SB2896 102ND GENERAL ASSEMBLY

LRB102 17909 JWD 25989 b

102ND GENERAL ASSEMBLY
State of Illinois
2021 and 2022
SB2896

Introduced 4/29/2021, by Sen. Celina Villanueva

SYNOPSIS AS INTRODUCED:

See Index

Creates the Consumers and Climate First Act. Provides that it is the policy of the State of Illinois to transition to 100% clean energy by 2050. Amends the Illinois Governmental Ethics Act. Expands the information required to be provided on a statement of economic interests to include employment by a public utility. Amends the Illinois Enterprise Zone Act. In provisions relating to High Impact Businesses, expands the definition of "new electric generating facility" to include a new utility scale solar power facility. Amends the Energy Policy and Planning Act. Expands the legislative findings to include climate change in the problems to be addressed by the State's energy policy. Amends the Illinois Power Agency Act. Provides that it is the policy of the State of Illinois to transition to 100% clean energy by 2050, authorizes actions and programs in support of the policy including the Illinois Solar for All Program. Defines "clean energy". Amends the Illinois Procurement Code. Authorizes procurement expenditures necessary for the Illinois Environmental Protection Agency to contract with a firm to perform audits under the Public Utilities Act. Amends the Illinois Municipal Code to create the Non-Home Rule Municipal Gas Use Tax Law. Provides that a non-home rule municipality may impose a tax on the privilege of using or consuming gas acquired in a purchase at retail and used or consumed within the corporate limits of the municipality. Defines "gas" and other terms. Amends the Public Utilities Act. Increases the amounts that public utilities must spend to implement energy efficiency measures targeted at low-income households. Prohibits deposits and late payment fees for low-income residential customers and applicants. Restricts the use of credit card convenience fees. Requires all public utilities to annually report the number of disconnections for nonpayment and reconnections according to specified criteria. Provides for an annual audit of the finances of all nuclear power plants operating in Illinois. Provides for specified electric utilities to prepare and file a distribution system investment plan that meets specified requirements no later than June 1, 2022. Makes other changes. Effective immediately.

A BILL FOR

AN ACT concerning regulation.

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

Article 1. Consumers and Climate First

Section 1-1. Short title. This Article may be cited as the Consumers and Climate First Act. As used in this Article, "this Act" refers to this Article.

Section 1-5. Clean Energy Goals.

(a) Article XI of the Constitution of the State of Illinois provides that every citizen deserves a healthful environment, that it is the public policy of the State to maintain a healthful environment for this generation and future generations and that the General Assembly should enable this policy.

(b) To fulfill this policy, Illinois has a responsibility to protect its citizens and economy against the threats of climate change, including threats to our economy, health, safety, and national security.

(c) Moving Illinois toward a goal of 100% clean energy by 2050 is in furtherance of the State's policy to provide a healthful environment for its citizens. To accomplish this goal, the State must undertake several policy initiatives, such as incentivizing renewable energy and other low or zero carbon sources of energy, adopting measures to reduce our energy usage, and improving the reliability and affordability of our energy system.

(d) The move toward 100% clean energy will allow Illinois to take advantage of the clean energy economy that can provide new quality jobs and economic opportunities, and wealth building in economically disadvantaged communities that have borne a disproportionate burden of pollution and climate change. It will further improve health outcomes through reduction of co-emissions of pollutants other than greenhouse gases for all citizens of the State. These improved health outcomes also provide economic benefits for the State.

(e) These initiatives must ensure that the development of a clean energy economy will provide benefits and opportunities for economically disadvantaged communities, communities of color and environmental justice communities, and a just transition for communities and workers who rely on existing power plants for jobs, property tax revenues, and other economic benefits.

(f) Energy efficiency should be prominent in the State's clean energy policy, since it is the most cost-effective energy resource. Energy efficiency upgrades help customers manage their individual energy bills, while reducing the total energy needs of the State and the cost of the energy system.

(g) The transportation sector is now the leading source of carbon pollution in Illinois, responsible for roughly one-third of carbon emissions in the State. The State should adopt policies that will encourage and expand access to public transit, promote walking and biking mobility, and increase electric vehicle adoption. If properly implemented, transitioning to electric vehicles can greatly decrease emissions from the transportation sector, provide reliability assistance to the electric power grid, and potentially lower electric bills for customers by moving electric demand to off-peak hours.

(h) The transition to a clean energy economy will also provide an impetus for the development of new technologies and products and the potential for manufacturing some of these products in Illinois.

(i) Energy storage can provide many services and benefits to the electricity grid, including reducing peak load, frequency regulation, voltage support, and the greater utilization of renewable energy, which will provide many benefits.

(j) Greater implementation of these new technologies and generation sources will provide for greater customer choice in their energy sources and usage. To help further these goals, new and innovative regulatory policies are needed to transition to a more resilient grid that is equipped to implement the clean energy economy, while also achieving reliability and affordability goals.

Article 5. Energy Transition

Section 5-1. Short title. This Article may be cited as the Energy Transition Act. As used in this Article, "this Act" refers to this Article.

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

"Clean Energy Jobs" means jobs in the solar energy, wind energy, energy efficiency, energy storage, solar thermal, hydrogen, carbon management, geothermal, electric vehicle industries, other renewable energy industries, industries achieving emission reductions, and other related sectors including related industries that manufacture, develop, build, maintain, or provide ancillary services to renewable energy resources or energy efficiency products or services, including the manufacture and installation of healthier building materials that contain fewer hazardous chemicals. "Clean Energy Jobs" include administrative, sales, other support functions within these industries and other related sector industries.

"Closure" means the permanent shutdown of an investor-owned electric generating unit or coal mine.

"Community-based organization" means an organization that: (1) provides employment, skill development or related services to members of the community; (2) includes community colleges, nonprofits, and local governments; (3) has at least one main operating office in the community or region it serves; and (4) demonstrates relationships with local residents and other organizations serving the community.

"Community-based provider" means a not-for-profit organization that has a history of serving low-wage, low-skilled workers, or individuals from economically disadvantaged communities.

"Department" means the Department of Commerce and Economic Opportunity, unless the text solely specifies a particular Department.

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

"Displaced energy worker" means an energy worker who has lost employment, or is anticipated by the Department to lose employment within the next 2 years, due to the reduced operation or closure of a fossil fuel power plant, nuclear power plant, or coal mine.

"Economically disadvantaged community" means areas of one or more census tracts where average household income does not exceed 80% of area median income.

"Equity focused populations" means (1) low-income persons; (2) persons residing in equity investment eligible communities; (3) persons who identify as Black, Indigenous, and People of Color (BIPOC); (4) justice-involved persons; (5) persons who are or were in the child welfare system; (6) energy workers; (7) dependents of displaced energy workers; (8) women; (9) LGBTQ+, transgender, or gender nonconforming persons; (10) persons with disabilities, and (11) members of any of these groups who are also youth.

"Equity investment eligible community" or "eligible community" mean people living in geographic areas throughout Illinois who will most benefit from equitable investments by the State that are designed to combat historic inequities and the effects of discrimination. "Eligible community" includes census tracts that meet the following characteristics:

(1) At least 15% of households or at least 20% of the population 18 or under fall below the federal poverty level; and

(2) falls in the top 25th percentile in the State on measured levels for one or more of the following environmental indicators from the United States Environmental Protection Agency's EJSCREEN screening tool:

(A) Diesel particulate matter level in air.

(B) Air toxics cancer risk.

(C) Air toxics respiratory hazard index.

(D) Indicator for major direct dischargers to water.

(E) Proximity to National Priorities List (NPL) sites.

(F) Proximity to Risk Management Plan (RMP) facilities.

(G) Proximity to Treatment and Storage and Disposal (TSDF) facilities.

(H) Ozone level in air.

(I) PM2.5 (particulate matter with diameters that are 2.5 micrometers and smaller) level in the air.

"Equity investment eligible persons" or "eligible persons" means persons who would most benefit from equitable investments by the State designed to combat discrimination, specifically:

(1) persons whose primary residence is in an equity investment eligible community;

(2) persons whose primary residence is in a municipality or a county with a population under 100,000 where the closure of an electric generating unit or coal mine has been publicly announced, or the electric generating unit or coal mine is in the process of closing or has closed within the last 5 years;

(3) persons who are graduates of or currently enrolled in the foster care system; or

(4) persons who were formerly incarcerated.

"Plant owner" means the owners of an investor-owned electric generating unit with a nameplate capacity of greater than 300 megawatts.

Section 5-10. Findings. The General Assembly finds that the clean energy sector is a growing area of the economy in the State of Illinois. The General Assembly further finds that State investment in the clean energy economy in Illinois can be a vehicle for expanding equitable access to public health, safety, a cleaner environment, quality jobs, and economic opportunity.

It is in the public policy interest of the State to ensure that Illinois residents from communities disproportionately impacted by climate change, facing coal plant or coal mine closures, economically disadvantaged communities, and individuals experiencing barriers to employment have access to State programs and good jobs and career opportunities in growing sectors of the State economy. To promote those interests in the growing clean energy sector, the General Assembly hereby creates the Energy Transition Act to increase access to and opportunities for education, training, and support services Illinois residents from communities disproportionately impacted by climate change, facing coal plant or coal mine closures, economically disadvantage communities, and individuals experiencing barriers to employment need to succeed in the labor market generally and the clean energy sector specifically. The General Assembly further finds that the programs included in the Energy Transition Act are essential to equitable, statewide access to quality training, jobs, and economic opportunities across the clean energy sector.

Section 5-15. Regional administrators.

(a) Subject to appropriations, the Department shall select 3 unique regional administrators: one regional administrator for coordination of the work in the Northern Illinois Program Delivery Area, one regional administrator selected for coordination of the work in the Central Illinois Program Delivery Area, and one regional administrator selected for coordination of the work in the Southern Illinois Program Delivery Area. (b) The Clean Jobs Workforce Network Hubs Program shall be administered by 3 regional administrators selected under this Section 5-15.

(c) The regional administrators shall have: strong capabilities, experience, and knowledge related to program development and fiscal management; cultural and language competency needed to be effective in their respective communities to be served; expertise in working in and with BIPOC and environmental justice communities; knowledge and experience in working with employer or sectoral partnerships, if applicable, in clean energy or related sectors; and awareness of industry trends and activities, workforce development best practices, regional workforce development needs, regional and industry employers, and community development. The regional administrators shall demonstrate a track record of strong partnerships with community-based organizations.

(d) The regional administrators shall work together to coordinate the implementation of the Clean Jobs Workforce Program.

