HB3624ham001 101ST GENERAL ASSEMBLY

Rep. Ann M. Williams

Filed: 3/7/2019

10100HB3624ham001 LRB101 09870 JLS 56878 a

AMENDMENT TO HOUSE BILL 3624

AMENDMENT NO. ______. Amend House Bill 3624 by replacing everything after the enacting clause with the following:

"Article 1.

Findings

Section 1-5. Findings.

(a) The growing clean energy economy in Illinois can be a vehicle for expanding equitable access to public health, safety, a cleaner environment, and quality jobs and economic opportunities, including wealth building, especially since economically disadvantaged communities and communities of color have had to bear the disproportionate burden of dirty fossil fuel pollution.

(b) Placing Illinois on a path to 100% renewable energy is vital to a clean energy future. To bring this vision to fruition, our energy policy must prioritize a just transition that incentivizes renewable development and other carbon-reducing policies, such as energy efficiency, while ensuring that the benefits and opportunities of a carbon-free future are accessible in economically disadvantaged communities, environmental justice communities, and communities of color.

(c) In the wake of federal reversals on climate action, the State of Illinois should pursue immediate action on policies that will ensure a just and responsible phase out of fossil fuels from the power sector to reduce harmful emissions from Illinois power plants, support power plant communities and workers, and allow the clean energy economy to continue growing in every corner of Illinois.

(d) Energy efficiency should form the basis of any robust clean energy policy. It is the cheapest clean energy resource, and efficiency upgrades help customers manage their energy bills directly by reducing the energy they need, and indirectly by holding demand and prices down statewide.

(e) The transportation sector is now the leading source of carbon pollution in Illinois, responsible for roughly one-third of all carbon emissions. The State of Illinois should set forth an ambitious goal to remove the equivalent of 1 million gasoline and diesel-powered vehicles from our roads by quickly implementing new policies that expand access to transit, promote walking and biking mobility, and increase electric vehicle adoption. If managed appropriately, electric vehicle adoption will drastically reduce emissions from transportation, and could save Illinois residents billions of dollars.

(f) In addition to better air quality and safer climate, Illinois residents that do not use electric vehicles also benefit from greater adoption through lower electric bills resulting from the greater utilization of the electric grid during off-peak hours.

(g) Energy storage, such as batteries, can provide many services to the electricity grid which benefit the grid, including managing (or shaving) peak load, frequency regulation, voltage support, reserve capacity, and black-start capability. And, if that storage facilitates greater utilization of renewables, it can allow for more clean energy to be accessible, reduce pollution, and provide multiple benefits.

(h) Illinois needs to adopt a broad-based policy approach to decarbonize Illinois' electric sector (both how much we produce and how much we consume) in a just and equitable way that puts our State on track to phase out emitting power plants by 2030.

(i) Illinois' policy approach must ensure the reduction of co-pollutant emissions that cause serious, local health impacts, prioritizing environmental justice communities near power plants.

(j) As we decarbonize Illinois' electric sector, Illinois must create new investment to stimulate the economic and environmental well-being of communities disproportionately impacted by the historical operation of, and recent or expected closures of, fossil fuel power plants.

Article 5.

Clean Jobs Workforce Hubs Act

Section 5-1. Short title. This Article may be cited as the Clean Jobs Workforce Hubs Act. References in this Article to "this Act" mean this Article.

Section 5-5. Legislative purpose. The General Assembly finds that the State of Illinois should build upon the success of the Future Energy Jobs Act and the Illinois Solar for All Program by further expanding equitable access to quality jobs and economic opportunities (especially for residents of economically disadvantaged communities, environmental justice communities, communities of color, returning citizens, foster care communities, and other underserved communities who have had to bear the disproportionate burden of dirty fossil fuel pollution) across the entire clean energy sector in Illinois, including solar, wind, energy efficiency, transportation electrification, and other related clean energy industries.

Section 5-10. Definitions. As used in this Act:

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

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

"Environmental justice communities" means the proposed definition of that term based on existing methodologies and findings used by the Illinois Power Agency and its Administrator in its Illinois Solar for All Program.

"Program" means the Clean Jobs Workforce Hubs Program.

Section 5-15. Clean Jobs Workforce Hubs Program. The Department must develop and administer the Clean Jobs Workforce Hubs Program to create a network of frontline organizations across the State that provide direct and sustained support for members of economically disadvantaged communities, environmental justice communities, communities of color, returning citizens, foster care communities, and displaced fossil fuel workers to enter and complete the pipeline for clean energy jobs in solar energy, wind energy, energy efficiency, electric vehicles and related industries. The Clean Jobs Workforce Hubs Program must:

(1) leverage frontline organizations to ensure members of disadvantaged communities across the State have dedicated and sustained support to enter and complete the career pipeline for clean energy jobs; and

(2) develop formal partnerships between frontline organizations and trades groups, labor unions, and clean energy employers to ensure Clean Jobs Workforce Hubs Program participants have priority access to pre-apprenticeship, apprenticeship, and other employment opportunities.

Section 5-20. Clean Jobs Workforce Hubs Network. The Clean Jobs Workforce Hubs Network, made up of frontline organizations across the State and administered by a Program Administrator, is required to provide the following:

(1) community education and outreach about workforce and training opportunities to ensure members of economically disadvantaged communities, environmental justice communities, communities of color, returning citizens, foster care communities, and displaced fossil fuel workers understand clean energy workforce and training opportunities;

(2) training, apprenticeship, job readiness, and skill development, including soft skills, math skills, technical skills, and other development needed for members of economically disadvantaged communities, environmental justice communities, communities of color, returning citizens, foster care communities, and displaced fossil fuel workers to enter clean energy-related training and apprenticeship programs and career paths;

(3) targeted outreach and recruitment to ensure people of color are invited, supported, and given preference in applying for both community-based and labor-based training opportunities, including apprenticeship and pre-apprenticeship programs;

(4) the development of partnerships with labor organizations to ensure Clean Jobs Workforce Hubs participants are recruited, placed, and supported in labor-based training programs, such as workforce development programs and pre-apprenticeship and apprenticeship programs;

(5) a stipend program for Clean Jobs Workforce Hubs participants in clean energy-related training programs and company apprenticeships, including providing funding to assist with transportation, child care, and other needed services and supplies during the length of programs; and

(6) direct assistance and counseling to participants in training and apprenticeship programs to help connect trainees to both union and non-union career options with renewable energy companies, energy efficiency companies, and other clean energy employers and to provide a direct resource for industry to identify qualified workers to meet program hiring or subcontracting requirements, including the workforce equity building actions required under Section 1-75 of the Illinois Power Agency Act and Section 16-128B of the Public Utilities Act. Placement activities should include outreach to public agencies, utilities, and clean energy companies, creation of formal partnerships with employers, job interview preparation, and on-the-job support and counseling.

Section 5-25. Program Administrator. Within 60 days after the effective date of this Act and after a comprehensive stakeholder process that includes representatives from frontline communities, the Department shall select a Program Administrator, as an individual or an organization, to coordinate the work of all or a portion of the work of the Clean Jobs Workforce Hubs. The Program Administrator shall have strong capabilities in program management, knowledge of industry trends and activities, workforce development best practices, and community development. The Program Administrator shall coordinate the work of all or a portion of the Clean Jobs Workforce Hubs network to ensure consistent execution, performance, partnerships, marketing, and program access across the State.

Section 5-30. Clean jobs curriculum.

(a) Within 60 days after the effective date of this Act, the Department must convene a comprehensive stakeholder process that includes representatives from the Illinois State Board of Education, the Illinois Community College Board, the Illinois Department of Labor, frontline organizations, workforce development providers, labor unions, building trades, clean energy employers, including solar industry, wind industry, energy efficiency, and transportation electrification, and other needed participants to identify the career pathways and training curriculum (such as the Multi-Craft Core Curriculum) needed to prepare workers to enter the clean energy field, including solar photovoltaic, solar thermal, wind energy, energy efficiency, site assessment, sales, and back office. Curriculum must also include broad occupational training to provide career entry into the general construction and building trades sector. Within 120 days after the stakeholder process is convened, the Department must publish a report that reflects the findings and core curriculum recommendations developed by the stakeholder group.

(b) Organizations that receive funding to provide training under the Clean Jobs Workforce Hubs Program, including community-based and labor-based training providers, must use the core curriculum that is developed under subsection (a).

Section 5-35. Administration; rules. The Department shall administer this Act and shall adopt any rules necessary for that purpose.

Article 10.

Expanding Clean Energy Entrepreneurship Act

Section 10-1. Short title. This Article may be cited as the Expanding Clean Energy Entrepreneurship Act. References in this Article to "this Act" mean this Article.

Section 10-5. Legislative purpose. The General Assembly finds that the State of Illinois should build upon the success of the Future Energy Jobs Act and the Illinois Solar for All Program by supporting small, disadvantaged clean energy businesses and contractors having equitable access to economic opportunities created by the growing clean energy sector in Illinois.

Section 10-10. Definitions. As used in this Act:

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

"Disadvantaged businesses and contractors" means an entity defined under Section 2 of the Business Enterprise for Minorities, Women, and Persons with Disabilities Act.

"Environmental justice communities" means the proposed definition of that term based on existing methodologies and findings used by the Illinois Power Agency and its Administrator in its Illinois Solar for All Program.

"Program" means the Expanding Clean Energy Entrepreneurship and Contractor Incubator Program.

Section 10-15. Expanding Clean Energy Entrepreneurship and Contractor Incubator Program. The Department must develop and administer the Expanding Clean Energy Entrepreneurship and Contractor Incubator Program to support the development of disadvantaged businesses and contractors and provide the needed resources for such businesses to be able to effectively compete for, gain, and execute clean energy-related projects. The Program must provide:

(1) Access to low-cost capital for small and disadvantaged clean energy businesses and contractors to be able to complete on a level playing field with more established, capitalized businesses across the entire clean energy sector in Illinois, including solar, wind, energy efficiency, transportation electrification, and other clean energy industries.

(2) Support for obtaining the necessary insurance, bonding, back office services, permits, certifications, and other financial assurance requirements needed to effectively compete for clean energy-related projects, incentive programs, and approved vendor and qualified installer opportunities.

(3) Development and support needed for disadvantaged clean energy contractors to build their business and connect them to specific projects, Approved Vendor subcontracting and qualified installer opportunities, partnerships, networks, capital, and other resources needed to compete for, gain, and execute clean energy-related project installation and subcontracts.

Section 10-20. Program Administrator. Within 60 days after the effective date of this Act, the Department shall select a Program Administrator, as an individual or an organization, to coordinate the work of all or a portion of the work of the Expanding Clean Energy Entrepreneurship and Contractor Incubator Program. The Program Administrator shall have strong capabilities in program management, knowledge of industry trends and activities, disadvantaged business and contractor development best practices, and related development support. The Program Administrator shall coordinate the work of all or a portion of the Program to ensure consistent execution, performance, partnerships, marketing, and program access across the State.

Section 10-25. Administration; rules. The Department shall administer this Act and shall adopt any rules necessary for that purpose.

Article 15.

Community Energy and Climate Planning Act

Section 15-1. Short title. This Article may be cited as the Community Energy and Climate Planning Act. References in this Article to "this Act" mean this Article.

Section 15-5. Legislative purpose. The General Assembly makes the following findings:

(1) The health, welfare, and prosperity of Illinois citizens require that Illinois take all steps possible to combat climate change, address harmful environmental impacts deriving from the generation of electricity, ensure affordable utility service, equitable and affordable access to transportation, and clean, safe, affordable housing.

(2) The achievement of these goals will depend on strong community engagement to ensure that programs and policy solutions meet the needs of disparate communities.

(3) Ensuring that these goals are met without adverse impacts on utility bill affordability, housing affordability, and other essential services will depend on the coordination of policies and programs within local communities.

Section 15-10. Definitions. As used in this Act:

"Alternative energy improvement" means the installation or upgrade of electrical wiring, outlets, or charging stations to charge a motor vehicle that is fully or partially powered by electricity; photovoltaic, energy storage, or thermal resource; or any combination thereof.

"Energy efficiency improvement" means equipment, devices, or materials intended to decrease energy consumption or promote a more efficient use of electricity, natural gas, propane, or other forms of energy on property, including, but not limited to, all of the following:

(1) insulation in walls, roofs, floors, foundations, or heating and cooling distribution systems;

(2) storm windows and doors, multi-glazed windows and doors, heat-absorbing or heat-reflective glazed and coated window and door systems, and additional glazing, reductions in glass area, and other window and door system modifications that reduce energy consumption;

(3) automated energy control systems;

(4) high efficiency heating, ventilating, or air-conditioning and distribution system modifications or replacements;

(5) caulking, weather-stripping, and air sealing;

(6) replacement or modification of lighting fixtures to reduce the energy use of the lighting system;

(7) energy controls or recovery systems;

(8) day lighting systems;

(9) any energy efficiency project, as defined in Section 825-65 of the Illinois Finance Authority Act; and

(10) any other installation or modification of equipment, devices, or materials approved as a utility cost-savings measure by the governing body.

"Energy project" means the installation or modification of an alternative energy improvement, energy efficiency improvement, or water use improvement, or the acquisition, installation, or improvement of a renewable energy system that is affixed to a stabilized existing property (including new construction).

"Environmental justice communities" means the proposed definition of that term based on existing methodologies and findings used by the Illinois Power Agency and its Administrator in its Illinois Solar for All Program.

"Governing body" means the county board or board of county commissioners of a county, the city council of a city, or the board of trustees of a village.

"Local unit of government" means a county, city, or village.

"Renewable energy resource" includes energy and its associated renewable energy credit or renewable energy credits from wind energy, solar thermal energy, geothermal energy, photovoltaic cells and panels, biodiesel, anaerobic digestion, and hydropower that does not involve new construction or significant expansion of hydropower dams. For purposes of this Act, landfill gas produced in the State is considered a renewable energy resource. "Renewable energy resource" does not include the incineration or burning of any solid material.

"Renewable energy system" means a fixture, product, device, or interacting group of fixtures, products, or devices on the customer's side of the meter that use one or more renewable energy resources to generate electricity, and specifically includes any renewable energy project, as defined in Section 825-65 of the Illinois Finance Authority Act.

"Water use improvement" means any fixture, product, system, device, or interacting group thereof for or serving any property that has the effect of conserving water resources through improved water management, efficiency, or thermal resource.

Section 15-15. Community Energy and Climate Plans; creation.

(a) Pursuant to the procedures in Section 15-20, a local unit of government may establish Community Energy and Climate Plans and identify boundaries and areas covered by the Plans.

(b) Community Energy and Climate Plans are intended to aid local governments develop a comprehensive approach to combining different energy and climate programs and funding resources to achieve complementary impact. An effective planning process shall:

(1) help communities discover ways that their local government, businesses, and residents can control their energy use and bills;

(2) ensure a cost-effective transition away from fossil fuels in the transportation sector;

(3) expand access to workforce development and job training opportunities in the emerging clean energy economy;

(4) promote economic development through improvements in community infrastructure, transit, and support for local business;

(5) improve the health of Illinois communities by reducing emissions, addressing existing brownfield areas, and promoting the integration of distributed energy resources;

(6) enable greater customer engagement, empowerment, and options for energy services, and ultimately reduce utility bills for Illinoisans;

(7) bring the benefits of grid modernization and the deployment of distributed energy resources to economically disadvantaged communities throughout Illinois; and

(8) support existing Illinois policy goals promoting energy efficiency, demand response and investments in renewable energy resources.

(c) A Community Energy and Climate Plan shall include discussion of:

(1) the demographics of the community, including information on the mix of residential and commercial areas and populations, ages, languages, education and workforce training. This includes an examination of the average utility bills paid within the community by class and census area, the percentage and locations of individuals requiring energy assistance, participation of community members in other assistance programs. This also includes an examination of the community's energy use, both for electricity, natural gas, and transportation and other fuels;

(2) the geography of the community, including the amount of green space, brownfield sites, open space for potential development, location of critical infrastructure such as emergency response facilities, health care and education facilities, and public transportation routes; and

(3) information on economic development opportunities, commercial usage, and employment opportunities.

(d) A Community Energy and Climate Plan shall address the following areas:

(1) distributed energy resources, including energy efficiency, demand response, dynamic pricing, energy storage, solar (thermal, rooftop, and community);

(2) building codes (both commercial and residential);

(3) vehicle miles traveled; and

(4) transit options, including individual car ownership, ride sharing, buses, trains, bicycles, and pedestrian walkways.

(e) A Community Energy and Climate Plan will conclude with proposals to:

(1) increase the use of electricity as a transportation fuel at multi-unit dwellings;

(2) maximize the system-wide benefits of transportation electrification;

(3) test innovative load management programs or rate structures associated with the use of electric vehicles by residential customers to achieve customer fuel cost savings relative to gasoline or diesel fuels and to optimize grid efficiency;

(4) increase the integration of distributed energy resources in the community;

(5) significantly expand the percentage of net-zero housing and net-zero buildings in the community;

(6) improve utility bill affordability;

(7) increase mass transit ridership;

(8) decrease vehicle miles traveled; and

(9) reduce local emissions of greenhouse gases, NOx, SOx, particulate matter, and other air pollutants.

(e) A Community Energy and Climate Plan may be administered by one or more program administrators or the local unit of government.

Section 15-20. Community Energy and Climate Planning process.

(a) An effective planning process shall engage with a diverse set of stakeholders in local communities, including: environmental justice organizations; economic development organizations; faith-based nonprofit organizations; educational institutions; interested residents; health care institutions; tenant organizations; housing institutions, developers, and owners; elected and appointed officials; and representatives reflective of each local community.

(b) An effective planning process shall engage with individual members of the community as much as possible to ensure that the Plans receive input from as diverse set of perspectives as possible.

(c) Plan materials and meetings related to the Plan shall be translated into languages that reflect the makeup of the local community.

(d) The planning process shall be conducted in an ethical, transparent fashion, and will continually review its policies and practices to determine how best to meet its objectives.

Section 15-25. Joint Community Energy and Climate Plans. A local unit of government may join with any other local unit of government, or with any public or private person, or with any number or combination thereof, under the Intergovernmental Cooperation Act, by contract or otherwise as may be permitted by law, for the implementation of a Community Energy and Climate Plan, in whole or in part.

Article 20.

Clean Energy Empowerment Zones Act

Section 20-1. Short title. This Article may be cited as the Clean Energy Empowerment Zones Act. References in this Article to "this Act" mean this Article.

Section 20-5. Legislative findings. The General Assembly finds that, as part of putting Illinois on path to 100% renewable energy, the State of Illinois should ensure a just transition to that goal, providing support for the transition of Illinois' communities and workers impacted by closures or reduced utilization of coal by allocating new State economic development resources for new business tax incentives, workforce training, site clean-up and reuse, and local tax revenue replacement.

Section 20-10. Definitions. As used in this Act:

"Agency" means the Illinois Environmental Protection Agency.

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

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

"Empowerment Zones" means Clean Energy Empowerment Zones Program.

"Environmental justice communities" means the proposed definition of that term based on existing methodologies and findings used by the Illinois Power Agency and its Administrator in its Illinois Solar for All Program.

Section 20-15. Clean Energy Empowerment Zones. Within 180 days after the effective date of this Act, the Illinois Department of Commerce and Economic Opportunity shall develop and implement strategic planning initiatives to support communities and workers who are economically impacted by the decline of fossil-fuel generation and broader changes in the electric sector. As part of this work, the Department shall:

(1) work with the Illinois Environmental Protection Agency, Illinois Environmental Justice Commission, and the Illinois Department of Labor to define "Economically Impacted Communities and Workers" by the decline of fossil-fuel use;

(2) establish funds to support impacted workers and communities through workforce training programs, new business tax incentives, and revitalization of sites previously used for or by those units, including, but not limited to, the generation sources, coal ash disposal sites, and areas otherwise blighted by fossil-fuel use;

(3) convene, jointly with the Agency and at least one community-based organization, quarterly stakeholder engagement sessions beginning in the fourth quarter of 2019 and continuing for not less than 2 years to gather input from impacted community members, businesses, elected officials, environmental organizations, and other relevant individuals or organizations on issues faced by impacted communities and potential economic development opportunities for those communities; and

(4) provide coordination and guidance for communities and prospective new businesses on available workforce training programs, revitalization opportunities, new business incentives, Community Energy and Climate Plans under the Community Energy and Climate Planning Act, beneficial electrification under Section 16-107.8 of the Public Utilities Act, and other State and federal programs such as Opportunity Zones (Internal Revenue Code 1400Z).

Article 90.

Amendatory Provisions

Section 90-5. The Electric Vehicle Act is amended by adding Sections 30, 35, and 40 as follows:

(20 ILCS 627/30 new)

Sec. 30. Electric Vehicle Charging Infrastructure Rebate and Incentive Program.

(a) The purpose of this Section is to provide rebates and other incentives to residential and commercial customers to increase the development of electric vehicle charging infrastructure.

(b) In this Section:

"Level 2 charging" means a charging method that allows an electric vehicle to be connected to permanently wired EVSE with a specialized connector (SAE J1772) with power levels rated at less than or equal to 240 VAC/80 amps.

"Level 3 charging" means a charging method that allows an electric vehicle to be connected to permanently wired EVSE with direct current service with power levels rated at 480VAC and a 3-phase circuit.

(c) Within 120 days after the effective date of this amendatory Act of the 101st General Assembly, the Department of Commerce and Economic Opportunity shall establish a program to provide rebates for residential customers who both install electric vehicle charging infrastructure on their premises and enroll in time-of-use, hourly rates, managed charging, or other beneficial electrification programs as defined in Section 16-107.8 of the Public Utilities Act sufficient to offset no less than 60% of the cost of installing that infrastructure (or another reasonable amount sufficient to incentivize development, as determined by the program administrator), except as provided in this subsection.

Residential customers residing in environmental justice communities, as defined in the Clean Energy Empowerment Zones Act, or households at or below 80% of the area median income, who install electric vehicle charging infrastructure and enroll in time-of-use, hourly rates, managed charging, or other beneficial electrification programs as defined in Section 16-107.8 of the Public Utilities Act shall be eligible to receive rebates of 90% of the cost of installing that infrastructure (or another reasonable amount sufficient to incentivize development, as determined by the program administrator).

(d) Within 120 days after the effective date of this amendatory Act of the 101st General Assembly, the Department of Commerce and Economic Opportunity shall establish a program to provide rebates for Level 2 charging and Level 3 charging for government and commercial customers to purchase and install electric vehicle charging infrastructure to support medium-duty and heavy-duty electric fleet vehicles. Eligible customers must both install electric vehicle charging infrastructure for the purpose of charging medium-duty and heavy-duty electric vehicles, as defined in this subsection, and participate in beneficial electrification strategies as defined in Section 16-107.8 of the Public Utilities Act, such as enrolling in managed charging, installing distributed generation which serves all or part of the energy supply needs of the charging infrastructure, or other programs. The amount of the rebate shall be sufficient to incentivize adoption of electric medium-duty and heavy-duty fleet vehicles, but no less than 50% of the cost of purchase and installation. For the purposes of this Section, medium-duty and heavy-duty electric vehicles include school buses, transit buses, freight trucks, delivery vehicles, and other vehicles as defined by the program administrator.

(e) Within 120 days after the effective date of this amendatory Act of the 101st General Assembly, the Department of Commerce and Economic Opportunity shall establish a program to provide rebates for commercial customers to purchase and install charging infrastructure to support light-duty electric vehicles, including personal vehicles used by employees, to enable charging on premises. Eligible customers must both install electric vehicle charging infrastructure for the purpose of charging and participate in beneficial electrification strategies as defined in Section 16-107.8 of the Public Utilities Act, such as enrolling in Managed Charging, installing distributed generation which serves all or part of the energy supply needs of the charging infrastructure, or other programs. The amount of the rebate shall be sufficient to incentivize installation of light-duty electric vehicle charging infrastructure, but no less than 50% of the cost of purchase and installation.

(f) Within 120 days after the effective date of this amendatory Act of the 101st General Assembly, the Department of Commerce and Economic Opportunity shall establish a program to provide rebates for Level 2 and Level 3 electric vehicle charging infrastructure which serves multi-family (three or more unit) residential premises. Owners of the multi-family property on whose premises the infrastructure will be installed or third parties are eligible to apply for the rebate. The amount of the rebate shall be sufficient to incentivize installation of light-duty electric vehicle charging infrastructure, but no less than 50% of the cost of purchase and installation.

(g) Within 120 days after the effective date of this amendatory Act of the 101st General Assembly, the Department of Commerce and Economic Opportunity shall establish a program to provide rebates for pilot programs which incentivize installation of electric vehicle charging infrastructure on the public way. Such programs shall include:

(1) local governments that develop publicly-available electric vehicle charging using streetlights or other city-owned infrastructure; and

(2) local governments and privately-owned third parties that install publicly-available electric vehicle charging infrastructure along State highways, interstates, and other corridors.

(h) Within 120 days after the effective date of this amendatory Act of the 101st General Assembly, the Department of Commerce and Economic Opportunity shall establish and implement an Electric Vehicle Access for All Program set forth in Section 35.

(i) The Department of Commerce and Economic Opportunity shall select, through a competitive bidding process, a program administrator to oversee and administer the programs described in this Section.

(j) The Department shall report to the Governor and the General Assembly regarding the effectiveness of the programs in increasing electric vehicle charging infrastructure development no later than July 1, 2021.

(20 ILCS 627/35 new)

Sec. 35. Electric Vehicle Access for All.

(a) The General Assembly finds that it is necessary to provide access to electric vehicles to residents in communities where and for individuals whom car ownership is not an option, affordable, or a preference, particularly for environmental justice communities and low-income communities.

(b) Within 120 days after the effective date of this amendatory Act of the 101st General Assembly, the Department of Commerce and Economic Opportunity shall establish and implement an Electric Vehicle Access for All Program, designed to maximize opportunities for carbon-free transportation across the State, particularly targeting environmental justice and low-income communities, which shall include the following initiatives:

(1) Car sharing. The Department of Commerce and Economic Opportunity shall develop and implement an electric vehicle car sharing program that enables residents opportunities to use electric vehicles owned by local municipalities or other third parties for occasional commutes.

(2) Pilot programs. The Department shall dedicate funding for local governments' eligible Community Energy and Climate Plans that include Electric Vehicle Access for All as priority initiatives.

(c) To the extent possible, the Department shall coordinate the Electric Vehicle Access for All program with the other programs established in this Act.

(20 ILCS 627/40 new)

Sec. 40. Carbon-Free Last Mile of Commutes Program.

(a) The purpose of this Section is to provide citizens access to carbon-free commuting by creating pilot programs to address the "last mile" of commutes, enabling a larger number of citizens to access public transportation and reducing the pollution impact of the entire commute.

(b) Within 120 days after the effective date of this amendatory Act of the 101st General Assembly, and for a period not less than 36 months thereafter, the Department of Commerce and Economic Opportunity shall establish and implement a Last Mile of Commutes Program, designed to maximize opportunities for carbon-free transportation across the State, particularly targeting environmental justice and low-income communities, to provide grants to pilot programs with the purpose of bridging public transportation gaps between residences and employment locations. Eligible programs may include electric shuttles, electric and non-electric bicycle and scooter sharing, electric vehicle sharing, and other carbon-free alternatives.

The Department of Commerce and Economic Opportunity shall select, through a competitive bidding program, a program administrator to oversee and administer the program.

(c) In conducting the program, the Department of Commerce and Economic Opportunity shall partner with appropriate transit agencies, employers, and other transportation services to increase the number of employment locations reachable by public transit. The Department of Commerce and Economic Opportunity shall additionally partner with local governments engaging in Community Energy and Climate Planning, as described in the Community Energy and Climate Planning Act, to implement Last Mile of Commutes Programs efficiently with needs identified in Community Energy and Climate Plans.

(d) The Department of Commerce and Economic Opportunity shall operate the Last Mile of Commutes Program in conjunction with the Electric Vehicle Access for All Program, to effectively coordinate the programs and maximize opportunities for carbon-free transportation across the State, particularly targeting environmental justice and low-income communities.

(e) The Department of Commerce and Economic Opportunity shall report to the Governor and the General Assembly regarding the effectiveness of the programs no later than July 1, 2021.

Section 90-10. The Illinois Power Agency Act is amended by changing Sections 1-5, 1-20, 1-56, and 1-75 as follows:

(20 ILCS 3855/1-5)

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

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

(1.5) To provide the highest quality of life for the residents of Illinois, and to provide for a clean and healthy environment, it is the policy of this State to rapidly transition to 100% renewable energy.

(2) (Blank).

(3) (Blank).

(4) 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 facilities, 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 renewable resources and zero emission credits from zero emission facilities 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. Developing new renewable energy resources in Illinois, including brownfield solar projects and community solar projects, will help to diversify Illinois electricity supply, avoid and reduce pollution, reduce peak demand, and enhance public health and well-being of Illinois residents.

(7) Developing community solar projects in Illinois will help to expand access to renewable energy resources to more Illinois residents.

(8) Developing brownfield solar projects in Illinois will help return blighted or contaminated land to productive use while enhancing public health and the well-being of Illinois residents.

(9) Energy efficiency, demand-response measures, zero emission energy, and renewable energy are resources currently underused in Illinois. These resources should be used, when cost effective, to reduce costs to consumers, improve reliability, and improve environmental quality and public health.

(10) 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.

(11) 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.

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

(13) To ensure that the benefits of installing renewable resources are available to all Illinois residents and located across the State, subject to appropriation, it is necessary for the Illinois Power Agency to provide public information and educational resources on how residents can benefit from the expansion of renewable energy in Illinois and participate in the Illinois Solar for All Program established in Section 1-56 of this Act, the Adjustable Block Program established in Section 1-75 of this Act, the job training programs established by paragraph (1) of subsection (a) of Section 16-108.12 of the Public Utilities Act, and the programs and resources established by the Clean Jobs Workforce Hubs Act.

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 delivery year commencing June 1, 2017, zero emission credits from zero emission facilities sufficient to achieve the standards specified in this Act.

(B) Conduct the competitive procurement processes identified in this Act.

(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.

(H) Implement renewable energy procurement and training programs throughout the State to diversify Illinois electricity supply, improve reliability, avoid and reduce pollution, reduce peak demand, and enhance public health and well-being of Illinois residents, including low-income residents.

(Source: P.A. 99-906, eff. 6-1-17.)

