jurisdictional load. This Section shall not apply to a small multi-jurisdictional utility until such time as a small multi-jurisdictional utility requests the Agency to prepare a procurement plan for their Illinois jurisdictional load. For the purposes of this Section, the term "eligible retail customers" has the same definition as found in Section 16-111.5(a) of the Public Utilities Act.

(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 the applicable 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) Through May 31, 2018, the The procurement plans shall include cost-effective renewable energy resources equal to a . A minimum percentage of each utility's actual total supply to serve the load for of eligible retail customers, as defined in Section 16-111.5(a) of the Public Utilities Act, as follows 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; at least 11.5% by June 1, 2016; and at least 13% by June 1, 2017.

For planning years commencing on or after June 1, 2018, the procurement plans shall include cost-effective renewable energy resources equal to a minimum percentage of each utility's actual load for retail customers whose electric service has not been declared competitive pursuant to Section 16-113 of the Public Utilities Act, as follows: at least 14.5% by June 1, 2018, and increasing by at least 1.5% each year thereafter to at least 25% by June 1, 2025.

For planning years commencing on or after June 1, 2018, the procurement plans shall include cost-effective renewable energy resources equal to the applicable portion of each utility's actual load for retail customers whose electric service has been declared competitive pursuant to Section 16-113 of the Public Utilities Act as follows: at least 14.5% by June 1, 2018, and increasing by at least 1.5% each year thereafter to at least 25% by June 1, 2025.

Beginning June 1, 2018, the applicable portion shall be 50% of each utility's actual load for retail customers whose electric service has been declared competitive pursuant to Section 16-113 of the Public Utilities Act. No later than a date set by the Agency, the applicable portion shall increase to 75% of each utility's actual load for such retail customers, and, no later than a date set by the Agency, the applicable portion shall increase to 100% of each utility's actual load for such retail customers. However, if an alternative retail electric supplier owns facilities on December 31, 2015 that generate renewable energy resources and supplies to certain customers pursuant to Section 16-115D of the Public Utilities Act, then the applicable portion identified in this paragraph (1) shall be reduced for a given year by the amount of those renewable energy resources supplied to those retail customers.

(A) For those planning years commencing prior to June 1, 2018, the following requirements shall apply:

(i) 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, of each year thereafter through May 31, 2018 2015 and thereafter.

(ii) 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 each year thereafter through May 31, 2018. 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.

(B) For those planning years commencing after May 31, 2018 and ending May 31, 2026, the following procurement requirements shall be achieved, to the extent the resources are available:

(i) for each planning year, 75% of the total renewable energy credits procured shall come from wind generation, provided that such credits do not include any generating unit whose costs were being recovered through rates regulated by any state or states on January 1, 2017;

(ii) no later than the planning year ending May 31, 2021, 5% of the total renewable energy credits procured or the equivalent amount of renewable energy credits from 1,000 megawatts of photovoltaic distributed generation nameplate capacity, whichever is greater, shall come from new photovoltaic distributed generation projects; of that amount, to the extent possible, the Agency shall procure 75% from photovoltaic distributed generation projects having an installed nameplate capacity of less than 2 megawatts and shall procure 25% from brownfield site projects or utility-scale photovoltaic projects that are greater than 2 megawatts of installed nameplate capacity; and

(iii) no later than the planning year ending May 31, 2026, 6% of the total renewable energy credits procured or the equivalent amount of renewable energy credits from 1,500 megawatts of photovoltaic distributed generation nameplate capacity, whichever is greater, shall come from new photovoltaic distributed generation projects; of that amount, to the extent possible, the Agency shall procure 75% from photovoltaic distributed generation projects having an installed nameplate capacity of less than 2 megawatts and shall procure 25% from brownfield site projects or utility-scale photovoltaic projects that are greater than 2 megawatts of installed nameplate capacity.

(C) The Agency may procure contracts of at least 15 years in length for the resources procured under items (ii) and (iii) of subparagraph (B) of paragraph (1) of this subsection (c), for which payment shall be made in full by the contracting utilities at such time that the facility producing the renewable energy credits is interconnected at the distribution system level of the utility and energized.

(D) 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.

(E) 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. A utility shall be deemed to have fully complied with the requirements of this subsection (c) by entering into contracts to procure the applicable percentage of renewable energy resources by June 1 of each year.

(F) Renewable energy credits from photovoltaic distributed generation that are the subject of items (ii) and (iii) of subparagraph (B) of paragraph (1) of this subsection (c) shall be purchased before any other renewable energy credits are purchased until such time as the targets specified therein have been achieved.

(2) For purposes of this subsection (c), the required procurement of cost-effective renewable energy resources for a particular year commencing prior to June 1, 2018 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, and, for planning years commencing on and after June 1, 2018, the required procurement of cost-effective renewable energy resources for a particular year shall be measured as a percentage of the actual amount of electricity (megawatt-hours) delivered by the electric utility in the planning year ending immediately prior to the procurement, to all retail customers in its service territory. For purposes of this subsection (c), the amount paid per kilowatthour means the total amount paid for electric service expressed on a per kilowatthour basis. For purposes of this subsection (c), the total amount paid for electric service includes without limitation amounts paid for supply, transmission, distribution, surcharges, and add-on taxes.

Notwithstanding the requirements of this subsection (c), the total of renewable energy resources procured pursuant to the procurement plan for any single year shall be subject to the limitations of this paragraph (2). Such procurement shall be reduced for all retail customers based on the 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. To arrive at a maximum dollar amount of renewable energy resources to be procured for the particular planning year, the resulting per kilowatthour amount shall be applied to the actual amount of kilowatthours of electricity delivered by the electric utility in the planning year immediately prior to the procurement to all retail customers in its service territory. The calculations required by this paragraph (2) shall be made only once for each planning year at the time that the renewable energy resources are procured. Once the determination as to the amount of renewable energy resources to procure is made based on the calculations set forth in this paragraph (2) and the contracts procuring those amounts are executed, no subsequent rate impact determinations shall be made and no adjustments to those contract amounts shall be allowed. All costs incurred under such contracts shall be fully recoverable by the electric utility as provided in this Section.

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

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

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

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

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

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

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

(6) Beginning with the planning year commencing June 1, 2018, the procurement plan shall include a renewable energy resources plan for the procurement of renewable energy credits in accordance with the requirements of Section 1-56 of this Act and renewable energy resources in accordance with the requirements of this Section. The renewable energy resources plan shall ensure adequate, reliable, affordable, efficient, and environmentally sustainable renewable energy resources at the lowest total cost over time, taking into account any benefits of price stability. The renewable energy resources plan shall also include the items set forth in subparagraphs (i) through (iii) of paragraph (5) of subsection (b) of Section 16-111.5 of the Public Utilities Act.

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

(7) The electric utility shall be entitled to recover all of its costs associated with the procurement of renewable energy resources pursuant to this Section through an automatic adjustment clause tariff in accordance with subsection (k) of Section 16-108 of the Public Utilities Act. All procurement of renewable energy resources in the procurement plans of the electric utilities shall be pursuant to a competitive bidding process and shall be approved by the Commission pursuant to Section 16-111.5 of the Public Utilities Act.

(d) Clean coal portfolio standard.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

(B) power purchase provisions, which shall:

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

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

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

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

(C) contract for differences provisions, which shall:

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

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

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

(D) general provisions, which shall:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

The facility cost report shall be prepared as follows:

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

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

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

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

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

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

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

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

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

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

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

(d-5) Zero emission standard.

(1) Beginning with the planning year commencing on June 1, 2017, the procurement plans shall include cost-effective zero emission credits from zero emission resources in an amount equal to 16% of the actual amount of electricity delivered by each electric utility to retail customers in the State during calendar year 2014. Notwithstanding whether a procurement event is conducted pursuant to Section 16-111.5 of the Public Utilities Act, the Agency and Commission shall immediately initiate an initial procurement process upon the effective date of this amendatory Act of the 99th General Assembly, which shall procure cost-effective zero emission credits from zero emission resources, in an amount equal to, for each planning year, 16% of each electric utility's annual retail sales of electricity to retail customers in the State during calendar year 2014.

The initial procurement plan and process shall be subject to the following provisions:

(A) To assist the Agency in preparing its proposed initial procurement plan, those zero emission resources that intend to participate in the procurement shall submit to the Agency the following information for each zero emission resource on or before the date established by the Agency:

(i) the in-service date and remaining useful life of the zero emission resource;

(ii) the projected zero emission credits to be generated over the remaining useful life of the zero emission resource;

(iii) the annual zero emission resource cost projections, expressed on a per megawatthour basis, over the next 4 planning years, which shall include the following: operation and maintenance expenses; fully allocated overhead costs, which shall be allocated using the methodology developed by the Institute for Nuclear Power Operations; fuel expenditures; non-fuel capital expenditures; spent fuel expenditures; a return on working capital; and any other costs necessary for continued operations, provided that "necessary" means, for purposes of this item (iii), that the costs could reasonably be avoided only by ceasing operations of the zero emission resource. In addition, those cost projections shall be adjusted to reflect operational risks that include, but are not limited to, operational cost risk, which is the risk that operating costs will be higher than reasonably anticipated, and capacity factor risk, which is the risk that per megawatthour costs will be higher than anticipated because of a lower than expected capacity factor. The cost projections shall be further adjusted by a per megawatthour facility adjustment to reflect market risks that include, but are not limited to, liquidated damages risk, which is the risk of a forced outage and the associated costs of covering contractual obligations; volatility risk, which is the risk that output from the resource may not be able to be sold at the same forward prices used as set forth in this paragraph (1); and basis risk, which is the risk that the difference between the nodal energy price for the resource and the associated zone-wide energy price will exceed the values calculated as set forth in this paragraph (1); and

(iv) a commitment to continue operating, for the duration of the contract or contracts executed pursuant to the initial procurement held under this subsection (d-5), the zero emission resource that produces the zero emission credits to be procured in the procurement.