Section 5-20. Clean Jobs Workforce Network Program.

(a) Subject to appropriations, the Department shall develop, and through regional administrators administer, the Clean Jobs Workforce Network Program ("Program") to create a network of 16 Program delivery Hub Sites with program elements delivered by community-based organizations and their subcontractors geographically distributed across the State.

(1) The Clean Jobs Workforce Hubs Network shall be made up of 16 Program delivery Hub Sites geographically distributed across the State, including at least one Hub Site located in or near each of the following areas: Chicago (South Side), Chicago (Southwest and West Sides), Waukegan, Rockford, Aurora, Joliet, Peoria, Champaign, Danville, Decatur, Carbondale, East St. Louis, and Alton.

(2) Three additional Hub Sites shall be determined by the Department. One of the additional sites shall be located in the Northern Illinois Program Delivery Area covering Northern Illinois, one of the additional sites shall be located in the Central Illinois Program Delivery Area covering Central Illinois, and one of the additional sites shall be located in the Southern Illinois Program Delivery Area covering Southern Illinois.

(b) The Program shall be available to members of one or more of the population groups listed as equity focused populations across the State to enter and complete the career pipeline for clean energy jobs, with the goal of serving all of the equity focused populations distributed across the network.

(c) The Program shall be available to members of one or more of the population groups listed as equity focused populations from communities in the following order of priority: (i) communities that host coal-fired power plants or coal mines, or both; and (ii) communities across the State.

(d) Program elements for each Hub Site shall be provided by a community-based organization. The Department shall initially select a community-based organization in each Hub Site and shall subsequently select a community-based organization in each Hub Site every 3 years. Community-based organizations delivering program elements outlined in subsection (e) may provide all elements required or may subcontract to other entities for provision of portions of program elements, including, but not limited to, administrative soft and hard skills for program participants, delivery of specific training in the core curriculum, or provision of other support functions for program delivery compliance.

(e) The Clean Jobs Workforce Hubs Network shall:

(1) coordinate with Energy Transition Navigators:

(A) to increase participation in the Clean Energy Workforce Network and clean energy and related sector workforce and training opportunities;

(B) coordinate recruitment, communications, and ongoing engagement with potential employers, including, but not limited to, activities such as job matchmaking initiatives, hosting events such as job fairs, and collaborating with other Hub Sites to identify and implement best practices for employer engagement;

(C) leverage community-based organizations, educational institutions, and community-based and labor-based training providers to ensure members of equity focused populations across the State have dedicated and sustained support to enter and complete the career pipeline for clean energy and related sector jobs; and

(D) develop formal partnerships, including formal sector partnerships between community-based organizations and (a) trades groups, (b) labor unions, and (c) entities that provide clean energy jobs, including businesses, nonprofit organizations, and worker-owned cooperatives to ensure that Program participants have priority access to high-quality preapprenticeship, apprenticeship, and other employment training and hiring opportunities.

(2) implement the Clean Jobs Curriculum to provide, which may include, but is not limited to, training, preapprenticeship, certification preparation, job readiness, and skill development, including soft skills, math skills, technical skills, certification test preparation, and other development needed, to Program participant members of disadvantaged communities specified in subsection (b) of this Section.

(f) Funding for the Program shall be made available from the Energy Transition Assistance Fund.

(g) The Department shall require submission of quarterly reports including program performance metrics by each Hub Site to the regional administrator of their Program Delivery Area. Program performance measures include, but are not limited to:

(1) demographic data, including racial, gender, and geographic distribution data, on Program trainees entering and graduating the Program;

(2) demographic data, including racial, gender, and geographic distribution data, on Program trainees who are placed in employment, including the percentages of trainees by race, gender, and geographic categories in each individual job type or category and whether employment is union, nonunion, or nonunion via temp agency;

(3) trainee job acquisition and retention statistics, including the duration of employment (start and end dates of hires) by race, gender, and geography;

(4) hourly wages, including hourly overtime pay rate, and benefits of trainees placed into employment by race, gender, and geography;

(5) percentage of jobs by race, gender, and geography held by Program trainees or graduates that are full-time equivalent positions, meaning that the position held is full-time, direct, and permanent based on 2,080 hours worked per year (paid directly by the employer, whose activities, schedule, and manner of work the employer controls, and receives pay and benefits in the same manner as permanent employees); and

(6) qualitative data consisting of open-ended reporting on pertinent issues, including, but not limited to, qualitative descriptions accompanying metrics or identifying key successes and challenges.

(h) Within 3 years of the effective date, the Department shall select an independent evaluator to review and prepare a report on the performance of the Program and regional administrators.

Section 5-25. Clean Jobs Curriculum.

(a) The Department shall convene a comprehensive stakeholder process that includes representatives from the Illinois State Board of Education, the Illinois Community College Board, the Department of Labor, community-based organizations, workforce development providers, labor unions, building trades, educational institutions, residents of BIPOC and low-income communities, residents of environmental justice communities, clean energy businesses, nonprofit organizations, worker-owned cooperatives, other groups that provide clean energy jobs opportunities, and other participants to identify the career pathways and training curriculum needed to prepare workers to enter clean energy jobs and build careers. The curriculum shall:

(1) identify the core training curricular competency areas needed to prepare workers to enter clean energy and related sector jobs, such as those included in, but not limited to, the Multi-Craft Core Curriculum, U.S. Department of Labor Employment and Training Administration-sponsored CareerOneStop Renewable Energy Competency Model, the Electric Vehicle Infrastructure Training Program;

(2) identify a set of certifications for clean energy and related sector job types to be included in respective training programs and used to inform core training Curricular competency areas, such as, but not limited to, North American Board of Certified Energy Practitioners (NABCEP) Board Certifications, Interstate Renewable Energy Council (IREC) Accredited Certificate Programs, American Society of Heating, Refrigerating and Air-Conditioning Engineers (ASHRAE) ANSI/ISO accreditation standard certifications, Electric Vehicle Infrastructure Training Program Certifications, and UL Certification for EV infrastructure;

(3) identify a set of required core cross-training competencies provided in each training area for clean energy jobs with the goal of enabling any trainee to receive a standard set of skills common to multiple training areas that would provide a foundation for pursuing a career composed of multiple clean energy job types;

(4) include approaches to integrate broad occupational training to provide career entry into the general construction and building trades sector and any remedial education and work readiness support necessary to achieve educational and professional eligibility thresholds;

(5) identify, directly or through references to external resources, career pathways for clean energy jobs types, such as, but not limited to, pathways identified in: IREC Careers in Climate Control Technology Map, IREC Solar Career Map for Workforce Training, NABCEP Certification Career Map, and U.S. Department of Labor's Bureau of Labor Statistics Green Jobs Initiative; and

(6) identify on-the-job training formats, where relevant; and identify suggested trainer certification standards, where relevant.

(b) The Department shall publish a report that includes the findings, recommendations, and core curriculum identified by the stakeholder group and shall post a copy of the report on its public website. The Department shall convene the process described to update and modify the recommended curriculum every 3 years to ensure the curriculum contents are current to the evolving clean energy industries, practices, and technologies.

(c) Organizations that receive funding to provide training under the Clean Jobs Workforce Hubs Program, including, but not limited to, community-based and labor-based training providers, and educational institutions must use the core curriculum that is developed under this Section.

Section 5-30. Energy Transition Barrier Reduction Program.

(a) Subject to appropriations, the Department shall create and administer an Energy Transition Barrier Reduction Program. The Energy Transition Barrier Reduction Program shall be used to provide supportive services for individuals impacted by the energy transition. Services allowed are intended to help equity focused populations overcome financial and other barriers to participation in the Clean Jobs Workforce Program.

(b) The Program shall be available to members of one or more of the equity focused populations from communities in the following order of priority: (i) communities that host coal-fired power plants, or coal mines, or both; and (ii) communities across the State.

(c) The Department shall determine appropriate allowable program costs, elements and financial supports to reduce barriers to successful participation in the Clean Jobs Workforce Program for equity focused populations.

(d) Community-based organizations and other nonprofits selected by the Department will be selected to provide supportive services described in this Section to equity focused populations participating in the Clean Jobs Workforce Program.

(e) The community-based organizations that provide support services under this Section shall coordinate with the Energy Transition Navigators to ensure equity focused populations have access to these services.

(f) Funding for the Program shall be made available from the Energy Transition Assistance Fund.

Section 5-35. Energy Transition Navigators.

(a) In order to engage equity focused populations to participate in the Clean Jobs Workforce Program and utilize the services offered under the Energy Transition Barrier Reduction Program, the Department shall, subject to appropriation, contract with community-based providers to conduct education, outreach, and recruitment services to equity focused populations to make sure they are aware of and engaged in the statewide and local workforce development systems. Additional strategies will include recruitment activities and events, among others.

(b) For members of equity focused populations who may be interested in entrepreneurial pursuits, Energy Transition Navigators will connect these individuals with their area Small Business Development Center, Procurement Technical Assistance Centers, and/or economic development organization to engage in services such as business consulting, business planning, regulatory compliance, marketing, training, accessing capital, government bid, certification assistance, and others.

(c) Energy Transition Navigators will build strong relationships with equity focused populations, organizations working with these populations, local workforce innovation boards, and other stakeholders to coordinate outreach initiatives promoting information about the programs and services offered under the Clean Jobs Workforce Program and Energy Transition Barrier Reduction Program, and support clients applying for these services and programs.

(d) Community education, outreach, and recruitment about the Clean Jobs Workforce Program and Energy Transition Barrier Reduction Program will be targeted to the equity focused populations.

(e) Community-based providers will partner with educational institutions or organizations working with equity focused populations, local employers, labor unions, and others to identify members of equity focused populations in eligible communities who are unable to advance in their careers due to inadequate skills. Community-based providers will provide information and consultation to equity focused populations on various educational opportunities and supportive services available to them.

(f) Community-based providers will establish partnerships with employers, educational institutions, local economic development organizations, environmental justice organizations, trades groups, labor unions, and entities that provide jobs, including businesses and other nonprofit organizations to target the skill needs of local industry. The community-based provider will work with local workforce innovation boards and other relevant partners to develop skill curriculum and career pathway support for disadvantaged individuals in equity focused populations that meets local employer's needs and establishes job placement opportunities after training.

(g) Funding for the Program shall be made available from the Energy Transition Assistance Fund.

(h) Priority in awarding grants under this Section will be given to organizations that also have experience serving equity investment eligible communities.