(20 ILCS 3855/1-20)

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

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

(1) Develop electricity procurement plans to ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time, taking into account any benefits of price stability, for electric utilities that on December 31, 2005 provided electric service to at least 100,000 customers in Illinois and for small multi-jurisdictional electric utilities that (A) on December 31, 2005 served less than 100,000 customers in Illinois and (B) request a procurement plan for their Illinois jurisdictional load. Except as provided in paragraph (1.5) of this subsection (a), the electricity procurement plans shall be updated on an annual basis and shall include electricity generated from renewable resources sufficient to achieve the standards specified in this Act. Beginning with the delivery year commencing June 1, 2017, develop procurement plans to include zero emission credits generated from zero emission facilities sufficient to achieve the standards specified in this Act. Beginning with the procurement for the delivery year commencing June 1, 2021, the Agency shall for each year develop a plan, as part of its procurement plan, to conduct a procurement of capacity from qualified resources needed to meet capacity requirements of the retail customers of electric utilities that serve more than 3,000,000 retail customers and are located in the PJM interconnection, subject to the open access tariff and manuals of PJM Interconnection and approved by the Federal Energy Regulatory Commission. The capacity procurement plan shall be updated annually and shall include electricity generated from renewable resources sufficient to achieve the renewable portfolio standards as specified in this Act.

(1.5) Develop a long-term renewable resources procurement plan in accordance with subsection (c) of Section 1-75 of this Act for renewable energy credits in amounts sufficient to achieve the standards specified in this Act for delivery years commencing June 1, 2017 and for the programs and renewable energy credits specified in Section 1-56 of this Act. Electricity procurement plans for delivery years commencing after May 31, 2017, shall not include procurement of renewable energy resources.

(2) Conduct competitive procurement processes to procure the supply resources identified in the electricity procurement plan, pursuant to Section 16-111.5 of the Public Utilities Act, and, for the delivery year commencing June 1, 2017, conduct procurement processes to procure zero emission credits from zero emission facilities, under subsection (d-5) of Section 1-75 of this Act.

(2.5) Beginning with the procurement for the 2017 delivery year, conduct competitive procurement processes and implement programs to procure renewable energy credits identified in the long-term renewable resources procurement plan developed and approved under subsection (c) of Section 1-75 of this Act and Section 16-111.5 of the Public Utilities Act.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

(21) To accept and expend appropriations.

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

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

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

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

(26) To review, revise, and approve sourcing agreements and mediate and resolve disputes between gas utilities and the clean coal SNG brownfield facility pursuant to subsection (h-1) of Section 9-220 of the Public Utilities Act.

(27) To request, review and accept proposals, execute contracts, purchase renewable energy credits and otherwise dedicate funds from the Illinois Power Agency Renewable Energy Resources Fund to create and carry out the objectives of the Illinois Solar for All program in accordance with Section 1-56 of this Act.

(Source: P.A. 99-906, eff. 6-1-17.)

(20 ILCS 3855/1-56)

Sec. 1-56. Illinois Power Agency Renewable Energy Resources Fund; Illinois Solar for All Program.

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

(b) The Illinois Power Agency Renewable Energy Resources Fund shall be administered by the Agency as described in this subsection (b), provided that the changes to this subsection (b) made by this amendatory Act of the 99th General Assembly shall not interfere with existing contracts under this Section.

(1) The Illinois Power Agency Renewable Energy Resources Fund shall be used to purchase renewable energy credits according to any approved procurement plan developed by the Agency prior to June 1, 2017.

(2) The Illinois Power Agency Renewable Energy Resources Fund shall also be used to create the Illinois Solar for All Program, which shall include incentives for low-income distributed generation and community solar projects, and other associated approved expenditures. The objectives of the Illinois Solar for All Program are to bring photovoltaics to low-income communities in this State in a manner that maximizes the development of new photovoltaic generating facilities, to create a long-term, low-income solar marketplace throughout this State, to integrate, through interaction with stakeholders, with existing energy efficiency initiatives, and to minimize administrative costs. The Agency shall include a description of its proposed approach to the design, administration, implementation and evaluation of the Illinois Solar for All Program, as part of the long-term renewable resources procurement plan authorized by subsection (c) of Section 1-75 of this Act, and the program shall be designed to grow the low-income solar market. The Agency or utility, as applicable, shall purchase renewable energy credits from the (i) photovoltaic distributed renewable energy generation projects and (ii) community solar projects that are procured under procurement processes authorized by the long-term renewable resources procurement plans approved by the Commission.

The Illinois Solar for All Program shall include the program offerings described in subparagraphs (A) through (D) of this paragraph (2), which the Agency shall implement through contracts with third-party providers and, subject to appropriation, pay the approximate amounts identified using monies available in the Illinois Power Agency Renewable Energy Resources Fund. Each contract that provides for the installation of solar facilities shall provide that the solar facilities will produce energy and economic benefits, at a level determined by the Agency to be reasonable, for the participating low income customers. The monies available in the Illinois Power Agency Renewable Energy Resources Fund and not otherwise committed to contracts executed under subsection (i) of this Section shall be allocated among the programs described in this paragraph (2), as follows: 22.5% of these funds shall be allocated to programs described in subparagraph (A) of this paragraph (2), 37.5% of these funds shall be allocated to programs described in subparagraph (B) of this paragraph (2), 15% of these funds shall be allocated to programs described in subparagraph (C) of this paragraph (2), and 25% of these funds, but in no event more than $50,000,000, shall be allocated to programs described in subparagraph (D) of this paragraph (2). Beginning with the 2019 update to the long-term renewable resource procurement plan authorized by subsection (c) of Section 1-75 of this Act, subject to appropriation and, following the 2021 delivery year, subject to fund availability through the Commission process described in subparagraph (Q) of paragraph (1) of subsection (c) of Section 1-75, funds shall be allocated to programs described in subparagraphs (E) and (F) of this paragraph (2). The allocation of funds among subparagraphs (A), (B), or (C) of this paragraph (2) may be changed if the Agency or administrator, through delegated authority, determines incentives in subparagraphs (A), (B), or (C) of this paragraph (2) have not been adequately subscribed to fully utilize the Illinois Power Agency Renewable Energy Resources Fund. The determination shall include input through a stakeholder process. Additionally, if the Commission process described in subparagraph (Q) of paragraph (1) of subsection (c) of Section 1-75 results in an increase in funds available to the Illinois Solar for All program, the Agency shall reallocate the funds among all the various subprograms of the Illinois Solar for All Program to provide funding for the subprograms described in subparagraphs (E) and (F) of this paragraph (2). This reallocation shall involve input through a stakeholder process. The program offerings described in subparagraphs (A) through (D) of this paragraph (2) shall also be implemented through contracts funded from such additional amounts as are allocated to one or more of the programs in the long-term renewable resources procurement plans as specified in subsection (c) of Section 1-75 of this Act and subparagraph (O) of paragraph (1) of such subsection (c).

Contracts that will be paid with funds in the Illinois Power Agency Renewable Energy Resources Fund shall be executed by the Agency. Contracts that will be paid with funds collected by an electric utility shall be executed by the electric utility.

Contracts under the Illinois Solar for All Program shall include an approach, as set forth in the long-term renewable resources procurement plans, to ensure the wholesale market value of the energy is credited to participating low-income customers or organizations and to ensure tangible economic benefits flow directly to program participants, except in the case of low-income multi-family housing where the low-income customer does not directly pay for energy. Priority shall be given to projects that demonstrate meaningful involvement of low-income community members in designing the initial proposals. Acceptable proposals to implement projects must demonstrate the applicant's ability to conduct initial community outreach, education, and recruitment of low-income participants in the community. Projects must include job training opportunities if available, and shall endeavor to coordinate with the job training programs described in paragraph (1) of subsection (a) of Section 16-108.12 of the Public Utilities Act.

(A) Low-income distributed generation incentive. This program will provide incentives to low-income customers, either directly or through solar providers, to increase the participation of low-income households in photovoltaic on-site distributed generation. Companies participating in this program that install solar panels shall commit to hiring job trainees for a portion of their low-income installations, and an administrator shall facilitate partnering the companies that install solar panels with entities that provide solar panel installation job training. It is a goal of this program that a minimum of 25% of the incentives for this program be allocated to projects located within environmental justice communities. Contracts entered into under this paragraph may be entered into with an entity that will develop and administer the program and shall also include contracts for renewable energy credits from the photovoltaic distributed generation that is the subject of the program, as set forth in the long-term renewable resources procurement plan.

(B) Low-Income Community Solar Project Initiative. Incentives shall be offered to low-income customers, either directly or through developers, to increase the participation of low-income subscribers of community solar projects. The developer of each project shall identify its partnership with community stakeholders regarding the location, development, and participation in the project, provided that nothing shall preclude a project from including an anchor tenant that does not qualify as low-income. Incentives should also be offered to community solar projects that are 100% low-income subscriber owned, which includes low-income households, not-for-profit organizations, and affordable housing owners. It is a goal of this program that a minimum of 25% of the incentives for this program be allocated to community photovoltaic projects in environmental justice communities. Contracts entered into under this paragraph may be entered into with developers and shall also include contracts for renewable energy credits related to the program.

(C) Incentives for non-profits and public facilities. Under this program funds shall be used to support on-site photovoltaic distributed renewable energy generation devices to serve the load associated with not-for-profit customers and to support photovoltaic distributed renewable energy generation that uses photovoltaic technology to serve the load associated with public sector customers taking service at public buildings. It is a goal of this program that at least 25% of the incentives for this program be allocated to projects located in environmental justice communities. Contracts entered into under this paragraph may be entered into with an entity that will develop and administer the program or with developers and shall also include contracts for renewable energy credits related to the program.

(D) Low-Income Community Solar Pilot Projects. Under this program, persons, including, but not limited to, electric utilities, shall propose pilot community solar projects. Community solar projects proposed under this subparagraph (D) may exceed 2,000 kilowatts in nameplate capacity, but the amount paid per project under this program may not exceed $20,000,000. Pilot projects must result in economic benefits for the members of the community in which the project will be located. The proposed pilot project must include a partnership with at least one community-based organization. Approved pilot projects shall be competitively bid by the Agency, subject to fair and equitable guidelines developed by the Agency. Funding available under this subparagraph (D) may not be distributed solely to a utility, and at least some funds under this subparagraph (D) must include a project partnership that includes community ownership by the project subscribers. Contracts entered into under this paragraph may be entered into with an entity that will develop and administer the program or with developers and shall also include contracts for renewable energy credits related to the program. A project proposed by a utility that is implemented under this subparagraph (D) shall not be included in the utility's rate base ratebase.

(E) Energy Sovereignty Distributed Generation Incentive. Beginning with the 2019 update to the long-term renewable resource procurement plan authorized by subsection (c) of Section 1-75 of this Act, subject to appropriation, the Illinois Power Agency shall create a program that provides incentives to low-income customers, either directly or through solar providers, to increase the participation of low-income households in photovoltaic on-site distributed generation in projects that are 100% low-income household owned, which includes low-income households, low-income households in environmental justice communities, not-for-profit organizations providing services to low-income households, affordable housing owners, and community-based limited liability companies providing services to low-income households. The program shall also provide incentives for photovoltaic on-site distributed generation projects that, by no later than 5 years after the device is interconnected at the distribution system level of the utility and energized, are a minimum of 49% low-income subscriber owned, which includes low-income households, low-income households in environmental justice communities, not-for-profit organizations providing services to low-income households, affordable housing owners, and community-based limited liability companies providing services to low-income households. Companies participating in this program that install solar panels shall commit to hiring job trainees for a portion of their low-income installations, and an administrator shall facilitate partnering the companies that install solar panels with entities that provide solar panel installation job training. It is a goal of this program that a minimum of 25% of the incentives for this program be allocated to projects in environmental justice communities. Contracts entered into under this paragraph may be entered into with an entity that will develop and administer the program and shall also include contracts for renewable energy credits from the photovoltaic distributed generation that is the subject of the program, as set forth in the long-term renewable resources procurement plan.

(F) Energy Sovereignty Community Solar Incentive. Beginning with the 2019 update to the long-term renewable resource procurement plan authorized by subsection (c) of Section 1-75 of this Act, subject to appropriation, the Illinois Power Agency shall create a program that shall provide incentives to low-income customers, either directly or through developers, to increase the participation of low-income subscribers of community solar projects in projects that are 100% low-income subscriber owned, which includes low-income households, low-income households in environmental justice communities, not-for-profit organizations providing services to low-income households, affordable housing owners, and community-based limited liability companies providing services to low-income households. The program shall also provide incentives for community solar projects that, by no later than 5 years after the device is interconnected at the distribution system level of the utility and energized, are a minimum of 49% low-income subscriber owned, which includes low-income households, low-income households in environmental justice communities, not-for-profit organizations providing services to low-income households, affordable housing owners, and community-based limited liability companies providing services to low-income households. The developer of each project shall identify its partnership with community stakeholders regarding the location, development and participation in the project. Companies participating in this program that install solar panels shall commit to hiring job trainees for a portion of their low-income installations, and an administrator shall facilitate partnering the companies that install solar panels with entities that provide solar panel installation job training. It is a goal of this program that a minimum of 25% of the incentives for this program be allocated to projects in environmental justice communities. Contracts entered into under this paragraph may be entered into with developers and shall also include contracts for renewable energy credits related to the program.

The requirement that a qualified person, as defined in paragraph (1) of subsection (i) of this Section, install photovoltaic devices does not apply to the Illinois Solar for All Program described in this subsection (b).

(3) Costs associated with the Illinois Solar for All Program and its components described in paragraph (2) of this subsection (b), including, but not limited to, costs associated with procuring experts, consultants, and the program administrator referenced in this subsection (b) and related incremental costs, and costs related to the evaluation of the Illinois Solar for All Program, may be paid for using monies in the Illinois Power Agency Renewable Energy Resources Fund, but the Agency or program administrator shall strive to minimize costs in the implementation of the program. The Agency shall purchase renewable energy credits from generation that is the subject of a contract under subparagraphs (A) through (D) of this paragraph (2) of this subsection (b), and may pay for such renewable energy credits through an upfront payment per installed kilowatt of nameplate capacity paid once the device is interconnected at the distribution system level of the utility and is energized. The payment shall be in exchange for an assignment of all renewable energy credits generated by the system during the first 15 years of operation and shall be structured to overcome barriers to participation in the solar market by the low-income community. The incentives provided for in this Section may be implemented through the pricing of renewable energy credits where the prices paid for the credits are higher than the prices from programs offered under subsection (c) of Section 1-75 of this Act to account for the incentives. The Agency shall ensure collaboration with community agencies, and allocate up to 5% of the funds available under the Illinois Solar for All Program to community-based groups to assist in grassroots education efforts related to the Illinois Solar for All Program. The Agency shall retire any renewable energy credits purchased from this program and the credits shall count towards the obligation under subsection (c) of Section 1-75 of this Act for the electric utility to which the project is interconnected.

(4) The Agency shall, consistent with the requirements of this subsection (b), propose the Illinois Solar for All Program terms, conditions, and requirements, including the prices to be paid for renewable energy credits, and which prices may be determined through a formula, through the development, review, and approval of the Agency's long-term renewable resources procurement plan described in subsection (c) of Section 1-75 of this Act and Section 16-111.5 of the Public Utilities Act. In the course of the Commission proceeding initiated to review and approve the plan, including the Illinois Solar for All Program proposed by the Agency, a party may propose an additional low-income solar or solar incentive program, or modifications to the programs proposed by the Agency, and the Commission may approve an additional program, or modifications to the Agency's proposed program, if the additional or modified program more effectively maximizes the benefits to low-income customers after taking into account all relevant factors, including, but not limited to, the extent to which a competitive market for low-income solar has developed. Following the Commission's approval of the Illinois Solar for All Program, the Agency or a party may propose adjustments to the program terms, conditions, and requirements, including the price offered to new systems, to ensure the long-term viability and success of the program. The Commission shall review and approve any modifications to the program through the plan revision process described in Section 16-111.5 of the Public Utilities Act.

(5) The Agency shall issue a request for qualifications for a third-party program administrator or administrators to administer all or a portion of the Illinois Solar for All Program. The third-party program administrator shall be chosen through a competitive bid process based on selection criteria and requirements developed by the Agency, including, but not limited to, experience in administering low-income energy programs and overseeing statewide clean energy or energy efficiency services. If the Agency retains a program administrator or administrators to implement all or a portion of the Illinois Solar for All Program, each administrator shall periodically submit reports to the Agency and Commission for each program that it administers, at appropriate intervals to be identified by the Agency in its long-term renewable resources procurement plan, provided that the reporting interval is at least quarterly.

(6) The long-term renewable resources procurement plan shall also provide for an independent evaluation of the Illinois Solar for All Program. At least every 2 years, the Agency shall select an independent evaluator to review and report on the Illinois Solar for All Program and the performance of the third-party program administrator of the Illinois Solar for All Program. The evaluation shall be based on objective criteria developed through a public stakeholder process. The process shall include feedback and participation from Illinois Solar for All Program stakeholders, including participants and organizations in environmental justice and historically underserved communities. The report shall include a summary of the evaluation of the Illinois Solar for All Program based on the stakeholder developed objective criteria. The report shall include the number of projects installed; the total installed capacity in kilowatts; the average cost per kilowatt of installed capacity to the extent reasonably obtainable by the Agency; the number of jobs or job opportunities created; economic, social, and environmental benefits created; and the total administrative costs expended by the Agency and program administrator to implement and evaluate the program. The report shall be delivered to the Commission and posted on the Agency's website, and shall be used, as needed, to revise the Illinois Solar for All Program. The Commission shall also consider the results of the evaluation as part of its review of the long-term renewable resources procurement plan under subsection (c) of Section 1-75 of this Act.

(7) If additional funding for the programs described in this subsection (b) is available under subsection (k) of Section 16-108 of the Public Utilities Act, then the Agency shall submit a procurement plan to the Commission no later than September 1, 2018, that proposes how the Agency will procure programs on behalf of the applicable utility. After notice and hearing, the Commission shall approve, or approve with modification, the plan no later than November 1, 2018.

(8) Beginning with the 2019 update to the long-term renewable resources procurement plan authorized by subsection (c) of Section 1-75 of this Act, subject to appropriation and, following the 2021 delivery year, subject to fund availability through the Commission process described in subparagraph (Q) of paragraph (1) of subsection (c) of Section 1-75, the Illinois Power Agency shall propose an expansion of the Illinois Solar for All Program. The expansion shall have as a goal quadrupling the annual installed capacity in kilowatts under subparagraphs (A), (B), and (C) of paragraph (2) as well as quintupling the grassroots education efforts under paragraph (3) of this subsection.

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

For the purposes of this subsection (b), the Agency shall define "environmental justice community" based on methodologies and findings established by the Illinois Power Agency and its Administrator for the Illinois Solar for All Program in its initial long-term renewable resources procurement plan and updated by the Illinois Power Agency and its Administrator for the Illinois Solar for All Program as part of the long-term renewable resources procurement plan update as part of long-term renewable resources procurement plan development, to ensure, to the extent practicable, compatibility with other agencies' definitions and may, for guidance, look to the definitions used by federal, state, or local governments.

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

(b-10) After the receipt of all payments required by Section 16-115D of the Public Utilities Act and payment in full of all contracts executed by the Agency under subsections (b) and (i) of this Section, if the balance of the Illinois Power Agency Renewable Energy Resources Fund is under $5,000, then the Fund shall be inoperative and any remaining funds and any funds submitted to the Fund after that date, shall be transferred to the Supplemental Low-Income Energy Assistance Fund for use in the Low-Income Home Energy Assistance Program, as authorized by the Energy Assistance Act.

(c) (Blank).

(d) (Blank).

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

(f) The selection of one or more third-party program managers or administrators, the selection of the independent evaluator, and the procurement processes described in this Section are exempt from the requirements of the Illinois Procurement Code, under 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 under this Section. Fees collected from bidders shall be deposited into the Renewable Energy Resources Fund.

(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. 98-672, eff. 6-30-14; 99-906, eff. 6-1-17.)

(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 delivery year commencing on June 1, 2017, the Planning and Procurement Bureau shall develop plans and processes for the procurement of zero emission credits from zero emission facilities in accordance with the requirements of subsection (d-5) 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.

Beginning with the plan or plans to be implemented in the 2017 delivery year, the Agency shall no longer include the procurement of renewable energy resources in the annual procurement plans required by this subsection (a), except as provided in subsection (q) of Section 16-111.5 of the Public Utilities Act and subsection (j) of this Section, and shall instead develop a long-term renewable resources procurement plan in accordance with subsection (c) of this Section and Section 16-111.5 of the Public Utilities Act.

(1) The Agency shall each year, beginning in 2008, as needed, issue a request for qualifications for experts or expert consulting firms to develop the procurement plans in accordance with Section 16-111.5 of the Public Utilities Act. In order to qualify an expert or expert consulting firm must have:

(A) direct previous experience assembling large-scale power supply plans or portfolios for end-use customers;

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

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

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

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

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

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

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

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

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

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

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

(E) expertise in credit and contract protocols;

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

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

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

(A) failure to satisfy qualification criteria;

(B) identification of a conflict of interest; or

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

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

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

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

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

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

(c) Renewable portfolio standard.

(1)(A) The Agency shall develop a long-term renewable resources procurement plan that shall include procurement programs and competitive procurement events necessary to meet the goals set forth in this subsection (c). The initial long-term renewable resources procurement plan shall be released for comment no later than 160 days after June 1, 2017 (the effective date of Public Act 99-906). The Agency shall review, and may revise on an expedited basis, the long-term renewable resources procurement plan at least every 2 years, which shall be conducted in conjunction with the procurement plan under Section 16-111.5 of the Public Utilities Act to the extent practicable to minimize administrative expense. The long-term renewable resources procurement plans shall be subject to review and approval by the Commission under Section 16-111.5 of the Public Utilities Act.

(B) Subject to subparagraph (F) of this paragraph (1), the long-term renewable resources procurement plan shall include the goals for procurement of renewable energy credits to meet at least the following overall percentages: 13% by the 2017 delivery year; increasing by at least 1.5% each delivery year thereafter to at least 25% by the 2025 delivery year; increasing by at least 4% each delivery year after the 2025 delivery year to at least 45% by 2030; increasing by at least 3% each delivery year after the 2030 delivery year to at least 60% by 2035, 75% by 2040, and 90% by 2045; increasing by at least 2% each delivery year after the 2045 delivery year to 100% by the 2050 delivery year and continuing at 100% no less than 25% for each delivery year thereafter. In the event of a conflict between these goals and the new wind and new photovoltaic procurement requirements described in items (i) through (iii) of subparagraph (C) and items (i) and (ii) of subparagraph (P) of this paragraph (1), the long-term plan shall prioritize compliance with the new wind and new photovoltaic procurement requirements described in items (i) through (iii) of subparagraph (C) and items (i) and (ii) of subparagraph (P) of this paragraph (1) over the annual percentage targets described in this subparagraph (B). The Agency shall not comply with the annual percentage targets described in this subparagraph (B) by procuring renewable energy credits on the spot market that are unlikely to lead to the development of new renewable resources.

For the delivery year beginning June 1, 2017, the procurement plan shall include cost-effective renewable energy resources equal to at least 13% of each utility's load for eligible retail customers and 13% of the applicable portion of each utility's load for retail customers who are not eligible retail customers, which applicable portion shall equal 50% of the utility's load for retail customers who are not eligible retail customers on February 28, 2017.

For the delivery year beginning June 1, 2018, the procurement plan shall include cost-effective renewable energy resources equal to at least 14.5% of each utility's load for eligible retail customers and 14.5% of the applicable portion of each utility's load for retail customers who are not eligible retail customers, which applicable portion shall equal 75% of the utility's load for retail customers who are not eligible retail customers on February 28, 2017.

For the delivery year beginning June 1, 2019, and for each year thereafter, the procurement plans shall include cost-effective renewable energy resources equal to a minimum percentage of each utility's load for all retail customers as follows: 16% by June 1, 2019; increasing by 1.5% each year thereafter to 25% by June 1, 2025; increasing by at least 4% each year thereafter to at least 45% by June 1, 2030; increasing by at least 3% each year thereafter to at least 90% by June 1, 2045; increasing by at least 2% each year thereafter to at least 100% by June 1, 2050 and 25% by June 1, 2026 and each year thereafter.

For each delivery year, the Agency shall first recognize each utility's obligations for that delivery year under existing contracts. Any renewable energy credits under existing contracts, including renewable energy credits as part of renewable energy resources, shall be used to meet the goals set forth in this subsection (c) for the delivery year.

(C) Of the renewable energy credits procured under this subsection (c), at least 75% shall come from wind and photovoltaic projects. The long-term renewable resources procurement plan described in subparagraph (A) of this paragraph (1) shall include the procurement of renewable energy credits in amounts equal to at least the following:

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

At least 2,000,000 renewable energy credits for each delivery year shall come from new wind projects; and

At least 2,000,000 renewable energy credits for each delivery year shall come from new photovoltaic projects; of that amount, to the extent possible, the Agency shall procure: at least 50% from solar photovoltaic projects using the program outlined in subparagraph (K) of this paragraph (1) from distributed renewable energy generation devices or community renewable generation projects; at least 40% from utility-scale solar projects; at least 2% from brownfield site photovoltaic projects that are not community renewable generation projects; and the remainder shall be determined through the long-term planning process described in subparagraph (A) of this paragraph (1).

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

At least 3,000,000 renewable energy credits for each delivery year shall come from new wind projects; and

At least 3,000,000 renewable energy credits for each delivery year shall come from new photovoltaic projects; of that amount, to the extent possible, the Agency shall procure: at least 50% from solar photovoltaic projects using the program outlined in subparagraph (K) of this paragraph (1) from distributed renewable energy devices or community renewable generation projects; at least 40% from utility-scale solar projects; at least 2% from brownfield site photovoltaic projects that are not community renewable generation projects; and the remainder shall be determined through the long-term planning process described in subparagraph (A) of this paragraph (1).

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

At least 4,000,000 renewable energy credits for each delivery year shall come from new wind projects; and

At least 4,000,000 renewable energy credits for each delivery year shall come from new photovoltaic projects; of that amount, to the extent possible, the Agency shall procure: at least 50% from solar photovoltaic projects using the program outlined in subparagraph (K) of this paragraph (1) from distributed renewable energy devices or community renewable generation projects; at least 40% from utility-scale solar projects; at least 2% from brownfield site photovoltaic projects that are not community renewable generation projects; and the remainder shall be determined through the long-term planning process described in subparagraph (A) of this paragraph (1).

For purposes of this Section:

"New wind projects" means wind renewable energy facilities that are energized after June 1, 2017 for the delivery year commencing June 1, 2017 or within 3 years after the date the Commission approves contracts for subsequent delivery years.

"New photovoltaic projects" means photovoltaic renewable energy facilities that are energized after June 1, 2017. Photovoltaic projects developed under Section 1-56 of this Act shall not apply towards the new photovoltaic project requirements in this subparagraph (C).

(D) Renewable energy credits shall be cost effective. For purposes of this subsection (c), "cost effective" means that the costs of procuring renewable energy resources do not cause the limit stated in subparagraph (E) of this paragraph (1) to be exceeded and, for renewable energy credits procured through a competitive procurement event, do not exceed benchmarks based on market prices for like products in the region. For purposes of this subsection (c), "like products" means contracts for renewable energy credits from the same or substantially similar technology, same or substantially similar vintage (new or existing), the same or substantially similar quantity, and the same or substantially similar contract length and structure. Benchmarks 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. If price benchmarks for like products in the region are not available, the procurement administrator shall establish price benchmarks based on publicly available data on regional technology costs and expected current and future regional energy prices. The benchmarks in this Section shall not be used to curtail or otherwise reduce contractual obligations entered into by or through the Agency prior to June 1, 2017 (the effective date of Public Act 99-906).

(E) For purposes of this subsection (c), the required procurement of cost-effective renewable energy resources for a particular year commencing prior to June 1, 2017 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 delivery year ending immediately prior to the procurement, and, for delivery years commencing on and after June 1, 2017, 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 delivery 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 under the procurement plan for any single year shall be subject to the limitations of this subparagraph (E). Such procurement shall be reduced for all retail customers based on the 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 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 delivery year, the resulting per kilowatthour amount shall be applied to the actual amount of kilowatthours of electricity delivered, or applicable portion of such amount as specified in paragraph (1) of this subsection (c), as applicable, by the electric utility in the delivery year immediately prior to the procurement to all retail customers in its service territory. The calculations required by this subparagraph (E) shall be made only once for each delivery 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 subparagraph (E) 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.

(F) If the limitation on the amount of renewable energy resources procured in subparagraph (E) of this paragraph (1) prevents the Agency from meeting all of the goals in this subsection (c), the Agency's long-term plan shall prioritize compliance with the requirements of this subsection (c) regarding renewable energy credits in the following order:

(i) renewable energy credits under existing contractual obligations;

(i-5) funding for the Illinois Solar for All Program, as described in subparagraph (O) of this paragraph (1);

(ii) renewable energy credits necessary to comply with the new wind and new photovoltaic procurement requirements described in items (i) through (iii) of subparagraph (C) of this paragraph (1); and

(ii-5) renewable energy credits necessary to comply with the new wind and new photovoltaic procurement requirements described in subparagraph (P) of this paragraph (1); and

(iii) renewable energy credits necessary to meet the remaining requirements of this subsection (c).

(G) The following provisions shall apply to the Agency's procurement of renewable energy credits under this subsection (c):

(i) Notwithstanding whether a long-term renewable resources procurement plan has been approved, the Agency shall conduct an initial forward procurement for renewable energy credits from new utility-scale wind projects within 160 days after June 1, 2017 (the effective date of Public Act 99-906). For the purposes of this initial forward procurement, the Agency shall solicit 15-year contracts for delivery of 1,000,000 renewable energy credits delivered annually from new utility-scale wind projects to begin delivery on June 1, 2019, if available, but not later than June 1, 2021. Payments to suppliers of renewable energy credits shall commence upon delivery. Renewable energy credits procured under this initial procurement shall be included in the Agency's long-term plan and shall apply to all renewable energy goals in this subsection (c).

(ii) Notwithstanding whether a long-term renewable resources procurement plan has been approved, the Agency shall conduct an initial forward procurement for renewable energy credits from new utility-scale solar projects and brownfield site photovoltaic projects within one year after June 1, 2017 (the effective date of Public Act 99-906). For the purposes of this initial forward procurement, the Agency shall solicit 15-year contracts for delivery of 1,000,000 renewable energy credits delivered annually from new utility-scale solar projects and brownfield site photovoltaic projects to begin delivery on June 1, 2019, if available, but not later than June 1, 2021. The Agency may structure this initial procurement in one or more discrete procurement events. Payments to suppliers of renewable energy credits shall commence upon delivery. Renewable energy credits procured under this initial procurement shall be included in the Agency's long-term plan and shall apply to all renewable energy goals in this subsection (c).