(B) Zero emission resources that bid into the initial procurement must commit to deliver all zero emission credits from the zero emission resource during the remaining useful life of the resource, and each winning zero emission resource shall be compensated for each planning year in an amount that equals the difference between the weighted average of all zero emission resources' average annual zero emission resource cost, expressed on a price per megawatthour basis, for the applicable planning year and each zero emission resource's projected energy revenues and projected capacity revenues for the applicable planning year. However, if the difference is a sum that is less than zero, then no compensation shall be provided to any entity. The components of this calculation are defined as follows:

(i) Weighted average of all zero emission resources' average annual zero emission resource cost: during the first 4 planning years, the weighted average of all zero emission resources' average annual zero emission resource cost shall be $42 per megawatthour. Thereafter, for each applicable planning year, the Agency shall calculate for each zero emission resource the average annual zero emission resource cost over the consecutive 4-year planning period ending immediately prior to the applicable planning year, and the average annual zero emission resource cost over the consecutive 4-year planning period ending on May 31 of the applicable planning year. The Agency shall use the 4-year cost projections submitted by zero emission resources pursuant to subparagraph (D) of this paragraph (1), and the averages calculated by the Agency shall be expressed on a price per megawatthour basis for the applicable year.

The weighted average of all zero emission resources' average annual zero emission resource cost for planning years commencing after the first 4 planning years shall be calculated using the following formula: the weighted average of all zero emission resources' average annual zero emission resource cost, expressed on a price per megawatt hour basis, established by the Commission for the planning year immediately preceding the applicable planning year multiplied by a ratio where the numerator is the weighted average of all zero emission resources' average annual zero emission resource costs over the consecutive 4-year planning period ending on May 31 of the applicable planning year and the denominator is the weighted average of all zero emission resources' average annual zero emission resource costs over the consecutive 4-year planning period ending immediately prior to the applicable planning year. The submissions and calculations required by this item (i) shall be made according to the schedule set forth in subparagraph (D) of this paragraph (1).

(ii) Projected energy revenues: the zero emission resource shall calculate projected energy revenues for the applicable planning year based on actual forward market prices as published by the Intercontinental Exchange, which shall be calculated as the average forward market energy price at the PJM Interconnection, LLC Northern Illinois Hub for all trade dates during the immediately preceding 12-month period that began on April 1 and ended March 31 and adjusted to reflect the historic basis price difference between the Northern Illinois Hub and the average day ahead price for energy during that period at the generating facility bus that is producing the credit.

(iii) Projected capacity revenues: for the planning years commencing June 1, 2017, June 1, 2018, and June 1, 2019, the zero emission resource shall calculate projected capacity revenues for the applicable planning year based on unit-specific market prices determined by the applicable regional transmission organization's procurement process, PJM Interconnection LLC or the Midcontinent Independent System Operator, Inc.; for planning years commencing after May 31, 2020, the zero emission resource shall calculate projected capacity revenues for the applicable planning year based on the zonal forward market prices determined by the applicable regional transmission organization's procurement process, PJM Interconnection LLC or the Midcontinent Independent System Operator, Inc.

(C) No later than 45 days after the effective date of this amendatory Act of the 99th General Assembly, the Agency shall submit to the Commission the proposed initial procurement plan. The plan shall be consistent with the provisions of this paragraph (1) and shall provide that winning bids shall be selected based on public interest criteria that include minimizing carbon dioxide emissions that result from electricity consumed in Illinois and minimizing sulfur dioxide, nitrogen oxide, and particulate matter emissions that adversely affect the citizens of this State. In particular, the selection of winning bids shall take into account the incremental environmental and reliability benefits resulting from the procurement, including any existing environmental and reliability benefits that are preserved by the procurement and would cease to exist if the procurement were not held. The Commission shall, after notice and hearing, but no later than 30 days after the Agency submits its plan, approve the plan or approve with modification. The Agency shall conduct the request for proposals process as soon as reasonably practicable after the effective date of this amendatory Act of the 99th General Assembly, and each utility shall enter into binding contractual arrangements with the winning suppliers. The procurement shall be completed no later than May 31, 2017. Notwithstanding the provisions of this subparagraph (C), the Agency and Commission shall conduct the procurement and plan approval processes required by this subsection (d-5) in conjunction with the procurement and plan approval processes required by subsection (c) of this Section and Section 16-111.5 of the Public Utilities Act, to the extent practicable.

Following the initial procurement event described in this paragraph (1), the Agency and Commission shall initiate additional procurement processes, as necessary, to replace any zero emission credits that were not delivered due to a supplier default or in the event that additional zero emission credits must be procured. Any such processes shall be conducted regardless of whether a procurement event is conducted pursuant to Section 16-111.5 of the Public Utilities Act. Each utility shall enter into binding contractual arrangements with the winning suppliers.

(D) Following the initial procurement event described in this paragraph (1), each zero emission resource that has executed a contract to deliver zero emission credits pursuant to this paragraph (1) shall submit its updated zero emission resource cost projections for the next 4 planning years, and projected energy revenues and projected capacity revenues for the next planning years, as those costs and revenues are defined in subparagraphs (A) and (B) of this paragraph (1), no later than April 10, 2018 and each April 10 thereafter. Consistent with subparagraph (B), the Agency shall determine the weighted average of all zero emission resources' average annual zero emission resource cost for the planning year that commences 4 years after the current planning year, on a per megawatthour basis, and shall calculate the payments to be made under each contract for the next planning year based on the updated projected energy revenues and capacity revenues submitted by the zero emission resources. The Agency shall publish the weighted average of all zero emission resources' average annual zero emission resource cost and payment calculations no later than May 25, 2018 and every May 25 thereafter.

(E) The contracts executed pursuant to this subsection (d-5) shall provide that the Agency, Commission, or zero emission resource may terminate a contract or contracts to be effective on June 1 of a given planning year, provided that notice of such termination must be made at least 4 years prior to the effective date of such termination and the earliest date on which a contract termination may take effect under this subparagraph (C) is the earlier of June 1, 2023 or 2 years after the State has adopted and implemented a plan pursuant to the provisions of Section 111(d) of the federal Clean Air Act, 42 U.S. C. 7411(d), as amended.

(F) Notwithstanding the requirements of this subsection (d-5), the contracts executed pursuant to this subsection (d-5) shall provide that the zero emission resource may, as applicable, suspend or terminate performance under the contracts in the following instances:

(i) A zero emission resource shall be excused from its performance under the contract for any cause beyond the control of the resource, including, but not restricted to, acts of God, flood, drought, earthquake, storm, fire, lightning, epidemic, war, riot, civil disturbance or disobedience, labor dispute, labor or material shortage, sabotage, acts of public enemy, explosions, orders, regulations or restrictions imposed by governmental, military, or lawfully established civilian authorities, which, in any of the foregoing cases, by exercise of commercially reasonable efforts the zero emission resource could not reasonably have been expected to avoid, and which, by the exercise of commercially reasonable efforts, it has been unable to overcome. In such event, the zero emission resource shall be excused from performance for the duration of the event, including, but not limited to, delivery of zero emission credits, and no payment shall be due to the zero emission resource during the duration of the event.

(ii) A zero emission resource shall be permitted to terminate the contract if legislation is enacted into law by the General Assembly that imposes or authorizes a new tax, special assessment, or fee on the generation of electricity, the ownership or leasehold of a generating unit, or the privilege or occupation of such generation, ownership, or leasehold of generation units by a zero emission resource. However, the provisions of this item (ii) do not apply to any generally applicable tax, special assessment or fee, or requirements imposed by federal law.

(iii) A zero emission resource shall be permitted to terminate the contract in the event that the resource requires capital expenditures that were neither known nor reasonably foreseeable at the time it executed the contract and that a prudent owner or operator of such resource would not undertake.

(iv) A zero emission resource shall be permitted to terminate the contract in the event the Nuclear Regulatory Commission terminates the resource's license.

(G) For purposes of this subsection (d-5), "cost-effective" means that the costs of procuring zero emission credits do not cause the limit stated in paragraph (2) of this subsection (d-5) to be exceeded.

(2) For purposes of this subsection (d-5), the required procurement of cost-effective zero emission credits for a particular period shall be measured as a percentage of the actual amount of electricity (megawatthours) delivered by the electric utility to all retail customers in the planning year ending immediately prior to the procurement, as incorporated in the procurement plan approved by the Commission. For purposes of this subsection (d-5), the amount paid per kilowatthour means the total amount paid for electric service expressed on a per kilowatthour basis. For purposes of this subsection (d-5), the total amount paid for electric service includes, without limitation, amounts paid for supply, transmission, distribution, surcharges, and add-on taxes.