(i) Each community-based organization that receives funding from the Department as an Energy Transition Navigator shall provide an annual report to the Department by April 1 of each calendar year. The annual report shall include the following information:

(1) a description of the community-based organization's recruitment, screening, and training efforts;

(2) the number of individuals who apply to, participate in, and complete programs offered through the Energy Transition Workforce Program, broken down by race, gender, age, and location; and

(3) any other information deemed necessary by the Department.

Section 5-40. Displaced Energy Workers Bill of Rights.

(a) The Department, in collaboration with the Illinois Department of Employment Security, shall have the authority to implement the Displaced Energy Workers Bill of Rights, and shall be responsible for the implementation of the Displaced Energy Workers Bill of Rights programs and rights created under this Section. Subject to appropriation, the Department shall provide the following benefits to displaced energy workers:

(1) The Department shall engage the employer and energy workers no later than within 30 days of a closure or deactivation notice being filed by the plant owner to the Regional Transmission Organization of jurisdiction, within 30 days of the announced closure of a coal mine, or within 30 days of a WARN notice being filed with the Department, whichever is first. The Department shall take reasonable steps to ensure that all displaced energy workers are educated on the various programs available through the Department to assist with the energy transition, including, but not limited to, the Illinois Dislocated Worker and Rapid Response programs. The Department will develop an outreach strategy, workforce toolkit and quick action plan to deploy when closures are announced. This strategy will include identifying any additional resources that may be needed to aid worker transitions that would require contracting services.

(2) The Department shall provide information and consultation to displaced energy workers on various employment and educational opportunities available to them, supportive services, and advise workers on which opportunities meet their skills, needs, and preferences.

(A) Available services will include reemployment services, training services, work-based learning services, and financial and retirement planning support.

(B) The Department will provide skills matching as part of career counseling services to enable assessment of the displaced energy worker's skills and map those skills to emerging occupations in the region or nationally, or both, depending on the displaced worker's preferences.

(C) For energy workers who may be interested in entrepreneurial pursuits, the Department will connect these individuals with their area Small Business Development Center, Procurement Technical Assistance Centers, and economic development organization to engage in services including, but not limited to, business consulting, business planning, regulatory compliance, marketing, training, accessing capital, and government bid certification assistance.

(b) Plant owners and the owners of coal mines located in Illinois shall be required to comply with the requirements set out in this subsection (b). The owners shall be required to take the following actions:

(1) provide written notice of deactivation or closure filing with the Regional Transmission Organization of jurisdiction to the Department within 48 hours, if applicable;

(2) provide employment information for energy workers; 90 days prior to the closure of an electric generating unit or mine, the owners of the power plant or mine shall provide energy workers information on whether there are employment opportunities provided by their employer; and

(3) annually report to the Department on announced closures of qualifying facilities. The report must include information on expected closure date, number of employees, planning processes, services offered for employees (such as training opportunities) leading up to the closure, efforts made to retain employees through other employment opportunities within the company, and any other information that the Department requires in order to implement this Section.

(4) Ninety days prior to closure date, the owners of the power plant or mine shall provide a final closure report to the Department that includes expected closure date, number of employees and salaries, transition support the company is providing to employee and timelines, including assistance for training opportunities, transportation support or child care resources to attend training, career counseling, resume support, and others. The closure report will be made available to the chief elected official of each municipal and county government within which the employment loss, relocation, or mass layoff occurs. It shall not be made publicly available.

(5) The owners of the power plant or mine will provide job descriptions for each employee at the plant or mine to the Department and the entity providing career and training counseling.

(6) The owners of the power plant or mine will make available to the Department and the entity providing career and training counseling any industry related certifications and on-the-job training the employee earned to allow union training programs, Community Colleges, or other certification programs to award credit for life experiences in order to reduce the amount of time to complete training, certificates or degrees for the dislocated employee.

Section 5-45. Displaced Energy Worker Dependent Transition Scholarship.

(a) Subject to appropriation, the benefits of this Section shall be administered by and paid for out of funds made available to the Illinois Student Assistance Commission.

(b) Any natural child, legally adopted child, or step-child of an eligible dislocated energy worker who possesses all necessary entrance requirements shall, upon application and proper proof, be awarded a transition scholarship consisting of the equivalent of one calendar year of full-time enrollment including summer terms, to the state-supported Illinois institution of higher learning of his or her choice.

(c) As used in this Section, "eligible dislocated energy worker" means an energy worker who has lost employment due to the reduced operation or closure of a fossil fuel power plant or coal mine.

(d) Full-time enrollment means 12 or more semester hours of courses per semester, or 12 or more quarter hours of courses per quarter, or the equivalent thereof per term. Scholarships utilized by dependents enrolled in less than full-time study shall be computed in the proportion which the number of hours so carried bears to full-time enrollment.

(e) Scholarships awarded under this Section may be used by a child without regard to his or her age. The holder of a Scholarship awarded under this Section shall be subject to all examinations and academic standards, including the maintenance of minimum grade levels, that are applicable generally to other enrolled students at the Illinois institution of higher learning where the Scholarship is being used.

(f) An applicant is eligible for a scholarship under this Section when the Commission finds the applicant:

(1) is the natural child, legally adopted child, or step-child of an eligible dislocated energy worker; and

(2) in the absence of transition scholarship assistance, will be deterred by financial considerations from completing an educational program at the state-supported Illinois institution of higher learning of his or her choice.

(g) Funds shall be made available from the Energy Transition Assistance Fund to the Commission to provide these grants.

(h) The scholarship shall only cover tuition and fees at the In-District/In-State rates but shall not exceed the cost equivalent of one calendar year of full-time enrollment, including summer terms, at the University of Illinois. The Commission shall determine the grant amount for each student.

Section 5-50. Energy Transition Community Grants.

(a) Subject to appropriation, the Department shall establish an Energy Transition Community Grant Program to award grants to promote economic development in eligible communities.

(b) Funds shall be made available from the Energy Transition Assistance Fund to the Department to provide these grants.

(c) Communities eligible to receive these grants must meet one or more of the following:

(1) the area contains a fossil fuel or nuclear power plant that was retired from service or has significantly reduced service within 10 years before the application for designation or will be retired or have service significantly reduced within 5 years following the application for designation;

(2) the area contains a coal mine that was closed or had operations significantly reduced within 10 years before the application for designation or is anticipated to be closed or have operations; or

(3) the area contains a nuclear power plant that was decommissioned, but continued storing nuclear waste before the effective date of this Act.

(d) Local units of governments in eligible areas may join with any other local unit of government, economic development organization, local educational institutions, community-based groups, or with any number or combination thereof to apply for the Energy Transition Community Grant.

(e) To receive grant funds, an eligible community must submit an application to the Department, using a form developed by the Department.

(f) For grants awarded to counties or other entities that are not the city that hosts or has hosted the investor-owned electric generating plant, a resolution of support for the project from the city or cities that hosts or has hosted the investor-owned electric generating plant is required to be submitted with the application.

(g) Grants must be used to plan for or address the economic and social impact on the community or region of plant retirement or transition.

(h) Project applications should include community input and consultation with a diverse set of stakeholders including, but not limited to: Regional Planning Councils, where applicable; economic development organizations; low-income or environmental justice communities; educational institutions; elected and appointed officials; organizations representing workers; and other relevant organizations.

(i) Grant costs are authorized to procure third-party vendors for grant writing and implementation costs, including for guidance and opportunities to apply for additional federal, State, local and private funding resources. If the application is approved for pre-award, one-time reimbursable costs to apply for the Energy Transition Community Grant are authorized up to 3% of the award.

Section 5-55. Energy Transition Assistance Fund.

(a) The Energy Transition Assistance Fund is created as a special fund in the State treasury to be used by the Department for purposes provided under this Act. The Department shall be responsible for the administration of the Fund.

(b) The Department is authorized to utilize up to 10% of the Energy Transition Assistance Fund for administrative and operational expenses to implement the requirements of this Act.

(c) The Fund shall be used to fund the following programs: Energy Transition Community Grants, Energy Transition Workforce Program, Energy Transition Barrier Reduction Program, Displaced Energy Worker Dependent Scholarship, and Displaced Energy Worker Bill of Rights.

(d) The Department shall strive to direct at least 40% of the expenditures in the Fund toward programs that benefit equity investment eligible communities.

Section 5-60. State Energy Transition Council.

(a) The State Energy Transition Council is hereby created within the Department.

(b) The Council shall consist of the following members, or their respective designees, and a staff member from each listed State agency to provide technical support to the Council:

the Director of Commerce and Economic Opportunity, who shall serve as the chair of the Council;

the Director of Employment Security;

the Secretary of Human Services;

the Director of Labor;

the Director of the Illinois Environmental Protection Agency;

the Executive Director of the Illinois Community College Board;

the State Superintendent of Education; and

the directors of such other State agencies as a majority of the Council may select.

The President of the Senate, the Minority Leader of the Senate, the Speaker of the House of Representatives, and the Minority Leader of the House of Representatives shall each appoint one member of the Council.

Members shall serve without compensation.

(c) The Council shall:

(1) further determine policy goals and plans of State agency activity as it relates to workforce and economic energy transition opportunities and support;

(2) align local, State and federal resources and programming, and leverage additional resources and programming, to invest in and support coal transition workers and coal transition communities;

(3) perform an assessment of existing tools and support offered through federal and State programs to meet the goals established by the Council;

(4) explore ways to support communities and energy workers as the State of Illinois transitions to a clean energy economy; and

(5) guide, inform and provide recommendations of policy proposals offered by the Energy Transition Advisory Council.

(d) The Council shall conduct its first meeting within 30 days after all members have been appointed. The Council shall meet quarterly after its first meeting. Additional hearings and public meetings are permitted at the discretion of the members. The Council may meet in person or through video or audio conference.

Section 5-65. Energy Transition Advisory Council.

(a) The Energy Transition Advisory Council is hereby created within the Department.

(b) The Council shall consist of the following voting members:

(1) two members representing trade associations;

(2) two members representing a labor union;

(3) two members representing local communities impacted by electric generating plant closures;

(4) two members representing electric generating plant operators;

(5) two members representing economic development organizations;

(6) two low-income persons residing in coal communities;

(7) two members representing higher education;

(8) two residents of environmental justice communities;

(9) two members from community-based organizations in environmental justice communities and community-based organizations serving low-income persons and families;

(10) two members who are policy or implementation experts on small business development, contractor incubation, or small business lending and financing needs;

(11) two members who are policy or implementation experts on workforce development for populations and individuals such as low-income persons and families, environmental justice communities, BIPOC communities, justice-involved persons, persons who are or were in the child welfare system, energy workers, gender nonconforming and transgender individuals, and youth; and

(12) two representatives of clean energy businesses, nonprofit organizations, or other groups that provide clean energy.