(iii) Subsequent forward procurements for utility-scale wind projects shall solicit at least 1,000,000 renewable energy credits delivered annually per procurement event and shall be planned, scheduled, and designed such that the cumulative amount of renewable energy credits delivered from all new wind projects in each delivery year shall not exceed the Agency's projection of the cumulative amount of renewable energy credits that will be delivered from all new photovoltaic projects, including utility-scale and distributed photovoltaic devices, in the same delivery year at the time scheduled for wind contract delivery.

(iv) If, at any time after the time set for delivery of renewable energy credits pursuant to the initial procurements in items (i) and (ii) of this subparagraph (G), the cumulative amount of renewable energy credits projected to be delivered from all new wind projects in a given delivery year exceeds the cumulative amount of renewable energy credits projected to be delivered from all new photovoltaic projects in that delivery year by 200,000 or more renewable energy credits, then the Agency shall within 60 days adjust the procurement programs in the long-term renewable resources procurement plan to ensure that the projected cumulative amount of renewable energy credits to be delivered from all new wind projects does not exceed the projected cumulative amount of renewable energy credits to be delivered from all new photovoltaic projects by 200,000 or more renewable energy credits, provided that nothing in this Section shall preclude the projected cumulative amount of renewable energy credits to be delivered from all new photovoltaic projects from exceeding the projected cumulative amount of renewable energy credits to be delivered from all new wind projects in each delivery year and provided further that nothing in this item (iv) shall require the curtailment of an executed contract. The Agency shall update, on a quarterly basis, its projection of the renewable energy credits to be delivered from all projects in each delivery year. Notwithstanding anything to the contrary, the Agency may adjust the timing of procurement events conducted under this subparagraph (G). The long-term renewable resources procurement plan shall set forth the process by which the adjustments may be made.

(v) All procurements under this subparagraph (G) shall comply with the geographic requirements in subparagraph (I) of this paragraph (1) and shall follow the procurement processes and procedures described in this Section and Section 16-111.5 of the Public Utilities Act to the extent practicable, and these processes and procedures may be expedited to accommodate the schedule established by this subparagraph (G).

(H) The procurement of renewable energy resources for a given delivery year shall be reduced as described in this subparagraph (H) if an alternative retail electric supplier meets the requirements described in this subparagraph (H).

(i) Within 45 days after June 1, 2017 (the effective date of Public Act 99-906), an alternative retail electric supplier or its successor shall submit an informational filing to the Illinois Commerce Commission certifying that, as of December 31, 2015, the alternative retail electric supplier owned one or more electric generating facilities that generates renewable energy resources as defined in Section 1-10 of this Act, provided that such facilities are not powered by wind or photovoltaics, and the facilities generate one renewable energy credit for each megawatthour of energy produced from the facility.

The informational filing shall identify each facility that was eligible to satisfy the alternative retail electric supplier's obligations under Section 16-115D of the Public Utilities Act as described in this item (i).

(ii) For a given delivery year, the alternative retail electric supplier may elect to supply its retail customers with renewable energy credits from the facility or facilities described in item (i) of this subparagraph (H) that continue to be owned by the alternative retail electric supplier.

(iii) The alternative retail electric supplier shall notify the Agency and the applicable utility, no later than February 28 of the year preceding the applicable delivery year or 15 days after June 1, 2017 (the effective date of Public Act 99-906), whichever is later, of its election under item (ii) of this subparagraph (H) to supply renewable energy credits to retail customers of the utility. Such election shall identify the amount of renewable energy credits to be supplied by the alternative retail electric supplier to the utility's retail customers and the source of the renewable energy credits identified in the informational filing as described in item (i) of this subparagraph (H), subject to the following limitations:

For the delivery year beginning June 1, 2018, the maximum amount of renewable energy credits to be supplied by an alternative retail electric supplier under this subparagraph (H) shall be 68% multiplied by 25% multiplied by 14.5% multiplied by the amount of metered electricity (megawatt-hours) delivered by the alternative retail electric supplier to Illinois retail customers during the delivery year ending May 31, 2016.

For delivery years beginning June 1, 2019 and each year thereafter, the maximum amount of renewable energy credits to be supplied by an alternative retail electric supplier under this subparagraph (H) shall be 68% multiplied by 50% multiplied by 16% multiplied by the amount of metered electricity (megawatt-hours) delivered by the alternative retail electric supplier to Illinois retail customers during the delivery year ending May 31, 2016, provided that the 16% value shall increase by 1.5% each delivery year thereafter to 25% by the delivery year beginning June 1, 2025, and thereafter the 25% value shall apply to each delivery year.

For each delivery year, the total amount of renewable energy credits supplied by all alternative retail electric suppliers under this subparagraph (H) shall not exceed 9% of the Illinois target renewable energy credit quantity. The Illinois target renewable energy credit quantity for the delivery year beginning June 1, 2018 is 14.5% multiplied by the total amount of metered electricity (megawatt-hours) delivered in the delivery year immediately preceding that delivery year, provided that the 14.5% shall increase by 1.5% each delivery year thereafter to 25% by the delivery year beginning June 1, 2025, and thereafter the 25% value shall apply to each delivery year.

If the requirements set forth in items (i) through (iii) of this subparagraph (H) are met, the charges that would otherwise be applicable to the retail customers of the alternative retail electric supplier under paragraph (6) of this subsection (c) for the applicable delivery year shall be reduced by the ratio of the quantity of renewable energy credits supplied by the alternative retail electric supplier compared to that supplier's target renewable energy credit quantity. The supplier's target renewable energy credit quantity for the delivery year beginning June 1, 2018 is 14.5% multiplied by the total amount of metered electricity (megawatt-hours) delivered by the alternative retail supplier in that delivery year, provided that the 14.5% shall increase by 1.5% each delivery year thereafter to 25% by the delivery year beginning June 1, 2025, and thereafter the 25% value shall apply to each delivery year.

On or before April 1 of each year, the Agency shall annually publish a report on its website that identifies the aggregate amount of renewable energy credits supplied by alternative retail electric suppliers under this subparagraph (H).

(I) The Agency shall design its long-term renewable energy procurement plan to maximize the State's interest in the health, safety, and welfare of its residents, including but not limited to minimizing sulfur dioxide, nitrogen oxide, particulate matter and other pollution that adversely affects public health in this State, increasing fuel and resource diversity in this State, enhancing the reliability and resiliency of the electricity distribution system in this State, meeting goals to limit carbon dioxide emissions under federal or State law, and contributing to a cleaner and healthier environment for the citizens of this State. In order to further these legislative purposes, renewable energy credits shall be eligible to be counted toward the renewable energy requirements of this subsection (c) if they are generated from facilities located in this State. The Agency may qualify renewable energy credits from facilities located in states adjacent to Illinois if the generator demonstrates and the Agency determines that the operation of such facility or facilities will help promote the State's interest in the health, safety, and welfare of its residents based on the public interest criteria described above. To ensure that the public interest criteria are applied to the procurement and given full effect, the Agency's long-term procurement plan shall describe in detail how each public interest factor shall be considered and weighted for facilities located in states adjacent to Illinois.

(J) In order to promote the competitive development of renewable energy resources in furtherance of the State's interest in the health, safety, and welfare of its residents, renewable energy credits shall not be eligible to be counted toward the renewable energy requirements of this subsection (c) if they are sourced from a generating unit whose costs were being recovered through rates regulated by this State or any other state or states on or after January 1, 2017. Each contract executed to purchase renewable energy credits under this subsection (c) shall provide for the contract's termination if the costs of the generating unit supplying the renewable energy credits subsequently begin to be recovered through rates regulated by this State or any other state or states; and each contract shall further provide that, in that event, the supplier of the credits must return 110% of all payments received under the contract. Amounts returned under the requirements of this subparagraph (J) shall be retained by the utility and all of these amounts shall be used for the procurement of additional renewable energy credits from new wind or new photovoltaic resources as defined in this subsection (c). The long-term plan shall provide that these renewable energy credits shall be procured in the next procurement event.

Notwithstanding the limitations of this subparagraph (J), renewable energy credits sourced from generating units that are constructed, purchased, owned, or leased by an electric utility as part of an approved project, program, or pilot under Section 1-56 of this Act shall be eligible to be counted toward the renewable energy requirements of this subsection (c), regardless of how the costs of these units are recovered.

(K) The long-term renewable resources procurement plan developed by the Agency in accordance with subparagraph (A) of this paragraph (1) shall include an Adjustable Block program for the procurement of renewable energy credits from new photovoltaic projects that are distributed renewable energy generation devices or new photovoltaic community renewable generation projects. The Adjustable Block program shall be designed to provide a transparent schedule of prices and quantities to enable the photovoltaic market to scale up and for renewable energy credit prices to adjust at a predictable rate over time. The prices set by the Adjustable Block program can be reflected as a set value or as the product of a formula.

The Adjustable Block program shall include for each category of eligible projects: a schedule of standard block purchase prices to be offered; a series of steps, with associated nameplate capacity and purchase prices that adjust from step to step; and automatic opening of the next step as soon as the nameplate capacity and available purchase prices for an open step are fully committed or reserved. Only projects energized on or after June 1, 2017 shall be eligible for the Adjustable Block program. For each block group the Agency shall determine the number of blocks, the amount of generation capacity in each block, and the purchase price for each block, provided that the purchase price provided and the total amount of generation in all blocks for all block groups shall be sufficient to meet the goals in this subsection (c). The Agency may periodically review its prior decisions establishing the number of blocks, the amount of generation capacity in each block, and the purchase price for each block, and may propose, on an expedited basis, changes to these previously set values, including but not limited to redistributing these amounts and the available funds as necessary and appropriate, subject to Commission approval as part of the periodic plan revision process described in Section 16-111.5 of the Public Utilities Act. The Agency may define different block sizes, purchase prices, or other distinct terms and conditions for projects located in different utility service territories if the Agency deems it necessary to meet the goals in this subsection (c).

The Adjustable Block program shall include at least the following block groups in at least the following amounts, which may be adjusted upon review by the Agency and approval by the Commission as described in this subparagraph (K):

(i) At least 25% from distributed renewable energy generation devices with a nameplate capacity of no more than 10 kilowatts.

(ii) At least 25% from distributed renewable energy generation devices with a nameplate capacity of more than 10 kilowatts and no more than 2,000 kilowatts. The Agency may create sub-categories within this category to account for the differences between projects for small commercial customers, large commercial customers, and public or non-profit customers.

(iii) At least 25% from photovoltaic community renewable generation projects.

(iv) The remaining 25% shall be allocated as specified by the Agency in the long-term renewable resources procurement plan.

The Adjustable Block program shall be designed to ensure that renewable energy credits are procured from photovoltaic distributed renewable energy generation devices and new photovoltaic community renewable energy generation projects in diverse locations, including urban and rural areas, and are not concentrated in a few geographic areas or excluding particular geographic areas.

The Adjustable Block Program shall be designed to prioritize the procurement of renewable energy credits from new photovoltaic community renewable energy projects that are organized by local communities, sited in the communities they serve, or are also brownfield site photovoltaic projects, as defined in Section 1-10 of this Act, for a portion of the overall renewable energy credits to be procured from new photovoltaic community renewable energy projects.

(L) The procurement of photovoltaic renewable energy credits under items (i) through (iv) of subparagraph (K) of this paragraph (1) shall be subject to the following contract and payment terms:

(i) The Agency shall procure contracts of at least 15 years in length.

(ii) For those renewable energy credits that qualify and are procured under item (i) of subparagraph (K) of this paragraph (1), the renewable energy credit purchase price shall be paid in full by the contracting utilities at the time that the facility producing the renewable energy credits is interconnected at the distribution system level of the utility and energized. The electric utility shall receive and retire all renewable energy credits generated by the project for the first 15 years of operation.

(iii) For those renewable energy credits that qualify and are procured under item (ii) and (iii) of subparagraph (K) of this paragraph (1) and any additional categories of distributed generation included in the long-term renewable resources procurement plan and approved by the Commission, 20 percent of the renewable energy credit purchase price shall be paid by the contracting utilities at the time that the facility producing the renewable energy credits is interconnected at the distribution system level of the utility and energized. The remaining portion shall be paid ratably over the subsequent 4-year period. The electric utility shall receive and retire all renewable energy credits generated by the project for the first 15 years of operation.

(iv) Each contract shall include provisions to ensure the delivery of the renewable energy credits for the full term of the contract.

(v) The utility shall be the counterparty to the contracts executed under this subparagraph (L) that are approved by the Commission under the process described in Section 16-111.5 of the Public Utilities Act. No contract shall be executed for an amount that is less than one renewable energy credit per year.

(vi) If, at any time, approved applications for the Adjustable Block program exceed funds collected by the electric utility or would cause the Agency to exceed the limitation described in subparagraph (E) of this paragraph (1) on the amount of renewable energy resources that may be procured, then the Agency shall consider future uncommitted funds to be reserved for these contracts on a first-come, first-served basis, with the delivery of renewable energy credits required beginning at the time that the reserved funds become available.

(vii) Nothing in this Section shall require the utility to advance any payment or pay any amounts that exceed the actual amount of revenues collected by the utility under paragraph (6) of this subsection (c) and subsection (k) of Section 16-108 of the Public Utilities Act, and contracts executed under this Section shall expressly incorporate this limitation.

(M) The Agency shall be authorized to retain one or more experts or expert consulting firms to develop, administer, implement, operate, and evaluate the Adjustable Block program described in subparagraph (K) of this paragraph (1), 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 selection of experts and expert consulting firms and the procurement process described in this subparagraph (M) are exempt from the requirements of Section 20-10 of the Illinois Procurement Code, under Section 20-10 of that Code. The Agency shall strive to minimize administrative expenses in the implementation of the Adjustable Block program.

The Agency and its consultant or consultants shall monitor block activity, share program activity with stakeholders and conduct regularly scheduled meetings to discuss program activity and market conditions. If necessary, the Agency may make prospective administrative adjustments to the Adjustable Block program design, such as redistributing available funds or making adjustments to purchase prices as necessary to achieve the goals of this subsection (c). Program modifications to any price, capacity block, or other program element that do not deviate from the Commission's approved value by more than 25% shall take effect immediately and are not subject to Commission review and approval. Program modifications to any price, capacity block, or other program element that deviate more than 25% from the Commission's approved value must be approved by the Commission as a long-term plan amendment under Section 16-111.5 of the Public Utilities Act. The Agency shall consider stakeholder feedback when making adjustments to the Adjustable Block design and shall notify stakeholders in advance of any planned changes.

(N) The long-term renewable resources procurement plan required by this subsection (c) shall include a community renewable generation program. The Agency shall establish the terms, conditions, and program requirements for community renewable generation projects with a goal to expand renewable energy generating facility access to a broader group of energy consumers, to ensure robust participation opportunities for residential and small commercial customers and those who cannot install renewable energy on their own properties. Any plan approved by the Commission shall allow subscriptions to community renewable generation projects to be portable and transferable. For purposes of this subparagraph (N), "portable" means that subscriptions may be retained by the subscriber even if the subscriber relocates or changes its address within the same utility service territory; and "transferable" means that a subscriber may assign or sell subscriptions to another person within the same utility service territory.

Electric utilities shall provide a monetary credit to a subscriber's subsequent bill for service for the proportional output of a community renewable generation project attributable to that subscriber as specified in Section 16-107.5 of the Public Utilities Act.

The Agency shall purchase renewable energy credits from subscribed shares of photovoltaic community renewable generation projects through the Adjustable Block program described in subparagraph (K) of this paragraph (1) or through the Illinois Solar for All Program described in Section 1-56 of this Act. The electric utility shall purchase any unsubscribed energy from community renewable generation projects that are Qualifying Facilities ("QF") under the electric utility's tariff for purchasing the output from QFs under Public Utilities Regulatory Policies Act of 1978.

The owners of and any subscribers to a community renewable generation project shall not be considered public utilities or alternative retail electricity suppliers under the Public Utilities Act solely as a result of their interest in or subscription to a community renewable generation project and shall not be required to become an alternative retail electric supplier by participating in a community renewable generation project with a public utility.

(O) For the delivery year beginning June 1, 2018, the long-term renewable resources procurement plan required by this subsection (c) shall provide for the Agency to procure contracts to continue offering the Illinois Solar for All Program described in subsection (b) of Section 1-56 of this Act, and the contracts approved by the Commission shall be executed by the utilities that are subject to this subsection (c). The long-term renewable resources procurement plan shall allocate 5% of the funds available under the plan for the applicable delivery year, or $10,000,000 per delivery year, whichever is greater, to fund the programs, and the plan shall determine the amount of funding to be apportioned to the programs identified in subsection (b) of Section 1-56 of this Act; provided that for the delivery years beginning June 1, 2017, June 1, 2021, and June 1, 2025, the long-term renewable resources procurement plan shall allocate 10% of the funds available under the plan for the applicable delivery year, or $20,000,000 per delivery year, whichever is greater, and $10,000,000 of such funds in such year shall be used by an electric utility that serves more than 3,000,000 retail customers in the State to implement a Commission-approved plan under Section 16-108.12 of the Public Utilities Act. In making the determinations required under this subparagraph (O), the Commission shall consider the experience and performance under the programs and any evaluation reports. The Commission shall also provide for an independent evaluation of those programs on a periodic basis that are funded under this subparagraph (O).

(P) For the delivery year beginning June 1, 2021, the long-term renewable resources procurement plan required by this subsection (c) shall also include and account for the annual procurement of new long-term contracts, including bundled contracts, as described in subsection (j) of this Section, from new wind projects and new photovoltaic projects such that, by the end of the 2030 delivery year:

(i) at least 25,000,000 renewable energy credits for each delivery year shall come from new wind projects; and

(ii) at least 25,000,000 renewable energy credits for each delivery year shall come from new photovoltaic projects.

The gradual increase in renewable resource procurement discussed in this subparagraph (P) shall involve annual procurements of new wind and new photovoltaic projects and, in the case of the Adjustable Block Program created by subparagraph (K) of this subsection (c), the annual release of new blocks of capacity each year with the goal of encouraging stability and steady growth in the solar market and avoiding boom-bust cycles.

In developing the long-term renewable resources procurement plan, the Agency shall develop bidding criteria to account for the ability of new photovoltaic and wind projects to deliver additional benefits for Illinois such as agriculture and pollinator-friendly projects, brownfield redevelopment, water-pollution buffers, and other land-use or environmental benefits.

In this Section:

"New wind projects" means wind renewable energy facilities that are energized after June 1, 2017 for the delivery year commencing June 1, 2017 or within 3 years after the date the Commission approves contracts for subsequent delivery years.

"New photovoltaic projects" means photovoltaic renewable energy facilities that are energized after June 1, 2017.

(Q) Beginning with the 2019 update to the long-term renewable resources procurement plan required by this subsection (c), the Agency shall evaluate the budget necessary to fund:

(i) purchases of renewable energy credits under existing contractual obligations;

(ii) the Illinois Solar for All Program, related grassroots education and expansion goals under Section 1-56(b)(2-8) of the Illinois Power Agency Act;

(iii) purchases of renewable energy credits necessary to comply with the new wind and new photovoltaic project requirements described in items (i) through (iii) of subparagraph (C) of this paragraph (1); and

(iv) purchases of renewable energy credits necessary to comply with the new wind project and new photovoltaic project procurement requirements described in subparagraph (P) of this paragraph (1).

Following the delivery year 2021, the Agency shall review the budget necessary to fund items (i) through (iv) of this subparagraph (Q) to determine if that budget exceeds the limitation on the amount of renewable energy resources procured in subparagraph (E) of this paragraph (1) when combined with savings achieved by the carbon-free resources procured in subsection (k) of this Section. If so, the Agency shall propose an alternative limitation which the Commission shall review and approve if the Commission finds an alternative limitation is necessary to achieve the requirements of items (i) through (iv) of this subparagraph (Q). The Commission shall find an alternative limitation necessary only if it determines it is a cost-effective way to achieve the goals of subsection (c) and paragraphs (2) through (8) of subsection (b) and as part of the review of the Agency's procurement plan for the delivery year following the year in which the Agency concludes an alternative limitation is necessary as described by the procurement process contained in Section 16-111.5 of the Public Utilities Act.

(1.5) No later than May 31, 2021, all Illinois electric cooperatives and municipal utilities shall develop a plan to ensure that their members and customers have access to renewable energy on a reasonably equivalent basis to all other residents in the State, including the overall percentage goals listed in subparagraph (A) of paragraph (1) of this Section and the carbon-free resources goals of subsection (k) of this Section 1-75. These plans shall be developed through a public process involving municipal utility and cooperative members, customers, and other members of the public, and shall be filed with the Illinois Commerce Commission at least every 2 years.

(2) (Blank).

(3) (Blank).

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

(5) Beginning with the 2010 delivery year and ending June 1, 2017, 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.

(6) The electric utility shall be entitled to recover all of its costs associated with the procurement of renewable energy credits under plans approved under this Section and Section 16-111.5 of the Public Utilities Act. These costs shall include associated reasonable expenses for implementing the procurement programs, including, but not limited to, the costs of administering and evaluating the Adjustable Block program, through an automatic adjustment clause tariff in accordance with subsection (k) of Section 16-108 of the Public Utilities Act.

(7) Renewable energy credits procured from new photovoltaic projects or new distributed renewable energy generation devices under this Section after June 1, 2017 (the effective date of Public Act 99-906) must be procured from devices installed by a qualified person in compliance with the requirements of Section 16-128A of the Public Utilities Act and any rules or regulations adopted thereunder.

In meeting the renewable energy requirements of this subsection (c), to the extent feasible and consistent with State and federal law, the renewable energy credit procurements, Adjustable Block solar program, and community renewable generation program shall provide employment opportunities for all segments of the population and workforce, including minority-owned and female-owned business enterprises, and shall not, consistent with State and federal law, discriminate based on race or socioeconomic status. Specifically, as the Agency conducts competitive procurement processes and implements programs to procure renewable energy credits identified in the long-term renewable resources procurement plan, the Agency must preference the procurement of renewable energy credits from those Approved Vendors and companies that meet multiple Equity Actions, including, but not limited to, the following:

(A) Hiring Equity Action: 30% of the company's workforce (measured by FTEs) are people of color (members of a racial or ethnic minority group) and receive at or above the prevailing wage.

(B) Clean Jobs Workforce Hubs Action: 30% of the workers associated with the project are graduates or trainees from the Clean Jobs Workforce Hubs programs, or equivalent certification, and paid at or above the prevailing wage.

(C) Disadvantaged Business Enterprise Action: being an entity defined under Section 2 of the Business Enterprise for Minorities, Women, and Persons with Disabilities Act.

(D) Contracting Equity Action: 51% of the company's subcontractors or vendors are entities defined under Section 2 of the Business Enterprise for Minorities, Women, and Persons with Disabilities Act or 30% of the workers associated with the project, including from all subcontractors and vendors, are people of color (members of a racial or ethnic minority group).

(E) Community Benefits Action: (i) for projects 100kW in size or larger, project has an executed Community Benefits Agreement that could include, but is not limited to, a commitment to hire local workers, union workers, displaced fossil fuel workers transitioning to clean energy work, or Clean Jobs Workforce Hubs graduates, a commitment to pay workers at or above the prevailing wage, and a commitment to give communities ownership opportunities in clean energy projects; and (ii) for projects under 100kW in size, companies pay their workforce at or above the prevailing wage.

(F) Small Business Action: company's workforce is comprised of 3 or fewer full-time employees.

(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 June 1, 2009 (the effective date of Public Act 95-1027), 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 willfully 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 delivery year commencing on June 1, 2017, the Agency shall, for electric utilities that serve at least 100,000 retail customers in this State, procure contracts with zero emission facilities that are reasonably capable of generating cost-effective zero emission credits in an amount approximately equal to 16% of the actual amount of electricity delivered by each electric utility to retail customers in the State during calendar year 2014. For an electric utility serving fewer than 100,000 retail customers in this State that requested, under Section 16-111.5 of the Public Utilities Act, that the Agency procure power and energy for all or a portion of the utility's Illinois load for the delivery year commencing June 1, 2016, the Agency shall procure contracts with zero emission facilities that are reasonably capable of generating cost-effective zero emission credits in an amount approximately equal to 16% of the portion of power and energy to be procured by the Agency for the utility. The duration of the contracts procured under this subsection (d-5) shall be for a term of 10 years ending May 31, 2027. The quantity of zero emission credits to be procured under the contracts shall be all of the zero emission credits generated by the zero emission facility in each delivery year; however, if the zero emission facility is owned by more than one entity, then the quantity of zero emission credits to be procured under the contracts shall be the amount of zero emission credits that are generated from the portion of the zero emission facility that is owned by the winning supplier.

The 16% value identified in this paragraph (1) is the average of the percentage targets in subparagraph (B) of paragraph (1) of subsection (c) of this Section 1-75 of this Act for the 5 delivery years beginning June 1, 2017.

The procurement process shall be subject to the following provisions:

(A) Those zero emission facilities that intend to participate in the procurement shall submit to the Agency the following eligibility information for each zero emission facility on or before the date established by the Agency:

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

(ii) the amount of power generated annually for each of the years 2005 through 2015, and the projected zero emission credits to be generated over the remaining useful life of the zero emission facility, which shall be used to determine the capability of each facility;

(iii) the annual zero emission facility cost projections, expressed on a per megawatthour basis, over the next 6 delivery 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; the cost of operational and market risks that could be avoided by ceasing operation; 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 facility; and

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

The information described in item (iii) of this subparagraph (A) may be submitted on a confidential basis and shall be treated and maintained by the Agency, the procurement administrator, and the Commission as confidential and proprietary and exempt from disclosure under subparagraphs (a) and (g) of paragraph (1) of Section 7 of the Freedom of Information Act. The Office of Attorney General shall have access to, and maintain the confidentiality of, such information pursuant to Section 6.5 of the Attorney General Act.

(B) The price for each zero emission credit procured under this subsection (d-5) for each delivery year shall be in an amount that equals the Social Cost of Carbon, expressed on a price per megawatthour basis. However, to ensure that the procurement remains affordable to retail customers in this State if electricity prices increase, the price in an applicable delivery year shall be reduced below the Social Cost of Carbon by the amount ("Price Adjustment") by which the market price index for the applicable delivery year exceeds the baseline market price index for the consecutive 12-month period ending May 31, 2016. If the Price Adjustment is greater than or equal to the Social Cost of Carbon in an applicable delivery year, then no payments shall be due in that delivery year. The components of this calculation are defined as follows:

(i) Social Cost of Carbon: The Social Cost of Carbon is $16.50 per megawatthour, which is based on the U.S. Interagency Working Group on Social Cost of Carbon's price in the August 2016 Technical Update using a 3% discount rate, adjusted for inflation for each year of the program. Beginning with the delivery year commencing June 1, 2023, the price per megawatthour shall increase by $1 per megawatthour, and continue to increase by an additional $1 per megawatthour each delivery year thereafter.

(ii) Baseline market price index: The baseline market price index for the consecutive 12-month period ending May 31, 2016 is $31.40 per megawatthour, which is based on the sum of (aa) the average day-ahead energy price across all hours of such 12-month period at the PJM Interconnection LLC Northern Illinois Hub, (bb) 50% multiplied by the Base Residual Auction, or its successor, capacity price for the rest of the RTO zone group determined by PJM Interconnection LLC, divided by 24 hours per day, and (cc) 50% multiplied by the Planning Resource Auction, or its successor, capacity price for Zone 4 determined by the Midcontinent Independent System Operator, Inc., divided by 24 hours per day.

(iii) Market price index: The market price index for a delivery year shall be the sum of projected energy prices and projected capacity prices determined as follows:

(aa) Projected energy prices: the projected energy prices for the applicable delivery year shall be calculated once for the year using the forward market price for the PJM Interconnection, LLC Northern Illinois Hub. The forward market price shall be calculated as follows: the energy forward prices for each month of the applicable delivery year averaged for each trade date during the calendar year immediately preceding that delivery year to produce a single energy forward price for the delivery year. The forward market price calculation shall use data published by the Intercontinental Exchange, or its successor.

(bb) Projected capacity prices:

(I) For the delivery years commencing June 1, 2017, June 1, 2018, and June 1, 2019, the projected capacity price shall be equal to the sum of (1) 50% multiplied by the Base Residual Auction, or its successor, price for the rest of the RTO zone group as determined by PJM Interconnection LLC, divided by 24 hours per day and, (2) 50% multiplied by the resource auction price determined in the resource auction administered by the Midcontinent Independent System Operator, Inc., in which the largest percentage of load cleared for Local Resource Zone 4, divided by 24 hours per day, and where such price is determined by the Midcontinent Independent System Operator, Inc.

(II) For the delivery year commencing June 1, 2020, and each year thereafter, the projected capacity price shall be equal to the sum of (1) 50% multiplied by the Base Residual Auction, or its successor, price for the ComEd zone as determined by PJM Interconnection LLC, divided by 24 hours per day, and (2) 50% multiplied by the resource auction price determined in the resource auction administered by the Midcontinent Independent System Operator, Inc., in which the largest percentage of load cleared for Local Resource Zone 4, divided by 24 hours per day, and where such price is determined by the Midcontinent Independent System Operator, Inc.

For purposes of this subsection (d-5):

"Rest of the RTO" and "ComEd Zone" shall have the meaning ascribed to them by PJM Interconnection, LLC.

"RTO" means regional transmission organization.

(C) No later than 45 days after June 1, 2017 (the effective date of Public Act 99-906), the Agency shall publish its proposed zero emission standard 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, but are not limited to, 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 benefits resulting from the procurement, such as any existing environmental benefits that are preserved by the procurements held under Public Act 99-906 and would cease to exist if the procurements were not held, including the preservation of zero emission facilities. The plan shall also describe in detail how each public interest factor shall be considered and weighted in the bid selection process to ensure that the public interest criteria are applied to the procurement and given full effect.

For purposes of developing the plan, the Agency shall consider any reports issued by a State agency, board, or commission under House Resolution 1146 of the 98th General Assembly and paragraph (4) of subsection (d) of this Section 1-75 of this Act, as well as publicly available analyses and studies performed by or for regional transmission organizations that serve the State and their independent market monitors.