Notwithstanding the requirements of this subsection (d-5), the total of zero emission credits procured pursuant to a procurement plan shall be subject to the limitations of this paragraph (2). For each 4-year period, the procurement shall be reduced for all retail customers based on the amount necessary to limit the annual estimated average net increase over each period due to the costs of these credits included in the amounts paid by eligible retail customers in connection with electric service to no more than 2.015% of the amount paid per kilowatthour by eligible retail customers during the year ending May 31, 2009. The result of this computation shall apply to and reduce the procurement for all retail customers, and all those customers shall pay the same single, uniform cents per kilowatthour charge pursuant to subsection (k) of Section 16-108 of the Public Utilities Act. To arrive at a maximum dollar amount of zero emission credits to be procured for the particular planning year, the resulting per kilowatthour amount shall be applied to the actual amount of kilowatthours of electricity delivered by the electric utility in the planning year immediately prior to the procurement, to all retail customers in its service territory. The calculations required by this paragraph (2) shall be made only once for each procurement plan year. Once the determination as to the amount of zero emission credits to procure is made based on the calculations set forth in this paragraph (2), no subsequent rate impact determinations shall be made and no adjustments to those contract amounts shall be allowed. All costs incurred under those contracts and in implementing this subsection (d-5) shall be recovered by the electric utility as provided in this Section.

No later than June 30, 2019, the Commission shall review the limitation on the amount of zero emission credits procured pursuant to this subsection (d-5) and report to the General Assembly its findings as to whether that limitation unduly constrains the procurement of cost-effective zero emission credits.

(3) Cost-effective zero emission credits procured from zero emission resources shall satisfy the applicable definitions set forth in Section 1-10 of this Act.

(4) The electric utility shall retire all zero emission credits used to comply with the requirements of this subsection (d-5).

(5) Electric utilities shall be entitled to recover all of the costs associated with the procurement of zero emission credits through an automatic adjustment clause tariff in accordance with subsection (k) of Section 16-108 of the Public Utilities Act.

(e) The draft procurement plans are subject to public comment, as required by Section 16-111.5 of the Public Utilities Act.

(f) The Agency shall submit the final procurement plan to the Commission. The Agency shall revise a procurement plan if the Commission determines that it does not meet the standards set forth in Section 16-111.5 of the Public Utilities Act.

(g) The Agency shall assess fees to each affected utility to recover the costs incurred in preparation of the annual procurement plan for the utility.

(h) The Agency shall assess fees to each bidder to recover the costs incurred in connection with a competitive procurement process.

(i) A renewable energy credit, carbon emission credit, or zero emission credit can only be used once to comply with a single portfolio or other standard as set forth in subsection (c), subsection (d), or subsection (d-5) of this Section, respectively. A renewable energy credit, carbon emission credit, or zero emission credit cannot be used to satisfy the requirements of more than one standard. In the event more than one type of credit is issued for the same megawatt hour of energy, only one credit can be used to satisfy the requirements of a single standard. After such use, the credit must be retired together with any other credits issued for the same megawatt hour of energy.

(Source: P.A. 97-325, eff. 8-12-11; 97-616, eff. 10-26-11; 97-618, eff. 10-26-11; 97-658, eff. 1-13-12; 97-813, eff. 7-13-12; 98-463, eff. 8-16-13.)

Section 10. The Public Utilities Act is amended by changing Sections 8-103, 8-104, 16-107, 16-107.5, 16-108, 16-111.5, 16-111.5B, 16-111.7, 16-115D, and 16-127 and by adding Sections 8-103B, 9-105, 9-107, 16-103.3, 16-107.6, 16-107.7, 16-108.9, and 16-108.10 as follows:

(220 ILCS 5/8-103)

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

(a) It is the policy of the State that electric utilities are required to use cost-effective energy efficiency and demand-response measures to reduce delivery load. Requiring investment in cost-effective energy efficiency and demand-response measures will reduce direct and indirect costs to consumers by decreasing environmental impacts and by avoiding or delaying the need for new generation, transmission, and distribution infrastructure. It serves the public interest to allow electric utilities to recover costs for reasonably and prudently incurred expenses for energy efficiency and demand-response measures. As used in this Section, "cost-effective" means that the measures satisfy the total resource cost test. The low-income measures described in subsection (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.

(a-5) This Section applies to electric utilities serving 3,000,000 or less retail customers in the State. Through December 31, 2017, this Section also applies to electric utilities serving more than 3,000,000 retail customers in the State.

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

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

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

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

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

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

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

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

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

Electric utilities may comply with this subsection (b) by meeting the annual incremental savings goal in the applicable year or by showing that the total cumulative annual savings within a 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.

(c) Electric utilities shall implement cost-effective demand-response measures to reduce peak demand by 0.1% over the prior year for eligible retail customers, as defined in Section 16-111.5 of this Act, and for customers that elect hourly service from the utility pursuant to Section 16-107 of this Act, provided those customers have not been declared competitive. 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) thereafter, the amount of energy efficiency and demand-response measures implemented for any single year shall be reduced by an amount necessary to limit the estimated average net increase due to the cost of these measures included in the amounts paid by eligible retail customers in connection with electric service to no more than the greater of 2.015% of the amount paid per kilowatthour by those customers during the year ending May 31, 2007 or the incremental amount per kilowatthour paid for these measures in 2011.

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

(e) 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. 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 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.

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. 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 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 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.

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

(7) Provide for an annual independent evaluation of the performance of the cost-effectiveness of the utility's portfolio of measures and the Department's portfolio of measures, as well as a full review of the 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.

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

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

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

(220 ILCS 5/8-103B new)

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

(a) It is the policy of the State that electric utilities are required to use cost-effective energy efficiency and demand-response measures to reduce delivery load. Requiring investment in cost-effective energy efficiency and demand-response measures will reduce direct and indirect costs to consumers by decreasing environmental impacts and by avoiding or delaying the need for new generation, transmission, and distribution infrastructure. It serves the public interest to allow electric utilities to recover costs for reasonably and prudently incurred expenses for energy efficiency and demand-response measures. As used in this Section, "cost-effective" means that the measures satisfy the total resource cost test. The low-income measures described in subsection (c) 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" 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.

(a-5) After December 31, 2017, this Section applies to electric utilities serving more than 3,000,000 retail customers in the State.

(b) For purposes of this Section, electric utilities subject to this Section shall be deemed to have achieved a cumulative persisting annual savings of 6.6%, or 5,777,692 megawatt-hours (MWhs), for the year ending December 31, 2017, which is based on the deemed average weather normalized sales of electric power and energy during calendar years 2014, 2015, and 2016 of 88,000,000 MWhs. The 88,000,000 MWhs of deemed electric power and energy sales shall also serve as the baseline value for calculating the cumulative persisting annual savings in subsection (b-5). After 2017, the deemed value of cumulative persisting annual savings shall be reduced each year, as follows, and the applicable value shall be applied to and count toward the utility's achievement of the cumulative persisting annual savings goals set forth in subsection (b-5):

(1) 5.8%, or 5,071,018 MWhs, deemed cumulative persisting annual savings for the year ending December 31, 2018;

(2) 5.2%, or 4,553,371 MWhs, deemed cumulative persisting annual savings for the year ending December 31, 2019;

(3) 4.5%, or 3,998.012 MWhs, deemed cumulative persisting annual savings for the year ending December 31, 2020;

(4) 4%, or 3,533,219 MWhs, deemed cumulative persisting annual savings for the year ending December 31, 2021;

(5) 3.5%, or 3,108,290 MWhs, deemed cumulative persisting annual savings for the year ending December 31, 2022;

(6) 3.1%, or 2,738,689 MWhs, deemed cumulative persisting annual savings for the year ending December 31, 2023;

(7) 2.8%, or 2,463,055 MWhs, deemed cumulative persisting annual savings for the year ending December 31, 2024;

(8) 2.5%, or 2,221,716 MWhs, deemed cumulative persisting annual savings for the year ending December 31, 2025;

(9) 2.3%, or 2,017,109 MWhs, deemed cumulative persisting annual savings for the year ending December 31, 2026;

(10) 2.1%, or 1,822,754 MWhs, deemed cumulative persisting annual savings for the year ending December 31, 2027;

(11) 1.8%, or 1,624,769 MWhs, deemed cumulative persisting annual savings for the year ending December 31, 2028;

(12) 1.7%, or 1,460,039 MWhs, deemed cumulative persisting annual savings for the year ending December 31, 2029; and

(13) 1.5%, or 1,181,647 MWhs, deemed cumulative persisting annual savings for the year ending December 31, 2030.

For purposes of this Section, "cumulative persisting annual savings" means the total electric energy savings in a given year from measures installed in that year or in previous years that are still operational and providing savings in that year because the measures have not yet reached the end of their useful lives.

(b-5) Beginning in 2018, electric utilities shall achieve the following cumulative persisting annual savings goals, as modified by subsection (f) of this Section and as compared to the deemed baseline of 88,000,000 MWhs of electric power and energy sales set forth in subsection (b), through the implementation of cost-effective energy efficiency measures during the applicable year and in prior years by the utility and, if applicable, the Department:

(1) 8% cumulative persisting annual savings for the year ending December 31, 2018;

(2) 9.5% cumulative persisting annual savings for the year ending December 31, 2019;

(3) 11% cumulative persisting annual savings for the year ending December 31, 2020;

(4) 12.5% cumulative persisting annual savings for the year ending December 31, 2021;

(5) 14% cumulative persisting annual savings for the year ending December 31, 2022;

(6) 15.5% cumulative persisting annual savings for the year ending December 31, 2023;

(7) 17% cumulative persisting annual savings for the year ending December 31, 2024;

(8) 18.5% cumulative persisting annual savings for the year ending December 31, 2025;

(9) 19.4% cumulative persisting annual savings for the year ending December 31, 2026;

(10) 20.3% cumulative persisting annual savings for the year ending December 31, 2027;

(11) 21.2% cumulative persisting annual savings for the year ending December 31, 2028;

(12) 22.1% cumulative persisting annual savings for the year ending December 31, 2029; and

(13) 23% cumulative persisting annual savings for the year ending December 31, 2030.