The President of the Senate, the Minority Leader of the Senate, the Speaker of the House of Representatives, and the Minority Leader of the House of Representatives shall each appoint one non-voting member of the Council.

(c) The Council shall:

(1) Coordinate and inform on worker and community support priorities beyond current federal, State, local, and private programs and resources.

(2) Advise and produce recommendations for further federal, State, and local programs and activities.

(3) Other duties determined by the Council to further the economic prosperity of the individuals and communities impacted by the energy transition.

(d) The Council shall conduct its first meeting within 30 days after all members have been appointed. The Council shall meet quarterly after its first meeting. Additional hearings and public meetings are permitted at the discretion of the members. The Council may meet in person or through video or audio conference.

(e) Members shall serve without compensation and may be reimbursed for reasonable expenses incurred in the performance of their duties from funds appropriated for that purpose.

Section 5-70. The Illinois Worker Adjustment and Retraining Notification Act is amended by changing Section 10 as follows:

(820 ILCS 65/10)

Sec. 10. Notice.

(a) An employer may not order a mass layoff, relocation, or employment loss unless, 60 days before the order takes effect, the employer gives written notice of the order to the following:

(1) affected employees and representatives of affected employees; and

(2) the Department of Commerce and Economic Opportunity and the chief elected official of each municipal and county government within which the employment loss, relocation, or mass layoff occurs.

(a-5) An employer of an investor-owned electric generating plant or coal mining operation may not order a mass layoff, relocation, or employment loss unless, 2 years before the order takes effect, the employer gives written notice of the order to the following:

(1) affected employees and representatives of affected employees; and

(2) the Department of Commerce and Economic Opportunity and the chief elected official of each municipal and county government within which the employment loss, relocation, or mass layoff occurs.

(b) An employer required to give notice of any mass layoff, relocation, or employment loss under this Act shall include in its notice the elements required by the federal Worker Adjustment and Retraining Notification Act (29 U.S.C. 2101 et seq.).

(c) Notwithstanding the requirements of subsection (a), an employer is not required to provide notice if a mass layoff, relocation, or employment loss is necessitated by a physical calamity or an act of terrorism or war.

(d) The mailing of notice to an employee's last known address or inclusion of notice in the employee's paycheck shall be considered acceptable methods for fulfillment of the employer's obligation to give notice to each affected employee under this Act.

(e) In the case of a sale of part or all of an employer's business, the seller shall be responsible for providing notice for any plant closing or mass layoff in accordance with this Section, up to and including the effective date of the sale. After the effective date of the sale of part or all of an employer's business, the purchaser shall be responsible for providing notice for any plant closing or mass layoff in accordance with this Section. Notwithstanding any other provision of this Act, any person who is an employee of the seller (other than a part-time employee) as of the effective date of the sale shall be considered an employee of the purchaser immediately after the effective date of the sale.

(f) An employer which is receiving State or local economic development incentives for doing or continuing to do business in this State may be required to provide additional notice pursuant to Section 15 of the Business Economic Support Act.

(g) The rights and remedies provided to employees by this Act are in addition to, and not in lieu of, any other contractual or statutory rights and remedies of the employees, and are not intended to alter or affect such rights and remedies, except that the period of notification required by this Act shall run concurrently with any period of notification required by contract or by any other law.

(h) It is the sense of the General Assembly that an employer who is not required to comply with the notice requirements of this Section should, to the extent possible, provide notice to its employees about a proposal to close a plant or permanently reduce its workforce.

(Source: P.A. 93-915, eff. 1-1-05.)

Article 10. Community Energy and Climate Planning

Section 10-1. 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 10-5. Findings and 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 10-10. 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 10-15. Community Energy and Climate Plans; creation.

(a) Pursuant to the procedures in Section 10-20, 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 may:

(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;

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

(9) ensure minorities, women, people with disabilities, and veterans meaningfully participate in the transition to a clean energy economy.

(c) A Community Energy and Climate Plan may 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, and the participation of community members in other assistance programs. This also includes an examination of the community's energy use, for electricity, natural gas, 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 may 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 may 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;

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

(10) expand opportunities for minorities, women, people with disabilities, and veterans to meaningfully participate in the transition to a clean energy economy.

Section 10-20. 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 a 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.

(e) The Community Energy and Climate Plans shall take into account other applicable or relevant economic development plans, such as a Comprehensive Economic Development Strategy, developed by a local unit of government, economic development organization, or Regional Planning Council.

Section 10-25. 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 15. Minimum Energy and Water Efficiency Standards

Section 15-1. Short title. This Article may be cited as the Minimum Energy and Water Efficiency Standards Act.

References in this Article to "this Act" mean this Article.

Section 15-5. Findings. The General Assembly finds that:

(1) Efficiency standards for certain products sold or installed in the State assure consumers and businesses that such products meet minimum efficiency performance levels, thus reducing energy and water waste and saving consumers and businesses money on utility bills.

(2) Efficiency standards contribute to the economy of this State by helping to better balance supply and demand for both energy and water, thus reducing pressure that creates higher natural gas, electricity, and water prices. By saving consumers and businesses money on utility bills, efficiency standards help the State and local economy, since utility bill savings can be spent on local goods and services.

(3) Such efficiency standards save energy and thus reduce pollution and other environmental impacts associated with the production, distribution, and use of electricity, natural gas, and other fuels.

(4) Such water efficiency standards save water and thus reduce the strain on the water supply. Furthermore, improved water efficiency can reduce or delay the need for water and sewer infrastructure improvements.

(5) Such efficiency standards can make electricity and natural gas systems more reliable by reducing the strain on systems during peak demand periods. Furthermore, improved efficiency can reduce or delay the need for new power plants, power transmission lines, and power distribution system upgrades as well as new and expanded gas pipelines.

Section 15-10. Definitions. In this Act:

"Agency" means the Illinois Environmental Protection Agency.

"Air purifier", also known as "room air cleaner", means an electric, cord-connected, portable appliance with the primary function of removing particulate matter from the air and which can be moved from room to room.

"Cold-only unit" means a water cooler that dispenses cold water only.

"Cold temperature fluorescent lamp" means a fluorescent lamp that is not a compact fluorescent lamp that is: (1) specifically designed to start at -20° F when used with a ballast conforming to the requirements of ANSI C78.81 and ANSI C78.901; and (2) expressly designated as a cold temperature lamp both in markings on the lamp and in marketing materials, including catalogs, sales literature, and promotional materials.

"Commercial dishwasher" means a machine designed to clean and sanitize plates, pots, pans, glasses, cups, bowls, utensils, and trays by applying sprays of detergent solution (with or without blasting media granules) and a sanitizing rinse.

"Commercial fryer" means an appliance, including a cooking vessel, in which oil is placed to such a depth that the cooking food is essentially supported by displacement of the cooking fluid rather than by the bottom of the vessel. Heat is delivered to the cooking fluid by means of an immersed electric element of band-wrapped vessel (electric fryers) or by heat transfer from gas burners through either the walls of the fryer or through tubes passing through the cooking fluid (gas fryers).

"Commercial hot-food holding cabinet" means a heated, fully enclosed compartment with one or more solid or transparent doors designed to maintain the temperature of hot food that has been cooked using a separate appliance. "Commercial hot-food holding cabinet" does not include heated glass merchandizing cabinets, drawer warmers, or cook-and-hold appliances.

"Commercial oven" means a chamber designed for heating, roasting, or baking food by conduction, convection, radiation, or electromagnetic energy.

"Commercial steam cooker" or "compartment steamer" means a device with one or more food-steaming compartments in which the energy in the steam is transferred to the food by direct contact and includes countertop models, wall-mounted models, and floor models mounted on a stand, pedestal, or cabinet-style base.

"Compensation" means money or any other valuable thing, regardless of form, received or to be received by a person for services rendered.

"Cook and cold unit" means a water cooler that dispenses both cold and room temperature water.

"Decorative gas fireplace" means a vented fireplace, including appliances that are freestanding, recessed, zero clearance, or gas fireplace inserts, that is fueled by natural gas or propane, marked for decorative use only, and not equipped with a thermostat or intended for use as a heater.

"Dual-flush effective flush volume" means the average flush volume of 2 reduced flushes and one full flush.

"Dual-flush water closet" means a water closet incorporating a feature that allows the user to flush the water closet with either a reduced or a full volume of water.

"Electric vehicle supply equipment" means conductors, including, but not limited to, ungrounded, grounded, and equipment grounding conductors, electric vehicle connectors, attachment plugs, and all other fittings, devices, power outlets, or apparatuses installed specifically for the purpose of delivering energy from the premises wiring to an electric vehicle. "Electric vehicle supply equipment" includes charging cords with NEMA 5-15P and NEMA 5-20P attachment plugs. "Electric vehicle supply equipment" does not include conductors, connectors, and fittings that are part of an electric vehicle.

"Faucet" means a private lavatory faucet, residential kitchen faucet, metering faucet, public lavatory faucet, or replacement aerator for a private lavatory, public lavatory, or residential kitchen faucet.

"Gas fireplace" means a decorative gas fireplace or a heating gas fireplace.

"Handheld shower head" means a shower head that can be held or fixed in place for the purpose of spraying water onto a bather and that is connected to a flexible hose.

"Heating gas fireplace" means a vented fireplace, including appliances that are freestanding, recessed, zero clearance, or gas fireplace inserts, that is fueled by natural gas or propane and is not a decorative fireplace.

"High color rendering index fluorescent lamp" or "high CRI fluorescent lamp" means a fluorescent lamp with a color rendering index of 87 or greater that is not a compact fluorescent lamp.

"Hot and cold unit" means a water cooler that dispenses hot, cold, or room temperature water.

"Impact-resistant fluorescent lamp" means a fluorescent lamp that is not a compact fluorescent lamp that:

(1) has a coating or equivalent technology that is compliant with NSF/ANSI 51 and is designed to contain glass if the glass envelope of the lamp is broken; and

(2) is designated and marketed for the intended application, with:

(A) the designation on the lamp packaging; and

(B) marketing materials that identify the lamp as being impact-resistant, shatter-resistant, shatterproof, or shatter-protected.

"Metering faucet" means a faucet with a fitting that, when turned on, will gradually shut itself off over a period of several seconds.

"On demand water cooler" means a water cooler that heats water as it is requested, typically taking a few minutes to deliver.

"Plumbing fixture" means an exchangeable device that connects to a plumbing system to deliver and drain away water and waste.