Upon publishing of the zero emission standard procurement plan, copies of the plan shall be posted and made publicly available on the Agency's website. All interested parties shall have 10 days following the date of posting to provide comment to the Agency on the plan. All comments shall be posted to the Agency's website. Following the end of the comment period, but no more than 60 days later than June 1, 2017 (the effective date of Public Act 99-906), the Agency shall revise the plan as necessary based on the comments received and file its zero emission standard procurement plan with the Commission.

If the Commission determines that the plan will result in the procurement of cost-effective zero emission credits, then the Commission shall, after notice and hearing, but no later than 45 days after the Agency filed the plan, approve the plan or approve with modification. For purposes of this subsection (d-5), "cost effective" means the projected costs of procuring zero emission credits from zero emission facilities do not cause the limit stated in paragraph (2) of this subsection to be exceeded.

(C-5) As part of the Commission's review and acceptance or rejection of the procurement results, the Commission shall, in its public notice of successful bidders:

(i) identify how the winning bids satisfy the public interest criteria described in subparagraph (C) of this paragraph (1) of 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;

(ii) specifically address how the selection of winning bids takes into account the incremental environmental benefits resulting from the procurement, including any existing environmental benefits that are preserved by the procurements held under Public Act 99-906 and would have ceased to exist if the procurements had not been held, such as the preservation of zero emission facilities;

(iii) quantify the environmental benefit of preserving the resources identified in item (ii) of this subparagraph (C-5), including the following:

(aa) the value of avoided greenhouse gas emissions measured as the product of the zero emission facilities' output over the contract term multiplied by the U.S. Environmental Protection Agency eGrid subregion carbon dioxide emission rate and the U.S. Interagency Working Group on Social Cost of Carbon's price in the August 2016 Technical Update using a 3% discount rate, adjusted for inflation for each delivery year; and

(bb) the costs of replacement with other zero carbon dioxide resources, including wind and photovoltaic, based upon the simple average of the following:

(I) the price, or if there is more than one price, the average of the prices, paid for renewable energy credits from new utility-scale wind projects in the procurement events specified in item (i) of subparagraph (G) of paragraph (1) of subsection (c) of this Section 1-75 of this Act; and

(II) the price, or if there is more than one price, the average of the prices, paid for renewable energy credits from new utility-scale solar projects and brownfield site photovoltaic projects in the procurement events specified in item (ii) of subparagraph (G) of paragraph (1) of subsection (c) of this Section 1-75 of this Act and, after January 1, 2015, renewable energy credits from photovoltaic distributed generation projects in procurement events held under subsection (c) of this Section 1-75 of this Act.

Each utility shall enter into binding contractual arrangements with the winning suppliers.

The procurement described in this subsection (d-5), including, but not limited to, the execution of all contracts procured, shall be completed no later than May 10, 2017. Based on the effective date of Public Act 99-906, the Agency and Commission may, as appropriate, modify the various dates and timelines under this subparagraph and subparagraphs (C) and (D) of this paragraph (1). The procurement and plan approval processes required by this subsection (d-5) shall be conducted 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. Notwithstanding whether a procurement event is conducted under Section 16-111.5 of the Public Utilities Act, the Agency shall immediately initiate a procurement process on June 1, 2017 (the effective date of Public Act 99-906).

(D) Following the procurement event described in this paragraph (1) and consistent with subparagraph (B) of this paragraph (1), the Agency shall calculate the payments to be made under each contract for the next delivery year based on the market price index for that delivery year. The Agency shall publish the payment calculations no later than May 25, 2017 and every May 25 thereafter.

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

(i) A zero emission facility 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 facility 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 facility 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 facility during the duration of the event.

(ii) A zero emission facility 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 facility. 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 facility shall be permitted to terminate the contract in the event that the resource requires capital expenditures in excess of $40,000,000 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 facility shall be permitted to terminate the contract in the event the Nuclear Regulatory Commission terminates the resource's license.

(F) If the zero emission facility elects to terminate a contract under this subparagraph (E) , of this paragraph (1), then the Commission shall reopen the docket in which the Commission approved the zero emission standard procurement plan under subparagraph (C) of this paragraph (1) and, after notice and hearing, enter an order acknowledging the contract termination election if such termination is consistent with the provisions of this subsection (d-5).

(2) 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 contracts executed under this subsection (d-5) shall provide that the total of zero emission credits procured under a procurement plan shall be subject to the limitations of this paragraph (2). For each delivery year, the contractual volume receiving payments in such year shall be reduced for all retail customers based on the amount necessary to limit the net increase that delivery year to the costs of those credits included in the amounts paid by eligible retail customers in connection with electric service to no more than 1.65% 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 under subsection (k) of Section 16-108 of the Public Utilities Act. To arrive at a maximum dollar amount of zero emission credits to be paid for the particular delivery year, the resulting per kilowatthour amount shall be applied to the actual amount of kilowatthours of electricity delivered by the electric utility in the delivery year immediately prior to the procurement, to all retail customers in its service territory. Unpaid contractual volume for any delivery year shall be paid in any subsequent delivery year in which such payments can be made without exceeding the amount specified in this paragraph (2). 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 be paid 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 under 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) Six years after the execution of a contract under this subsection (d-5), the Agency shall determine whether the actual zero emission credit payments received by the supplier over the 6-year period exceed the Average ZEC Payment. In addition, at the end of the term of a contract executed under this subsection (d-5), or at the time, if any, a zero emission facility's contract is terminated under subparagraph (E) of paragraph (1) of this subsection (d-5), then the Agency shall determine whether the actual zero emission credit payments received by the supplier over the term of the contract exceed the Average ZEC Payment, after taking into account any amounts previously credited back to the utility under this paragraph (3). If the Agency determines that the actual zero emission credit payments received by the supplier over the relevant period exceed the Average ZEC Payment, then the supplier shall credit the difference back to the utility. The amount of the credit shall be remitted to the applicable electric utility no later than 120 days after the Agency's determination, which the utility shall reflect as a credit on its retail customer bills as soon as practicable; however, the credit remitted to the utility shall not exceed the total amount of payments received by the facility under its contract.

For purposes of this Section, the Average ZEC Payment shall be calculated by multiplying the quantity of zero emission credits delivered under the contract times the average contract price. The average contract price shall be determined by subtracting the amount calculated under subparagraph (B) of this paragraph (3) from the amount calculated under subparagraph (A) of this paragraph (3), as follows:

(A) The average of the Social Cost of Carbon, as defined in subparagraph (B) of paragraph (1) of this subsection (d-5), during the term of the contract.

(B) The average of the market price indices, as defined in subparagraph (B) of paragraph (1) of this subsection (d-5), during the term of the contract, minus the baseline market price index, as defined in subparagraph (B) of paragraph (1) of this subsection (d-5).

If the subtraction yields a negative number, then the Average ZEC Payment shall be zero.

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

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

(6) 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) and (m) of Section 16-108 of the Public Utilities Act, and the contracts executed under this subsection (d-5) shall provide that the utilities' payment obligations under such contracts shall be reduced if an adjustment is required under subsection (m) of Section 16-108 of the Public Utilities Act.

(7) This subsection (d-5) shall become inoperative on January 1, 2028.

(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. If 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.

(j) Bundled procurement.

(1) Beginning with the energy, capacity and renewable energy credits to be delivered in the delivery year commencing on June 1, 2021, the Agency shall procure cost-effective, long-term bundled contracts for energy supply, renewable energy credits from new renewable energy projects as defined in subparagraph (P) of subsection (c) of this Section, and, subject to the requirements of subsection (k) of this Section, capacity, 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. At a minimum, energy supply procured by the Agency through new long-term bundled contracts shall be:

(A) 3,000,000 megawatt-hours and associated renewable energy credits and, subject to the requirements of subsection (k) of this Section, capacity from new wind and solar projects for the delivery year beginning June 1, 2021.

(B) 6,000,000 megawatt-hours and associated renewable energy credits and, subject to the requirements of subsection (k) of this Section, capacity from new wind and solar projects for the delivery year beginning June 1, 2022.

(C) 9,000,000 megawatt-hours and associated renewable energy credits and, subject to the requirements of subsection (k) of this Section, capacity from new wind and solar projects for the delivery year beginning June 1, 2023.

(D) 12,000,000 megawatt-hours and associated renewable energy credits and, subject to the requirements of subsection (k) of this Section, capacity from new wind and solar projects for the delivery year beginning June 1, 2024.

(E) 15,000,000 megawatt-hours and associated renewable energy credits and, subject to the requirements of subsection (k) of this Section, capacity from new wind and solar projects for the delivery year beginning June 1, 2025.

(F) 18,000,000 megawatt-hours and associated renewable energy credits and, subject to the requirements of subsection (k) of this Section, capacity from new wind and solar projects for the delivery year beginning June 1, 2026.

(G) 21,000,000 megawatt-hours and associated renewable energy credits and, subject to the requirements of subsection (k) of this Section, capacity from new wind and solar projects for the delivery year beginning June 1, 2027.

(H) 24,000,000 megawatt-hours and associated renewable energy credits and, subject to the requirements of subsection (k) of this Section, capacity from new wind and solar projects for the delivery year beginning June 1, 2028 and thereafter.

(2) Long-term bundled contracts as described in this subsection shall refer to contracts that contain no less than a 15-year period.

(3) Long-term bundled contracts shall only be awarded for new renewable energy projects as defined in subparagraphs (C) and (P) of subsection (c) of this Section. Nothing in this Section is intended to preclude distributed generation from participating.

(4) Long-term bundled contracts as described in this subsection may include procurements that include energy supply plus renewable energy credits, procurements that include capacity, subject to the requirements of subsection (k) of this Section, plus renewable energy credits, or procurements that include energy supply plus capacity plus renewable energy credits.

(5) Long-term bundled contracts as described in this subsection shall be procured in a procurement event prior to the scheduled Reliability Pricing Model Auctions of the PJM Interconnection LLC and the Planning Resource Actions of the Midcontinent Independent System Operator.

(k) Carbon-free resources.

(1) Carbon-free capacity. Beginning with the procurement for the delivery year commencing June 1, 2022, if possible, but no later than for the delivery year commencing June 1, 2023, the Agency shall develop a plan and conduct a procurement of capacity from qualified resources as part of its procurement plan described in Section 16-111.5 of the Public Utilities Act with the goals of reducing pollution from the power sector, lowering consumer costs, and creating investment opportunities for new renewable resources. For the purposes of this subsection, "qualified resources" means (A) energy efficiency measures that are implemented pursuant to plans approved by the Commission under Sections 8-103, 8-103B, and 8-104 of the Public Utilities Act; (B) renewable energy resources; (C) zero emission facilities; and (D) resources as part of a clean peak program under subsection (l) of this Section, subject to the requirements in the open access tariff and manuals of PJM Interconnection and approved by the Federal Energy Regulatory Commission. The capacity portion of qualified resources shall be counted toward fulfillment of capacity obligations within the local delivery area of an electric utility serving more than 3,000,000 retail customers that is a member of PJM Interconnection LLC, as defined in the open access tariff and manuals of PJM Interconnection and approved by the Federal Energy Regulatory Commission, as applicable. The Agency shall calculate the eligible capacity contribution of qualified resources procured, and match it to an equivalent megawatt quantity or portion of capacity obligation of load within the local delivery zone. The resulting capacity and load obligation shall be reported in accordance with the applicable provisions of the Open Access Transmission Tariff and manuals of PJM Interconnection LLC.

(2) Carbon-free supply. Beginning with the delivery year commencing June 1, 2021, the Agency shall ensure its procurement of energy supply, 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, achieves a progressive annual ramp down to an emission rate of zero pounds of carbon dioxide emissions per megawatt-hour by May 31, 2030. At a minimum, energy supply procured by the Agency through new long-term bundled contracts shall be:

(A) 1,000 pounds per megawatt-hour of carbon dioxide emissions per megawatt-hour for the delivery year beginning June 1, 2021.

(B) 500 pounds per megawatt-hour of carbon dioxide emissions per megawatt-hour for the delivery year beginning June 1, 2026.

(C) zero pounds per megawatt-hour of carbon dioxide emissions per megawatt-hour for the delivery year beginning June 1, 2030 and thereafter.

(l) Clean Peak Program.

(1) In this subsection:

"Energy storage response threshold level" means a level, in megawatts, for the designated locational delivery area system-wide demand at which energy storage resources must begin providing demand reduction at its committed level. The energy storage response threshold level shall be set by the Agency to coincide with the top 100 hours of demand in the designated zone, accounting for seasonal variability in capacity needs and any capacity performance requirements included in the Open Access Transmission Tariff and manuals of PJM Interconnection, LLC.

"Demand response threshold level" means a level, in megawatts, of the locational delivery area system-wide demand at which demand response resources must begin providing demand reduction at its committed demand response threshold level. The demand response threshold level shall be set by the Agency to coincide with the top 100 hours of demand in the designated zone, accounting for seasonal variability in capacity needs and any capacity performance requirements included in the Open Access Transmission Tariff and manuals of PJM Interconnection LLC.

(2) The Agency shall develop a Clean Peak Program plan that shall include programs and competitive procurement events necessary to meet the goals set forth in this subsection (l). Within 90 days after the effective date of this amendatory Act of the 101st General Assembly, the Agency shall release for comment an initial Clean Peak Program plan. The Clean Peak Program plan shall be subject to review and approval by the Commission under Section 16-111.5 of the Public Utilities Act. The Agency shall review and update on an annual basis a Clean Peak Program plan which shall be reviewed and approved by the Commission in conjunction with the procurement plan under Section 16-111.5 of the Public Utilities Act to the extent practicable to minimize administrative expense.

(3) The Clean Peak Program shall include progressive annual goals and efforts to achieve a 15% reduction in the Capacity and Network Service Peak Load Contributions in the Commission zone, as determined by PJM Interconnection LLC in its Open Access Transmission Tariff, by the beginning of the delivery year commencing June 1, 2023, and each year thereafter, based on the measured Capacity and Network Service Peak Load Contribution of the designated zone for the delivery year commencing June 1, 2017.

(4) The Clean Peak Program shall consist of the following elements:

(A) Energy storage resources that commit to achieve a reduction in electricity demand in the designated zone, in megawatts based on seasonal capability, when the electricity demand of the designated zone reaches an energy storage response threshold level, in megawatts.

(B) Energy storage resources, co-located with and that are energized primarily from wind and solar projects, that commit to achieve a reduction in electricity demand in the designated zone, in megawatts based on seasonal capability, when the electricity demand of the designated zone reaches an energy storage response threshold level, in megawatts.

(C) Demand response resources, not including generators powered by diesel fuel or natural gas, that commit to achieve a reduction in electricity demand in the designated zone, in megawatts based on seasonal capability, when the electricity demand of the designated zone reaches a demand response threshold level, in megawatts.

(D) Utility-run demand-response programs, price-responsive demand programs, time-of-use, and hourly rate programs, beneficial electrification programs as described in Section 16-107.8 of the Public Utilities Act, any capacity value developed by the Illinois Commerce Commission as part of the distributed generation rebate described in Section 16-106.7 of the Public Utilities Act, or as otherwise provided for by the Commission.

(E) Demand response and energy efficiency resources as defined by the Open Access Transmission Tariff and manuals of PJM Interconnection LLC.

(5) To the extent practical, the Agency shall procure resources identified in subparagraphs (A) through (C) in paragraph (4) as part of the Carbon-Free Capacity Procurement described in paragraph (1) of subsection (k).

(6) The Agency shall calculate the eligible capacity contribution of the items in paragraph (4) of this subsection (l) as part of any resource-specific carve-out in the Open Access Transmission Tariff and manuals of PJM Interconnection LLC.

(7) As part of its annual plan, the Agency shall solicit comment on new ways and methods for achieving cost-effective demand reductions to meet the goals of this subsection and, upon review, include new program proposals in its annual plan for review and approval by the Commission.

(Source: P.A. 99-536, eff. 7-8-16; 99-906, eff. 6-1-17; 100-863, eff. 8-14-18; revised 10-18-18.)

Section 90-15. The School Code is amended by adding Section 2-3.176 as follows:

(105 ILCS 5/2-3.176 new)

Sec. 2-3.176. Clean jobs curriculum.

(a) The General Assembly recognizes that clean energy is a growing and important sector of the State's economy and that significant job opportunity exists in the sector. Consistent with Section 5-30 of the Clean Jobs Workforce Hubs Act, the Board shall participate in the development of the clean jobs curriculum convened by the Department of Commerce and Economic Opportunity. The Board shall identify and collaboratively with stakeholders identified by the Board develop curriculum based on anticipated clean energy job availability and growth. Clean energy jobs considered shall include, but are not limited to, solar photovoltaic, solar thermal, wind energy, energy efficiency, site assessment, sales, and back office.

(b) In the development of the clean jobs curriculum, the Board shall consider broad occupational training applicable to the general construction sector as well as sector-specific skills.

(c) Consideration should be given to skills applicable to trainees for whom secondary and higher education has not been available.

Section 90-20. The Public Utilities Act is amended by changing Sections 8-103B, 9-220.3, 16-107, 16-107.5, 16-107.6, 16-111.5, and 16-128B and by adding Sections 8-104.1, 16-107.7, 16-107.8, 16-108.9, 16-108.13, 16-108.17, and 16-115E as follows:

(220 ILCS 5/8-103B)

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 expenditures 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.

(a-5) This Section applies to electric utilities serving more than 500,000 retail customers in the State for those multi-year plans commencing after December 31, 2017.

(b) For purposes of this Section, electric utilities subject to this Section that serve more than 3,000,000 retail customers in the State shall be deemed to have achieved a cumulative persisting annual savings of 6.6% from energy efficiency measures and programs implemented during the period beginning January 1, 2012 and ending December 31, 2017, which percent 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. For the purposes of this subsection (b) and subsection (b-5), the 88,000,000 MWhs of deemed electric power and energy sales shall be reduced by the number of MWhs equal to the sum of the annual consumption of customers that are exempt from subsections (a) through (j) of this Section under subsection (l) of this Section, as averaged across the calendar years 2014, 2015, and 2016. After 2017, the deemed value of cumulative persisting annual savings from energy efficiency measures and programs implemented during the period beginning January 1, 2012 and ending December 31, 2017, 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% deemed cumulative persisting annual savings for the year ending December 31, 2018;

(2) 5.2% deemed cumulative persisting annual savings for the year ending December 31, 2019;

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

(4) 4.0% deemed cumulative persisting annual savings for the year ending December 31, 2021;

(5) 3.5% deemed cumulative persisting annual savings for the year ending December 31, 2022;

(6) 3.1% deemed cumulative persisting annual savings for the year ending December 31, 2023;

(7) 2.8% deemed cumulative persisting annual savings for the year ending December 31, 2024;

(8) 2.5% deemed cumulative persisting annual savings for the year ending December 31, 2025;

(9) 2.3% deemed cumulative persisting annual savings for the year ending December 31, 2026;

(10) 2.1% deemed cumulative persisting annual savings for the year ending December 31, 2027;

(11) 1.8% deemed cumulative persisting annual savings for the year ending December 31, 2028;

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

(13) 1.5% deemed cumulative persisting annual savings for the year ending December 31, 2030; .

(14) 1.3% deemed cumulative persisting annual savings for the year ending December 31, 2031;

(15) 1.1% deemed cumulative persisting annual savings for the year ending December 31, 2032;

(16) 0.9% deemed cumulative persisting annual savings for the year ending December 31, 2033;

(17) 0.7% deemed cumulative persisting annual savings for the year ending December 31, 2034;

(18) 0.5% deemed cumulative persisting annual savings for the year ending December 31, 2035;

(19) 0.4% deemed cumulative persisting annual savings for the year ending December 31, 2036;

(20) 0.3% deemed cumulative persisting annual savings for the year ending December 31, 2037;

(21) 0.2% deemed cumulative persisting annual savings for the year ending December 31, 2038;

(22) 0.1% deemed cumulative persisting annual savings for the year ending December 31, 2039; and

(23) 0.0% deemed cumulative persisting annual savings for the year ending December 31, 2040 and all subsequent years.

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, but no earlier than January 1, 2012, 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 subject to this Section that serve more than 3,000,000 retail customers in the State 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), as reduced by the number of MWhs equal to the sum of the annual consumption of customers that are exempt from subsections (a) through (j) of this Section under subsection (l) of this Section as averaged across the calendar years 2014, 2015, and 2016, through the implementation of energy efficiency measures during the applicable year and in prior years, but no earlier than January 1, 2012:

(1) 7.8% cumulative persisting annual savings for the year ending December 31, 2018;

(2) 9.1% cumulative persisting annual savings for the year ending December 31, 2019;

(3) 10.4% cumulative persisting annual savings for the year ending December 31, 2020;

(4) 11.8% cumulative persisting annual savings for the year ending December 31, 2021;

(5) 13.1% cumulative persisting annual savings for the year ending December 31, 2022;

(6) 14.4% cumulative persisting annual savings for the year ending December 31, 2023;

(7) 15.7% cumulative persisting annual savings for the year ending December 31, 2024;

(8) 17% cumulative persisting annual savings for the year ending December 31, 2025;

(9) 17.9% cumulative persisting annual savings for the year ending December 31, 2026;

(10) 18.8% cumulative persisting annual savings for the year ending December 31, 2027;

(11) 19.7% cumulative persisting annual savings for the year ending December 31, 2028;

(12) 20.6% cumulative persisting annual savings for the year ending December 31, 2029; and

(13) 21.5% cumulative persisting annual savings for the year ending December 31, 2030.

No later than December 31, 2020, the Illinois Commerce Commission shall establish additional cumulative persisting annual savings goals for the years 2031 through 2035. The Commission shall also establish additional cumulative persisting annual savings goals every 5 years thereafter to ensure utilities always have goals that extend at least 11 years into the future. The cumulative persisting annual savings goals beyond the year 2030 shall increase by 0.9 percentage points per year, absent a Commission decision to initiate a proceeding to consider establishing goals that increase by more or less than that amount. Such a proceeding must be conducted in accordance with the procedures described in subsection (f) of this Section. If such a proceeding is initiated, the cumulative persisting annual savings goals established by the Commission through that proceeding shall reflect the Commission's best estimate of the maximum amount of additional savings that are forecast to be cost-effectively achievable unless such best estimates would result in goals that represent less than 0.5 percentage point annual increases in total cumulative persisting annual savings. The Commission may only establish goals that represent less than 0.5 percentage point annual increases in cumulative persisting annual savings if it can demonstrate, based on clear and convincing evidence, that 0.5 percentage point increases are not cost-effectively achievable. The Commission shall inform its decision based on an energy efficiency potential study which conforms to the requirements of subsection (f-5) of this Section.

(b-10) For purposes of this Section, electric utilities subject to this Section that serve less than 3,000,000 retail customers but more than 500,000 retail customers in the State shall be deemed to have achieved a cumulative persisting annual savings of 6.6% from energy efficiency measures and programs implemented during the period beginning January 1, 2012 and 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 36,900,000 MWhs. For the purposes of this subsection (b-10) and subsection (b-15), the 36,900,000 MWhs of deemed electric power and energy sales shall be reduced by the number of MWhs equal to the sum of the annual consumption of customers that are exempt from subsections (a) through (j) of this Section under subsection (l) of this Section, as averaged across the calendar years 2014, 2015, and 2016. After 2017, the deemed value of cumulative persisting annual savings from energy efficiency measures and programs implemented during the period beginning January 1, 2012 and ending December 31, 2017, 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-15):

(1) 5.8% deemed cumulative persisting annual savings for the year ending December 31, 2018;

(2) 5.2% deemed cumulative persisting annual savings for the year ending December 31, 2019;

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

(4) 4.0% deemed cumulative persisting annual savings for the year ending December 31, 2021;

(5) 3.5% deemed cumulative persisting annual savings for the year ending December 31, 2022;

(6) 3.1% deemed cumulative persisting annual savings for the year ending December 31, 2023;

(7) 2.8% deemed cumulative persisting annual savings for the year ending December 31, 2024;

(8) 2.5% deemed cumulative persisting annual savings for the year ending December 31, 2025;

(9) 2.3% deemed cumulative persisting annual savings for the year ending December 31, 2026;

(10) 2.1% deemed cumulative persisting annual savings for the year ending December 31, 2027;

(11) 1.8% deemed cumulative persisting annual savings for the year ending December 31, 2028;

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

(13) 1.5% deemed cumulative persisting annual savings for the year ending December 31, 2030; .

(14) 1.3% deemed cumulative persisting annual savings for the year ending December 31, 2031;

(15) 1.1% deemed cumulative persisting annual savings for the year ending December 31, 2032;

(16) 0.9% deemed cumulative persisting annual savings for the year ending December 31, 2033;

(17) 0.7% deemed cumulative persisting annual savings for the year ending December 31, 2034;

(18) 0.5% deemed cumulative persisting annual savings for the year ending December 31, 2035;

(19) 0.4% deemed cumulative persisting annual savings for the year ending December 31, 2036;

(20) 0.3% deemed cumulative persisting annual savings for the year ending December 31, 2037;

(21) 0.2% deemed cumulative persisting annual savings for the year ending December 31, 2038;

(22) 0.1% deemed cumulative persisting annual savings for the year ending December 31, 2039; and

(23) 0.0% deemed cumulative persisting annual savings for the year ending December 31, 2040 and all subsequent years.

(b-15) Beginning in 2018, electric utilities subject to this Section that serve less than 3,000,000 retail customers but more than 500,000 retail customers in the State shall achieve the following cumulative persisting annual savings goals, as modified by subsection (b-20) and subsection (f) of this Section and as compared to the deemed baseline as reduced by the number of MWhs equal to the sum of the annual consumption of customers that are exempt from subsections (a) through (j) of this Section under subsection (l) of this Section as averaged across the calendar years 2014, 2015, and 2016, through the implementation of energy efficiency measures during the applicable year and in prior years, but no earlier than January 1, 2012:

(1) 7.4% cumulative persisting annual savings for the year ending December 31, 2018;

(2) 8.2% cumulative persisting annual savings for the year ending December 31, 2019;

(3) 9.0% cumulative persisting annual savings for the year ending December 31, 2020;

(4) 9.8% cumulative persisting annual savings for the year ending December 31, 2021;

(5) 10.6% cumulative persisting annual savings for the year ending December 31, 2022;

(6) 11.4% cumulative persisting annual savings for the year ending December 31, 2023;

(7) 12.2% cumulative persisting annual savings for the year ending December 31, 2024;

(8) 13% cumulative persisting annual savings for the year ending December 31, 2025;

(9) 13.6% cumulative persisting annual savings for the year ending December 31, 2026;

(10) 14.2% cumulative persisting annual savings for the year ending December 31, 2027;

(11) 14.8% cumulative persisting annual savings for the year ending December 31, 2028;

(12) 15.4% cumulative persisting annual savings for the year ending December 31, 2029; and

(13) 16% cumulative persisting annual savings for the year ending December 31, 2030.

No later than December 31, 2020, the Illinois Commerce Commission shall establish additional cumulative persisting annual savings goals for the years 2031 through 2035. The Commission shall also establish additional cumulative persisting annual savings goals every 5 years thereafter to ensure utilities always have goals that extend at least 11 years into the future. The cumulative persisting annual savings goals beyond the year 2030 shall increase by 0.6 percentage points per year, absent a Commission decision to initiate a proceeding to consider establishing goals that increase by more or less than that amount. Such a proceeding must be conducted in accordance with the procedures described in subsection (f)of this Section. If such a proceeding is initiated, the cumulative persisting annual savings goals established by the Commission through that proceeding shall reflect the Commission's best estimate of the maximum amount of additional savings that are forecast to be cost-effectively achievable unless such best estimates would result in goals that represent less than 0.4 percentage point annual increases in total cumulative persisting annual savings. The Commission may only establish goals that represent less than 0.4 percentage point annual increases in cumulative persisting annual savings if it can demonstrate, based on clear and convincing evidence, that 0.4 percentage point increases are not cost-effectively achievable. The Commission shall inform its decision based on an energy efficiency potential study which conforms to the requirements of subsection (f-5) of this Section.

The difference between the cumulative persisting annual savings goal for the applicable calendar year and the cumulative persisting annual savings goal for the immediately preceding calendar year is 0.8% for the period of January 1, 2018 through December 31, 2025 and 0.6% for the period of January 1, 2026 through December 31, 2030.

(b-20) Each electric utility subject to this Section may include cost-effective voltage optimization measures in its plans submitted under subsections (f) and (g) of this Section, and the costs incurred by a utility to implement the measures under a Commission-approved plan shall be recovered under 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. Utilities may claim savings from voltage optimization on circuits for more than 15 years if they can demonstrate that they have made additional investments necessary to enable voltage optimization savings to continue beyond 15 years. Such demonstrations must be subject to the review of independent evaluation.

Within 270 days after June 1, 2017 (the effective date of Public Act 99-906) this amendatory Act of the 99th General Assembly, an electric utility that serves less than 3,000,000 retail customers but more than 500,000 retail customers in the State shall file a plan with the Commission that identifies the cost-effective voltage optimization investment the electric utility plans to undertake through December 31, 2024. The Commission, after notice and hearing, shall approve or approve with modification the plan within 120 days after the plan's filing and, in the order approving or approving with modification the plan, the Commission shall adjust the applicable cumulative persisting annual savings goals set forth in subsection (b-15) to reflect any amount of cost-effective energy savings approved by the Commission that is greater than or less than the following cumulative persisting annual savings values attributable to voltage optimization for the applicable year:

(1) 0.0% of cumulative persisting annual savings for the year ending December 31, 2018;

(2) 0.17% of cumulative persisting annual savings for the year ending December 31, 2019;

(3) 0.17% of cumulative persisting annual savings for the year ending December 31, 2020;

(4) 0.33% of cumulative persisting annual savings for the year ending December 31, 2021;

(5) 0.5% of cumulative persisting annual savings for the year ending December 31, 2022;

(6) 0.67% of cumulative persisting annual savings for the year ending December 31, 2023;

(7) 0.83% of cumulative persisting annual savings for the year ending December 31, 2024; and

(8) 1.0% of cumulative persisting annual savings for the year ending December 31, 2025 and all subsequent years.

(b-25) In the event an electric utility jointly offers an energy efficiency measure or program with a gas utility under 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, 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 electric utility shall prioritize programs for low-income residential customers to the extent practicable. An electric utility may recover the costs of offering the gas energy efficiency measures under this subsection (b-25).

For those energy efficiency measures or programs that save both electricity and other fuels but are not jointly offered with a gas utility under plans approved under this Section and Section 8-104 or not offered with an affiliated gas utility under paragraph (6) of subsection (f) of Section 8-104 of this Act, 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.