(b-10) Each electric utility that serves more than 3,000,000 retail customers in the State shall include cost-effective voltage optimization measures in its plans submitted pursuant to subsection (f) or (g) of this Section, and the costs incurred by a utility to implement the measures pursuant to a Commission-approved plan shall be recovered, at the utility's election, either through the automatic adjustment clause tariff approved under subsection (d) of this Section, an energy efficiency formula rate tariff approved under subsection (d) of this Section, or pursuant to the provisions of Article IX or Section 16-108.5 of this Act. For purposes of this Section, the measure life of voltage optimization measures shall be 15 years. The measure life period is independent of the depreciation rate of the voltage optimization assets deployed.

In the event an electric utility jointly offers an energy efficiency measure or program with a gas utility pursuant to plans approved under this Section and Section 8-104 of this Act, the electric utility may continue offering the program, including the gas energy efficiency measures, in the event the gas utility discontinues funding the program. In that event, up to 30% of the annual savings goal calculated pursuant to subsection (b) of this Section may be met through savings of fuels other than electricity, and the energy savings value associated with such other fuels shall be converted to electric energy savings on an equivalent Btu basis for the premises. However, the utility shall prioritize gas savings for low-income residential customers to the extent practicable. An electric utility may recover the costs of offering the gas energy efficiency measures pursuant to this subsection (b-10).

For those energy efficiency measures or programs that are not jointly offered with a gas utility pursuant to plans approved under this Section and Section 8-104, the electric utility may count savings of fuels other than electricity toward the achievement of its annual savings goal, and the energy savings value associated with such other fuels shall be converted to electric energy savings on an equivalent Btu basis at the premises.

(c) Electric utilities shall be responsible for overseeing the design, development, and filing of energy efficiency plans with the Commission and may, as part of that implementation, outsource various aspects of program development and implementation. A minimum of 10% of the entire portfolio budget for a given year shall be used to procure cost-effective energy efficiency measures from units of local government, municipal corporations, school districts, public housing, and community college districts, provided that a minimum percentage of available funds shall be used to procure energy efficiency from public housing, which percentage shall be equal to public housing's share of public building energy consumption.

The utilities shall also implement energy efficiency measures targeted at low-income households, which, for purposes of this Section, shall be defined as households at or below 80% of area median income, and expenditures to implement the measures shall be no less than $50,000,000 per year. For the multi-year plan commencing on January 1, 2018, the energy savings attributable to such programs shall not be less than 29,239,766 kilowatt-hours per year for the years commencing January 1, 2018 and January 1, 2019. For every 2-year period thereafter, the utility shall submit an informational filing to the Commission 90 days prior to the beginning of the 2-year period that calculates the (i) cost per kilowatt-hour of energy savings to be achieved and (ii) the resulting annual energy savings to be achieved each year, under the low-income programs during the applicable 2-year period.

Each electric utility shall assess opportunities to implement cost-effective energy efficiency measures and programs through a public housing authority or authorities located in its service territory. If such opportunities are identified, the utility shall propose such measures and programs to address the opportunities. Expenditures to address such opportunities shall be credited toward the minimum procurement and expenditure requirements set forth in this subsection (c).

Implementation of energy efficiency measures and programs targeted at low-income households should be contracted, when it is practicable, to independent third parties that have demonstrated capabilities to serve such households, with a preference for not-for-profit entities and government agencies that have existing relationships with or experience serving low-income communities in the State.

Each electric utility shall develop and implement reporting procedures that address and assist in determining the amount of energy savings that can be applied to the low-income procurement and expenditure requirements set forth in this subsection (c).

The electric utilities shall also convene a low-income energy efficiency advisory committee to assist in the design and evaluation of the low-income energy efficiency programs. The committee shall be comprised of the electric utilities subject to the requirements of this Section, the gas utilities subject to the requirements of Section 8-104 of this Act, the utilities' low-income energy efficiency implementation contractors, and representatives of community-based organizations.

(d) A utility providing approved energy efficiency measures and, if applicable, demand-response measures in the State shall be permitted to recover costs of those measures as follows:

(1) The utility may recover its costs 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.

(2) A utility may recover its costs through an energy efficiency formula rate approved by the Commission pursuant to a filing under subsection (f) or (g) of this Section, 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. The energy efficiency formula rate shall be implemented through a tariff filed with the Commission under subsection (f) or (g) of this Section that is consistent with the provisions of this paragraph (2) and that shall be applicable to all delivery services customers. The Commission shall conduct an investigation of the tariff in a manner consistent with the provisions of this paragraph (2), subsection (f) or (g) of this Section, and the provisions of Article IX of this Act to the extent they do not conflict with this paragraph (2). The energy efficiency formula rate approved by the Commission shall remain in effect at the discretion of the utility and shall do the following:

(A) Provide for the recovery of the utility's actual costs incurred under this Section 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.

(B) 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.

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

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

(ii) 580 basis points.

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 (2).

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

(i) 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; however, this protocol shall not apply if such expense related to costs incurred under this Section is recovered under Article IX or Section 16-108.5 of this Act; incentive compensation expense that is based on net income or an affiliate's earnings per share shall not be recoverable under the energy efficiency formula rate;

(ii) recovery of pension and other post-employment benefits expense, provided that such costs are supported by an actuarial study; however, this protocol shall not apply if such expense related to costs incurred under this Section is recovered under Article IX or Section 16-108.5 of this Act;

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

(iv) as described in subsection (e), amortization of costs incurred under this Section; and

(v) projected, weather normalized billing determinants for the applicable rate year.

(E) Provide for an annual reconciliation, as described in paragraph (3) of this subsection (d), less any deferred taxes related to the reconciliation, with interest at an annual rate of return equal to the utility's weighted average cost of capital, including a revenue conversion factor calculated to recover or refund all additional income taxes that may be payable or receivable as a result of that return, of the energy efficiency revenue requirement reflected in rates for each calendar year, beginning with the calendar year in which the utility files its energy efficiency formula rate tariff pursuant to this paragraph (2), 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, the projected costs to be incurred by the utility during the rate year pursuant the utility's multi-year plan approved under subsection (f) or (g) of this Section, including, but not limited to, the projected capital investment costs and projected regulatory asset balances with correspondingly updated depreciation and amortization reserves and expense, that shall populate the energy efficiency formula rate and set the initial rates under the formula.

The Commission shall review the proposed tariff in conjunction with its review of a proposed multi-year plan, as specified in paragraph (5) of subsection (g) of this Section. The 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 beginning with the January monthly billing period following the Commission's approval.

Rate design and cost allocation across customer classes shall be consistent with the utility's automatic adjustment clause tariff in effect on the effective date of this amendatory Act of the 99th General Assembly.

In the event the energy efficiency formula rate is terminated, the then current rates shall remain in effect until such time as the energy efficiency costs are incorporated into new rates that are set pursuant to this subsection (d) or Article IX of this Act, subject to retroactive rate adjustment, with interest, to reconcile rates charged with actual costs.

(3) The provisions of this paragraph (3) shall only apply to an electric utility that has elected to file an energy efficiency formula rate under paragraph (2) of this subsection (d). Subsequent to the Commission's issuance of an order approving the utility's energy efficiency formula rate structure and protocols, and initial rates under paragraph (2) of this subsection (d), the utility shall file, on or before June 1 of each year, with the Chief Clerk of the Commission its updated cost inputs to the energy efficiency 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:

(A) The inputs to the energy efficiency formula rate for the applicable rate year shall be based on the projected costs to be incurred by the utility during the rate year pursuant to the utility's multi-year plan approved under subsection (f) or (g) of this Section, including, but not limited to, projected capital investment costs and projected regulatory asset balances with correspondingly updated depreciation and amortization reserves and expense. The filing shall also include a reconciliation of the energy efficiency 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. Such over-collection or under-collection shall be adjusted to remove any deferred taxes related to the reconciliation, for purposes of calculating interest at an annual rate of return equal to the utility's weighted average cost of capital approved by the Commission for the prior rate year, including a revenue conversion factor calculated to recover or refund all additional income taxes that may be payable or receivable as a result of that return. 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 subparagraph (E) of paragraph (2) of this subsection (d).

Notwithstanding any other provision of law to the contrary, the intent of the reconciliation is to ultimately reconcile both the revenue requirement reflected in rates for each calendar year, beginning with the calendar year in which the utility files its energy efficiency formula rate tariff pursuant to paragraph (2) of this subsection (d), 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.

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.

(B) 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 paragraph (3).

(C) The filing shall include relevant and necessary data and documentation for the applicable rate year. Normalization adjustments shall not be required.

Within 45 days after the utility files its annual update of cost inputs to the energy efficiency 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 whether the projected costs to be incurred by the utility and recovered during the applicable rate year, and that are reflected in the inputs to the energy efficiency formula rate, are consistent with the utility's approved multi-year plan under subsection (f) or (g) of this Section and whether the costs incurred by the utility during the prior rate year were prudent and reasonable. 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 of Practice 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 paragraph (3) to consider or order any changes to the structure or protocols of the energy efficiency formula rate approved pursuant to paragraph (2) of this subsection (d). In a proceeding under this paragraph (3), the Commission shall enter its order no later than the earlier of 195 days after the utility's filing of its annual update of cost inputs to the energy efficiency formula rate or December 15. 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; however, nothing in this paragraph (3) 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 energy efficiency 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.