"Portable electric spa" means a factory-built electric spa or hot tub which may or may not include any combination of integral controls, water heating, or water circulating equipment.

"Pressure regulator" means a device that maintains constant operating pressure immediately downstream from the device, given higher pressure upstream.

"Public lavatory faucet" means a faucet with a fitting designed to be installed in nonresidential bathrooms that are exposed to walk-in traffic.

"Replacement aerator" means an aerator sold as a replacement, separate from the faucet to which it is intended to be attached.

"Residential ventilating fan" means a ceiling-mounted fan, wall-mounted fan, or remotely mounted in-line fan designed to be used in a bathroom or utility room for the purpose of moving air from inside the building to the outdoors.

"Shower head" means a device through which water is discharged for a shower bath. "Shower head" includes a handheld shower head. "Shower head" does not include a shower head for a safety shower.

"Spray sprinkler body" means the exterior case or shell of a sprinkler incorporating a means of connection to the piping system designed to convey water to a nozzle or orifice.

"State-regulated general service lamp" means any of the following medium-base incandescent light bulbs:

(1) Reflector lamps that are:

(A) ER30, BR30, BR40, or ER40 lamps rated at 50 watts or less;

(B) BR30, BR40, or ER40 lamps rated at 65 watts; or

(C) R20 lamps rated at 45 watts or less.

(2) B, BA, CA, F, and G shape lamps, as defined in ANSI C79.1:2002 with a lumen output of greater than or equal to 200 and rated at 40 watts or less.

(3) A and C shape lamps, as defined in ANSI C79.1:2002 with lumen output greater than or equal to 200 and less than 310.

(4) Shatter-resistant lamps.

(5) 3-way lamps.

"Storage-type water cooler" means a water cooler in which thermally conditioned water is stored in a tank in the water cooler and is available instantaneously. "Storage-type water cooler" includes point-of-use, dry storage compartment, and bottled water coolers.

"Trough-type urinal" means a urinal designed for simultaneous use by 2 or more persons.

"Urinal" means a plumbing fixture that receives only liquid body waste and conveys the waste through a trap into a drainage system.

"Water closet" means a plumbing fixture having a water-containing receptor that receives liquid and solid body waste through an exposed integral trap into a drainage system.

"Water cooler" means a freestanding device that consumes energy to cool or heat potable water.

Section 15-15. Scope.

(a) The provisions of this Act apply to:

(1) air purifiers;

(2) commercial dishwashers;

(3) commercial fryers;

(4) commercial hot-food holding cabinets;

(5) commercial ovens;

(6) commercial steam cookers;

(7) computers and computer monitors;

(8) electric vehicle supply equipment;

(9) faucets;

(10) gas fireplaces;

(11) high CRI, cold temperature, and impact-resistant fluorescent lamps;

(12) portable electric spas;

(13) residential ventilating fans;

(14) shower heads;

(15) spray sprinkler bodies;

(16) State-regulated general service lamps;

(17) urinals;

(18) water closets;

(19) water coolers; and

(20) any other products as may be designated by the Agency in accordance with Section 15-30 or under Section 15-40.

(b) The provisions of this Act do not apply to:

(1) new products manufactured in the State and sold outside the State;

(2) new products manufactured outside the State and sold at wholesale inside the State for final retail sale and installation outside the State;

(3) products installed in mobile manufactured homes at the time of construction; or

(4) products designed expressly for installation and use in recreational vehicles.

Section 15-20. Standards.

(a) Not later than one year after the effective date of this Act, the Agency shall adopt rules establishing minimum efficiency standards for the types of new products set forth in Section 15-15.

(b) The rules shall provide for the following minimum efficiency standards:

(1) Air purifiers, except industrial air purifiers, shall meet the following requirements as measured in accordance with the ENERGY STAR Program Requirements Product Specification for Room Air Cleaners, Version 2.0:

(A) clean air delivery rate for smoke shall be 30 or greater;

(B) for models with a clean air delivery rate for smoke less than 100, clean air delivery rate per watt for smoke shall be greater than or equal to 1.7;

(C) for models with a clean air delivery rate for smoke greater than or equal to 100 and less than 150, clean air delivery rate per watt for smoke shall be greater than or equal to 1.9;

(D) for models with a clean air delivery rate for smoke greater than or equal to 150, clean air delivery rate per watt for smoke shall be greater than or equal to 2.0;

(E) for ozone-emitting models, measured ozone shall be less than or equal to 50 parts per billion (ppb);

(F) for models with a Wi-Fi network connection enabled by default when shipped, partial on mode power shall not exceed 2 watts; and

(G) For models without a Wi-Fi network connection enabled by default when shipped, partial on mode power shall not exceed 1 watt.

(2) Commercial dishwashers included in the scope of the ENERGY STAR Program Requirements Product Specification for Commercial Dishwashers, Version 2.0, shall meet the qualification criteria of that specification.

(3) Commercial fryers included in the scope of the ENERGY STAR Program Requirements Product Specification for Commercial Fryers, Version 2.0, shall meet the qualification criteria of that specification.

(4) Commercial hot-food holding cabinets shall meet the qualification criteria of the ENERGY STAR Program Requirements Product Specification for Commercial Hot Food Holding Cabinets, Version 2.0.

(5) Commercial steam cookers shall meet the requirements of the ENERGY STAR Program Requirements Product Specification for Commercial Steam Cookers, Version 1.2. Commercial ovens included in the scope of the ENERGY STAR Program Requirements Product Specification for Commercial Ovens, Version 2.2, shall meet the qualification criteria of that specification.

(6) Computers and computer monitors shall be consistent with similar energy and water efficiency standards adopted federally and in other states.

(7) Electric vehicle supply equipment included in the scope of the ENERGY STAR Program Requirements Product Specification for Electric Vehicle Supply Equipment, Version 1.0 (Rev. April 2017), shall meet the qualification criteria of that specification.

(8) Faucets, except for metering faucets, shall meet the standards shown in this paragraph when tested in accordance with Appendix S to Subpart B of Part 430 of Title 10 of the Code of Federal Regulations and compliance with those requirements shall be, "Uniform Test Method for Measuring the Water Consumption of Faucets and Showerheads", as in effect on January 1, 2020.

(A) Lavatory faucets and replacement aerators shall not exceed a maximum flow rate of 1.5 gallons per minute at 60 pounds per square inch.

(B) Residential kitchen faucets and replacement aerators shall not exceed a maximum flow rate of 1.8 gallons per minute at 60 pounds per square inch, with optional temporary flow of 2.2 gallons per minute, provided they default to a maximum flow rate of 1.8 gallons per minute at 60 pounds per square inch after each use.

(C) Public lavatory faucets and replacement aerators shall not exceed a maximum flow rate of 0.5 gallons per minute at 60 pounds per square inch.

(9) Gas fireplaces shall comply with the following requirements:

(A) Gas fireplaces shall be capable of automatically extinguishing any pilot flame when the main gas burner flame is established and when it is extinguished.

(B) Gas fireplaces must prevent any ignition source for the main gas burner flame from operating continuously for more than 7 days.

(C) Decorative gas fireplaces must have a direct vent configuration, unless marked for replacement use only.

(D) Heating gas fireplaces shall have a fireplace efficiency greater than or equal to 50% when tested in accordance with CSA P.4.1-15, "Testing Method for Measuring Annual Fireplace Efficiency".

(10) High CRI, cold temperature, and impact-resistant fluorescent lamps shall meet the minimum efficacy requirements contained in Section 430.32(n)(4) of Title 10 of the Code of Federal Regulations as in effect on January 1, 2020, as measured in accordance with Appendix R to Subpart B of Part 430 of Title 10 of the Code of Federal Regulations, "Uniform Test Method for Measuring Average Lamp Efficacy, Color Rendering Index, and Correlated Color Temperature of Electric Lamps", as in effect on January 1, 2020.

(11) Portable electric spas shall meet the requirements of the "American National Standard for Portable Electric Spa Energy Efficiency".

(12) In-line residential ventilating fans shall have a fan motor efficacy of no less than 2.8 cubic feet per minute per watt. All other residential ventilating fans shall have a fan motor efficacy of no less than 1.4 cubic feet per minute per watt for airflows less than 90 cubic feet per minute and no less than 2.8 cubic feet per minute per watt for other airflows when tested in accordance with Home Ventilation Institute Publication 916 "HVI Airflow Test Procedure".

(13) Shower heads shall not exceed a maximum flow rate of 2.0 gallons per minute at 80 pounds per square feet when tested in accordance with Appendix S to Subpart B of Part 430 of Title 10 of the Code of Federal Regulations and compliance with those requirements shall be "Uniform Test Method for Measuring the Water Consumption of Faucets and Showerheads", as in effect on January 1, 2020.

(14) Spray sprinkler bodies that are not specifically excluded from the scope of the WaterSense Specification for Spray Sprinkler Bodies, Version 1.0, shall include an integral pressure regulator and shall meet the water efficiency and performance criteria and other requirements of that specification.

(15) State-regulated general service lamps shall meet or exceed a lamp efficacy of 45 lumens per watt when tested in accordance with the federal test procedures for general service lamps, prescribed in Section 430.23(gg) of Title 10 of the Code of Federal Regulations as in effect on January 1, 2020.

(16) Urinals and water closets, other than those designed and marketed exclusively for use at prisons or mental health facilities, shall meet the standards shown in paragraphs (1) through (3) when tested in accordance with Appendix T to Subpart B of Part 430 of Title 10 of the Code of Federal Regulations, "Uniform Test Method for Measuring the Water Consumption of Water Closets and Urinals", as in effect on January 1, 2020, and water closets shall pass the waste extraction test for water closets of the American Society of Mechanical Engineers A112.19.2/CSA B45.1-2018.

(A) Wall-mounted urinals, except for trough-type urinals, shall have a maximum flush volume of 0.5 gallons per flush.

(B) Floor-mounted urinals, except for trough-type urinals, shall have a maximum flush volume of 0.5 gallons per flush.

(C) Water closets, except for dual-flush tank-type water closets, shall have a maximum flush volume of 1.28 gallons per flush.

(D) Dual-flush tank-type water closets shall have a maximum dual-flush effective flush volume of 1.28 gallons per flush.

(18) Water coolers included in the scope of the ENERGY STAR Program Requirements Product Specification for Water Coolers, Version 2.0, shall have on mode with no water draw energy consumption less than or equal the following values as measured in accordance with the test requirements of that program:

(A) 0.16 kilowatt-hours per day for cold-only units and cook and cold units;

(B) 0.87 kilowatt-hours per day for storage-type hot and cold units; and

(C) 0.18 kilowatt-hours per day for on demand hot and cold units.