In no event shall more than 10% of each year's applicable annual total savings requirement incremental goal as defined in paragraph (7) of subsection (g) of this Section be met through savings of fuels other than electricity.

(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%, for electric utilities that serve more than 3,000,000 retail customers in the State, and a minimum of 7%, for electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers in the State, of the utility's entire portfolio funding level 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, and buildings owned by nonprofit organizations,, 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 $35,000,000 $25,000,000 per year for electric utilities that serve more than 3,000,000 retail customers in the State and no less than $11,000,000 $8,350,000 per year for electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers in the State. Spending on efficiency programs targeted at low-income households shall be approximately proportional to the magnitude of cost-effective energy efficiency opportunities in low-income single-family and multi-family buildings.

The utilities shall work to bundle low-income energy efficiency offerings with other programs that serve low-income households to maximize the benefits going to these households. The utilities shall market and implement low-income energy efficiency programs in coordination with low-income assistance programs, Solar for All, and weatherization whenever practicable. The program implementer shall walk the customer through the enrollment process for any programs for which the customer is eligible. The utilities shall also pilot targeting customers with high arrearages, high energy intensity (ratio of energy usage divided by home or unit square footage), or energy assistance programs with energy efficiency offerings, and then track reduction in arrearages as a result of the targeting. This targeting and bundling of low-income energy programs shall be offered to both low-income single-family and multi-family customers (owners and residents).

The utilities shall also implement a health and safety fund of a minimum of 0.5%, for electric utilities that serve more than 3,000,000 retail customers in the State, and a minimum of 0.5%, for electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers in the State, of the utility's entire portfolio funding level for a given year, that shall be used for the purpose of making grants for technical assistance, construction, reconstruction, improvement, or repair of buildings to facilitate their participation in the energy efficiency programs targeted at low-income single-family and multi-family households. These funds may also be used for the purpose of making grants for technical assistance, construction, reconstruction, improvement, or repair of the following buildings to facilitate their participation in the energy efficiency programs created by this Section: (1) buildings that are owned or operated by registered 501(c)(3) public charities; and (2) day care centers, day care homes, or group day care homes, as defined under 89 Ill. Adm. Code Part 406, 407, or 408, respectively.

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 participate in shall also convene a low-income energy efficiency advisory committee to allow a variety of stakeholders, especially those living or working in low-communities, 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 8-104.1 8-104 of this Act, the utilities' low-income energy efficiency implementation contractors, nonprofit organizations, community action agencies, advocacy groups, State and local governmental agencies, and representatives of community-based organizations. The committee shall be convened by an independent third-party facilitator and a community-based organization in a low-income community. There shall be a leadership committee comprised of a variety of stakeholders, with at least one community-based organization involved. Meetings shall include concrete opportunities for groups to provide meaningful input into plan design, mid-cycle changes, and evaluation throughout the year to help reduce litigation in future plan filings. All meetings must be accessible, with rotating locations, call-in options, and materials and agendas circulated well in advance. There shall also be opportunities for input outside of meetings from those with limited capacity and ability to attend, via one-on-one meetings, surveys, and calls. Meetings shall also include opportunities to bundle and coordinate low-income energy efficiency with Solar for All and energy assistance programs. Meetings shall include educational opportunities for stakeholders to learn more about these additional offerings, and the committee shall assist in the figuring out the best methods for coordinated delivery and implementation of offerings when serving low-income communities.

(d) Notwithstanding any other provision of law to the contrary, a utility providing approved energy efficiency measures and, if applicable, demand-response measures in the State shall be permitted to recover all reasonable and prudently incurred costs of those measures from all retail customers, except as provided in subsection (l) of this Section, as follows, provided that nothing in this subsection (d) permits the double recovery of such costs from customers:

(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. To enable the financing of the incremental capital expenditures, including regulatory assets, for electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers in the State, the utility's actual year-end capital structure that includes a common equity ratio, excluding goodwill, of up to and including 50% of the total capital structure shall be deemed reasonable and used to set rates.

(2) A utility may recover its costs through an energy efficiency formula rate approved by the Commission under a filing under subsections (f) and (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 subsections (f) and (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), subsections (f) and (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. To enable the financing of the incremental capital expenditures, including regulatory assets, for electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers in the State, a participating electric utility's actual year-end capital structure that includes a common equity ratio, excluding goodwill, of up to and including 50% of the total capital structure shall be deemed reasonable and used to set rates.

(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 under 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 under the utility's multi-year plan approved under subsections (f) and (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.

The tariff's rate design and cost allocation across customer classes shall be consistent with the utility's automatic adjustment clause tariff in effect on June 1, 2017 (the effective date of Public Act 99-906) this amendatory Act of the 99th General Assembly; however, the Commission may revise the tariff's rate design and cost allocation in subsequent proceedings under paragraph (3) of this subsection (d).

If 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 under 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, as well as the information described in paragraph (9) of subsection (g) of this Section. 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 under the utility's multi-year plan approved under subsections (f) and (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 under 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 under 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 with reasonable notice, initiate a proceeding 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 subsections (f) and (g) of this Section and whether the costs incurred by the utility during the prior rate year were prudent and reasonable. The Commission shall also have the authority to investigate the information and data described in paragraph (9) of subsection (g) of this Section, including the proposed adjustment to the utility's return on equity component of its weighted average cost of capital. During the course of the proceeding, 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 administrative law judge. 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, during the proceeding as it would apply in a proceeding 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 under 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 utility's proposed return on equity calculation, as described in paragraphs (7) through (9) of subsection (g) of this Section, 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 Commission's determinations of the prudence and reasonableness of the costs incurred, and determination of such return on equity calculation, 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 under the provisions of this Act.

(e) Beginning on June 1, 2017 (the effective date of Public Act 99-906) this amendatory Act of the 99th General Assembly, a utility subject to the requirements of this Section may elect to defer, as a regulatory asset, up to the full amount of its expenditures incurred under this Section for each annual period, including, but not limited to, any expenditures incurred above the funding level set by subsection (f) of this Section for a given year. The total expenditures 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 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 under 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 under 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 schedule set forth in paragraphs (1) through (3) of this subsection (f). 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.

(1) No later than 30 days after June 1, 2017 (the effective date of Public Act 99-906) 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 or in paragraphs (1) through (4) of subsection (b-15) of this Section, as applicable, through implementation of energy efficiency measures; however, the goals may be reduced if the utility's expenditures are limited pursuant to subsection (m) of this Section or, for a utility that serves less than 3,000,000 retail customers, if each of the following conditions are met: (A) the plan's analysis and forecasts of the utility's ability to acquire energy savings demonstrate that achievement of such goals is not cost effective; and (B) the amount of energy savings achieved by the utility as determined by the independent evaluator for the most recent year for which savings have been evaluated preceding the plan filing was less than the average annual amount of savings required to achieve the goals for the applicable 4-year plan period. Except as provided in subsection (m) of this Section, annual increases in cumulative persisting annual savings goals during the applicable 4-year plan period shall not be reduced to amounts that are less than the maximum amount of cumulative persisting annual savings that is forecast to be cost-effectively achievable during the 4-year plan period. The Commission shall review any proposed goal reduction as part of its review and approval of the utility's proposed plan.

(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 or in paragraphs (5) through (8) of subsection (b-15) of this Section, as applicable, through implementation of energy efficiency measures; however, the goals may be reduced if the utility's expenditures are limited pursuant to subsection (m) of this Section or, each of the following conditions are met: (A) the plan's analysis and forecasts of the utility's ability to acquire energy savings demonstrate by clear and convincing evidence that achievement of such goals is not cost effective; and (B) the amount of energy savings achieved by the utility as determined by the independent evaluator for the most recent year for which savings have been evaluated preceding the plan filing was less than the average annual amount of savings required to achieve the goals for the applicable 4-year plan period. Except as provided in subsection (m) of this Section, annual increases in cumulative persisting annual savings goals during the applicable 4-year plan period shall not be reduced to amounts that are less than the maximum amount of cumulative persisting annual savings that is forecast to be cost-effectively achievable during the 4-year plan period. The Commission shall review any proposed goal reduction as part of its review and approval of the utility's proposed plan, taking into account the results of the potential study required by subsection (f-5)of this Section.

(3) No later than March 1, 2025, each electric utility shall file a 4-year 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 (12) (13) of subsection (b-5) of this Section or in paragraphs (9) through (12) (13) of subsection (b-15) of this Section, as applicable, through implementation of energy efficiency measures; however, the goals may be reduced if the utility's expenditures are limited pursuant to subsection (m) of this Section or, each of the following conditions are met: (A) the plan's analysis and forecasts of the utility's ability to acquire energy savings demonstrate by clear and convincing evidence that achievement of such goals is not cost effective; and (B) the amount of energy savings achieved by the utility as determined by the independent evaluator for the most recent year for which savings have been evaluated preceding the plan filing was less than the average annual amount of savings required to achieve the goals for the applicable 4-year 5-year plan period. Except as provided in subsection (m) of this Section, annual increases in cumulative persisting annual savings goals during the applicable 4-year 5-year plan period shall not be reduced to amounts that are less than the maximum amount of cumulative persisting annual savings that is forecast to be cost-effectively achievable during the 4-year 5-year plan period. The Commission shall review any proposed goal reduction as part of its review and approval of the utility's proposed plan, taking into account the results of the potential study required by subsection (f-5)of this Section.

(4) No later than March 1, 2029, and every 4 years thereafter, each electric utility shall file a 4-year energy efficiency plan commencing on January 1, 2030, and every 4 years thereafter, respectively, that is designed to achieve the cumulative persisting annual savings goals established by the Illinois Commerce Commission pursuant to direction of subsections (b-5) and (b-15) of this Section, as applicable, through implementation of energy efficiency measures; however, the goals may be reduced if the utility's expenditures are limited pursuant to subsection (m) of this Section or, each of the following conditions are met: (A) the plan's analysis and forecasts of the utility's ability to acquire energy savings demonstrate by clear and convincing evidence that achievement of such goals is not cost effective; and (B) the amount of energy savings achieved by the utility as determined by the independent evaluator for the most recent year for which savings have been evaluated preceding the plan filing was less than the average annual amount of savings required to achieve the goals for the applicable 4-year plan period. Except as provided in subsection (m) of this Section, annual increases in cumulative persisting annual savings goals during the applicable 4-year plan period shall not be reduced to amounts that are less than the maximum amount of cumulative persisting annual savings that is forecast to be cost-effectively achievable during the 4-year plan period. The Commission shall review any proposed goal reduction as part of its review and approval of the utility's proposed plan.

Each utility's plan shall set forth the utility's proposals to meet the energy efficiency standards identified in subsection (b-5) or (b-15), as applicable and as such standards may have been modified under this subsection (f), taking into account the unique circumstances of the utility's service territory and results of an energy efficiency potential study as described in subsection (f-5) of this Section. 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, or 105 days after June 1, 2017 (the effective date of Public Act 99-906) this amendatory Act of the 99th General Assembly, whichever is later. 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.

(f-5) Energy efficiency potential study. An energy efficiency potential study shall be commissioned and overseen by the Illinois Commerce Commission. The potential study shall be reviewed as part of the approval of a utility's plan filed pursuant to subsection (f) of this Section. The potential study shall be designed and conducted with input from a Potential Study Stakeholder Committee established by the Commission. This Committee shall be comprised of representatives from each electric utility, the Illinois Attorney General's office, at least 2 environmental stakeholders, at least one community based organization, and additional parties representing consumers. The Committee shall provide input, at a minimum, into the scope of work for the studies, the selection of vendors to perform the studies in accordance with appropriate confidentiality and conflict of interest provisions, and draft work products. The Committee shall make best efforts to achieve consensus on the key elements of the potential study, including:

(i) savings potential from efficiency measures and program concepts that are known at the time of the study;

(ii) likely emergence of new technology or new program concepts that could emerge;

(iii) likely savings potential from efficiency measures that may be unique to individual industries or individual facilities; and

(iv) the experience of other similar utilities, areas and jurisdictions in maximizing achievement of cost-effective savings.

When the Committee is not able to reach consensus, the Commission shall make the final decision.

(g) In submitting proposed plans and funding levels under subsection (f) of this Section to meet the savings goals identified in subsection (b-5) or (b-15) of this Section, as applicable, the utility shall:

(1) Demonstrate that its proposed energy efficiency measures will achieve the applicable requirements that are identified in subsection (b-5) or (b-15) of this Section, as modified by subsection (f) of this Section.

(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 or complies with paragraphs (1) through (3) of subsection (f) of this Section and represents a diverse cross-section of opportunities for customers of all rate classes, other than those customers described in subsection (l) of this Section, to participate in the programs. Individual measures need not be cost effective.

(3.5) Demonstrate that the utility's plan integrates the delivery of energy efficiency programs with natural gas efficiency programs, programs promoting distributed solar, programs promoting demand response and other efforts to address bill payment issues, including, but not limited to, LIHEAP and the Percent Income Payment Plan, to the extent such integration is practical and has the potential to enhance customer engagement, minimize market confusion, or reduce administrative costs.

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

(A) beginning with the year commencing January 1, 2019, electric utilities that serve more than 3,000,000 retail customers in the State shall fund third-party energy efficiency programs in an amount that is no less than $25,000,000 per year, and electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers in the State shall fund third-party energy efficiency programs in an amount that is no less than $8,350,000 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; the solicitation process must be either for programs that fill gaps in the utility's program portfolio or for programs that target business sectors, building types, geographies, or other specific parts of its customer base with initiatives that would be more effective at reaching these customer segments than the utilities' programs filed in its energy efficiency plans.

(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; and

(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.

The electric utility shall recover all costs associated with Commission-approved, third-party administered programs regardless of the success of those programs.

(4.5) 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 continues until December 31, 2026.

(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) For electric utilities that serve more than 3,000,000 retail customers in the State:

(A) Through December 31, 2025, provide for an adjustment to the return on equity component of the utility's weighted average cost of capital calculated under subsection (d) of this Section:

(i) If the independent evaluator determines that the utility achieved a cumulative persisting annual savings that is less than the applicable annual incremental goal, 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.

(ii) If the independent evaluator determines that the utility achieved a cumulative persisting annual savings that is more than the applicable annual incremental goal, 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. If the applicable annual incremental goal was reduced under paragraphs (1) or (2) of subsection (f) of this Section, then the following adjustments shall be made to the calculations described in this item (ii):

(aa) the calculation for determining achievement that is at least 125% of the applicable annual incremental goal shall use the unreduced applicable annual incremental goal to set the value; and

(bb) the calculation for determining achievement that is less than 125% but more than 100% of the applicable annual incremental goal shall use the reduced applicable annual incremental goal to set the value for 100% achievement of the goal and shall use the unreduced goal to set the value for 125% achievement. The 8 basis point value shall also be modified, as necessary, so that the 200 basis points are evenly apportioned among each percentage point value between 100% and 125% achievement.

(B) For the period January 1, 2026 through December 31, 2029 and in all subsequent 4-year periods 2030, provide for an adjustment to the return on equity component of the utility's weighted average cost of capital calculated under subsection (d) of this Section:

(i) If the independent evaluator determines that the utility achieved a cumulative persisting annual savings that is less than the applicable annual incremental goal, 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 66% of such goal. If the utility achieved more than 66% of the applicable annual incremental goal but less than 100% of such goal, then the return on equity component shall be reduced by 6 basis points for each percent by which the utility failed to achieve the goal.

(ii) If the independent evaluator determines that the utility achieved a cumulative persisting annual savings that is more than the applicable annual incremental goal, 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 134% of such goal. If the utility achieved more than 100% of the applicable annual incremental goal but less than 134% of such goal, then the return on equity component shall be increased by 6 basis points for each percent by which the utility achieved above the goal. If the applicable annual incremental goal was reduced under paragraph (3) of subsection (f) of this Section, then the following adjustments shall be made to the calculations described in this item (ii):

(aa) the calculation for determining achievement that is at least 134% of the applicable annual incremental goal shall use the unreduced applicable annual incremental goal to set the value; and

(bb) the calculation for determining achievement that is less than 134% but more than 100% of the applicable annual incremental goal shall use the reduced applicable annual incremental goal to set the value for 100% achievement of the goal and shall use the unreduced goal to set the value for 134% achievement. The 6 basis point value shall also be modified, as necessary, so that the 200 basis points are evenly apportioned among each percentage point value between 100% and 134% achievement.

(C) Notwithstanding the provisions of subparagraphs (A) and (B) of this paragraph (7), if the applicable annual incremental goal for an electric utility is ever less than 0.6% of deemed average weather normalized sales of electric power and energy during calendar years 2014, 2015, and 2016, an adjustment to the return on equity component of the utility's weighted average cost of capital calculated under subsection (d) of this Section shall be made as follows:

(i) If the independent evaluator determines that the utility achieved a cumulative persisting annual savings that is less than would have been achieved had the applicable annual incremental goal been achieved, then the return on equity component shall be reduced by a maximum of 200 basis points if the utility achieved no more than 75% of its applicable annual total savings requirement as defined in paragraph (7.5) of this subsection. If the utility achieved more than 75% of the applicable annual total savings requirement 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.

(ii) If the independent evaluator determines that the utility achieved a cumulative persisting annual savings that is more than would have been achieved had the applicable annual incremental goal been achieved, then the return on equity component shall be increased by a maximum of 200 basis points if the utility achieved at least 125% of its applicable annual total savings requirement. If the utility achieved more than 100% of the applicable annual total savings requirement 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 applicable annual total savings requirement. If the applicable annual incremental goal was reduced under paragraphs (1) or (2) of subsection (f) of this Section, then the following adjustments shall be made to the calculations described in this item (ii):

(aa) the calculation for determining achievement that is at least 125% of the applicable annual total savings requirement shall use the unreduced applicable annual incremental goal to set the value; and

(bb) the calculation for determining achievement that is less than 125% but more than 100% of the Applicable Annual Total Savings Requirement shall use the reduced applicable annual incremental goal to set the value for 100% achievement of the goal and shall use the unreduced goal to set the value for 125% achievement. The 8 basis point value shall also be modified, as necessary, so that the 200 basis points are evenly apportioned among each percentage point value between 100% and 125% achievement.

(7.5) 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 subsections (b-5) and (b-15) of this Section and as these goals may have been modified as provided for under subsection (b-20) and paragraphs (1) through (3) of subsection (f) of this Section. Under subsections (b), (b-5), (b-10), and (b-15) of this Section, a utility must first replace energy savings from measures that have reached the end of their measure lives and would otherwise have to be replaced to meet the applicable savings goals identified in subsection (b-5) or (b-15) of this Section before any progress towards achievement of its applicable annual incremental goal may be counted. Notwithstanding anything else set forth in this Section, the difference between the actual annual incremental savings achieved in any given year, including the replacement of energy savings from measures that have expired, and the applicable annual incremental goal shall not affect adjustments to the return on equity for subsequent calendar years under this subsection (g).

As used in this Section, "applicable annual total savings requirement" means the sum of (i) the applicable annual savings goal; plus (ii) the amount of new annual savings required to replace savings from efficiency measures that provided cumulative persisting annual savings in the previous year, including savings from programs in 2012 through 2017 for which savings are deemed in subsections (b) and (b-10), but which reached the end of their measure lives by the end of the previous year.

(8) For electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers in the State:

(A) Through December 31, 2025, the applicable annual incremental goal shall be compared to the annual incremental savings as determined by the independent evaluator.

(i) The return on equity component shall be reduced by 8 basis points for each percent by which the utility did not achieve 84.4% of the applicable annual incremental goal.

(ii) The return on equity component shall be increased by 8 basis points for each percent by which the utility exceeded 100% of the applicable annual incremental goal.

(iii) The return on equity component shall not be increased or decreased if the annual incremental savings as determined by the independent evaluator is greater than 84.4% of the applicable annual incremental goal and less than 100% of the applicable annual incremental goal.

(iv) The return on equity component shall not be increased or decreased by an amount greater than 200 basis points pursuant to this subparagraph (A).

(B) For the period of January 1, 2026 through December 31, 2029 and in all subsequent 4-year periods 2030, the applicable annual incremental goal shall be compared to the annual incremental savings as determined by the independent evaluator.

(i) The return on equity component shall be reduced by 6 basis points for each percent by which the utility did not achieve 100% of the applicable annual incremental goal.

(ii) The return on equity component shall be increased by 6 basis points for each percent by which the utility exceeded 100% of the applicable annual incremental goal.

(iii) The return on equity component shall not be increased or decreased by an amount greater than 200 basis points pursuant to this subparagraph (B).

(C) Notwithstanding provisions in subparagraphs (A) and (B) of paragraph (7) of this subsection, if the applicable annual incremental goal for an electric utility is ever less than 0.6% of deemed average weather normalized sales of electric power and energy during calendar years 2014, 2015 and 2016, an adjustment to the return on equity component of the utility's weighted average cost of capital calculated under subsection (d) of this Section shall be made as follows:

(i) The return on equity component shall be reduced by 8 basis points for each percent by which the utility did not achieve 100% of the applicable annual total savings requirement.

(ii) The return on equity component shall be increased by 8 basis points for each percent by which the utility exceeded 100% of the applicable annual total savings requirement.

(iii) The return on equity component shall not be increased or decreased by an amount greater than 200 basis points pursuant to this subparagraph (C).

(D) (C) If the applicable annual incremental goal was reduced under paragraphs (1), (2), or (3), or (4) of subsection (f) of this Section, then the following adjustments shall be made to the calculations described in subparagraphs (A), and (B), and (C) of this paragraph (8):

(i) The calculation for determining achievement that is at least 125% or 134%, as applicable, of the applicable annual incremental goal or the applicable annual total savings requirement, as applicable, shall use the unreduced applicable annual incremental goal to set the value.

(ii) For the period through December 31, 2025, the calculation for determining achievement that is less than 125% but more than 100% of the applicable annual incremental goal or the applicable annual total savings requirement, as applicable, shall use the reduced applicable annual incremental goal to set the value for 100% achievement of the goal and shall use the unreduced goal to set the value for 125% achievement. The 8 basis point value shall also be modified, as necessary, so that the 200 basis points are evenly apportioned among each percentage point value between 100% and 125% achievement.

(iii) For the period of January 1, 2026 through December 31, 2029 and all subsequent 4-year periods, the calculation for determining achievement that is less than 125% or 134%, as applicable, but more than 100% of the applicable annual incremental goal or the applicable annual total savings requirement, as applicable, shall use the reduced applicable annual incremental goal to set the value for 100% achievement of the goal and shall use the unreduced goal to set the value for 125% achievement. The 6 or 8 basis point values, as applicable, shall also be modified, as necessary, so that the 200 basis points are evenly apportioned among each percentage point value between 100% and 125% or between 100% and 134% achievement, as applicable. 2030, the calculation for determining achievement that is less than 134% but more than 100% of the applicable annual incremental goal shall use the reduced applicable annual incremental goal to set the value for 100% achievement of the goal and shall use the unreduced goal to set the value for 125% achievement. The 6 basis point value shall also be modified, as necessary, so that the 200 basis points are evenly apportioned among each percentage point value between 100% and 134% achievement.

(9) 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, as well as an estimate of job impacts and other macroeconomic impacts of the efficiency programs for that 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, under paragraph (7) or (8) of this subsection (g), as applicable, 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. However, if the utility recovers the costs incurred under this Section under paragraphs (2) and (3) of subsection (d) of this Section, then the utility shall not be required to submit such informational filing, and shall instead submit the information that would otherwise be included in the informational filing as part of its filing under paragraph (3) of such subsection (d) that is due on or before June 1 of each year.

For those utilities that must submit the informational filing, 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 paragraphs (7) and (8) of this subsection (g) shall be applied as described in such paragraphs through a separate tariff mechanism, which shall be filed by the utility under subsections (f) and (g) of this Section.

(10) Electric utilities required to implement efficiency programs under subsections (b-5) and (b-15) shall report annually to the Illinois Commerce Commission and the General Assembly on how hiring, contracting, job training, and other practices related to its energy efficiency programs enhance the diversity of vendors working on such programs. These reports must include data on vendor and employee diversity.

(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, subject to the data privacy and confidentiality protections of applicable law.

(j) 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 measure life values for energy efficiency measures implemented for low-income households under subsection (c) of this Section are incorporated into such Commission-approved manuals, the low-income measures shall have the same measure life values that are established for same measures implemented in households that are not low-income households.

(k) 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 expenditures 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 June 1, 2017 (the effective date of Public Act 99-906) 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 subsection. Such costs shall include those incurred or to be incurred by the utility under its multi-year plan approved under subsections (f) and (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 (k). 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 (k). 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.

(l) (Blank). For the calendar years covered by a multi-year plan commencing after December 31, 2017, subsections (a) through (j) of this Section do not apply to any retail customers of an electric utility that serves more than 3,000,000 retail customers in the State and whose total highest 30 minute demand was more than 10,000 kilowatts, or any retail customers of an electric utility that serves less than 3,000,000 retail customers but more than 500,000 retail customers in the State and whose total highest 15 minute demand was more than 10,000 kilowatts. For purposes of this subsection (l), "retail customer" has the meaning set forth in Section 16-102 of this Act. A determination of whether this subsection is applicable to a customer shall be made for each multi-year plan beginning after December 31, 2017. The criteria for determining whether this subsection (l) is applicable to a retail customer shall be based on the 12 consecutive billing periods prior to the start of the first year of each such multi-year plan.

(m) Notwithstanding the requirements of this Section, as part of a proceeding to approve a multi-year plan under subsections (f) and (g) of this Section if the multi-year plan has been designed to maximize savings, but does not meet the cost cap limitations of this subsection, the Commission shall reduce the amount of energy efficiency measures implemented for any single year, and whose costs are recovered under subsection (d) of this Section, by an amount necessary to limit the estimated average net increase due to the cost of the measures to no more than

(1) 3.5% for the each of the 4 years beginning January 1, 2018,

(2) 3.75% for each of the 4 years beginning January 1, 2022, and

(3) 4% for each of the 5 years beginning January 1, 2026,

(4) 4.25% for the 5 years beginning January 1, 2031, and

(5) 4.25% plus a 0.25% increase for every subsequent 5-year period, of the average amount paid per kilowatthour by residential eligible retail customers during calendar year 2015. An electric utility may spend up to 10% more in any year during an applicable multi-year plan period to cost-effectively achieve additional savings so long as the average over the applicable multi-year plan period does not exceed the percentages defined in items (1) through (5). To determine the total amount that may be spent by an electric utility in any single year, the applicable percentage of the average amount paid per kilowatthour shall be multiplied by the total amount of energy delivered by such electric utility in the calendar year 2015, adjusted to reflect the proportion of the utility's load attributable to customers who are exempt from subsections (a) through (j) of this Section under subsection (l) of this Section. For purposes of this subsection (m), the amount paid per kilowatthour includes, without limitation, estimated amounts paid for supply, transmission, distribution, surcharges, and add-on taxes. For purposes of this Section, "eligible retail customers" shall have the meaning set forth in Section 16-111.5 of this Act. Once the Commission has approved a plan under subsections (f) and (g) of this Section, no subsequent rate impact determinations shall be made.

(Source: P.A. 99-906, eff. 6-1-17; 100-840, eff. 8-13-18; revised 10-19-18.)

(220 ILCS 5/8-104.1 new)

Sec. 8-104.1. Gas utilities; annual savings goals.

(a) It is the policy of the State that gas utilities are required to use cost-effective energy efficiency to reduce delivery load. Requiring investment in cost-effective energy efficiency will reduce direct and indirect costs to consumers by decreasing environmental impacts and by reducing the amount of natural gas that needs to be purchased and avoiding or delaying the need for new transmission, distribution, storage and other related infrastructure. It serves the public interest to allow gas utilities to recover costs for reasonably and prudently incurred expenditures for energy efficiency measures.

(b) In 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 natural gas system and the participant in the delivery of those efficiency measures and including avoided costs associated with the use of electricity or other fuels, avoided cost associated with reduced water consumption, and avoided costs associated with reduced operation and maintenance costs, as well as other quantifiable societal benefits, 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. 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 shall be used. The low-income measures described in subsection (f) of this Section shall not be required to meet the total resource cost test.

"Cumulative persisting annual savings" means the total gas energy savings in a given year from measures installed in that year or in previous years, but no earlier than January 1, 2020, that are still operational and providing savings in that year because the measures have not yet reached the end of their useful lives.

(c) This Section applies to all gas distribution utilities in the State for those multi-year plans that include energy efficiency programs commencing after December 31, 2019.

(d) Beginning in 2020, gas utilities subject to this Section shall achieve the following cumulative persisting annual savings goals, as compared to a deemed baseline equivalent to the utility's average annual therm sales in 2016 through 2018 through the implementation of energy efficiency measures during the applicable year and in prior years, but no earlier than January 1, 2020:

(1) 1.2% cumulative persisting annual savings for the year ending December 31, 2020;

(2) 2.1% cumulative persisting annual savings for the year ending December 31, 2021;

(3) 3.0% cumulative persisting annual savings for the year ending December 31, 2022;

(4) 3.9% cumulative persisting annual savings for the year ending December 31, 2023;

(5) 4.8% cumulative persisting annual savings for the year ending December 31, 2024;

(6) 5.7% cumulative persisting annual savings for the year ending December 31, 2025;

(7) 6.6% cumulative persisting annual savings for the year ending December 31, 2026;

(8) 7.4% cumulative persisting annual savings for the year ending December 31, 2027;

(9) 8.2% cumulative persisting annual savings for the year ending December 31, 2028;

(10) 9.0% cumulative persisting annual savings for the year ending December 31, 2029;

(11) 9.8% cumulative persisting annual savings for the year ending December 31, 2030;

(12) 10.6% cumulative persisting annual savings for the year ending December 31, 2031;

(13) 11.4% cumulative persisting annual savings for the year ending December 31, 2032;

(14) 12.1% cumulative persisting annual savings for the year ending December 31, 2033;

(15) 12.8% cumulative persisting annual savings for the year ending December 31, 2034; and

(16) 13.5% cumulative persisting annual savings for the year ending December 31, 2035.