(e) Beginning on the effective date of this amendatory Act of the 99th General Assembly, a utility subject to the requirements of this Section may elect to defer the full amount of its expenses incurred pursuant to this Section for each annual period as a regulatory asset. The total expenses deferred as a regulatory asset in a given year shall be amortized and recovered over a period that is equal to the weighted average of the energy efficiency measure lives implemented for that year that are reflected in the regulatory asset. The unamortized balance shall be recognized as of December 31 for a given year. The utility shall also earn a return on the total of the unamortized balances of all of the energy efficiency regulatory assets, less any deferred taxes related to those unamortized balances, at an annual rate equal to the utility's weighted average cost of capital that includes, based on a year-end capital structure, the utility's actual cost of debt for the applicable calendar year and a cost of equity, which shall be calculated as the sum of the (i) the average for the applicable calendar year of the monthly average yields of 30-year U.S. Treasury bonds published by the Board of Governors of the Federal Reserve System in its weekly H.15 Statistical Release or successor publication; and (ii) 580 basis points, including a revenue conversion factor calculated to recover or refund all additional income taxes that may be payable or receivable as a result of that return. Capital investment costs, including, but not limited to, capital investment costs associated with voltage optimization measures that are described in subsection (b) of this Section, shall be depreciated and recovered over their useful lives consistent with generally accepted accounting principles. The weighted average cost of capital shall be applied to the capital investment cost balance, less any accumulated depreciation and accumulated deferred income taxes, as of December 31 for a given year.

When an electric utility creates a regulatory asset pursuant to the provisions of this Section, the costs are recovered over a period during which customers also receive a benefit which is in the public interest. Accordingly, it is the intent of the General Assembly that an electric utility that elects to create a regulatory asset pursuant to the provisions of this Section shall recover all of the associated costs as set forth in this Section. After the Commission has approved the prudence and reasonableness of the costs that comprise the regulatory asset, the electric utility shall be permitted to recover all such costs, and the value and recoverability through rates of the associated regulatory asset shall not be limited, altered, impaired, or reduced.

(f) Beginning in 2017, each electric utility shall file an energy efficiency plan with the Commission to meet the energy efficiency standards for the next applicable multi-year period beginning January 1 of the year following the filing, according to the following schedule:

(1) No later than 30 days after the effective date of this amendatory Act of the 99th General Assembly or May 1, 2017, whichever is later, each electric utility shall file a 4-year energy efficiency plan commencing on January 1, 2018 that is designed to achieve the cumulative persisting annual savings goals specified in paragraphs (1) through (4) of subsection (b-5) of this Section through implementation of energy efficiency measures; however, the goals shall be reduced if the plan demonstrates that achievement of such goals is not cost effective.

(2) No later than March 1, 2021, each electric utility shall file a 4-year energy efficiency plan commencing on January 1, 2022 that is designed to achieve the cumulative persisting annual savings goals specified in paragraphs (5) through (8) of subsection (b-5) of this Section through implementation of energy efficiency measures; however, the goals shall be reduced if the plan demonstrates that achievement of such goals is not cost effective.

(3) No later than March 1, 2025, each electric utility shall file a 5-year energy efficiency plan commencing on January 1, 2026 that is designed to achieve the cumulative persisting annual savings goals specified in paragraphs (9) through (13) of subsection (b-5) of this Section through implementation of energy efficiency measures; however, the goals shall be reduced if the plan demonstrates that achievement of such goals is not cost effective.

If a utility does not file such a plan on or before the applicable filing deadline for the plan, it shall face a penalty of $100,000 per day until the plan is filed.

Each utility's plan shall set forth the utility's proposals to meet the utility's portion of the energy efficiency standards identified in subsection (b), as modified by subsections (d) and (e) of this Section, if applicable, taking into account the unique circumstances of the utility's service territory. For those plans commencing on January 1, 2018, the Commission shall seek public comment on the utility's plan and shall issue an order approving or disapproving each plan no later than August 31, 2017. For those plans commencing after December 31, 2021, the Commission shall seek public comment on the utility's plan and shall issue an order approving or disapproving each plan within 6 months after its submission. If the Commission disapproves a plan, the Commission shall, within 30 days, describe in detail the reasons for the disapproval and describe a path by which the utility may file a revised draft of the plan to address the Commission's concerns satisfactorily. If the utility does not refile with the Commission within 60 days, 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.

(g) In submitting proposed plans and funding levels to meet the savings goals adopted by this Act the utility shall:

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

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

(3) Demonstrate that its overall portfolio of measures, not including low-income programs described in subsection (c) of this Section, is 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. Consistent with existing law, individual measures need not be cost effective, and the design of the portfolio, including its individual programs and measures, shall be subject to practical implementation considerations and limitations.

(4) Present a third-party energy efficiency implementation program subject to the following requirements:

(A) beginning with the year commencing January 1, 2019, the utility shall fund third-party energy efficiency programs in an amount that is no less than $50,000,000 per year;

(B) during 2018, the utility shall conduct a solicitation process for purposes of requesting proposals from third-party vendors for those third-party energy efficiency programs to be offered during one or more of the years commencing January 1, 2019, January 1, 2020, and January 1, 2021; for those multi-year plans commencing on January 1, 2022 and January 1, 2026, the utility shall conduct a solicitation process during 2021 and 2025, respectively, for purposes of requesting proposals from third-party vendors for those third-party energy efficiency programs to be offered during one or more years of the respective multi-year plan period; for each solicitation process, the utility shall identify the sector, technology, or geographical area for which it is seeking requests for proposals;

(C) the utility shall propose the bidder qualifications, performance measurement process, and contract structure, which must include a performance payment mechanism and general terms and conditions; the proposed qualifications, process, and structure shall be subject to Commission approval;

(D) the utility shall retain an independent third party to score the proposals received through the solicitation process described in this paragraph (4), rank them according to their cost per lifetime kilowatt-hours saved, and assemble the portfolio of third-party programs;

(E) for purposes of determining under paragraph (7) of this subsection (g) the amount of cumulative persisting annual savings achieved by the utility, the programs implemented by third parties pursuant to this paragraph (4) shall be deemed to have achieved 80% of their projected savings regardless of the savings determined by the independent evaluator; if the independent evaluator determines that one or more programs achieved more than 80% of their projected savings, such incremental amount shall be credited to the utility's overall energy savings for the applicable year; and

(F) in the event a third-party vendor fails to achieve 2 consecutive quarterly performance targets, the utility shall have the right to cancel the contract and reallocate the funds to other third-party programs or programs administered by the utility.

The electric utility shall recover all costs associated with Commission-approved, third-party administered programs regardless of the success of those programs, which is a restatement and clarification of existing law by this amendatory Act of the 99th General Assembly.

(5) Include a proposed or revised cost-recovery tariff mechanism, as provided for under subsection (d) of this Section, 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.

(6) Provide for an annual independent evaluation of the performance of the cost-effectiveness of the utility's portfolio of measures, as well as a full review of the multi-year plan 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.

(7) Through December 31, 2030, provide for an adjustment to the return on equity component of the utility's weighted average cost of capital calculated pursuant to subsection (d) of this Section:

(A) If the independent evaluator determines that the utility achieved a cumulative persisting annual savings that is less than the applicable annual incremental goal set forth in subsection (b) of this Section, then the return on equity component shall be reduced by a maximum of 200 basis points in the event that the utility achieved no more than 75% of such goal. If the utility achieved more than 75% of the applicable annual incremental goal but less than 100% of such goal, then the return on equity component shall be reduced by 8 basis points for each percent by which the utility failed to achieve the goal.

(B) If the independent evaluator determines that the utility achieved a cumulative persisting annual savings that is more than the applicable annual incremental goal set forth in subsection (b) of this Section, then the return on equity component shall be increased by a maximum of 200 basis points in the event that the utility achieved at least 125% of such goal. If the utility achieved more than 100% of the applicable annual incremental goal but less than 125% of such goal, then the return on equity component shall be increased by 8 basis points for each percent by which the utility achieved above the goal.

In the event that third-party implementation under paragraph (4) of this subsection (g) or the low-income energy efficiency programs under subsection (c) of this Section fail to perform as anticipated, the utility's annual goal shall be adjusted downward in proportion to the failure to perform. The utility shall provide a methodology to adjust the annual goal in the event of such a failure to perform.

For purposes of this Section, the term "applicable annual incremental goal" means the difference between the cumulative persisting annual savings goal for the calendar year that is the subject of the independent evaluator's determination and the cumulative persisting annual savings goal for the immediately preceding calendar year, as such goals are defined in subsection (b-5) of this Section and as such goals may have been modified as provided for under paragraphs (1) through (3) of subsection (f) and to account for any adjustments resulting from the methodology approved under this paragraph (7) to address performance failure related to low-income and third-party administered energy efficiency programs.

The utility shall submit the energy savings data to the independent evaluator no later than 30 days after the close of the plan year. The independent evaluator shall determine the cumulative persisting annual savings for a given plan year no later than 120 days after the close of the plan year. The utility shall submit an informational filing to the Commission no later than 160 days after the close of the plan year that attaches the independent evaluator's final report identifying the cumulative persisting annual savings for the year and calculates any resulting change to the utility's return on equity component of the weighted average cost of capital applicable to the next plan year beginning with the January monthly billing period and extending through the December monthly billing period. Following the utility's submittal of its informational filing for a given year, the Commission may, on its own motion or by petition, initiate an investigation of such filing, provided, however, that the utility's proposed return on equity calculation shall be deemed the final, approved calculation on December 15 of the year in which it is filed unless the Commission enters an order on or before December 15, after notice and hearing, that modifies such calculation consistent with this Section.