Section 15-25. Implementation.

(a) On or after January 1, 2023, no new air purifier, cold temperature fluorescent lamp, commercial dishwasher, commercial fryer, commercial hot-food holding cabinet, commercial oven, commercial steam cooker, computer or computer monitor, electrical vehicle supply equipment, faucet, gas fireplace, high CRI fluorescent lamp, impact-resistant fluorescent lamp, portable electric spa, residential ventilating fan, shower head, spray sprinkler body, State-regulated general service lamp, urinal, water closet, or water cooler may be sold or offered for sale, lease, or rent in the State unless the new product meets the requirements of the standards provided in Section 15-20.

(b) No later than 6 months from the effective date of this Act, and as necessary thereafter, the Agency shall determine which general service lamps are subject to federal preemption. On or after January 1, 2022, no general service lamp that is not subject to federal preemption may be sold or offered for sale in the State unless the efficiency of the new product meets or exceeds the efficiency standards provided in Section 15-20.

(c) One year after the date upon which the sale or offering for sale of certain products becomes subject to the requirements of subsection (a) or (b) of this Section, no such products may be installed for compensation in the State unless the efficiency of the new product meets or exceeds the efficiency standards provided in Section 15-20.

Section 15-30. New and revised standards. The Agency may adopt rules, in accordance with the provisions of Illinois Administrative Procedure Act, to establish increased efficiency standards for the products listed or incorporated in Section 15-15. The Agency may also establish standards for products not specifically listed in Section 15-15.

Section 15-35. Protection against repeal of federal standards.

(a) If any of the energy or water conservation standards issued or approved for publication by the Office of the United States Secretary of Energy as of January 1, 2018, under the federal Energy Policy and Conservation Act, are withdrawn, repealed, or otherwise voided, the minimum energy or water efficiency level permitted for products previously subject to federal energy or water conservation standards shall be the previously applicable federal standards, and no such new product may be sold or offered for sale, lease or rent in the State unless it meets or exceeds such standards.

(b) This Section shall not apply to any federal energy or water conservation standard set aside by a court upon the petition of a person who will be adversely affected, as provided in Section 6306(b) of Title 42 of the United States Code.

Section 15-40. Testing, certification, labeling, and enforcement.

(a) The manufacturers of products covered by this Act shall test samples of their products in accordance with the test procedures adopted under this Act. The Agency may adopt updated test methods when new versions of test procedures become available.

(b) Manufacturers of new products covered by Section 15-15 of this Act shall certify to the Agency that such products are in compliance with the provisions of this Act. Such certifications shall be based on test results. The Agency shall adopt rules governing the certification of such products and shall coordinate with the certification programs of other states and federal agencies with similar standards.

(c) Manufacturers of new products covered by Section 15-15 of this Act shall identify each product offered for sale or installation in the State as in compliance with the provisions of this Act by means of a mark, label, or tag on the product and packaging at the time of sale or installation. The Agency shall adopt rules governing the identification of such products and packaging, which shall be coordinated to the greatest practical extent with the labeling programs of other states and federal agencies with equivalent efficiency standards. The Agency shall allow the use of existing marks, labels, or tags, which connote compliance with the efficiency requirements of this Act.

(d) The Agency may test products covered by Section 15-15. If products so tested are found not to be in compliance with the minimum efficiency standards established under Section 15-20, the Agency shall:

(1) charge the manufacturer of such product for the cost of product purchase and testing; and

(2) make information available to the public on products found not to be in compliance with the standards.

(e) With prior notice and at reasonable and convenient hours, the Agency may cause periodic inspections to be made of distributors or retailers of new products covered by Section 15-15 in order to determine compliance with the provisions of this Act.

(f) The Agency shall investigate complaints received concerning violations of this Act and shall report the results of such investigations to the Attorney General. The Attorney General may institute proceedings to enforce the provisions of this Act. Any manufacturer, distributor, or retailer, or any person who installs a product covered by this Act for compensation, who violates any provision of this Act, shall be issued a warning by the Agency for any first violation and subject to a civil penalty of up to one hundred dollars for each offense. Repeat violations shall be subject to a civil penalty of not more than $500 for each offense. Each violation shall constitute a separate offense, and each day that such violation continues shall constitute a separate offense.

(g) The Agency may adopt such further rules as necessary to ensure the proper implementation and enforcement of the provisions of this Act.

Article 20. Electric Vehicle Charging Act

Section 20-1. Short title. This Article may be cited as the Electric Vehicle Charging Act. References in this Article to "this Act" mean this Article.

Section 20-5. Legislative intent. Electric vehicles are an important tool to fight the climate crisis, tackle air pollution, and provide safe, clean, and affordable personal transportation. The State should encourage urgent and widespread adoption of electric vehicles. Since most current electric vehicle owners are single-family homeowners who charge at home, providing access to home charging for those in multi-unit dwellings is crucial to wider electric vehicle adoption. This includes condominium unit owners and renters, regardless of parking space ownership and regardless of income. Therefore, a significant portion of parking spaces in new and renovated residential and commercial developments must be capable of electric vehicle charging. Additionally, renters and condominium unit owners must be able to install charging equipment for their cars under reasonable conditions.

Section 20-10. Applicability. This Act applies to new or renovated residential or nonresidential buildings that have parking spaces and are constructed or renovated after the effective date of this Act.

Section 20-15. Definitions. As used in this Act:

"Association" has the meaning set forth in subsection (o) of Section 2 of the Condominium Property Act or Section 1-5 of the Common Interest Community Association Act, as applicable.

"Electric vehicle" means (i) a vehicle that is exclusively powered by and refueled by electricity, (2) must be plugged in to charge, and (3) is licensed to drive on public roadways. "Electric vehicle" does not include (i) electric motorcycles, or (ii) hybrid electric vehicles and extended-range electric vehicles that are also equipped with conventional fueled propulsion or auxiliary engines.

"Electric vehicle capable" means having an installed electrical panel capacity with a dedicated branch circuit and a continuous raceway from the panel to the future electric vehicle parking space.

"Electric vehicle station" means a station that is designed in compliance with the relevant building code and delivers electricity from a source outside an electric vehicle into one or more electric vehicles.

"Electric vehicle system" includes several charging points simultaneously connecting several electric vehicles to the electric vehicle charging station and any related equipment needed to facilitate charging an electric vehicle. "Electric vehicle charging system" means a device that is:

(1) used to provide electricity to an electric vehicle;

(2) designed to ensure that a safe connection has been made between the electric grid and the electric vehicle; and

(3) able to communicate with the vehicle's control system so that electricity flows at an appropriate voltage and current level. An electric vehicle charging system may be wall mounted or pedestal style, may provide multiple cords to connect with electric vehicles, and shall:

(i) be certified by underwriters laboratories or have been granted an equivalent certification; and

(ii) comply with the current version of Article 625 of the National Electrical Code.

"Electric vehicle supply equipment" means a conductor, including an ungrounded, grounded, and equipment grounding conductor, and electric vehicle connectors, attachment plugs, and all other fittings, devices, power outlets, and apparatuses installed specifically for the purpose of transferring energy between the premises wiring and the electric vehicle.

"Electric vehicle ready" means a parking space that is designed and constructed to include a fully wired circuit with a 208-volt to 250-volt, rated no more than 50-ampere electric vehicle charging receptacle outlet or termination point, including the conduit, wiring, and electrical service capacity necessary to serve that receptacle, to allow for future electric vehicle supply equipment.

"Level 1" means a charging system that provides charging through a 120-volt AC plug with a cord connector that meets the SAE International J2954 standard or successor standard.

"Level 2" means a charging system that provides charging through a 208-volt to 240-volt AC plug with a cord connector that meets the SAE International J2954 standard or a successor standard.

"New" means any newly constructed building and associated newly constructed parking facility.

"Reasonable restriction" means a restriction that does not significantly increase the cost of the electric vehicle charging station or electric vehicle charging system or significantly decrease its efficiency or specified performance.

"Renovated" means altered or added where electrical service capacity is increased.

Section 20-20. Residential requirements. A new or renovated residential building shall have:

(1) 100% of its total parking spaces electric vehicle ready, if there are one to 6 parking spaces;

(2) 100% of its total parking spaces electric vehicle capable, of which at least 20% shall be electric vehicle ready, if there are 6 to 23 parking spaces; or

(3) 100% of its total parking spaces electric vehicle capable, if there are 24 or more parking spaces, of which at least 5 spots shall be EV Ready. Additionally, if there are 24 or more parking spaces, a new or renovated residential building shall provide at least one parking space with electric vehicle supply equipment installed, and for each additional parking space with electric vehicle supply equipment installed, the electric vehicle ready requirement is decreased by 2%.

Where additional parking exists or is feasible, each parking space shall be marked and signed for common use by residents. A resident shall use an electric vehicle parking space only when he or she is charging his or her electric vehicle.

Section 20-25. Nonresidential requirements. A new or renovated nonresidential building shall have 20% of its total parking spaces electric vehicle ready.

Section 20-30. Electric vehicle charging station policy for unit owners.

(a) Any covenant, restriction, or condition contained in any deed, contract, security interest, or other instrument affecting the transfer or sale of any interest in a condominium or common interest community, and any provision of a governing document that effectively prohibits or unreasonably restricts the installation or use of an electric vehicle charging station within a unit owner's unit or a designated parking space, including, but not limited to, a deeded parking space, a parking space in a unit owner's exclusive use common area, or a parking space that is specifically designated for use by a particular unit owner, or is in conflict with this Section, is void and unenforceable.

(b) This Section does not apply to provisions that impose a reasonable restriction on an electric vehicle charging station. However, it is the policy of this State to promote, encourage, and remove obstacles to the use of an electric vehicle charging station.

(c) An electric vehicle charging station shall meet applicable health and safety standards and requirements imposed by State and local authorities, and all other applicable zoning, land use, or other ordinances or land use permits.

(d) If approval is required for the installation or use of an electric vehicle charging station, the association shall process and approve the application in the same manner as an application for approval of an architectural modification to the property, and the association shall not willfully avoid or delay the adjudication of the application. The approval or denial of an application shall be in writing.

(e) If the electric vehicle charging station is to be placed in a common area or exclusive use common area, as designated by the condominium or common interest community association, the following applies:

(1) The unit owner shall first obtain approval from the association to install the electric vehicle charging station and the association shall approve the installation if the unit owner agrees, in writing, to:

(i) comply with the association's architectural standards for the installation of the electric vehicle charging station;

(ii) engage a licensed electrical contractor to install the electric vehicle charging station;

(iii) within 14 days after approval, provide a certificate of insurance that names the association as an additional insured party under the unit owner's insurance policy as required under paragraph (3); and

(iv) pay for both the costs associated with the installation of and the electricity usage associated with the electric vehicle charging station.