No later than December 31, 2025, the Illinois Commerce Commission shall establish additional cumulative persisting annual savings goals for the years 2036 through 2040. The Commission shall also establish additional cumulative persisting annual savings goals every 5 years thereafter to ensure utilities always have goals that extend at least 11 years into the future. The cumulative persisting annual savings goals beyond the year 2035 shall increase by 0.6 percentage points per year absent a Commission decision to initiate a proceeding to consider establishing goals that increase by more or less than that amount. Such a proceeding must be conducted in accordance with the procedures described in subsection (f) of this Section. If such a proceeding is initiated, the cumulative persisting annual savings goals established by the Commission through that proceeding shall reflect the Commission's best estimate of the maximum amount of additional gas savings that are forecast to be cost-effectively achievable unless such best estimates would result in goals that represent less than 0.4 percentage point annual increases in total cumulative persisting annual savings. The Commission may only establish goals that represent less than 0.4 percentage point annual increases in cumulative persisting annual savings if it can demonstrate, based on clear and convincing evidence, that 0.4 percentage point increases are not cost-effectively achievable. The Commission shall inform its decision based on an energy efficiency potential study which conforms to the requirements of subsection (j-5) of this Section.

(e) If a gas utility jointly offers an energy efficiency measure or program with an electric utility under plans approved under this Section and Section 8-103B of this Act, the gas utility may continue offering the program, including the electric energy efficiency measures, if the electric utility discontinues funding the program. In that event, the energy savings value associated with such other fuels shall be converted to gas energy savings on an equivalent Btu basis for the premises. However, the gas utility shall prioritize programs for low-income residential customers to the extent practicable. A gas utility may recover the costs of offering the gas energy efficiency measures under this subsection (e).

For those energy efficiency measures or programs that save both gas and other fuels but are not jointly offered with an electric utility under plans approved under this Section and Section 8-103B, the gas utility may count savings of fuels other than gas toward the achievement of its annual savings goal, and the energy savings value associated with such other fuels shall be converted to gas energy savings on an equivalent Btu basis at the premises.

In no event shall more than 10% of each year's applicable annual total savings requirement as defined in paragraph (8) of subsection (j) of this Section be met through savings of fuels other than gas.

(f) Gas utilities are 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 utility's entire portfolio funding level 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, community college districts, and nonprofit-owned buildings 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 single-family and multi-family 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 20% of the utility's total efficiency portfolio budget.

At least 70% of spending on measures in programs targeted at low-income households shall go toward measures that reduce space heating needs through improvements to the building envelope or heating distribution systems. Programs targeted at low-income households, which address single-family and multi-family buildings shall be treated such that savings opportunities in each building type are approximately in proportional to the magnitude of cost-effective energy efficiency opportunities in these respective building types.

Each gas 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 (f).

Implementation of energy efficiency measures and programs targeted at low-income households shall be contracted, when it is practical, 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 gas 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 (f).

The gas utilities shall participate in a low-income energy efficiency advisory committee designed to allow a variety of stakeholders, especially those living or working in low-income communities, 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 Section 8-103B of this Act, the gas utilities subject to the requirements of this Section, the utilities' low-income energy efficiency implementation contractors, nonprofit organizations, community action agencies, advocacy groups, State and local governmental agencies, and representatives of community-based organizations. The committee shall be convened by an independent third-party facilitator and a community-based organization in a low-income community. There shall be a leadership committee comprised of a variety of stakeholders, with at least one community-based organization involved. Meetings shall include concrete opportunities for groups to provide meaningful input into plan design, mid-cycle changes, and evaluation throughout the year to help reduce litigation in future plan filings. All meetings must be accessible, with rotating locations, call-in options, and materials and agendas circulated well in advance. There shall also be opportunities for input outside of meetings from those with limited capacity and ability to attend, via one-on-one meetings, surveys, and calls. Meetings shall also include opportunities to bundle and coordinate low-income energy efficiency with Solar for All and energy assistance programs. Meetings shall include educational opportunities for stakeholders to learn more about these additional offerings, and the committee shall assist in the figuring out the best methods for coordinated delivery and implementation of offerings when serving low-income communities.

(g) At least 50% of the entire efficiency program portfolio budget shall be spent on efficiency measures that reduce the amount of space heating needs through improvements to the efficiency of building envelopes (including, but not limited to, insulation measures, efficient windows and air leakage reduction) or through improvements to systems for distributing heat (including, but not limited to, duct leakage reduction, duct insulation or pipe insulation) in buildings. Spending on efficient furnaces, efficient boilers, or other efficient heating systems is permitted within the efficiency program portfolio, but does not count toward this minimum requirement for spending on building envelope and heating distribution efficiencies. Spending on low-income building envelope measures or heating distribution system measures does count toward this requirement. The portion of portfolio spending on program marketing, training of installers, audits of buildings, inspections of work performed, and other administrative and technical expenses that are clearly tied to promotion or installation of building envelope or heating distribution system measures shall count toward this requirement. If this minimum requirement is not met, any performance incentive earned under paragraph (7) of subsection (j) should be reduced by the percentage point level of shortfall in meeting this requirement; if the utility is subject to a performance penalty, then the magnitude of the penalty shall be increased by the percentage point shortfall in meeting this requirement.

(h) Notwithstanding any other provision of law to the contrary, a utility providing approved energy efficiency measures in the State shall be permitted to recover all reasonable and prudently incurred costs of those measures from all retail customers, provided that nothing in this subsection (h) permits the double recovery of such costs from customers.

(i) Beginning in 2019, each gas 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 schedule set forth in paragraphs (1) through (5) of this subsection (i). 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.

(1) No later than 120 days after the effective date of this amendatory Act of the 101st General Assembly, each gas utility shall file an energy efficiency plan to supersede its previously filed energy efficiency plan for the year beginning January 1, 2020 that is designed to achieve the cumulative persisting annual savings goals specified in paragraphs (1) and (2) of subsection (d) of this Section through implementation of energy efficiency measures.

(2) No later March 1, 2021, each gas 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 (3) through (6) of subsection (d) of this Section through implementation of energy efficiency measures; however, the goals may be reduced if each of the following conditions are met: (A) the plan's analysis and forecasts of the utility's ability to acquire energy savings demonstrate beyond a reasonable doubt that achievement of such goals is not cost-effective; and (B) the amount of energy savings planned to be achieved by the utility in 2021, as documented pursuant to paragraph (1) of this subsection (i) and approved by the Illinois Commerce Commission, was less than the average annual amount of savings required to achieve the goals for the applicable 4-year plan period. Annual increases in cumulative persisting annual savings goals during the applicable 4-year plan period shall not be reduced to amounts that are less than the maximum amount of cumulative persisting annual savings that is forecast to be cost-effectively achievable during the 4-year plan period. The Commission shall review any proposed goal reduction as part of its review and approval of the utility's proposed plan, taking into account the results of the potential study required by subsection (j-5) of this Section.

(3) No later than March 1, 2025, each gas utility shall file a 4-year energy efficiency plan commencing on January 1, 2026 that is designed to achieve the cumulative persisting annual savings goals specified in paragraphs (7) through (10) of subsection (d) of this Section through implementation of energy efficiency measures; however, the goals may be reduced if each of the following conditions are met: (A) the plan's analysis and forecasts of the utility's ability to acquire energy savings demonstrate beyond a reasonable doubt that achievement of such goals is not cost-effective; and (B) the amount of energy savings achieved by the utility as determined by the independent evaluator for the most recent year for which savings have been evaluated preceding the plan filing was less than the average annual amount of savings required to achieve the goals for the applicable 4-year plan period. Annual increases in cumulative persisting annual savings goals during the applicable 4-year plan period shall not be reduced to amounts that are less than the maximum amount of cumulative persisting annual savings that is forecast to be cost-effectively achievable during the 4-year plan period. The Commission shall review any proposed goal reduction as part of its review and approval of the utility's proposed plan, taking into account the results of the potential study required by subsection (j-5) of this Section.

(4) No later than March 1, 2029, each gas utility shall file a 4-year energy efficiency plan commencing on January 1, 2030 that is designed to achieve the cumulative persisting annual savings goals specified in paragraphs (11) through (14) of subsection (d) of this Section through implementation of energy efficiency measures; however, the goals may be reduced if each of the following conditions are met: (A) the plan's analysis and forecasts of the utility's ability to acquire energy savings demonstrate beyond a reasonable doubt that achievement of such goals is not cost-effective; and (B) the amount of energy savings achieved by the utility as determined by the independent evaluator for the most recent year for which savings have been evaluated preceding the plan filing was less than the average annual amount of savings required to achieve the goals for the applicable 4-year plan period. Annual increases in cumulative persisting annual savings goals during the applicable 4-year plan period shall not be reduced to amounts that are less than the maximum amount of cumulative persisting annual savings that is forecast to be cost-effectively achievable during the 4-year plan period. The Commission shall review any proposed goal reduction as part of its review and approval of the utility's proposed plan, taking into account the results of the potential study required by subsection (j-5) of this Section.

(5) No later than March 1, beginning in 2033 and each 4 years afterwards, each gas utility shall file a 4-year energy efficiency plan commencing on January 1, beginning in 2034 and each 4-year period afterwards, that is designed to achieve the cumulative persisting annual savings goals established by the Illinois Commerce Commission pursuant to direction of subsection (d) of this Section, through implementation of energy efficiency measures; however, the goals may be reduced if each of the following conditions are met: (A) the plan's analysis and forecasts of the utility's ability to acquire energy savings demonstrate beyond a reasonable doubt that achievement of such goals is not cost-effective; and (B) the amount of energy savings achieved by the utility as determined by the independent evaluator for the most recent year for which savings have been evaluated preceding the plan filing was less than the average annual amount of savings required to achieve the goals for the applicable 4-year plan period. Annual increases in cumulative persisting annual savings goals during the applicable 4-year plan period shall not be reduced to amounts that are less than the maximum amount of cumulative persisting annual savings that is forecast to be cost-effectively achievable during the 4-year plan period. The Commission shall review any proposed goal reduction as part of its review and approval of the utility's proposed plan, taking into account the results of the potential study required by subsection (j-5) of this Section.

Each utility's plan shall set forth the utility's proposals to meet the energy efficiency standards identified in subsection (d). For those plans commencing on January 1, 2021, 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, 2020, or 105 days after the effective date of this amendatory Act of the 101st General Assembly, whichever is later. For those plans commencing after December 31, 2022, 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 measures. Penalties shall be deposited into the Energy Efficiency Trust Fund.

(j) In submitting proposed plans and funding levels under subsection (i) of this Section to meet the savings goals identified in subsection (d), the utility shall:

(1) Demonstrate that its proposed energy efficiency measures will achieve the applicable requirements that are identified in subsection (d) of this Section.

(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 (f) of this Section, is cost-effective using the total resource cost test, complies with subsection (i) of this Section and represents a diverse cross-section of opportunities for customers of all rate classes, to participate in the programs. Individual measures need not be cost effective.

(3.5) Demonstrate that the utility's plan integrates the delivery of energy efficiency programs with electric efficiency programs and other efforts to address bill payment issues, including, but not limited to, LIHEAP and the Percent Income Payment Plan, to the extent such integration is practical and has the potential to enhance customer engagement, minimize market confusion, or reduce administrative costs.

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

(A) Beginning with the year commencing January 1, 2021, gas utilities shall fund third-party energy efficiency programs in an amount that is no less than 10% of total efficiency portfolio budgets per year.

(B) For multi-year plans commencing on January 1, 2022, January 1, 2026, January 1, 2030, and every 4 years thereafter, the utility shall conduct a solicitation process during 2021, 2025, 2029, and every 4 years thereafter, 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; the solicitation process must be for programs that fill gaps in the utility's program portfolio or targets business sectors, building types, geographies or other specific parts of its customer base with initiatives that would be more effective at reaching these customer segments than the utilities' programs filed in its energy efficiency plans.

(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.

The gas utility shall recover all costs associated with Commission-approved, third-party administered programs regardless of the success of those programs.

(5) Include a proposed or revised cost-recovery mechanism, as provided for under subsection (h) of this Section, to fund the proposed energy efficiency 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) Each gas utility shall be eligible to earn a shareholder incentive for effective implementation of its efficiency programs. The incentive shall be tied to each utility's annual energy efficiency spending and its savings relative to its applicable annual total savings requirement as defined in paragraph (8) of this subsection (j). There shall be no incentive if the independent evaluator determines the utility failed to achieve savings equal to at least 75% of its applicable annual total savings requirement and an incentive equal 0.3% of total annual efficiency spending in the year being evaluated for every one percentage point above 75% of its applicable annual total savings requirement that the utility achieved in that year, with a maximum incentive of 15% for achieving 125% of its applicable annual total savings requirement.

(7.5) In this Section, "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 (d) of this Section. Under subsection (d) of this Section, a utility must first replace energy savings from measures that have reached the end of their measure lives and would otherwise have to be replaced to meet the applicable savings goals identified in subsection (d) of this Section before any progress toward achievement of its applicable annual incremental goal may be counted. Notwithstanding anything else set forth in this Section, the difference between the actual annual incremental savings achieved in any given year, including the replacement of energy savings from measures that have expired, and the applicable annual incremental goal shall not affect adjustments to the return on equity for subsequent calendar years under this subsection (j).

(8) In this Section, "Applicable Annual Total Savings Requirement" means the total amount of new annual savings that the utility must achieve in any given year to achieve the Applicable Annual Incremental Goal. This shall be equal to the Applicable Annual Incremental Savings Goal plus the total new annual savings that are required to replace savings from efficiency measures that provided cumulative persistent annual savings in the previous year but expired in or at the end of the previous year and are therefore no longer producing savings.

(9) 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 and the utility's performance relative to its Applicable Annual Total Savings Requirement for a given plan year no later than 120 days after the close of the plan year. The independent evaluator must also estimate the job impacts and other macroeconomic impacts of the utility's efficiency programs. 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, under paragraph (7) of this subsection (j), as applicable, the magnitude of any shareholder incentive which the utility has earned.

(10) Gas utilities shall report annually to the Illinois Commerce Commission and General Assembly on how hiring, contracting, job training, and other practices related to its energy efficiency programs enhance the diversity of vendors working on such programs. These reports must include data on vendor and employee diversity.

(j-5) Energy efficiency potential study. An energy efficiency potential study shall be commissioned and overseen by the Illinois Commerce Commission. The potential study shall be reviewed as part of the approval of a utility's plan filed pursuant to subsection (f) of this Section. The potential study shall be designed and conducted with input from a Potential Study Stakeholder Committee established by the Commission. This Committee shall be comprised of representatives from each electric utility, the Illinois Attorney General's office, at least 2 environmental stakeholders, at least one community-based organization, and additional parties representing consumers. The Committee shall provide input, at a minimum, into the scope of work for the studies, the selection of vendors to perform the studies in accordance with appropriate confidentiality and conflict of interest provisions, and draft work products. The Committee shall make best efforts to achieve consensus on the key elements of the potential study, including:

(i) savings potential from efficiency measures and program concepts that are known at the time of the study;

(ii) likely emergence of new technology or new program concepts that could emerge;

(iii) likely savings potential from efficiency measures that may be unique to individual industries or individual facilities; and

(iv) the experience of other similar utilities, areas and jurisdictions in maximizing achievement of cost-effective savings.

When the committee is not able to reach consensus, the Commission shall make the final decision.

(k) 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.

(l) When practical, gas utilities shall incorporate advanced metering infrastructure data into the planning, implementation, and evaluation of energy efficiency measures and programs, subject to the data privacy and confidentiality protections of applicable law.

(m) 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 measure life values for energy efficiency measures implemented for low-income households under subsection (f) of this Section are incorporated into such Commission-approved manuals, the low-income measures shall have the same measure life values that are established for same measures implemented in households that are not low-income households.

(220 ILCS 5/9-220.3)

(Section scheduled to be repealed on December 31, 2023)

Sec. 9-220.3. Natural gas surcharges authorized.

(a) Tariff.

(1) Pursuant to Section 9-201 of this Act, a natural gas utility serving more than 700,000 customers may file a tariff for a surcharge which adjusts rates and charges to provide for recovery of costs associated with investments in qualifying infrastructure plant, independent of any other matters related to the utility's revenue requirement.

(2) Within 30 days after the effective date of this amendatory Act of the 98th General Assembly, the Commission shall adopt emergency rules to implement the provisions of this amendatory Act of the 98th General Assembly. The utility may file with the Commission tariffs implementing the provisions of this amendatory Act of the 98th General Assembly after the effective date of the emergency rules authorized by subsection (i).

(3) The Commission shall issue an order approving, or approving with modification to ensure compliance with this Section, the tariff no later than 120 days after such filing of the tariffs filed pursuant to this Section. The utility shall have 7 days following the date of service of the order to notify the Commission in writing whether it will accept any modifications so identified in the order or whether it has elected not to proceed with the tariff. If the order includes no modifications or if the utility notifies the Commission that it will accept such modifications, the tariff shall take effect on the first day of the calendar year in which the Commission issues the order, subject to petitions for rehearing and appellate procedures. After the tariff takes effect, the utility may, upon 10 days' notice to the Commission, file to withdraw the tariff at any time, and the Commission shall approve such filing without suspension or hearing, subject to a final reconciliation as provided in subsection (e) of this Section.

(4) When a natural gas utility withdraws the surcharge tariff, the utility shall not recover any additional charges through the surcharge approved pursuant to this Section, subject to the resolution of the final reconciliation pursuant to subsection (e) of this Section. The utility's qualifying infrastructure investment net of accumulated depreciation may be transferred to the natural gas utility's rate base in the utility's next general rate case. The utility's delivery base rates in effect upon withdrawal of the surcharge tariff shall not be adjusted at the time the surcharge tariff is withdrawn.

(5) A natural gas utility that is subject to its delivery base rates being fixed at their current rates pursuant to a Commission order entered in Docket No. 11-0046, notwithstanding the effective date of its tariff authorized pursuant to this Section, shall reflect in a tariff surcharge only those projects placed in service after the fixed rate period of the merger agreement has expired by its terms.

(b) For purposes of this Section, "qualifying infrastructure plant" includes only plant additions placed in service not reflected in the rate base used to establish the utility's delivery base rates. "Costs associated with investments in qualifying infrastructure plant" shall include a return on qualifying infrastructure plant and recovery of depreciation and amortization expense on qualifying infrastructure plant, net of the depreciation included in the utility's base rates on any plant retired in conjunction with the installation of the qualifying infrastructure plant. Collectively the "qualifying infrastructure plant" and "costs associated with investments in qualifying infrastructure plant" are referred to as the "qualifying infrastructure investment" and that are related to one or more of the following:

(1) the installation of facilities to retire and replace underground natural gas facilities, including facilities appurtenant to facilities constructed of those materials such as meters, regulators, and services, and that are constructed of cast iron, wrought iron, ductile iron, unprotected coated steel, unprotected bare steel, mechanically coupled steel, copper, Cellulose Acetate Butyrate (CAB) plastic, pre-1973 DuPont Aldyl "A" polyethylene, PVC, or other types of materials identified by a State or federal governmental agency as being prone to leakage;

(2) the relocation of meters from inside customers' facilities to outside;

(3) the upgrading of the gas distribution system from a low pressure to a medium pressure system, including installation of high-pressure facilities to support the upgrade;

(4) modernization investments by a combination utility, as defined in subsection (b) of Section 16-108.5 of this Act, to install:

(A) advanced gas meters in connection with the installation of advanced electric meters pursuant to Sections 16-108.5 and 16-108.6 of this Act; and

(B) the communications hardware and software and associated system software that creates a network between advanced gas meters and utility business systems and allows the collection and distribution of gas-related information to customers and other parties in addition to providing information to the utility itself;

(5) replacing high-pressure transmission pipelines and associated facilities identified as having a higher risk of leakage or failure or installing or replacing high-pressure transmission pipelines and associated facilities to establish records and maximum allowable operating pressures;

(6) replacing difficult to locate mains and service pipes and associated facilities; and

(7) replacing or installing transmission and distribution regulator stations, regulators, valves, and associated facilities to establish over-pressure protection.

With respect to the installation of the facilities identified in paragraph (1) of subsection (b) of this Section, the natural gas utility shall determine priorities for such installation with consideration of projects either: (i) integral to a general government public facilities improvement program or (ii) ranked in the highest risk categories in the utility's most recent Distribution Integrity Management Plan where removal or replacement is the remedial measure.

(c) Qualifying infrastructure investment, defined in subsection (b) of this Section, recoverable through a tariff authorized by subsection (a) of this Section, shall not include costs or expenses incurred in the ordinary course of business for the ongoing or routine operations of the utility, including, but not limited to:

(1) operating and maintenance costs; and

(2) costs of facilities that are revenue-producing, which means facilities that are constructed or installed for the purpose of serving new customers.

(d) Gas utility commitments. A natural gas utility that has in effect a natural gas surcharge tariff pursuant to this Section shall:

(1) recognize that the General Assembly identifies improved public safety and reliability of natural gas facilities as the cornerstone upon which this Section is designed, and qualifying projects should be encouraged, selected, and prioritized based on these factors; and

(2) provide information to the Commission as requested to demonstrate that (i) the projects included in the tariff are indeed qualifying projects and (ii) the projects are selected and prioritized taking into account improved public safety and reliability.

(3) The amount of qualifying infrastructure investment eligible for recovery under the tariff in the applicable calendar year is limited to the lesser of (i) the actual qualifying infrastructure plant placed in service in the applicable calendar year and (ii) the difference by which total plant additions in the applicable calendar year exceed the baseline amount, and subject to the limitation in subsection (g) of this Section. A natural gas utility can recover the costs of qualifying infrastructure investments through an approved surcharge tariff from the beginning of each calendar year subject to the reconciliation initiated under paragraph (2) of subsection (e) of this Section, during which the Commission may make adjustments to ensure that the limits defined in this paragraph are not exceeded. Further, if total plant additions in a calendar year do not exceed the baseline amount in the applicable calendar year, the Commission, during the reconciliation initiated under paragraph (2) of subsection (e) of this Section for the applicable calendar year, shall adjust the amount of qualifying infrastructure investment eligible for recovery under the tariff to zero.

(4) For purposes of this Section, "baseline amount" means an amount equal to the utility's average of total depreciation expense, as reported on page 336, column (b) of the utility's ILCC Form 21, for the calendar years 2006 through 2010.

(e) Review of investment.

(1) The amount of qualifying infrastructure investment shall be shown on an Information Sheet supplemental to the surcharge tariff and filed with the Commission monthly or some other time period at the option of the utility. The Information Sheet shall be accompanied by data showing the calculation of the qualifying infrastructure investment adjustment. Unless otherwise ordered by the Commission, each qualifying infrastructure investment adjustment shown on an Information Sheet shall become effective pursuant to the utility's approved tariffs.

(2) For each calendar year in which a surcharge tariff is in effect, the natural gas utility shall file a petition with the Commission to initiate hearings to reconcile amounts billed under each surcharge authorized pursuant to this Section with the actual prudently incurred costs recoverable under this tariff in the preceding year. The petition filed by the natural gas utility shall include testimony and schedules that support the accuracy and the prudence of the qualifying infrastructure investment for the calendar year being reconciled. The petition filed shall also include the number of jobs attributable to the natural gas surcharge tariff as required by rule. The review of the utility's investment shall include identification and review of all plant that was ranked within the highest risk categories in that utility's most recent Distribution Integrity Management Plan.

(f) The rate of return applied shall be the overall rate of return authorized by the Commission in the utility's last gas rate case.

(g) The cumulative amount of increases billed under the surcharge, since the utility's most recent delivery service rate order, shall not exceed an annual average 4% of the utility's delivery base rate revenues, but shall not exceed 5.5% in any given year. On the effective date of new delivery base rates, the surcharge shall be reduced to zero with respect to qualifying infrastructure investment that is transferred to the rate base used to establish the utility's delivery base rates, provided that the utility may continue to charge or refund any reconciliation adjustment determined pursuant to subsection (e) of this Section.

(h) If a gas utility obtains a surcharge tariff under this Section 9-220.3, then it and its affiliates are excused from the rate case filing requirements contained in Sections 9-220(h) and 9-220(h-1). In the event a natural gas utility, prior to the effective date of this amendatory Act of the 98th General Assembly, made a rate case filing that is still pending on the effective date of this amendatory Act of the 98th General Assembly, the natural gas utility may, at the time it files its surcharge tariff with the Commission, also file a notice with the Commission to withdraw its rate case filing. Any affiliate of such natural gas utility may also file to withdraw its rate case filing. Upon receipt of such notice, the Commission shall dismiss the rate case filing with prejudice and such tariffs and the record related thereto shall not be the subject of any further hearing, investigation, or proceeding of any kind related to rates for gas delivery services. Notwithstanding the foregoing, a natural gas utility shall not be permitted to withdraw a rate case filing for which a proposed order recommending a rate reduction is pending. A natural gas utility shall not be permitted to withdraw the gas delivery services tariffs that are the subject of Commission Docket Nos. 12-0511/12-0512 (cons.). None of the costs incurred for the withdrawn rate case are recoverable from ratepayers.

(i) The Commission shall promulgate rules and regulations to carry out the provisions of this Section under the emergency rulemaking provisions set forth in Section 5-45 of the Illinois Administrative Procedure Act, and such emergency rules shall be effective no later than 30 days after the effective date of this amendatory Act of the 98th General Assembly.

(j) Utilities that have elected to recover qualifying infrastructure investment costs pursuant to this Section shall file annually their Distribution Integrity Management Plan (DIMP) with the Commission no later than June 1 of each year the utility has said tariff in effect. The DIMP shall include the following information:

(1) Baseline Distribution System Data: Information such as demand, system pressures and flows, and metering infrastructure.

(2) Financial Data: historical and projected spending on distribution system infrastructure.

(3) Scenario Analysis: Discussion of projected changes in usage over time.

(4) Descriptions of all qualifying infrastructure investment proposed for the coming year.

(k) Within 45 days after filing, the Commission shall, with reasonable notice, open an investigation to consider whether the Plan meets the objectives set forth in this subsection and contains the information required by subsection (j). The Commission shall issue a final order approving the Plan, with any modifications the Commission deems reasonable and appropriate to achieve the goals of this Section, within 270 days of the Plan filing. The investigation will assess whether the DIMP:

(1) ensures optimized utilization of utility infrastructure assets and resources to minimize total system costs;

(2) enables greater customer engagement, empowerment, and options for services;

(3) to the maximum extent possible, achieves and or supports the achievement of greenhouse gas emissions reductions as described by Section 9.10 of the Environmental Protection Act; and

(4) supports existing Illinois policy goals promoting energy efficiency.

The Commission process shall maximize the sharing of information, ensure robust stakeholder participation, and recognize the responsibility of the utility to ultimately manage the grid in a safe, reliable manner.

(l) (j) This Section is repealed December 31, 2023.

(Source: P.A. 98-57, eff. 7-5-13.)

(220 ILCS 5/16-107)

Sec. 16-107. Real-time pricing.

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

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

(b-5) Each electric utility shall file a tariff or tariffs allowing residential retail customers in the electric utility's service area to elect real-time pricing beginning January 2, 2007. The Commission may, after notice and hearing, approve the tariff or tariffs. 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 under 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 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.

(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.

(e) Eligible customers shall include, but are not limited to, customers participating in net electricity metering under the terms of Section 16-107.5 of this Act.

(Source: P.A. 99-906, eff. 6-1-17.)

(220 ILCS 5/16-107.5)

Sec. 16-107.5. Net electricity metering.

(a) The General Assembly 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. The General Assembly further finds and declares that ensuring a smooth, predictable transition from full net metering of the retail electricity rate to the distributed generation rebate described in Section 16-107.6 of this Act is important to achieve these legislative goals. In implementing this transition, the Commission shall ensure that distributed generation customers are fairly compensated for the benefits and services that customer-sited distributed generation provides and that the distributed generation market in Illinois continues to experience stable growth for both small and large customers.

(b) As used in this Section, (i) "community renewable generation project" shall have the meaning set forth in Section 1-10 of the Illinois Power Agency Act; (ii) "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; (iii) "electricity provider" means an electric utility or alternative retail electric supplier; (iv) "eligible renewable electrical generating facility" means a generator that is interconnected under rules adopted by the Commission 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; (v) "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 or subscriber; (vi) "subscriber" shall have the meaning as set forth in Section 1-10 of the Illinois Power Agency Act; and (vii) "subscription" shall have the meaning set forth in Section 1-10 of the Illinois Power Agency Act.

(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, which may be the smart meter described by subsection (b) of Section 16-108.5 of this Act.

(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, which may be the smart meter described by subsection (b) of Section 16-108.5 of this Act.

(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 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 hourly or 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 hourly or 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.

(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. After such time as the load of the electricity provider's net metering customers equals 5% of the total peak demand supplied by that electricity provider during the previous year and after the effective date of the distributed generation rebate tariffs prescribed by subsection (e) of Section 16-107.6 of this Act, eligible customers that begin taking net metering shall only be eligible for netting of energy.

(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.

(l)(1) Notwithstanding the definition of "eligible customer" in item (ii) of subsection (b) of this Section, each electricity provider shall allow net metering as set forth in this subsection (l) and for the following projects:

(A) 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 200 watts in such 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, provided that the facility is also located within the utility's service territory;

(B) 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; and

(C) subscriptions to community renewable generation projects.

In addition, the nameplate capacity of the eligible renewable electric generating facility that serves the demand of the properties, units, or apartments identified in paragraphs (1) and (2) of this subsection (l) shall not exceed 2,000 kilowatts in nameplate capacity in total. Any eligible renewable electrical generating facility or community renewable generation project that is powered by photovoltaic electric energy and installed after the effective date of this amendatory Act of the 99th General Assembly must be installed by a qualified person in compliance with the requirements of Section 16-128A of the Public Utilities Act and any rules or regulations adopted thereunder.

(2) Notwithstanding anything to the contrary, an electricity provider shall provide credits for the electricity produced by the projects described in paragraph (1) of this subsection (l). The electricity provider shall provide credits at the subscriber's energy supply rate on the subscriber's monthly bill equal to the subscriber's share of the production of electricity from the project, as determined by paragraph (3) of this subsection (l).

(3) For the purposes of facilitating net metering, the owner or operator of the eligible renewable electrical generating facility or community renewable generation project shall be responsible for determining the amount of the credit that each customer or subscriber participating in a project under this subsection (l) is to receive in the following manner:

(A) The owner or operator shall, on a monthly basis, provide to the electric utility the kilowatthours of generation attributable to each of the utility's retail customers and subscribers participating in projects under this subsection (l) in accordance with the customer's or subscriber's share of the eligible renewable electric generating facility's or community renewable generation project's output of power and energy for such month. The owner or operator shall electronically transmit such calculations and associated documentation to the electric utility, in a format or method set forth in the applicable tariff, on a monthly basis so that the electric utility can reflect the monetary credits on customers' and subscribers' electric utility bills. The electric utility 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 electric utility with the documentation detailing the calculations supporting the credit in the manner set forth in the applicable tariff.