The adjustments to the return on equity component described in this paragraph (7) shall be applied as described in this paragraph through a separate tariff mechanism, which shall be filed by the utility under subsection (f) or (g) of this Section.

(h) No more than 6% of energy efficiency and demand-response program revenue may be allocated for research, development, or pilot deployment of new equipment or measures.

(i) When practicable, electric utilities shall incorporate advanced metering infrastructure data into the planning, implementation, and evaluation of energy efficiency measures and programs.

(j) Consistent with existing law, the independent evaluator shall follow the guidelines and use the savings set forth in Commission-approved energy efficiency policy manuals and technical reference manuals, as each may be updated from time to time. Until such time as values for the following measures are incorporated into such Commission-approved manuals, the following measure life values shall apply:

(1) With respect to operational energy efficiency measures:

(A) a 5-year measure life value shall be used for energy savings resulting from operational energy efficiency measures that are implemented and validated; and

(B) a 10-year measure life value shall be used for energy savings resulting from operational energy efficiency measures that are implemented, validated, and persisting, as confirmed through a monitoring-based or hardwired feedback mechanism.

For purposes of this Section, operational energy efficiency measures are those measures that adjust or optimize operational set points and hours of operation of energy using systems.

(2) A 20-year measure life value shall be used for energy savings resulting from light emitting diode streetlights.

(3) A 25-year measure life value shall be used for energy savings resulting from energy efficiency measures implemented in integrated whole-building new construction.

(k) Notwithstanding any provision of law to the contrary, a 10-year measure life value shall be used for energy savings resulting from energy efficiency measures implemented for low-income households under subsection (c) of this Section.

(l) Notwithstanding any provision of law to the contrary, an electric utility subject to the requirements of this Section may file a tariff cancelling an automatic adjustment clause tariff in effect under this Section or Section 8-103, which shall take effect no later than one business day after the date such tariff is filed. Thereafter, the utility shall be authorized to defer and recover its expenses incurred under this Section through a new tariff authorized under subsection (d) of this Section or in the utility's next rate case under Article IX or Section 16-108.5 of this Act, with interest at an annual rate equal to the utility's weighted average cost of capital as approved by the Commission in such case. If the utility elects to file a new tariff under subsection (d) of this Section, the utility may file the tariff within 10 days after the effective date of this amendatory Act of the 99th General Assembly, and the cost inputs to such tariff shall be based on the projected costs to be incurred by the utility during the calendar year in which the new tariff is filed and that were not recovered under the tariff that was cancelled as provided for in this paragraph. Such costs shall include those incurred or to be incurred by the utility under its multi-year plan approved under subsection (f) or (g) of this Section, including, but not limited to, projected capital investment costs and projected regulatory asset balances with correspondingly updated depreciation and amortization reserves and expense. The Commission shall, after notice and hearing, approve, or approve with modification, such tariff and cost inputs no later than 75 days after the utility filed the tariff, provided that such approval, or approval with modification, shall be consistent with the provisions of this Section to the extent they do not conflict with this subsection (l). The tariff approved by the Commission shall take effect no later than 5 days after the Commission enters its order approving the tariff.

No later than 60 days after the effective date of the tariff cancelling the utility's automatic adjustment clause tariff, the utility shall file a reconciliation that reconciles the moneys collected under its automatic adjustment clause tariff with the costs incurred during the period beginning June 1, 2016 and ending on the date that the electric utility's automatic adjustment clause tariff was cancelled. In the event the reconciliation reflects an under-collection, the utility shall recover the costs as specified in this subsection (l). If the reconciliation reflects an over-collection, the utility shall apply the amount of such over-collection as a one-time credit to retail customers' bills.

(220 ILCS 5/8-104)

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

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

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

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

(1) 0.2% by May 31, 2012;

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

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

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

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

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

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

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

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

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

(e) The provisions of this subsection (e) apply to those multi-year plans that commence prior to January 1, 2018 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.

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.

(e-5) The provisions of this subsection (e-5) shall be applicable to those multi-year plans that commence after December 31, 2017. Natural gas utilities shall be responsible for overseeing the design, development, and filing of their efficiency plans with the Commission and 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 utilities shall also 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.

(e-10) 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.

(e-15) For those multi-year plans that commence prior to January 1, 2018, each Each utility shall include, in its recovery of costs, the costs estimated for both the utility's and the Department's implementation of energy efficiency measures. Costs collected by the utility for measures implemented by the Department shall be submitted to the Department pursuant to Section 605-323 of the Civil Administrative Code of Illinois, shall be deposited into the Energy Efficiency Portfolio Standards Fund, and shall be used by the Department solely for the purpose of implementing these measures. A utility shall not be required to advance any moneys to the Department but only to forward such funds as it has collected. The Department shall report to the Commission on an annual basis regarding the costs actually incurred by the Department in the implementation of the measures. Any changes to the costs of energy efficiency measures as a result of plan modifications shall be appropriately reflected in amounts recovered by the utility and turned over to the Department.

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

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

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

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

(f) No later than October 1, 2010, each gas utility shall file an energy efficiency plan with the Commission to meet the energy efficiency standards through May 31, 2014. No later than October 1, 2013, each gas utility shall file an energy efficiency plan with the Commission to meet the energy efficiency standards through May 31, 2017. Beginning in 2017 and every 4 Every 3 years thereafter, each utility shall file, no later than October 1, an energy efficiency plan with the Commission to meet the energy efficiency standards for the next applicable 4-year period beginning January 1 of the year following the filing. For those multi-year plans commencing on January 1, 2018, each utility shall file its proposed energy efficiency plan no later than 30 days after the effective date of this amendatory Act of the 99th General Assembly or May 1, 2017, whichever is later. Beginning in 2021 and every 4 years thereafter, each utility shall file its energy efficiency plan no later than March 1. If a utility does not file such a plan on or before the applicable filing deadline for the plan by 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. For those plans commencing after December 31, 2021, the The Commission shall seek public comment on the utility's plan and shall issue an order approving or disapproving each plan within 6 months after its submission. For those plans commencing on January 1, 2018, the Commission shall seek public comment on the utility's plan and shall issue an order approving or disapproving each plan no later than August 31, 2017. 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) For those multi-year plans that commence prior to January 1, 2018, coordinate Coordinate with the Department to present a portfolio of energy efficiency measures proportionate to the share of total annual utility revenues in Illinois from households at or below 150% of the poverty level. 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 low-income programs described in covered by item (4) of this subsection (f) and subsection (e-5) of this Section, 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 or 8-103B 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. For those multi-year plans that commence prior to January 1, 2018, the 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, if applicable, the Department's portfolio of measures, an annual independent review, and a full independent evaluation of the multi-year 3-year results of the performance and the cost-effectiveness of the utility's and, if applicable, Department's portfolios of measures and broader net program impacts and, to the extent practical, for adjustment of the measures on a going forward basis as a result of the evaluations. The resources dedicated to evaluation shall not exceed 3% of portfolio resources in any given multi-year 3-year period.

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

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

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

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

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

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

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

If a gas utility fails to meet the efficiency standard specified in subsection (c) of this Section, as modified by subsection (d) of this Section, in any 2 consecutive multi-year 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 multi-year 3-year planning period commencing subsequent to the application, and will maintain for accounting purposes, an energy efficiency reserve account and that the customer will accrue funds in said account to be held for the purpose of funding, in whole or in part, energy efficiency measures of the customer's choosing, which may include, but are not limited to, projects involving combined heat and power systems that use the same energy source both for the generation of electrical or mechanical power and the production of steam or another form of useful thermal energy or the use of combustible gas produced from biomass, or both;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

(220 ILCS 5/9-105 new)

Sec. 9-105. Demand-based delivery services charge.

(a) Beginning with the January 2019 monthly billing period for an electric utility that serves more than 3,000,000 retail customers in the State and beginning with the January 2021 monthly billing period for an electric utility that serves 3,000,000 or less retail customers but more than 500,000 retail customers in the State, such utility may recover its costs of providing delivery services to retail customers through a charge based on kilowatts of demand. A utility that elects to recover its costs as provided in this Section shall file its tariffs pursuant to Section 9-201 of this Act, provided that a participating utility as defined in Section 16-108.5 of this Act shall file such tariffs pursuant to subsection (e) of Section 16-108.5.

(b) Tariffs filed by a utility under subsection (a) of this Section shall be subject to the following provisions:

(1) The categories of costs being recovered through a fixed charge on the effective date of this amendatory Act of the 99th General Assembly shall continue to be recovered through a fixed charge; however, this paragraph (1) shall not limit the consideration and inclusion of additional cost components to be recovered through a fixed charge.

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

(3) Taxes assessed on a kilowatt-hour basis shall continue to be recovered on a kilowatt-hour basis.

(4) The costs of providing delivery services to those retail customers subject to the tariff that are not recovered under paragraphs (1) through (3) of this subsection (b) shall be recovered through a charge based on kilowatts of demand, and the tariffs shall be designed to allocate costs to the cost causer generally based on the demands that customers place on the utility's systems.