(2) The unit owner, and each successive unit owner of the electric vehicle charging station, is responsible for:

(i) costs for damage to the electric vehicle charging station, common area, exclusive use common area, or separate interests resulting from the installation, maintenance, repair, removal, or replacement of the electric vehicle charging station;

(ii) costs for the maintenance, repair, and replacement of the electric vehicle charging station until it has been removed, and for the restoration of the common area after removal;

(iii) costs of electricity associated with the charging station, which shall be based on:

(A) an inexpensive submetering device; or

(B) a reasonable calculation of cost, based on the average miles driven, efficiency of the electric vehicle calculated by the United States Environmental Protection Agency, and the cost of electricity for the common area; and

(iv) disclosing to a prospective buyer the existence of any electric vehicle charging station of the unit owner and the related responsibilities of the unit owner under this Section.

(3) The purpose of the costs under paragraph (2) is for the reasonable reimbursement of electricity usage, and shall not be set to deliberately exceed the reasonable reimbursement.

(4) The unit owner of the electric vehicle charging station, whether the electric vehicle charging station is located within the common area or exclusive use common area, shall, at all times, maintain a liability coverage policy. The unit owner that submitted the application to install the electric vehicle charging station shall provide the association with the corresponding certificate of insurance within 14 days after approval of the application. The unit owner, and each successive unit owner, shall provide the association with the certificate of insurance annually thereafter.

(5) A unit owner is not required to maintain a homeowner liability coverage policy for an existing National Electrical Manufacturers Association standard alternating current power plug.

(f) Except as provided in subsection (g), the installation of an electric vehicle charging station for the exclusive use of a unit owner in a common area that is not an exclusive use common area shall be authorized by the association only if installation in the unit owner's designated parking space is impossible or unreasonably expensive. In such an event, the association shall enter into a license agreement with the unit owner for the use of the space in a common area, and the unit owner shall comply with all of the requirements in subsection (e).

(g) An association may install an electric vehicle charging station in the common area for the use of all unit owners and members of the association. The association shall develop appropriate terms of use for the electric vehicle charging station.

(h) An association may create a new parking space where one did not previously exist to facilitate the installation of an electric vehicle charging station.

(i) An association that willfully violates this Section shall be liable to the unit owner for actual damages and shall pay a civil penalty to the unit owner not to exceed $1,000.

(j) In any action by a unit owner requesting to have an electric vehicle charging station installed and seeking to enforce compliance with this Section, the court shall award reasonable attorney's fees to a prevailing plaintiff.

Section 20-35. Electric vehicle charging system policy for renters.

(a) Notwithstanding any provision in the lease to the contrary, and subject to subsection (b):

(1) A tenant may install, at the tenant's expense for the tenant's own use, a level 1 or level 2 electric vehicle charging system on or in the leased premises.

(2) A landlord shall not assess or charge a tenant any fee for the placement or use of an electric vehicle charging system, except that:

(i) The landlord may:

(A) require reimbursement for the actual cost of electricity provided by the landlord that was used by the electric vehicle charging system; or

(B) charge a reasonable fee for access. If the electric vehicle charging system is part of a network for which a network fee is charged, the landlord's reimbursement may include the amount of the network fee. Nothing in this subparagraph requires a landlord to impose upon a tenant a fee or charge other than the rental payments specified in the lease.

(ii) The landlord may require reimbursement for the cost of the installation of the electric vehicle charging system, including any additions or upgrades to existing wiring directly attributable to the requirements of the electric vehicle charging system, if the landlord places or causes the electric vehicle charging system to be placed at the request of the tenant.

(iii) If the tenant desires to place an electric vehicle charging system in an area accessible to other tenants, the landlord may assess or charge the tenant a reasonable fee to reserve a specific parking space in which to install the electric vehicle charging system.

(b) A landlord may require a tenant to comply with:

(1) bona fide safety requirements consistent with an applicable building code or recognized safety standard for the protection of persons and property;

(2) a requirement that the electric vehicle charging system be registered with the landlord within 30 days after installation; or

(3) reasonable aesthetic provisions that govern the dimensions, placement, or external appearance of an electric vehicle charging system.

(c) A tenant may place an electric vehicle charging system in an area accessible to other tenants if:

(1) the electric vehicle charging system is in compliance with all applicable requirements adopted by a landlord under subsection (b); and

(2) the tenant agrees, in writing, to:

(i) comply with the landlord's design specifications for the installation of an electric vehicle charging system;

(ii) engage the services of a duly licensed and registered electrical contractor familiar with the installation and code requirements of an electric vehicle charging system; and

(iii) provide, within 14 days after receiving the landlord's consent for the installation, a certificate of insurance naming the landlord as an additional insured party on the tenant's renter's insurance policy for any claim related to the installation, maintenance, or use of the electric vehicle charging system or, at the landlord's option, reimbursement to the landlord for the actual cost of any increased insurance premium amount attributable to the electric vehicle charging system, notwithstanding any provision to the contrary in the lease. The tenant shall provide reimbursement for an increased insurance premium amount within 14 days after the tenant receives the landlord's invoice for the amount attributable to the electric vehicle charging system.

(d) If the landlord consents to a tenant's installation of an electric vehicle charging system on property accessible to other tenants, including a parking space, carport, or garage stall, then, unless otherwise specified in a written agreement with the landlord:

(1) The tenant, and each successive tenant with exclusive rights to the area where the electric vehicle charging system is installed, is responsible for costs for damages to the electric vehicle charging system and to any other property of the landlord or another tenant resulting from the installation, maintenance, repair, removal, or replacement of the electric vehicle charging system.

(i) Costs under this paragraph shall be based on:

(A) an inexpensive submetering device; or

(B) a reasonable calculation of cost, based on the average miles driven, efficiency of the electric vehicle calculated by the United States Environmental Protection Agency, and the cost of electricity for the common area.

(ii) The purpose of the costs under this paragraph is for reasonable reimbursement of electricity usage and shall not be set to deliberately exceed that reasonable reimbursement.

(2) Each successive tenant with exclusive rights to the area where the electric vehicle charging system is installed shall assume responsibility for the repair, maintenance, removal, and replacement of the electric vehicle charging system until the electric vehicle charging system is removed.

(3) The tenant, and each successive tenant with exclusive rights to the area where the electric vehicle charging system is installed, shall, at all times, have and maintain an insurance policy covering the obligations of the tenant under this subsection and shall name the landlord as an additional insured party under the policy.

(4) The tenant, and each successive tenant with exclusive rights to the area where the electric vehicle charging system is installed, is responsible for removing the system if reasonably necessary or convenient for the repair, maintenance, or replacement of any property of the landlord, whether or not leased to another tenant.

(e) An electric vehicle charging system installed at the tenant's cost is the property of the tenant. Upon termination of the lease, if the electric vehicle charging system is removable, the tenant may either remove it or sell it to the landlord or another tenant for an agreed price. Nothing in this subsection requires the landlord or another tenant to purchase the electric vehicle charging system.

(f) A landlord that willfully violates this Section shall be liable to the tenant for actual damages, and shall pay a civil penalty to the tenant in an amount not to exceed $1,000.

(g) In any action by a tenant requesting to have an electric vehicle charging system installed and seeking to enforce compliance with this Section, the court shall award reasonable attorney's fees to a prevailing plaintiff.

Article 30. Amendatory Provisions

Section 30-10. The Illinois Governmental Ethics Act is amended by changing Sections 4A-102 and 4A-103 and by adding Section 1-121.5 as follows:

(5 ILCS 420/1-121.5 new)

Sec. 1-121.5. "Public utility" has the meaning provided in Section 3-105 of the Public Utilities Act.

(5 ILCS 420/4A-102) (from Ch. 127, par. 604A-102)

Sec. 4A-102. The statement of economic interests required by this Article shall include the economic interests of the person making the statement as provided in this Section. The interest (if constructively controlled by the person making the statement) of a spouse or any other party, shall be considered to be the same as the interest of the person making the statement. Campaign receipts shall not be included in this statement.

(a) The following interests shall be listed by all persons required to file:

(1) The name, address and type of practice of any professional organization or individual professional practice in which the person making the statement was an officer, director, associate, partner or proprietor, or served in any advisory capacity, from which income in excess of $1200 was derived during the preceding calendar year;

(2) The nature of professional services (other than services rendered to the unit or units of government in relation to which the person is required to file) and the nature of the entity to which they were rendered if fees exceeding $5,000 were received during the preceding calendar year from the entity for professional services rendered by the person making the statement.

(3) The identity (including the address or legal description of real estate) of any capital asset from which a capital gain of $5,000 or more was realized in the preceding calendar year.

(4) The name of any unit of government which has employed the person making the statement during the preceding calendar year other than the unit or units of government in relation to which the person is required to file.

(5) The name of any entity from which a gift or gifts, or honorarium or honoraria, valued singly or in the aggregate in excess of $500, was received during the preceding calendar year.

(b) The following interests shall also be listed by persons listed in items (a) through (f), item (l), item (n), and item (p) of Section 4A-101:

(1) The name and instrument of ownership in any entity doing business in the State of Illinois, in which an ownership interest held by the person at the date of filing is in excess of $5,000 fair market value or from which dividends of in excess of $1,200 were derived during the preceding calendar year. (In the case of real estate, location thereof shall be listed by street address, or if none, then by legal description). No time or demand deposit in a financial institution, nor any debt instrument need be listed;

(2) Except for professional service entities, the name of any entity and any position held therein from which income of in excess of $1,200 was derived during the preceding calendar year, if the entity does business in the State of Illinois. No time or demand deposit in a financial institution, nor any debt instrument need be listed.

(3) The identity of any compensated lobbyist with whom the person making the statement maintains a close economic association, including the name of the lobbyist and specifying the legislative matter or matters which are the object of the lobbying activity, and describing the general type of economic activity of the client or principal on whose behalf that person is lobbying.

(c) The following interests shall also be listed by persons listed in items (a) through (c) and item (e) of Section 4A-101.5:

(1) The name and instrument of ownership in any entity doing business with a unit of local government in relation to which the person is required to file if the ownership interest of the person filing is greater than $5,000 fair market value as of the date of filing or if dividends in excess of $1,200 were received from the entity during the preceding calendar year. (In the case of real estate, location thereof shall be listed by street address, or if none, then by legal description). No time or demand deposit in a financial institution, nor any debt instrument need be listed.