(B) For those participating customers and subscribers who receive their energy supply from an alternative retail electric supplier, the electric utility shall remit to the applicable alternative retail electric supplier the information provided under subparagraph (A) of this paragraph (3) for such customers and subscribers in a manner set forth in such alternative retail electric supplier's net metering program, or as otherwise agreed between the utility and the alternative retail electric supplier. The alternative retail electric supplier shall then submit to the utility the amount of the charges for power and energy to be applied to such customers and subscribers, including the amount of the credit associated with net metering.

(C) A participating customer or subscriber may provide authorization as required by applicable law that directs the electric utility to submit information to the owner or operator of the eligible renewable electrical generating facility or community renewable generation project to which the customer or subscriber has an ownership or leasehold interest or a subscription. Such information shall be limited to the components of the net metering credit calculated under this subsection (l), including the bill credit rate, total kilowatthours, and total monetary credit value applied to the customer's or subscriber's bill for the monthly billing period.

(l-5) Within 90 days after the effective date of this amendatory Act of the 99th General Assembly, each electric utility subject to this Section shall file a tariff to implement the provisions of subsection (l) of this Section, which shall, consistent with the provisions of subsection (l), describe the terms and conditions under which owners or operators of qualifying properties, units, or apartments may participate in net metering. The Commission shall approve, or approve with modification, the tariff within 120 days after the effective date of this amendatory Act of the 99th General Assembly.

(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.

(n) At such time, if any, that the load of the electricity provider's net metering customers equals 5% of the total peak demand supplied by that electricity provider during the previous year, as specified in subsection (j) of this Section, the net metering services described in subsections (d), (d-5), (e), (e-5), and (f) of this Section shall no longer be offered, except as to those retail customers that are receiving net metering service under these subsections at the time the net metering services under those subsections are no longer offered. Those retail customers that begin taking net metering service after the date that net metering services are no longer offered under such subsections shall be subject to the provisions set forth in the following paragraphs (1) through (3) of this subsection (n):

(1) An electricity provider shall charge or credit for the net electricity supplied to eligible customers or provided by eligible customers whose electric supply service is not provided based on hourly pricing in the following manner:

(A) 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 paragraph (3) of this subsection (n).

(B) 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 energy credit that reflects the kilowatt-hour based energy 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 energy 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.

(C) 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.

(2) An electricity provider shall charge or credit for the net electricity supplied to eligible customers or provided by eligible customers whose electric supply service is provided based on hourly pricing in the following manner:

(A) If the amount of electricity used by the customer during any hourly 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 paragraph (3) of this subsection (n).

(B) 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 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 period.

(3) 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 charge or credit that the customer receives for net electricity shall be at a rate equal to the customer's energy supply rate. The customer remains responsible for the gross amount of delivery services charges, supply-related charges that are kilowatt based, and 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. Paragraphs (1) and (2) of this subsection (n) 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 paragraph (3) 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.

(Source: P.A. 99-906, eff. 6-1-17.)

(220 ILCS 5/16-107.6)

Sec. 16-107.6. 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.

"Distribution system reliability event" means when, for standard service voltage, voltage variations are measured at any customer's point of delivery above a maximum of 127 volts or below a minimum of 113 volts for periods longer than 2 minutes in each instance.

"Subscriber" has the meaning set forth in Section 1-10 of the Illinois Power Agency Act.

"Subscription" has the meaning set forth in Section 1-10 of the Illinois Power Agency Act.

"Threshold date" means the date on which the load of an electricity provider's net metering customers equals 5% of the total peak demand supplied by that electricity provider during the previous year, as specified under subsection (j) of Section 16-107.5 of this Act.

(b) An electric utility that serves more than 200,000 customers in the State shall 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 primarily used to offset that customer's electricity load;

(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 interconnected under rules adopted by the Commission by means of the inverter or smart inverter required by this Section, as applicable.

For purposes of this Section, "distributed generation" shall satisfy the definition of distributed renewable energy generation device set forth in Section 1-10 of the Illinois Power Agency Act to the extent such definition is consistent with the requirements of this Section.

In addition, any new photovoltaic distributed generation that is installed after the effective date of this amendatory Act of the 99th General Assembly must be installed by a qualified person, as defined by subsection (i) of Section 1-56 of the Illinois Power Agency Act.

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 for the purpose of preserving reliability during distribution system reliability events and shall address the terms and conditions of the operation and the compensation associated with the operation. Nothing in this Section shall negate or supersede Institute of Electrical and Electronics Engineers interconnection requirements or standards or other similar standards or requirements. The tariff shall also provide for additional uses of the smart inverter that shall be separately compensated and which may include, but are not limited to, voltage and VAR support, regulation, and other grid services. As part of the proceeding described in subsection (e) of this Section, the Commission shall review and determine whether smart inverters can provide any additional uses or services. If the Commission determines that an additional use or service would be beneficial, the Commission shall determine the terms and conditions of the operation and how the use or service should be separately compensated.

(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 under this Section for distributed generation that satisfies the criteria set forth in subsection (b) of this Section:

(1) Until the utility files its tariff or tariffs to place into effect the rebate values established by the Commission under subsection (e) of this Section, non-residential customers that are taking service under a net metering program offered by an electricity provider under the terms of Section 16-107.5 of this Act may apply for a rebate as provided for in this Section. The value of the rebate shall be $250 per kilowatt of nameplate generating capacity, measured as nominal DC power output, of a non-residential customer's distributed generation.

(2) After the utility's tariff or tariffs setting the new rebate values established under subsection (d) of this Section take effect, retail customers may, as applicable, make the following elections:

(A) Residential customers that are taking service under a net metering program offered by an electricity provider under the terms of Section 16-107.5 of this Act on the threshold date may elect to either continue to take such service under the terms of such program as in effect on such threshold 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 under the terms of this Section, provided that such application must be submitted within 6 months after the effective date of the tariff approved under subsection (d) of this Section. The value of the rebate shall be the amount established by the Commission and reflected in the utility's tariff pursuant to subsection (e) of this Section.

(B) Non-residential customers that are taking service under a net metering program offered by an electricity provider under the terms of Section 16-107.5 of this Act on the threshold date may apply for a rebate as provided for in this Section. The value of the rebate shall be the amount established by the Commission and reflected in the utility's tariff pursuant to subsection (e) of this Section.

(3) Upon approval of a rebate application submitted under this subsection (c), the retail customer shall no longer be entitled to receive any delivery service credits for the excess electricity generated by its facility and shall be subject to the provisions of subsection (n) of Section 16-107.5 of this Act.

(4) To be eligible for a rebate described in this subsection (c), customers who begin taking service after the effective date of this amendatory Act of the 99th General Assembly under a net metering program offered by an electricity provider under the terms of Section 16-107.5 of this Act must have a smart inverter associated with the customer's distributed generation.

(d) The Commission shall review the proposed tariff submitted under subsections (b) and (c) of this Section and may make changes to the tariff that are consistent with this Section and with the Commission's authority under Article IX of this Act, subject to notice and hearing. Following notice and hearing, the Commission shall issue an order approving, or approving with modification, such tariff no later than 240 days after the utility files its tariff.

(e) When the total generating capacity of the electricity provider's net metering customers is equal to 3%, the Commission shall open an investigation into an annual process and formula for calculating the value of rebates for the retail customers described in subsections (b) and (f) of this Section that submit rebate applications after the threshold date for an electric utility that elected to file a tariff pursuant to this Section. The investigation shall include diverse sets of stakeholders, calculations for valuing distributed energy resource benefits to the grid based on best practices, and assessments of present and future technological capabilities of distributed energy resources. The value of such rebates shall reflect the value of the distributed generation to the distribution system at the location at which it is interconnected, taking into account the geographic, time-based, and performance-based benefits, as well as technological capabilities and present and future grid needs. The approved tariff shall provide for volumetric-based cost recovery. The Commission shall assign a higher value for rebates for distributed generation co-located with appropriately-sized energy storage systems that reflect the additional values that energy storage can provide to the energy system. The Commission shall assign an additional value for distributed generation that is co-located or in close proximity to electric vehicle charging infrastructure that is part of a managed charging or time-of-use program, or other beneficial electrification program, as described in Section 16-107.8 of this Act, reflecting the value of the additional benefits created by locating the project near and supporting the adoption of electric vehicle infrastructure that is helping reduce pollution from the transportation sector. No later than 10 days after the Commission enters its final order under this subsection (e), the utility shall file its tariff or tariffs in compliance with the order, and the Commission shall approve, or approve with modification, the tariff or tariffs within 45 days after the utility's filing. For those rebate applications filed after the threshold date but before the utility's tariff or tariffs filed pursuant to this subsection (e) take effect, the value of the rebate shall remain at the value established in subsection (c) of this Section until the tariff is approved. As part of the annual process, the Commission shall ensure that the distributed generation rebate results in stable growth for both small and large distributed generation customers in Illinois as provided in subsection (j) of Section 16-107.5 of this Act, with particular attention to impacts for residential customers.

(f) Notwithstanding any provision of this Act to the contrary, the owner, developer, or subscriber of a generation facility that is part of a net metering program provided under subsection (l) of Section 16-107.5 shall also be eligible to apply for the rebate described in this Section. A subscriber to the generation facility may apply for a rebate in the amount of the subscriber's subscription only if the owner, developer, or previous subscriber to the same panel or panels has not already submitted an application, and, regardless of whether the subscriber is a residential or non-residential customer, may be allowed the amount identified in paragraph (1) of subsection (c) or in subsection (e) of this Section applicable to such customer on the date that the application is submitted. An application for a rebate for a portion of a project described in this subsection (f) may be submitted at or after the time that a related request for net metering is made.

(g) No later than 60 days after the utility receives an application for a rebate under its tariff approved under subsection (d) or (e) of this Section, the utility shall issue a rebate to the applicant under the terms of the tariff. In the event the application is incomplete or the utility is otherwise unable to calculate the payment based on the information provided by the owner, the utility shall issue the payment no later than 60 days after the application is complete or all requested information is received.

(h) An electric utility shall recover from its retail customers all of the costs of the rebates made under a tariff or tariffs placed into effect under this Section, including, but not limited to, the value of the rebates and all costs incurred by the utility to comply with and implement this Section, consistent with the following provisions:

(1) The utility shall defer the full amount of its costs incurred under this Section as a regulatory asset. The total costs deferred as a regulatory asset shall be amortized over a 15-year period. 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 balance of the regulatory assets, less any deferred taxes related to the unamortized balance, 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 (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.

When an electric utility creates a regulatory asset under 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 under the provisions of this Section shall recover all of the associated costs, including, but not limited to, its cost of capital 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. To enable the financing of the incremental capital expenditures, including regulatory assets, for electric utilities that serve less than 3,000,000 retail customers but more than 500,000 retail customers in the State, the utility's actual year-end capital structure that includes a common equity ratio, excluding goodwill, of up to and including 50% of the total capital structure shall be deemed reasonable and used to set rates.

(2) The utility, at its election, may recover all of the costs it incurs under this Section as part of a filing for a general increase in rates under Article IX of this Act, as part of an annual filing to update a performance-based formula rate under subsection (d) of Section 16-108.5 of this Act, or through an automatic adjustment clause tariff, provided that nothing in this paragraph (2) permits the double recovery of such costs from customers. If the utility elects to recover the costs it incurs under this Section through an automatic adjustment clause tariff, the utility may file its proposed tariff together with the tariff it files under subsection (b) of this Section or at a later time. The proposed tariff shall provide for an annual reconciliation, 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 as calculated under paragraph (1) of this subsection (h), 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 revenue requirement reflected in rates for each calendar year, beginning with the calendar year in which the utility files its automatic adjustment clause tariff under this subsection (h), 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 Commission shall review the proposed tariff and may make changes to the tariff that are consistent with this Section and with the Commission's authority under Article IX of this Act, subject to notice and hearing. Following notice and hearing, the Commission shall issue an order approving, or approving with modification, such tariff no later than 240 days after the utility files its tariff.

(i) No later than 90 days after the Commission enters an order, or order on rehearing, whichever is later, approving an electric utility's proposed tariff under subsection (d) of this Section, the electric utility shall provide notice of the availability of rebates under this Section. Subsequent to the utility's notice, any entity that offers in the State, for sale or lease, distributed generation and estimates the dollar saving attributable to such distributed generation shall provide estimates based on both delivery service credits and the rebates available under this Section.

(Source: P.A. 99-906, eff. 6-1-17.)

(220 ILCS 5/16-107.7 new)

Sec. 16-107.7. Residential time-of-use pricing.

(a) The General Assembly finds and declares that a time of use pricing plan can reduce costs to the grid, create jobs, lower energy costs for customers, and help Illinois achieve its energy policy goals by improving load shape, encouraging energy conservation, and shifting usage away from periods where fossil fuels are used to meet peak demand. Further, by providing to consumers information that ties the cost of service to the timing of energy use, time-of-use rates give customers the opportunity to reduce their energy bills by using electricity when it is less costly. Time-of-use rates can help allocate electricity system costs more accurately and thus equitably to those who cause costs. Such rates can also reduce the need for ramping resources and, therefore, increase the grid's ability to integrate greater quantities of variable renewable energy and distributed energy resources.

(b) An electric utility that has a tariff in effect under Section 16-108.5 as of the effective date of this amendatory Act of the 101st General Assembly 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 the effective date of this amendatory Act of the 101st General Assembly. The utility shall implement the requirements of this paragraph by filing a tariff with the Commission, which shall be subject to the following provisions:

(1) The tariff shall include 3 time blocks: a peak time block defined as 3 p.m. to 7 p.m. on non-holiday weekdays, an off-peak time block defined as 10 a.m. to 3 p.m. and 7 p.m. to 10 p.m. on non-holiday weekdays, and a super-off-peak time block defined as all other hours.

(2) The tariff shall create price ratios between the blocks as follows: the super-off-peak time block price shall be no less than zero but no greater than one-half of the price of the off-peak time block price, and the off-peak time block price shall be no greater than one-half of the price of the peak time block price.

(3) Notwithstanding the requirements of Section 16-103.3 of this Act, the time-of-use rate shall include 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 January 1, 2019, within the prices for each time block and seasonal block in which the associated costs generally are incurred. If the Open Access Transmission Tariff subsequently renames those terms, the services reflected under those terms shall continue to be included in the time-of-use rate described in this paragraph (2).

(4) Adjustments to the charges set by the tariff may be made on a semi-annual basis, as follows: each May and November, the utility shall submit to the Commission, through an informational filing, its updated charges, and such charges shall take effect beginning with the June monthly billing period and December monthly billing period, respectively.

(5) The tariff shall include a purchased energy adjustment to fully recover the supply costs for the customers taking service under this tariff.

"Eligible customers" includes, but is not limited to, customers participating in net electricity metering under the terms of Section 16-107.5 of this Act.

(c) The Commission shall, after notice and hearing, approve the tariff or tariffs with modifications the Commission finds necessary to improve the program design, customer participation in the program, or coordination with existing utility pricing programs, energy efficiency programs, demand response programs, and any other programs supporting Illinois energy policy goals and the integration of distributed energy resources. A proceeding under this subsection may not exceed 120 days in length.

(d) If the Commission issues an order pursuant to this subsection, 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 time-of-use 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 the program, 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 this Section. 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 website.

(e) Once the tariff or tariffs has been in effect for 24 months, the Commission may, upon complaint, petition, or its own initiative, open a proceeding to investigate whether changes or modifications to the tariff or tariffs, program administration and any other program design element is necessary to achieve the goals described in subsection (a) of this Section. Such a proceeding may not last more than 120 days from the date upon which the investigation is opened by Commission order.

(f) 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.

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

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

(220 ILCS 5/16-107.8 new)

Sec. 16-107.8. Beneficial electrification.

(a) The purpose of this Section is to decrease reliance on fossil fuels and to ensure that electric vehicle adoption and increased electricity usage demand do not place significant additional burdens on the electric distribution system.

(b) In this Section, "managed charging program" means a program whereby owners of electric vehicles connect their charging infrastructure to a network or software that has the ability to manage the time and level of charge based on the electric distribution grid's current demand, market rates, or availability of clean energy generation. "Managed charging program" includes a program under which owners of electric vehicles participate in a dynamic rate program, such as a time-of-use, hourly or other program under which rates vary based on time, which is designed to incent vehicle charging at times of lower demand, increased clean energy generation, or efficient use of the electric distribution grid.

(c) Within 120 days after the effective date of this amendatory Act of the 101st General Assembly, the Illinois Commerce Commission shall initiate a process whereby the Commission shall develop a forward-looking plan for strategically increasing transportation electrification in the State. The process shall be open and transparent with inclusion of stakeholder interests, including stakeholders representing environmental justice interests. This process shall conclude within 270 days of opening. The plan shall incentivize transportation electrification through beneficial electrification programs, as described in subsection (d), taking into consideration incentives available through the Department of Commerce and Economic Opportunity and other sources. The plan may include specific directives for public utilities in the State that enable transportation electrification or beneficial electrification. The plan should specifically address environmental justice interests and should provide opportunities for residents and businesses in environmental justice communities to directly benefit from transportation electrification.

(d) Beneficial electrification programs, as described elsewhere in this Act and in the Electric Vehicle Act, shall be defined as programs which replace fossil fuel use and improve electric grid operation. Programs should provide for incentives such that customers are encouraged to use electricity at times of low overall system usage or at times when generation from renewable energy sources is high. Programs that qualify as "beneficial electrification programs" include:

(1) time-of-use rates under Section 16-107.7;

(2) hourly pricing rates;

(3) managed charging programs;

(4) electric vehicle-to-grid;

(5) demand response;

(6) renewable energy generation located in close proximity to the intended energy user; and

(7) other such programs as defined by the Commission in the stakeholder process described in subsection (b).

(220 ILCS 5/16-108.9 new)

Sec. 16-108.9. Clean Energy Empowerment Zone pilot projects.

(a) The General Assembly finds that it is important to support the rapid transition in the energy sector to put Illinois on a path to 100% renewable energy. This will require leveraging new technologies and solutions to support grid reliability to address issues such as the shift from large, centralized, fossil generation to wind, solar, and distributed energy resources. To that end, the General Assembly sees the need for developing pilot projects in Clean Energy Empowerment Zones that enhance reliability while facilitating the transition towards clean energy.

(b) An electric utility serving more than 100,000 retail customers may propose one or more Clean Energy Empowerment Zone pilot projects to the Illinois Commerce Commission to conduct a competitive procurement for independently-owned energy storage systems to be located in Clean Energy Empowerment Zones. The Commission shall evaluate the projects based on their ability to address present and future reliability needs identified by the Midcontinent Independent System Operator, PJM Interconnection, electric utilities, or independent analysts. In addition to supporting reliability, a qualifying project must support the transition towards or development of clean energy.

(c) The Clean Energy Empowerment Zones described in this Section shall be the same as defined by the Department of Commerce and Economic Opportunity in the Clean Energy Empowerment Zones Act.

(d) The Clean Energy Empowerment Zone pilot projects shall closely coordinate with actual and expected development of new wind projects and new solar projects as described in Section 1-75 of the Illinois Power Agency Act, electric vehicle adopted, and Community Energy and Climate Plans as defined in the Community Energy and Climate Planning Act.

(e) Upon approval of a Clean Energy Empowerment Zone pilot project by the Illinois Commerce Commission, an electric utility is authorized to enter into a distribution services contract with new energy storage system projects in accordance with the approved project. Nothing in this Section or in the distribution services contract shall preclude the energy storage project from providing additional wholesale market services.

(f) An electric utility that elects to undertake the investment described in subsection (b) of this Section may, at its election, recover the costs of such investment through an automatic adjustment clause tariff or through a delivery services charge regardless of how the costs are classified on the utility's books and records of account.

(g) To the extent feasible and consistent with State and federal law, the investments made pursuant to this Section shall provide employment opportunities for former workers in fossil fuel industries and participants in the Clean Jobs Workforce Hubs as defined in the Clean Jobs Workforce Hubs Act.

(h) Nothing in this Section is intended to limit the ability of any other entity to develop, construct, or install an energy storage system. In addition, nothing in this Section is intended to limit or alter otherwise applicable interconnection requirements.

(220 ILCS 5/16-108.13 new)

Sec. 16-108.13. Clean Jobs Workforce Hubs.

(a) An electric utility that serves more than 3,000,000 customers in the State shall spend $25,000,000 per year beginning January 1, 2020 to fund the programs across the State associated with Clean Jobs Workforce Hubs as described in the Clean Jobs Workforce Hubs Act and in this Section. The utility shall invest in a network of frontline organizations that provide direct and sustained support for members of economically disadvantaged communities, environmental justice communities, communities of color, returning citizens, foster care communities, and displaced fossil fuel workers to enter and complete the pipeline for clean energy jobs in solar energy, wind energy, energy efficiency, electric vehicles, and related industries.

(b) Within 60 days after the effective date of this amendatory Act of the 101st General Assembly, and after a comprehensive stakeholder process that includes representatives from frontline communities, the Illinois Commerce Commission shall select an individual or an organization to be the program administrator to coordinate the work of all or a portion of the work of the Clean Jobs Workforce Hubs.

(c) Within 120 Days after the effective date of this amendatory Act of the 101st General Assembly, and after a comprehensive stakeholder process led by the program administrator that includes representatives from frontline communities, an electric utility that serves more than 3,000,000 customers in the State shall file with the Commission a plan developed by the program administrator to implement this Section. Within 60 days after the plan is filed, the Commission shall enter an order approving the plan if it is consistent with this Section or, if the plan is not consistent with this Section, the Commission shall explain the deficiencies, after which time the utility shall file a new plan developed by the program administrator to address the deficiencies.

(220 ILCS 5/16-108.17 new)

Sec. 16-108.17. Distribution system planning.

(a) It is the policy of the State of Illinois to promote cost-effective distribution system planning that minimizes long-term costs for Illinois customers and supports the achievement of State carbon reduction and energy policy goals.

The General Assembly makes the following findings:

(1) Investment in infrastructure to support existing and new distributed energy resources creates significant economic development, environmental and public health benefits in the State of Illinois.

(2) Distribution system planning is an important tool for the Commission, electric utilities, and stakeholders to identify and support opportunities to maintain and enhance the safety, security, reliability, and resilience of the electricity grid, at fair and reasonable costs, consistent with the state's energy policies.

(3) A distribution system planning process can minimize distribution system costs to consumers while advancing other Illinois energy policy goals by supporting integration of distributed energy resources and the procurement of non-wires alternatives to capital investments.

(4) The planning process should maximize the sharing of information, minimize overlap with existing filing requirements to ensure robust stakeholder participation, and recognize the responsibility of the utility to ultimately manage the grid in a safe, reliable manner.

(b) Terms used in this Section shall have the same meanings as defined in Sections 16-102, 16-107.6, and 16-108.

(c) An electric utility serving more than 100,000 customers on January 1, 2009 shall prepare and file a distribution system investment plan no later than June 1, 2020. Within 45 days after the filing, the Commission shall, with reasonable notice, open an investigation to consider whether the plan meets the objectives defined in subsection (d) and contains the information required by subsection (e). The Commission shall issue a final order approving the plan, with any modifications the Commission deems reasonable and appropriate to achieve the goals of this Section, within 270 days of the plan filing. The final approved plan shall be part of the record used in the Commission proceeding referenced in subsection (e) of Section 16-107.6, provided that investigation has not been completed prior to the initial filing date referenced in this subsection (c).

(d) The plan shall be designed to:

(1) ensure optimized utilization of electricity grid assets and resources to minimize total system costs;

(2) enable greater customer engagement, empowerment, and options for energy services;

(3) move toward the creation of efficient, cost-effective, accessible grid platforms for new products, new services, and opportunities for adoption of new distributed technologies;

(4) bring the benefits of grid modernization and the deployment of distributed energy resources to all communities, including economically disadvantaged communities, throughout Illinois;

(5) reduce grid congestion to facilitate availability and development of distributed energy resources;

(6) provide for the analysis of the cost-effectiveness of proposed system investments;

(7) to the maximum extent possible, achieve or support the achievement of greenhouse gas emissions as defined in Section 9.10 of the Environmental Protection Act; and

(8) support existing Illinois policy goals promoting the steady long-term growth of energy efficiency, demand response and investments in renewable energy resources.

(e) The plan shall contain the following information:

(1) Distribution system planning processes: A description of the utility's distribution system planning process, including:

(A) the overview of the process, including frequency and duration of the process, roles and responsibilities of individuals and organizations involved;

(B) the description of internal organizational alignment of the process with other internal planning processes; and

(C) the description of process alignment with any other external planning process, such as those required by a regional transmission operator.

(2) Baseline distribution system data: A discussion detailing the current operating conditions for the distribution utility system, including a detailed description, with supporting data, of system conditions, including asset age and useful life, ratings, loadings, and other characteristics, as well as:

(A) distribution system annual loss percentage for the prior year (average of 12 monthly loss percentages);

(B) the maximum hourly coincident load (kW) for the distribution system as measured at the interface between the transmission and distribution system;

(C) total distribution substation capacity in kVA;

(D) total distribution transformer capacity in kVA;

(E) total miles of overhead distribution wire;

(F) total miles of underground distribution wire;

(G) a list of all high-voltage and low-voltage substations, or circuits, along with the following for each substation: nameplate rating; firm capacity (or max desired peak demand given contingency or redundancies desired); maximum historic peak demand, including specific day and hours of the day which peak load was experienced; average annual peak load growth over the previous 5 years; forecast annual peak load growth over the next 10 years; types of monitoring and control capabilities, or planned additions of such; a summary of existing system visibility and measurement (feeder-level and time) interval and planned visibility improvements; include information on percentage of the system with each level of visibility (such as max/min, daytime/nighttime, monthly/daily reads, automated/manual); and number of customer meters with advanced metering infrastructure/smart meters and those without, planned advanced metering infrastructure investments, and overview of functionality available; and

(H) discussion of how IEEE Std. 1547-2018 impacts distribution system planning considerations (e.g. opportunities and constraints related to interoperability).

(3) Financial data.

(A) historical distribution system spending for the past 5 years, in each category: age-related replacements and asset renewal; system expansion or upgrades for capacity; system expansion or upgrades for reliability and power quality; and

(B) projected distribution system spending for 10 years into the future for the categories listed in paragraph (1), itemizing any non-traditional distribution projects, including: planned distribution capital projects, including drivers for the project, and summary of anticipated changes in historic spending; and provide any available cost-benefit analysis in which the company evaluated a non-traditional distribution system solution to either a capital or operating upgrade or replacement.

(4) Distributed energy resource deployment.

(A) Discussion of how the impacts of the utility's energy efficiency program impacts are factored into load forecasts at the substation or circuit level.

(B) Discussion of how other distributed energy resources are considered in load forecasting and any expected changes in load forecasting methodology.

(C) Total costs spent on distributed energy resource generation installation in the prior year (including application review, responding to inquiries, metering, testing, and make ready costs.

(D) Total charges to customers/member installers for distributed energy resource generation installations, in the prior year (including application, metering, and make ready fees.

(E) Total nameplate kW of distributed energy resource generation systems that completed interconnection to the system in the prior year.

(F) Total number of distributed energy resource generation systems that completed interconnection to the system in the prior year.

(G) Current distributed energy resource deployment by type, size, and geographic dispersion (as useful for planning purposes; such as, by planning areas, service/work center areas, and cities.

(H) Information on areas of existing or forecasted low, moderate, and high distributed energy resource penetration.

(I) List of areas with existing or forecasted abnormal voltage or frequency issues that may benefit from the utilization of advanced inverter technology.

(5) Hosting capacity and interconnection requirements: A hosting capacity analysis, made available to the public on a website with mapping and GIS capability, and with detail at the block level, that includes a detailed and current analysis of how much capacity is available on each substation, circuit, and node for integrating new distributed energy resource as allowed by thermal ratings, protection system limits, power quality standards, and safety standards. The analysis must also include:

(A) circuit level maps and downloadable data sets for public use;

(B) an assessment of how utility planned investments over the next 5 years will impact the analysis; and

(C) a narrative discussion on how the hosting capacity analysis advances customer-sited distributed energy resource (in particular PV and electric storage systems) and how the utility anticipates the analysis identifying interconnection points on the distribution system and necessary distribution upgrades to support the continued development of distributed generation resources.

(6) Scenario analysis and forecasting: The plan shall include load forecasts over the next 10 years at the substation and circuit level using dynamic load forecasting utilizing multiple scenarios and probabilistic planning. In particular, the plan shall include the following:

(A) Definitions and a discussion of the development of base-case, medium, and high scenarios regarding increased distributed energy resource deployment. Scenarios shall reflect a reasonable mix of individual distributed energy resource adoption and aggregated or bundled distributed energy resource service types, and shall include the projected load forecast impacts of distributed energy resource investments, including investments in energy efficiency, demand response. The scenario analysis shall include information on the methodologies used to develop the low, medium, and high scenarios, including the distributed energy resource adoption rates, geographic deployment assumptions, expected distributed energy resource load profiles, and any other relevant assumptions factored into the scenario discussion.

(B) A discussion of the processes and tools that would be necessary to accommodate the specified levels of distributed energy resource adoption, including whether existing processes and tools would be sufficient. Provide a discussion of the system impacts that may arise from increased distributed energy resource adoption, potential barriers to distributed energy resource integration, and the types of system upgrades that may be necessary to accommodate the distributed energy resource at the listed penetration levels.

(C) A discussion of how present and projected reductions in the demand for energy may result from measures to improve energy efficiency in the industrial, commercial, residential, and energy producing sectors of the utility service territory.

(D) Information on anticipated impacts from FERC Order 841 (Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators) and a discussion of potential impacts from the related FERC Docket No. RM18-9-000 (Participation of Distributed Energy Resource Aggregations in Markets Operated by Regional Transmission Organizations and Independent System Operators).

(E) Discussion of how the distribution system planning is coordinated with Commission orders regarding the procurement of renewable resources as discussed in Section 16-111.5, energy efficiency plans as discussed in Section 8-103B, distributed generation rebates as discussed in Section 16-107.6, and any other order affecting the goals described in subsection (d) of this Section.