(5) For purposes of this Section, the kilowatts of demand for each residential customer of an electric utility that serves more than 3,000,000 retail customers in the State shall be calculated based on the maximum kilowatts delivered to the customer during a 30-minute interval over a 16-hour period beginning at 6 a.m. and ending at 10 p.m. Central Prevailing Time on a non-holiday weekday during the monthly billing period or periods for which the bill is rendered; the kilowatts of demand for each residential customer of an electric utility that serves 3,000,000 or less retail customers but more than 500,000 retail customers in the State shall be calculated based on the maximum kilowatts delivered to the customer during a 60-minute interval over a 16-hour period beginning at 6 a.m. and ending at 10 p.m. Central Prevailing Time on a non-holiday weekday during the monthly billing period or periods for which the bill is rendered. For purposes of this Section, 30-minute intervals shall begin on the hour and 30 minutes past the hour and 60-minute intervals shall begin on the hour. An electric utility may elect to estimate retail customers' kilowatt demands if the interval data necessary to determine such customers' kilowatt demands is not available.

(c) An electric utility that elects to recover its costs of providing delivery services to retail customers pursuant to subsection (a) of this Section shall notify the Commission of its election to do so no later than 20 months before the tariff to recover such costs would take effect under this Section. An electric utility that makes such election shall also be subject to the following provisions, as applicable:

(1) If the utility elects to recover, pursuant to this Section, its costs of providing delivery services to residential retail customers, then the utility shall also file a tariff that limits the amount of the delivery services revenue requirement that is allocated to be recovered from such customers through the customer charge to no more than 14% on average among residential retail customers. The tariff shall take effect at the same time the utility's tariff authorized by subsection (a) of this Section takes effect.

(2) If the utility elects to recover, pursuant to this Section, its costs of providing delivery services to eligible retail customers, as defined by Section 16-111.5 of this Act, then the utility shall also offer a market-based, time-of-use rate for eligible retail customers that choose to take power and energy supply service from the utility. The utility shall file its time-of-use rate tariff no later than 120 days after its demand-based rates applicable to such customers take effect pursuant to subsection (a) of this Section.

(3) Beginning with the year in which a utility elects to recover, pursuant to this Section, its costs of providing delivery services to such eligible retail customers, the utility shall spend $15,000,000 over 3 years in customer education and outreach efforts designed to inform eligible retail customers about the rate design changes to be implemented pursuant to this Section and to empower such customers regarding how to respond to the new rate design. The investment shall be a recoverable expense.

(4) If the electric utility also has a performance-based formula rate in effect pursuant to Section 16-108.5 of this Act, then the utility shall be permitted to revise the formula rate and schedules to reduce the 50 basis point values to zero that would otherwise apply under paragraph (5) of subsection (c) of Section 16-108.5 of this Act. If the utility no longer has a performance-based formula rate in effect pursuant to Section 16-108.5 of this Act, then the utility shall be permitted to implement the revenue balancing adjustment tariff described in Section 9-107 of this Act.

(220 ILCS 5/9-107 new)

Sec. 9-107. Revenue balancing adjustment tariff.

(a) In this Section:

"Reconciliation period" means a period beginning with the January monthly billing period and extending through the December monthly billing period.

"Rate case reconciliation revenue requirement" means the final distribution revenue requirement or requirements approved by the Commission in the utility's rate case or formula rate proceeding to set the rates initially applicable in the relevant reconciliation period after the conclusion of the period. In the event the Commission has approved more than one revenue requirement for the reconciliation period, the amount of rate case revenue under each approved revenue requirement shall be prorated based upon the number of days under which each revenue requirement was in effect.

(b) An electric utility that is authorized under paragraph (4) of subsection (c) of Section 9-105 of this Act to implement a revenue balancing adjustment tariff under this Section because the utility no longer has a performance-based formula rate in effect pursuant to Section 16-108.5 of this Act, may file the tariff for the purpose of preventing undercollections or overcollections of distribution revenues as compared to the revenue requirement or requirements approved by the Commission on which the rates giving rise to those revenues were based. The tariff shall calculate an annual adjustment that reflects any difference between the actual delivery service revenue collected for services provided during the relevant reconciliation period and the rate case reconciliation revenue requirement for the relevant reconciliation period and shall set forth the reconciliation categories or classes, or a combination of both, in a manner determined at the utility's discretion.

(c) A utility that elects to file the tariff authorized by this Section shall file the tariff outside the context of a general rate case or formula rate proceeding, and the Commission shall, after notice and hearing, approve the tariff or approve with modification no later than 120 days after the utility files the tariff, and the tariff shall remain in effect at the discretion of the utility. The tariff shall also require that the electric utility submit an annual revenue balancing reconciliation report to the Commission reflecting the difference between the actual delivery service revenue and rate case revenue for the applicable reconciliation and identifying the charges or credits to be applied thereafter. The annual revenue balancing reconciliation report shall be filed with the Commission no later than March 20 of the year following a reconciliation period. The Commission may initiate a review of the revenue balancing reconciliation report each year to determine if any subsequent adjustment is necessary to align actual delivery service revenue and rate case revenue. In the event the Commission elects to initiate such review, the Commission shall, after notice and hearing, enter an order approving, or approving as modified, such revenue balancing reconciliation report no later than 120 days after the utility files its report with the Commission. If the Commission does not initiate such review, the revenue balancing reconciliation report and the identified charges or credits shall be deemed accepted and approved 120 days after the utility files the report and shall not be subject to review in any other proceeding.

(220 ILCS 5/16-103.3 new)

Sec. 16-103.3. Unbundling of charges related to electricity supply and regional transmission organization services. Beginning with the January 2019 monthly billing period, an electric utility that provides electric service to more than 3,000,000 retail customers in the State shall restructure its retail electricity supply charges applicable to eligible retail customers, as defined by Section 16-111.5 of this Act, for whom the electric utility procures electric power and energy pursuant to Section 1-75 of the Illinois Power Agency Act and Section 16-111.5 of this Act. The restructuring shall allocate to these customers, and separately state, the following: the costs of electric capacity, costs of transmission services, and charges for network integration transmission service, transmission enhancement, and locational reliability, as these terms are defined in the PJM Interconnection Open Access Transmission Tariff on March 1, 2016. In the event the Open Access Transmission Tariff subsequently renames those terms, the services reflected under those terms shall continue to be subject to the restructuring described in this Section.

It is the intent of this Section that eligible retail customers taking electricity supply service from an electric utility that provides electric service to more than 3,000,000 retail customers in the State pay charges for the electricity supply and regional transmission organization-related services costs that generally reflect the manner in which the associated costs are incurred.

(220 ILCS 5/16-107)

Sec. 16-107. Real-time pricing.

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

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

(b-5) Each electric utility shall file a tariff or tariffs allowing residential retail customers in the electric utility's service area to elect real-time pricing beginning January 2, 2007. The Commission may, after notice and hearing, approve the tariff or tariffs. A customer who elects real-time pricing shall remain on such rate for a minimum of 12 months. The Commission may, after notice and hearing, approve the tariff or tariffs, provided that the Commission finds that the potential for demand reductions will result in net economic benefits to all residential customers of the electric utility. In examining economic benefits from demand reductions, the Commission shall, at a minimum, consider the following: improvements to system reliability and power quality, reduction in wholesale market prices and price volatility, electric utility cost avoidance and reductions, market power mitigation, and other benefits of demand reductions, but only to the extent that the effects of reduced demand can be demonstrated to lower the cost of electricity delivered to residential customers. A tariff or tariffs approved pursuant to this subsection (b-5) shall, at a minimum, describe (i) the methodology for determining the market price of energy to be reflected in the real-time rate and (ii) the manner in which customers who elect real-time pricing will be provided with ready access to hourly market prices, including, but not limited to, day-ahead hourly energy prices. A customer who elects real-time pricing pursuant to a tariff approved under this subsection (b-5) and thereafter terminates the election shall not return to taking service under the tariff for a period of 12 months following the date on which the customer terminated real-time pricing. However, this limitation shall cease to apply on such date that the provision of electric power and energy is declared competitive under Section 16-113 of this Act for the customer group or groups to which this subsection (b-5) applies.

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 5/16-107.5)

Sec. 16-107.5. Net electricity metering.

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

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

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

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

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

(3) For all other eligible customers, until such time as the local electric utility installs a smart meter, as described by subsection (b) of Section 16-108.5 of this Act, the electricity provider may arrange for the local electric utility or a meter service provider to install and maintain metering equipment capable of measuring the flow of electricity both into and out of the customer's facility at the same rate and ratio, typically through the use of a dual channel meter. If the eligible customer's existing electric revenue meter does not meet this requirement, then the costs of installing such equipment shall be paid for by the customer.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

(i) All electricity providers shall begin to offer net metering no later than April 1, 2008. However, this Section shall not apply to an electric utility, or the customers to which such utility provides delivery services, beginning on the date that the utility's tariff to recover its delivery services costs pursuant to subsection (a) of Section 9-105 of this Act takes effect, if any. Retail customers that are receiving net metering service pursuant to this Section at such time as this Section ceases to apply to the electric utility shall be entitled to continue the service pursuant to subsections (c) and (e) of Section 16-107.7 of this Act.

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

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

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

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

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

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

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

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

(220 ILCS 5/16-107.6 new)

Sec. 16-107.6. Net electricity metering.

(a) This Section shall apply to an electric utility, and the customers to which the utility provides delivery services, beginning on the date that the utility's tariff to recover its delivery services costs through a demand-based rate pursuant to subsection (a) of Section 9-105 of this Act takes effect, if any. A retail customer that is receiving net metering service pursuant to Section 16-107.5 of this Act at the time this Section applies to such electric utility, shall be entitled to continue such service pursuant to subsections (c) and (e) of Section 16-107.7 of this Act.

(b) As used in this Section:

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

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

"Eligible renewable electrical generating facility" means a generator that is connected to the utility's distribution system at a voltage of no greater than 12.47 kilovolts and is powered by solar electric energy, wind, dedicated crops grown for electricity generation, agricultural residues, untreated and unadulterated wood waste, landscape trimmings, livestock manure, anaerobic digestion of livestock or food processing waste, fuel cells or microturbines powered by renewable fuels, or hydroelectric energy.

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

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

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

(1) If the amount of electricity used by the customer during the billing period exceeds the amount of electricity produced by the customer, then the electricity provider shall charge the customer for the net kilowatt-hour based electricity charges reflected in the customer's electric service rate supplied to and used by the customer as provided in subsection (f) of this Section.

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

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

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

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

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

(f) An electricity provider shall provide electric service to eligible customers who utilize net metering at non-discriminatory rates that are identical, with respect to rate structure, retail rate components, and any monthly charges, to the rates that the customer would be charged if not a net metering customer. An electricity provider shall charge the customer for the net electricity supplied to and used by the customer according to the terms of the contract or tariff to which the same customer would be assigned or be eligible for if the customer was not a net metering customer. An electricity provider shall not charge net metering customers any fee or charge or require additional equipment, insurance, or any other requirements not specifically authorized by interconnection standards authorized by the Commission, unless the fee, charge, or other requirement would apply to other similarly situated customers who are not net metering customers. The customer remains responsible for the gross amount of delivery services charges and supply-related charges that are kilowatt based, as well as all taxes and fees related to such charges. The customer also remains responsible for all taxes and fees that would otherwise be applicable to the net amount of electricity used by the customer. Subsections (d) and (e) of this Section shall not be construed to prevent an arms-length agreement between an electricity provider and an eligible customer that sets forth different prices, terms, and conditions for the provision of net metering service, including, but not limited to, the provision of the appropriate metering equipment for non-residential customers. Nothing in this subsection (f) shall be interpreted to mandate that a utility that is only required to provide delivery services to a given customer must also sell electricity to such customer.

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

(h) Each electricity provider shall maintain records and report annually to the Commission the total number of net metering customers served by the electricity provider, as well as the type, capacity, and energy sources of the generating systems used by the net metering customers. Nothing in this Section shall limit the ability of an electricity provider to request the redaction of confidential business information.

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

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

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

In addition, the demand of the properties, units, or apartments identified in subparagraphs (1) and (2) of this subsection (i) whose meters are aggregated and that contribute to or are served by an eligible renewable electrical generating facility shall not exceed 2,000 kilowatts in nameplate capacity in total. For the purposes of this subsection (i), "meter aggregation" means the combination of reading and billing on a pro rata basis for the types of customers described in this subsection (i). For purposes of facilitating such reading and billing, the owner or operator of the eligible renewable electrical generating facility shall be responsible for determining the amount of the credit that each customer participating in meter aggregation pursuant to this subsection (i) is to receive in the following manner:

(A) For those participating customers who receive their energy supply from an electricity provider that is an electric utility, the owner or operator shall, on a monthly basis, calculate the monetary value of the energy credit for each such customer that is to be applied to the customer's electric utility bill by the electricity provider. The owner or operator shall calculate such monthly credit for each such customer in accordance with the customer's share of the eligible renewable electric generating facility's output of power and energy for a given month and the cents-per-kilowatt-hour price of power and energy supply service set forth in the applicable tariff or tariffs of the customer's electricity provider for that same month. In the event that more than one price for power and energy supply service was in effect during the applicable month, the owner or operator shall calculate the credit based on an appropriate weighting. The owner or operator shall electronically transmit such calculations and data to the electricity provider, in a format or method as agreed to by the electricity provider and the owner or operator, on a monthly basis so that the electricity provider can reflect the monetary credits on customers' electric utility bills. The electricity provider shall be permitted to revise its tariffs to implement the provisions of this amendatory Act of the 99th General Assembly. The owner or operator shall separately provide the electricity provider with the documentation detailing the calculations supporting the credit in the manner set forth in the applicable tariff.

(B) For those participating customers who receive their energy supply from an alternative retail electric supplier, the owner or operator shall determine the monthly credit, in a dollar amount, and provide the information to the alternative retail electric supplier in a manner set forth in such alternative retail electric supplier's meter aggregation program, or as otherwise agreed between the parties.

(j) Each electric utility subject to this Section shall file a tariff to implement the provisions of subsection (i) of this Section in conjunction with the tariff that the utility files to implement subsection (a) of Section 9-105 of this Act, which shall, consistent with the provisions of such subsection, describe the terms and conditions pursuant to which owners or operators of qualifying properties, units, or apartments may participate in meter aggregation for purposes of net metering. The tariff approved pursuant to this subsection shall become effective on the same date that the tariff implementing subsection (a) of Section 9-105 of this Act becomes effective.

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

(220 ILCS 5/16-107.7 new)

Sec. 16-107.7. Distributed generation rebate.

(a) In this Section:

"Smart inverter" means a device that converts direct current into alternating current and can autonomously contribute to grid support during excursions from normal operating voltage and frequency conditions by providing each of the following: dynamic reactive and real power support, voltage and frequency ride-through, ramp rate controls, communication systems with ability to accept external commands, and other functions from the electric utility.

"Threshold date" means:

(1) For distributed generation that is located in the service territory of an electric utility that serves more than 3,000,000 retail customers in the State, the date on which the combined nameplate capacity of such distributed generation located in such service territory that is enrolled in the rebate programs implemented pursuant to this Section reaches 150 megawatts; and

(2) For distributed generation that is located in the service territory of an electric utility that serves 3,000,000 or less retail customers in the State, the date on which the combined nameplate capacity of distributed generation located in such service territory that is enrolled the rebate programs implemented pursuant to this Section reaches 75 megawatts.

(b) An electric utility that serves more than 200,000 customers in the State may file a petition with the Commission requesting approval of the utility's tariff to provide a rebate to a retail customer who owns or operates distributed generation that meets the following criteria:

(1) has a nameplate generating capacity no greater than 2,000 kilowatts and is designed not to exceed the peak load of the customer's premises;

(2) is located on the customer's premises, for the customer's own use, and not for commercial use or sales, including, but not limited to, wholesale sales of electric power and energy;

(3) is located in the electric utility's service territory; and

(4) is connected to the utility's distribution system at a voltage of no greater than 12.47 kilovolts by means of the inverter or smart inverter required by this Section, as applicable. The tariff shall provide that the utility shall be permitted to operate and control the smart inverter associated with the distributed generation that is the subject of the rebate and shall address the terms and conditions of the operation and the compensation associated with the operation.

If an electric utility elects to recover its costs of providing delivery services to retail customers pursuant to subsection (a) of Section 9-105 of this Act, it shall be required to file the proposed tariffs described in this Section. Such tariff or tariffs, as applicable, shall be filed with the tariffs filed to implement subsection (a) of Section 9-105 of this Act, and shall become effective upon the same date that the tariffs filed to implement subsection (a) of Section 9-105 become effective.

(c) The proposed tariff authorized by subsection (b) of this Section shall include the following participation terms and formulae to calculate the value of the rebates to be applied pursuant to this Section for distributed generation that satisfies the criteria set forth in subsection (b) of this Section:

(1) Until the earlier of the threshold date or December 31, 2021:

(A) Retail customers may, as applicable, make the following elections:

(i) Residential customers that are taking service pursuant to a net metering program offered by an electricity provider under the terms of Section 16-107.5 of this Act on the effective date of this amendatory Act of the 99th General Assembly may elect to either continue to take such service pursuant to the terms of such program as in effect on such effective date for the useful life of the customer's eligible renewable electric generating facility as defined in such Section, or file an application to receive a rebate pursuant to the terms of this Section, provided that such application must be submitted within 6 months after the effective date of the tariff approved under this subsection (c) and the inverter associated with such customer's distributed generation need not be a smart inverter.

(ii) Residential customers that begin taking service pursuant to a net metering program offered by an electricity provider under the terms of Section 16-107.5 of this Act after the effective date of this amendatory Act of the 99th General Assembly may elect to either continue to take such service pursuant to the terms of such program as in effect on such effective date until December 31, 2021, or file an application to receive a rebate pursuant to the terms of this Section, provided, however, that the inverter associated with the customer's distributed generation must be a smart inverter.

(iii) Non-residential customers that are taking service pursuant to a net metering program offered by an electricity provider under the terms of Section 16-107.5 of this Act on the effective date of this amendatory Act of the 99th General Assembly may apply for a rebate as provided for in this Section, provided that the inverter associated with such customer's distributed generation need not be a smart inverter.

(iv) Non-residential customers that begin taking service pursuant to a net metering program offered by an electricity provider under the terms of Section 16-107.5 of this Act after the effective date of this amendatory Act of the 99th General Assembly may apply for a rebate as provided for in this Section; however, the inverter associated with the customer's distributed generation must be a smart inverter.

Upon approval of a rebate application submitted under items (i) or (ii) of this subparagraph (A), the retail customer shall no longer be entitled to receive any delivery service credits for the excess electricity generated by its facility.

(B) The value of the rebates shall be:

(i) $1,000 per kilowatt of nameplate generating capacity, measured as nominal DC power output, of a residential customer's distributed generation; and

(ii) $500 per kilowatt of nameplate generating capacity, measured as nominal DC power output, of a non-residential customer's distributed generation.

(2) After the threshold date but until no later than December 31, 2021:

(A) Retail customers may, as applicable, make the following elections:

(i) Residential customers that begin taking