(7) Non-wires alternatives analysis:

(A) Detailed discussion of all distribution system projects in the coming 10 years that are anticipated to have a total cost of greater than $1,000,000. For these projects, an analysis of how non-wires alternatives, including increased local energy efficiency beyond what will occur through system-wide programs, demand response, distributed generation, and storage, compare in terms of viability, price, and long-term value shall be included. Such comparisons must include consideration of the benefits of distributed energy resources beyond meeting local reliability needs (for example, avoided energy costs, avoided system capacity costs, avoided transmission costs, and reduced exposure to future environmental regulations).

(B) Identification of the project types that would lend themselves to non-traditional solutions (i.e. load relief or reliability).

(C) Timelines needed to consider alternatives to any project types that would lend themselves to non-traditional solutions (allowing time for potential request for proposal, response, review, contracting and implementation).

(D) The cost threshold of any project type that would need to be met to have a non-traditional solution reviewed.

(8) Proposed distribution system investments: The plan shall identify proposed investments, including the reason for investment, projected costs, scope of work, prioritization, sequencing of investments, and explanations of how planned investments will support the goals described in subsection (d) of this Section.

(f) The Commission shall approve, approve with modifications, or reject the plan within 180 days. The Commission may approve the plan if it finds that the plan will achieve the goals described in subsection (d) of this Section. Proceedings under this Section shall proceed according to the rules provided by Article IX of this Act (9-201). Information contained in the approved plan shall be considered part of the record in any Commission proceeding under subsection (e) of Section 16-107.6 of this Act.

(g) Plan updates: Subsequent to the initial plan approval, the utility shall file an update to the plan on June 1, 2022, and every 24 months thereafter. This update shall describe the distribution system investments made during the prior plan period, the investments planned to be made in the following 24 months, and updates to the information required by subsection (e) of this Section. Within 35 days after the utility files its annual report, the Commission shall, upon complaint, petition, or its own initiative, but with reasonable notice, enter upon an investigation regarding the utility's plan update to ensure that the objectives described in subsection (d) of this Section are being achieved. If the Commission finds, after notice and hearing, that the utility's Plan is materially deficient in any way, the Commission shall issue an order requiring the participating utility to devise a corrective action plan, subject to Commission approval and oversight, to bring the plan into alignment with the goals of this Section. The Commission's order must be entered within 180 days after the utility files its annual report. The Commission shall have the authority to modify the information required by subsection (e) of this Section provided that modification does not impair the achievement of the goals described in subsection (d) of this Section.

(220 ILCS 5/16-111.5)

Sec. 16-111.5. Provisions relating to procurement.

(a) An electric utility that on December 31, 2005 served at least 100,000 customers in Illinois shall procure power and energy for its eligible retail customers in accordance with the applicable provisions set forth in Section 1-75 of the Illinois Power Agency Act and this Section. Beginning with the delivery year commencing on June 1, 2017, such electric utility shall also procure zero emission credits from zero emission facilities in accordance with the applicable provisions set forth in Section 1-75 of the Illinois Power Agency Act, and, for years beginning on or after June 1, 2017, the utility shall procure renewable energy resources in accordance with the applicable provisions set forth in Section 1-75 of the Illinois Power Agency Act and this Section. Beginning with the delivery year commencing on June 1, 2022, if possible, but no later than for the delivery year commencing June 1, 2023, an electric utility that on December 31, 2005 served at least 3,000,000 customers in Illinois shall procure capacity for its retail customers in accordance with the applicable provisions set for in Section 1-75 of the Illinois Power Agency Act and this Section. A small multi-jurisdictional electric utility that on December 31, 2005 served less than 100,000 customers in Illinois may elect to procure power and energy for all or a portion of its eligible Illinois retail customers in accordance with the applicable provisions set forth in this Section and Section 1-75 of the Illinois Power Agency Act. This Section shall not apply to a small multi-jurisdictional utility until such time as a small multi-jurisdictional utility requests the Illinois Power Agency to prepare a procurement plan for its eligible retail customers. "Eligible retail customers" for the purposes of this Section means those retail customers that purchase power and energy from the electric utility under fixed-price bundled service tariffs, other than those retail customers whose service is declared or deemed competitive under Section 16-113 and those other customer groups specified in this Section, including self-generating customers, customers electing hourly pricing, or those customers who are otherwise ineligible for fixed-price bundled tariff service. For those customers that are excluded from the procurement plan's electric supply service requirements, and the utility shall procure any supply requirements, including capacity, ancillary services, and hourly priced energy, in the applicable markets as needed to serve those customers, provided that the utility may include in its procurement plan load requirements for the load that is associated with those retail customers whose service has been declared or deemed competitive pursuant to Section 16-113 of this Act to the extent that those customers are purchasing power and energy during one of the transition periods identified in subsection (b) of Section 16-113 of this Act.

(b) A procurement plan shall be prepared for each electric utility consistent with the applicable requirements of the Illinois Power Agency Act and this Section. For purposes of this Section, Illinois electric utilities that are affiliated by virtue of a common parent company are considered to be a single electric utility. Small multi-jurisdictional utilities may request a procurement plan for a portion of or all of its Illinois load. Each procurement plan shall analyze the projected balance of supply and demand for those retail customers to be included in the plan's electric supply service requirements over a 5-year period, with the first planning year beginning on June 1 of the year following the year in which the plan is filed. The plan shall specifically identify the long-term bundled contracts to be procured, as described in Section 1-75 of the Illinois Power Agency Act, the carbon-free capacity and supply to be procured, as described in Section 1-75 of the Illinois Power Agency Act, and the wholesale products to be procured following plan approval, and shall follow all the requirements set forth in the Public Utilities Act and all applicable State and federal laws, statutes, rules, or regulations, as well as Commission orders. Nothing in this Section precludes consideration of contracts longer than 5 years and related forecast data. Unless specified otherwise in this Section, in the procurement plan or in the implementing tariff, any procurement occurring in accordance with this plan shall be competitively bid through a request for proposals process. Approval and implementation of the procurement plan shall be subject to review and approval by the Commission according to the provisions set forth in this Section. A procurement plan shall include each of the following components:

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

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

(ii) switching trends and competitive retail market analysis;

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

(iv) growth forecasts by customer class.

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

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

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

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

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

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

(A) be procured by a demand-response provider from those retail customers included in the plan's electric supply service requirements;

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

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

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

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

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

(iv) the proposed mix and selection of standard wholesale products for which contracts will be executed during the next year, separately or in combination, to meet that portion of its load requirements not met through pre-existing contracts or new bundled contracts, as described in Section 1-75 of the Illinois Power Agency Act, including, but not limited to, monthly 5 x 16 peak period block energy, monthly off-peak wrap energy, monthly 7 x 24 energy, annual 5 x 16 energy, annual off-peak wrap energy, annual 7 x 24 energy, monthly capacity, annual capacity, peak load capacity obligations, capacity purchase plan, and ancillary services;

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

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

(vii) the amount of supply procured from bundled contracts, as described in Section 1-75 of the Illinois Power Agency Act, and the amount of supply expected to be procured during the next year from new bundled contracts;

(viii) the amount of capacity procured from bundled contracts, as described in Section 1-75 of the Illinois Power Agency Act, and the amount of capacity to be procured during the next year from new bundled contracts.

(ix) the amount of capacity procured from carbon-free capacity pursuant to Section 1-75 of the Illinois Power Agency Act and this Section, and the amount of capacity to be procured during the next year from eligible carbon-free resources.

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

(5) Long-Term Renewable Resources Procurement Plan. The Agency shall prepare a long-term renewable resources procurement plan for the procurement of renewable energy credits under Sections 1-56 and 1-75 of the Illinois Power Agency Act for delivery beginning in the 2017 delivery year.

(i) The initial long-term renewable resources procurement plan and all subsequent revisions shall be subject to review and approval by the Commission. For the purposes of this Section, "delivery year" has the same meaning as in Section 1-10 of the Illinois Power Agency Act. For purposes of this Section, "Agency" shall mean the Illinois Power Agency.

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

(A) Electric utilities shall provide a range of load forecasts to the Illinois Power Agency within 45 days of the Agency's request for forecasts, which request shall specify the length and conditions for the forecasts including, but not limited to, the quantity of distributed generation expected to be interconnected for each year.

(B) The Agency shall publish for comment the initial long-term renewable resources procurement plan no later than 120 days after the effective date of this amendatory Act of the 99th General Assembly and shall review, and may revise, the plan at least every 2 years thereafter. To the extent practicable, the Agency shall review and propose any revisions to the long-term renewable energy resources procurement plan in conjunction with the Agency's other planning and approval processes conducted under this Section. The initial long-term renewable resources procurement plan shall:

(aa) Identify the procurement programs and competitive procurement events consistent with the applicable requirements of the Illinois Power Agency Act and shall be designed to achieve the goals set forth in subsection (c) of Section 1-75 of that Act.

(bb) Include a schedule for procurements for renewable energy credits from utility-scale wind projects, utility-scale solar projects, and brownfield site photovoltaic projects consistent with subparagraph (G) of paragraph (1) of subsection (c) of Section 1-75 of the Illinois Power Agency Act.

(cc) Identify the process whereby the Agency will submit to the Commission for review and approval the proposed contracts to implement the programs required by such plan.

Copies of the initial long-term renewable resources procurement plan and all subsequent revisions shall be posted and made publicly available on the Agency's and Commission's websites, and copies shall also be provided to each affected electric utility. An affected utility and other interested parties shall have 45 days following the date of posting to provide comment to the Agency on the initial long-term renewable resources procurement plan and all subsequent revisions. All comments submitted to the Agency shall be specific, supported by data or other detailed analyses, and, if objecting to all or a portion of the procurement plan, accompanied by specific alternative wording or proposals. All comments shall be posted on the Agency's and Commission's websites. During this 45-day comment period, the Agency shall hold at least one public hearing within each utility's service area that is subject to the requirements of this paragraph (5) for the purpose of receiving public comment. Within 21 days following the end of the 45-day review period, the Agency may revise the long-term renewable resources procurement plan based on the comments received and shall file the plan with the Commission for review and approval.

(C) Within 14 days after the filing of the initial long-term renewable resources procurement plan or any subsequent revisions, any person objecting to the plan may file an objection with the Commission. Within 21 days after the filing of the plan, the Commission shall determine whether a hearing is necessary. The Commission shall enter its order confirming or modifying the initial long-term renewable resources procurement plan or any subsequent revisions within 120 days after the filing of the plan by the Illinois Power Agency.

(D) The Commission shall approve the initial long-term renewable resources procurement plan and any subsequent revisions, including expressly the forecast used in the plan and taking into account that funding will be limited to the amount of revenues actually collected by the utilities, if the Commission determines that the plan will reasonably and prudently accomplish the requirements of Section 1-56 and subsection (c) of Section 1-75 of the Illinois Power Agency Act. The Commission shall also approve the process for the submission, review, and approval of the proposed contracts to procure renewable energy credits or implement the programs authorized by the Commission pursuant to a long-term renewable resources procurement plan approved under this Section.

(iii) The Agency or third parties contracted by the Agency shall implement all programs authorized by the Commission in an approved long-term renewable resources procurement plan without further review and approval by the Commission. Third parties shall not begin implementing any programs or receive any payment under this Section until the Commission has approved the contract or contracts under the process authorized by the Commission in item (D) of subparagraph (ii) of paragraph (5) of this subsection (b) and the third party and the Agency or utility, as applicable, have executed the contract. For those renewable energy credits subject to procurement through a competitive bid process under the plan or under the initial forward procurements for wind and solar resources described in subparagraph (G) of paragraph (1) of subsection (c) of Section 1-75 of the Illinois Power Agency Act, the Agency shall follow the procurement process specified in the provisions relating to electricity procurement in subsections (e) through (i) of this Section.

(iv) An electric utility shall recover its costs associated with the procurement of renewable energy credits under this Section through an automatic adjustment clause tariff under subsection (k) of Section 16-108 of this Act. A utility shall not be required to advance any payment or pay any amounts under this Section that exceed the actual amount of revenues collected by the utility under paragraph (6) of subsection (c) of Section 1-75 of the Illinois Power Agency Act and subsection (k) of Section 16-108 of this Act, and contracts executed under this Section shall expressly incorporate this limitation.

(v) For the public interest, safety, and welfare, the Agency and the Commission may adopt rules to carry out the provisions of this Section on an emergency basis immediately following the effective date of this amendatory Act of the 99th General Assembly.

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

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

(1) The procurement administrator shall:

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

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

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

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

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

(vi) administer the request for proposals process;

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

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

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

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

(xi) administer related contingency procurement events.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

(j) Within 60 days following August 28, 2007 (the effective date of Public Act 95-481), each electric utility that on December 31, 2005 provided electric service to at least 100,000 customers in Illinois shall prepare and file with the Commission an initial procurement plan, which shall conform in all material respects to the requirements of the procurement plan set forth in subsection (b); provided, however, that the Illinois Power Agency Act shall not apply to the initial procurement plan prepared pursuant to this subsection. The initial procurement plan shall identify the portfolio of power and energy products to be procured and delivered for the period June 2008 through May 2009, and shall identify the proposed procurement administrator, who shall have the same experience and expertise as is required of a procurement administrator hired pursuant to Section 1-75 of the Illinois Power Agency Act. Copies of the procurement plan shall be posted and made publicly available on the Commission's website. The initial procurement plan may include contracts for renewable resources that extend beyond May 2009.

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

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

(k) (Blank).

(k-5) (Blank).

(l) An electric utility shall recover its costs incurred under this Section, including, but not limited to, the costs of procuring power and energy demand-response resources under this Section. The utility shall file with the initial procurement plan its proposed tariffs through which its costs of procuring power that are incurred pursuant to a Commission-approved procurement plan and those other costs identified in this subsection (l), will be recovered. The tariffs shall include a formula rate or charge designed to pass through both the costs incurred by the utility in procuring a supply of electric power and energy for the applicable customer classes with no mark-up or return on the price paid by the utility for that supply, plus any just and reasonable costs that the utility incurs in arranging and providing for the supply of electric power and energy. The formula rate or charge shall also contain provisions that ensure that its application does not result in over or under recovery due to changes in customer usage and demand patterns, and that provide for the correction, on at least an annual basis, of any accounting errors that may occur. A utility shall recover through the tariff all reasonable costs incurred to implement or comply with any procurement plan that is developed and put into effect pursuant to Section 1-75 of the Illinois Power Agency Act and this Section, including any fees assessed by the Illinois Power Agency, costs associated with load balancing, and contingency plan costs. The electric utility shall also recover its full costs of procuring electric supply for which it contracted before the effective date of this Section in conjunction with the provision of full requirements service under fixed-price bundled service tariffs subsequent to December 31, 2006. All such costs shall be deemed to have been prudently incurred. The pass-through tariffs that are filed and approved pursuant to this Section shall not be subject to review under, or in any way limited by, Section 16-111(i) of this Act. All of the costs incurred by the electric utility associated with the purchase of zero emission credits in accordance with subsection (d-5) of Section 1-75 of the Illinois Power Agency Act and, beginning June 1, 2017, all of the costs incurred by the electric utility associated with the purchase of renewable energy resources in accordance with Sections 1-56 and 1-75 of the Illinois Power Agency Act, shall be recovered through the electric utility's tariffed charges applicable to all of its retail customers, as specified in subsection (k) of Section 16-108 of this Act, and shall not be recovered through the electric utility's tariffed charges for electric power and energy supply to its eligible retail customers.

(m) The Commission has the authority to adopt rules to carry out the provisions of this Section. For the public interest, safety, and welfare, the Commission also has authority to adopt rules to carry out the provisions of this Section on an emergency basis immediately following August 28, 2007 (the effective date of Public Act 95-481).

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

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

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

(q) If the Illinois Power Agency filed with the Commission, under Section 16-111.5 of this Act, its proposed procurement plan for the period commencing June 1, 2017, and the Commission has not yet entered its final order approving the plan on or before the effective date of this amendatory Act of the 99th General Assembly, then the Illinois Power Agency shall file a notice of withdrawal with the Commission, after the effective date of this amendatory Act of the 99th General Assembly, to withdraw the proposed procurement of renewable energy resources to be approved under the plan, other than the procurement of renewable energy credits from distributed renewable energy generation devices using funds previously collected from electric utilities' retail customers that take service pursuant to electric utilities' hourly pricing tariff or tariffs and, for an electric utility that serves less than 100,000 retail customers in the State, other than the procurement of renewable energy credits from distributed renewable energy generation devices. Upon receipt of the notice, the Commission shall enter an order that approves the withdrawal of the proposed procurement of renewable energy resources from the plan. The initially proposed procurement of renewable energy resources shall not be approved or be the subject of any further hearing, investigation, proceeding, or order of any kind.

This amendatory Act of the 99th General Assembly preempts and supersedes any order entered by the Commission that approved the Illinois Power Agency's procurement plan for the period commencing June 1, 2017, to the extent it is inconsistent with the provisions of this amendatory Act of the 99th General Assembly. To the extent any previously entered order approved the procurement of renewable energy resources, the portion of that order approving the procurement shall be void, other than the procurement of renewable energy credits from distributed renewable energy generation devices using funds previously collected from electric utilities' retail customers that take service under electric utilities' hourly pricing tariff or tariffs and, for an electric utility that serves less than 100,000 retail customers in the State, other than the procurement of renewable energy credits for distributed renewable energy generation devices.

(Source: P.A. 99-906, eff. 6-1-17.)

(220 ILCS 5/16-115E new)

Sec. 16-115E. Carbon-free supply for alternative retail electric suppliers and electric utilities operating outside their service territories.

(a) Beginning in the delivery year that commences on June 1, 2021, an alternative retail electric supplier shall be responsible for procuring cost-effective electricity that has an annual carbon dioxide emissions rate, in pounds of CO2 emissions per megawatt-hour, no greater than the annual targets in subsection (k) of Section 1-75 of the Illinois Power Agency Act.

(b) Each alternative retail electric supplier shall, by September 1, 2021 and by September 1 of each year thereafter, prepare and submit to the Commission a public report, in a format to be specified by the Commission, that provides information certifying compliance by the alternative retail electric supplier with this Section, including the source, quantity and hourly CO₂ emissions of supplied electricity, and any other information that the Commission determines necessary to ensure compliance with this Section.

(220 ILCS 5/16-128B)

Sec. 16-128B. Qualified energy efficiency installers.

(a) Within 18 months after the effective date of this amendatory Act of the 99th General Assembly, the Commission shall adopt rules, including emergency rules, establishing a process for entities installing energy efficiency measures to certify compliance with the requirements of this Section.

The process shall include an option to complete the certification electronically by completing forms on-line. An entity installing energy efficiency measures shall be permitted to complete the certification after the subject work has been completed.

The Commission shall maintain on its website a list of entities installing energy efficiency measures that have successfully completed the certification process.

(b) In addition to any authority granted to the Commission under this Act, the Commission may:

(1) determine which entities are subject to certification under this Section;

(2) impose reasonable certification fees and penalties;

(3) adopt disciplinary procedures;

(4) investigate any and all activities subject to this Section, including violations thereof;

(5) adopt procedures to issue or renew, or to refuse to issue or renew, a certification or to revoke, suspend, place on probation, reprimand, or otherwise discipline a certified entity under this Act or take other enforcement action against an entity subject to this Section; and

(6) prescribe forms to be issued for the administration and enforcement of this Section.

(c) An electric utility may not provide a retail customer with a rebate or other energy efficiency incentive for a measure that exceeds a minimal amount determined by the Commission unless the customer provides the electric utility with (1) a certification that the person installing the energy efficiency measure was a self-installer; or (2) evidence that the energy efficiency measure was installed by an entity certified under this Section that is also in good standing with the Commission.

(d) The Commission shall:

(1) require entities installing energy efficiency measures to be certified to do business and to be bonded in this State;

(2) ensure that entities installing energy efficiency measures have the requisite knowledge, skill, training, experience, and competence to perform functions in a safe and reliable manner as required under subsection (a) of Section 16-128 of this Act;

(3) ensure that entities installing energy efficiency measures conform to applicable building and electrical codes;

(4) ensure that all entities installing energy efficiency measures meet recognized industry standards as the Commission deems appropriate;

(5) include any additional requirements that the Commission deems reasonable to ensure that entities installing energy efficiency measures meet adequate training, financial, and competency requirements;

(6) ensure that all entities installing energy efficiency measures obtain certificates of insurance in sufficient amounts and coverages that the Commission so determines; and

(7) identify and determine the training or other programs by which persons or entities may obtain the requisite training, skill, or experience necessary to achieve and maintain compliance with the requirements of this Section.

(e) Fees and penalties collected under this Section shall be deposited into the Public Utility Fund and used to fund the Commission's compliance with the obligations imposed by this Section.

(f) The rules adopted under this Section shall specify the initial dates for compliance with the rules.

(g) For purposes of this Section, entities installing energy efficiency measures shall endeavor to support the diversity goals of this State by attracting, developing, retaining, and providing opportunities to employees of all backgrounds and by supporting female-owned, minority-owned, veteran-owned, and small businesses. Specifically, the Commission shall require that preference must be given to those certified energy efficiency installers who meet multiple workforce equity building actions, including, but not limited to, the following:

(A) Hiring equity action: 30% of the entity's workforce (measured by FTEs) are people of color (members of a racial or ethnic minority group) and receive at or above the prevailing wage.

(B) Clean Jobs Workforce Hubs action: 30% of the workers associated with the project are graduates or trainees from the Clean Jobs Workforce Hubs programs, or equivalent certification, and paid at or above the prevailing wage.

(C) Disadvantaged Business Enterprise Action: being an entity defined under Section 2 of the Business Enterprise for Minorities, Women, and Persons with Disabilities Act.

(D) Contracting Equity Action: 51% of the entity's subcontractors or vendors are entities defined under Section 2 of the Business Enterprise for Minorities, Women, and Persons with Disabilities Act or 30% of the workers associated with the project, including from all subcontractors and vendors, are people of color (members of a racial or ethnic minority group).

(E) Small business action: entity's workforce is comprised of 3 or fewer full-time employees.

(Source: P.A. 99-906, eff. 6-1-17.)

Section 90-25. The Environmental Protection Act is amended by changing Section 9.10 and by adding Sections 4.2 and 13.9 as follows:

(415 ILCS 5/4.2 new)

Sec. 4.2. Renewable energy benefits. The Illinois Environmental Protection Agency shall conduct a study regarding the ability of solar and wind projects to deliver additional benefits for Illinois such as agriculture and pollinator-friendly projects, brownfield redevelopment, water-pollution buffers, and other land-use or environmental benefits. On or before July 1, 2020, the Agency shall report its findings and recommendations to the General Assembly and to the Governor.

(415 ILCS 5/9.10)

Sec. 9.10. Fossil fuel-fired electric generating plants.

(a) The General Assembly finds and declares that:

(1) fossil fuel-fired electric generating plants are a significant source of air emissions in this State and have become the subject of a number of important new studies of their effects on the public health;

(2) existing state and federal policies, that allow older plants that meet federal standards to operate without meeting the more stringent requirements applicable to new plants, are being questioned on the basis of their environmental impacts and the economic distortions such policies cause in a deregulated energy market;

(3) fossil fuel-fired electric generating plants are, or may be, affected by a number of regulatory programs, some of which are under review or development on the state and national levels, and to a certain extent the international level, including the federal acid rain program, tropospheric ozone, mercury and other hazardous pollutant control requirements, regional haze, and global warming;

(4) scientific uncertainty regarding the formation of certain components of regional haze and the air quality modeling that predict impacts of control measures requires careful consideration of the timing of the control of some of the pollutants from these facilities, particularly sulfur dioxides and nitrogen oxides that each interact with ammonia and other substances in the atmosphere;

(5) the development of energy policies to promote a safe, sufficient, reliable, and affordable energy supply on the state and national levels is being affected by the on-going deregulation of the power generation industry and the evolving energy markets;

(6) the Governor's formation of an Energy Cabinet and the development of a State energy policy calls for actions by the Agency and the Board that are in harmony with the energy needs and policy of the State, while protecting the public health and the environment;

(7) reducing greenhouse gas emissions and other air pollutants such as particulate matter, sulfur dioxide, and nitrogen oxide is critical to improving the health and welfare of Illinois residents by decreasing respiratory diseases, cardiovascular diseases, and related mortalities; lowering customers' energy costs; and responding to the growing impacts of climate change from fossil-fuel generation;

(8) through reductions in harmful emissions and strategic planning for Illinois citizens currently employed by and communities reliant on fossil-fuel electricity generation units, eliminating greenhouse gas emissions from the electricity generation sector is a priority for the State;

(9) The 100th General Assembly recognized this problem and, in passing House Resolution 490 on June 26, 2017, it supported the Paris Climate Agreement and urged the State of Illinois join the United States Climate Alliance and develop a plan to achieve 100% clean energy by 2045;

(7) Illinois coal is an abundant resource and an important component of Illinois' economy whose use should be encouraged to the greatest extent possible consistent with protecting the public health and the environment;

(8) renewable forms of energy should be promoted as an important element of the energy and environmental policies of the State and that it is a goal of the State that at least 5% of the State's energy production and use be derived from renewable forms of energy by 2010 and at least 15% from renewable forms of energy by 2020;

(10) (9) efforts on the state and federal levels are underway to consider the multiple environmental regulations affecting electric generating plants in order to improve the ability of government and the affected industry to engage in effective planning through the use of multi-pollutant strategies; and

(11) (10) these issues, taken together, call for a comprehensive review of the impact of these facilities on the public health, considering also the energy supply, reliability, and costs, the role of renewable forms of energy, and the developments in federal law and regulations that may affect any state actions, prior to making final decisions in Illinois.

(b) Taking into account the findings and declarations of the General Assembly contained in subsection (a) of this Section, the Agency shall, within 180 days after the effective date of this amendatory Act of the 101st General Assembly, initiate a rulemaking to amend Title 35 of the Illinois Administrative Code to establish annual greenhouse gas pollution caps and further co-pollutant reductions beginning in 2020 from electric generating units (including, but not limited to, coal-fired, coal-derived, oil-fired, combustion turbine, integrated gasification combined cycle, and cogeneration facilities above or below 25 MW) and progressively eliminate all emissions of greenhouse gases, particulate matter, mercury, nitrogen oxides, and sulfur dioxide from Illinois' electric sector by the year 2030. As part of this rulemaking, the Agency shall:

(1) ensure that environmental justice communities are protected and develop an environmental justice analysis in partnership with the Illinois Commission on Environmental Justice that includes a cumulative impacts assessment and proposed definition of environmental justice communities based on existing methodologies and findings used by the Illinois Power Agency and its Administrator in its Illinois Solar for All Program;

(2) identify electric generating units located in or near environmental justice communities and require more rapid greenhouse gas and co-pollutant emissions reductions of those facilities

(3) conduct a robust and inclusive stakeholder process prior to issuing a draft rule to the Illinois Pollution Control Board that includes a formal public comment period with public hearings accessible to working residents;

(4) participate in strategic planning efforts with the Department of Commerce and Economic Opportunity to identify needs and initiatives for communities and workers economically impacted by the decline in fossil fuel generation. before September 30, 2004, but not before September 30, 2003, issue to the House and Senate Committees on Environment and Energy findings that address the potential need for the control or reduction of emissions from fossil fuel-fired electric generating plants, including the following provisions:

(1) reduction of nitrogen oxide emissions, as appropriate, with consideration of maximum annual emissions rate limits or establishment of an emissions trading program and with consideration of the developments in federal law and regulations that may affect any State action, prior to making final decisions in Illinois;

(2) reduction of sulfur dioxide emissions, as appropriate, with consideration of maximum annual emissions rate limits or establishment of an emissions trading program and with consideration of the developments in federal law and regulations that may affect any State action, prior to making final decisions in Illinois;

(3) incentives to promote renewable sources of energy consistent with item (8) of subsection (a) of this Section;

(4) reduction of mercury as appropriate, consideration of the availability of control technology, industry practice requirements, or incentive programs, or some combination of these approaches that are sufficient to prevent unacceptable local impacts from individual facilities and with consideration of the developments in federal law and regulations that may affect any state action, prior to making final decisions in Illinois; and

(5) establishment of a banking system, consistent with the United States Department of Energy's voluntary reporting system, for certifying credits for voluntary offsets of emissions of greenhouse gases, as identified by the United States Environmental Protection Agency, or other voluntary reductions of greenhouse gases. Such reduction efforts may include, but are not limited to, carbon sequestration, technology-based control measures, energy efficiency measures, and the use of renewable energy sources.

The Agency shall consider the impact on the public health, considering also energy supply, reliability and costs, the role of renewable forms of energy, and developments in federal law and regulations that may affect any state actions, prior to making final decisions in Illinois.

(c) Nothing in this Section is intended to or should be interpreted in a manner to limit or restrict the authority of the Illinois Environmental Protection Agency to propose, or the Illinois Pollution Control Board to adopt, any regulations applicable or that may become applicable to the facilities covered by this Section that are required by federal law.

(d) The Agency may file proposed rules with the Board to effectuate the goals set forth in subsection (b). its findings provided to the Senate Committee on Environment and Energy and the House Committee on Environment and Energy in accordance with subsection (b) of this Section. Any such proposal shall not be submitted sooner than 90 days after the issuance of the findings provided for in subsection (b) of this Section. The Board shall take action on any such proposal within one year of the Agency's filing of the proposed rules.

(e) This Section shall apply only to those electrical generating units that are subject to the provisions of Subpart W of Part 217 of Title 35 of the Illinois Administrative Code, as promulgated by the Illinois Pollution Control Board on December 21, 2000.

(Source: P.A. 92-12, eff. 7-1-01; 92-279, eff. 8-7-01.)

(415 ILCS 5/13.9 new)

Sec. 13.9. Coal ash regulation.

(a) In this Section, "coal ash" means coal combustion waste as defined in Section 3.140.

(b) Within 180 days after the effective date of this amendatory Act of the 101st General Assembly, the Agency shall initiate a rulemaking to amend 35 Ill. Adm. Code Part 620 to establish and enforce limits on annual coal ash disposal in the State. This rule must include specific enforcement measures that are available to the public if the Agency or a regulated party fails to meet these requirements. Also as part of this rule, the Agency shall set forth a procedure by which owners or operators, or both, of both active and inactive coal ash impoundments shall identify and eliminate all sources of contamination from the storage of coal combustion residual waste in Illinois, by December 31, 2030.

(415 ILCS 5/9.15 rep.)

Section 90-30. The Environmental Protection Act is amended by repealing Section 9.15.

(415 ILCS 140/Act rep.)

Section 90-35. The Kyoto Protocol Act of 1998 is repealed.

Article 99.

Effective Date

Section 999. Effective date. This Act takes effect upon becoming law.".