(2) Except for professional service entities, the name of any entity and any position held therein from which income in excess of $1,200 was derived during the preceding calendar year if the entity does business with a unit of local government in relation to which the person is required to file. No time or demand deposit in a financial institution, nor any debt instrument need be listed.

(3) The name of any entity and the nature of the governmental action requested by any entity which has applied to a unit of local government in relation to which the person must file for any license, franchise or permit for annexation, zoning or rezoning of real estate during the preceding calendar year if the ownership interest of the person filing is in excess of $5,000 fair market value at the time of filing or if income or dividends in excess of $1,200 were received by the person filing from the entity during the preceding calendar year.

(d) The following interest shall also be listed by persons listed in items (a) through (f) of Section 4A-101: the name of any spouse or immediate family member living with such person employed by a public utility in this State and the name of the public utility that employs such person.

For the purposes of this Section, the unit of local government in relation to which a person is required to file under item (e) of Section 4A-101.5 shall be the unit of local government that contributes to the pension fund of which such person is a member of the board.

(Source: P.A. 101-221, eff. 8-9-19.)

(5 ILCS 420/4A-103) (from Ch. 127, par. 604A-103)

Sec. 4A-103. The statement of economic interests required by this Article to be filed with the Secretary of State shall be filled in by typewriting or hand printing, shall be verified, dated, and signed by the person making the statement and shall contain substantially the following:

STATEMENT OF ECONOMIC INTEREST

(TYPE OR HAND PRINT)

.............................................................

(name)

.............................................................

(each office or position of employment for which this statement is filed)

.............................................................

(full mailing address)

GENERAL DIRECTIONS:

The interest (if constructively controlled by the person making the statement) of a spouse or any other party, shall be considered to be the same as the interest of the person making the statement.

Campaign receipts shall not be included in this statement.

If additional space is needed, please attach supplemental listing.

1. List the name and instrument of ownership in any entity doing business in the State of Illinois, in which the ownership interest held by the person at the date of filing is in excess of $5,000 fair market value or from which dividends in excess of $1,200 were derived during the preceding calendar year. (In the case of real estate, location thereof shall be listed by street address, or if none, then by legal description.) No time or demand deposit in a financial institution, nor any debt instrument need be listed.

2. List the name, address and type of practice of any professional organization in which the person making the statement was an officer, director, associate, partner or proprietor or served in any advisory capacity, from which income in excess of $1,200 was derived during the preceding calendar year.

3. List the nature of professional services rendered (other than to the State of Illinois) to each entity from which income exceeding $5,000 was received for professional services rendered during the preceding calendar year by the person making the statement.

.............................................................

.............................................................

4. List the identity (including the address or legal description of real estate) of any capital asset from which a capital gain of $5,000 or more was realized during the preceding calendar year.

.............................................................

.............................................................

5. List the identity of any compensated lobbyist with whom the person making the statement maintains a close economic association, including the name of the lobbyist and specifying the legislative matter or matters which are the object of the lobbying activity, and describing the general type of economic activity of the client or principal on whose behalf that person is lobbying.

6. List the name of any entity doing business in the State of Illinois from which income in excess of $1,200 was derived during the preceding calendar year other than for professional services and the title or description of any position held in that entity. (In the case of real estate, location thereof shall be listed by street address, or if none, then by legal description). No time or demand deposit in a financial institution nor any debt instrument need be listed.

7. List the name of any unit of government which employed the person making the statement during the preceding calendar year other than the unit or units of government in relation to which the person is required to file.

.............................................................

.............................................................

8. List the name of any entity from which a gift or gifts, or honorarium or honoraria, valued singly or in the aggregate in excess of $500, was received during the preceding calendar year.

.............................................................

9. List the name of any spouse or immediate family member living with the person making this statement employed by a public utility in this State and the name of the public utility that employs the relative. VERIFICATION:

"I declare that this statement of economic interests (including any accompanying schedules and statements) has been examined by me and to the best of my knowledge and belief is a true, correct and complete statement of my economic interests as required by the Illinois Governmental Ethics Act. I understand that the penalty for willfully filing a false or incomplete statement shall be a fine not to exceed $1,000 or imprisonment in a penal institution other than the penitentiary not to exceed one year, or both fine and imprisonment."

................ .......................................... (date of filing) (signature of person making the statement)

(Source: P.A. 95-173, eff. 1-1-08.)

Section 30-15. The Illinois Enterprise Zone Act is amended by changing Section 5.5 as follows:

(20 ILCS 655/5.5) (from Ch. 67 1/2, par. 609.1)

Sec. 5.5. High Impact Business.

(a) In order to respond to unique opportunities to assist in the encouragement, development, growth, and expansion of the private sector through large scale investment and development projects, the Department is authorized to receive and approve applications for the designation of "High Impact Businesses" in Illinois subject to the following conditions:

(1) such applications may be submitted at any time during the year;

(2) such business is not located, at the time of designation, in an enterprise zone designated pursuant to this Act;

(3) the business intends to do one or more of the following:

(A) the business intends to make a minimum investment of $12,000,000 which will be placed in service in qualified property and intends to create 500 full-time equivalent jobs at a designated location in Illinois or intends to make a minimum investment of $30,000,000 which will be placed in service in qualified property and intends to retain 1,500 full-time retained jobs at a designated location in Illinois. The business must certify in writing that the investments would not be placed in service in qualified property and the job creation or job retention would not occur without the tax credits and exemptions set forth in subsection (b) of this Section. The terms "placed in service" and "qualified property" have the same meanings as described in subsection (h) of Section 201 of the Illinois Income Tax Act; or

(B) the business intends to establish a new electric generating facility at a designated location in Illinois. "New electric generating facility", for purposes of this Section, means a newly-constructed electric generation plant or a newly-constructed generation capacity expansion at an existing electric generation plant, including the transmission lines and associated equipment that transfers electricity from points of supply to points of delivery, and for which such new foundation construction commenced not sooner than July 1, 2001. Such facility shall be designed to provide baseload electric generation and shall operate on a continuous basis throughout the year; and (i) shall have an aggregate rated generating capacity of at least 1,000 megawatts for all new units at one site if it uses natural gas as its primary fuel and foundation construction of the facility is commenced on or before December 31, 2004, or shall have an aggregate rated generating capacity of at least 400 megawatts for all new units at one site if it uses coal or gases derived from coal as its primary fuel and shall support the creation of at least 150 new Illinois coal mining jobs, or (ii) shall be funded through a federal Department of Energy grant before December 31, 2010 and shall support the creation of Illinois coal-mining jobs, or (iii) shall use coal gasification or integrated gasification-combined cycle units that generate electricity or chemicals, or both, and shall support the creation of Illinois coal-mining jobs. The business must certify in writing that the investments necessary to establish a new electric generating facility would not be placed in service and the job creation in the case of a coal-fueled plant would not occur without the tax credits and exemptions set forth in subsection (b-5) of this Section. The term "placed in service" has the same meaning as described in subsection (h) of Section 201 of the Illinois Income Tax Act; or

(B-5) the business intends to establish a new gasification facility at a designated location in Illinois. As used in this Section, "new gasification facility" means a newly constructed coal gasification facility that generates chemical feedstocks or transportation fuels derived from coal (which may include, but are not limited to, methane, methanol, and nitrogen fertilizer), that supports the creation or retention of Illinois coal-mining jobs, and that qualifies for financial assistance from the Department before December 31, 2010. A new gasification facility does not include a pilot project located within Jefferson County or within a county adjacent to Jefferson County for synthetic natural gas from coal; or

(C) the business intends to establish production operations at a new coal mine, re-establish production operations at a closed coal mine, or expand production at an existing coal mine at a designated location in Illinois not sooner than July 1, 2001; provided that the production operations result in the creation of 150 new Illinois coal mining jobs as described in subdivision (a)(3)(B) of this Section, and further provided that the coal extracted from such mine is utilized as the predominant source for a new electric generating facility. The business must certify in writing that the investments necessary to establish a new, expanded, or reopened coal mine would not be placed in service and the job creation would not occur without the tax credits and exemptions set forth in subsection (b-5) of this Section. The term "placed in service" has the same meaning as described in subsection (h) of Section 201 of the Illinois Income Tax Act; or

(D) the business intends to construct new transmission facilities or upgrade existing transmission facilities at designated locations in Illinois, for which construction commenced not sooner than July 1, 2001. For the purposes of this Section, "transmission facilities" means transmission lines with a voltage rating of 115 kilovolts or above, including associated equipment, that transfer electricity from points of supply to points of delivery and that transmit a majority of the electricity generated by a new electric generating facility designated as a High Impact Business in accordance with this Section. The business must certify in writing that the investments necessary to construct new transmission facilities or upgrade existing transmission facilities would not be placed in service without the tax credits and exemptions set forth in subsection (b-5) of this Section. The term "placed in service" has the same meaning as described in subsection (h) of Section 201 of the Illinois Income Tax Act; or

(E) the business intends to establish a new wind power facility at a designated location in Illinois. For purposes of this Section, "new wind power facility" means a newly constructed electric generation facility, or a newly constructed expansion of an existing electric generation facility, placed in service on or after July 1, 2009, that generates electricity using wind energy devices, and such facility shall be deemed to include all associated transmission lines, substations, and other equipment related to the generation of electricity from wind energy devices. For purposes of this Section, "wind energy device" means any device, with a nameplate capacity of at least 0.5 megawatts, that is used in the process of converting kinetic energy from the wind to generate electricity; or

(E-5) the business intends to establish a new utility scale solar or photovoltaic community renewable energy generation facility at a designated location in Illinois. For purposes of this Section, "new utility scale solar power facility" has the same meaning as "utility-scale solar" in the Illinois Power Agency Act and was put into service on or after July 1, 2021, and such facility shall be deemed to include all associated transmission lines, substations, and other equipment related to the generation of electricity from photovoltaic cells. For the purposes of this Section "community renewable energy generation facility" has the same meaning as "community renewable generation facility" in the Illinois Power Agency Act and was placed in service on or after July 1, 2021, that generates electricity using photovoltaic cells; or

(F) the business commits to (i) make a minimum investment of $500,000,000, which will be placed in service in a qualified property, (ii) create 125 full-time equivalent jobs at a designated location in Illinois, (iii) establish a fertilizer plant at a designated location in Illinois that complies with the set-back standards as described in Table 1: Initial Isolation and Protective Action Distances in the 2012 Emergency Response Guidebook published by the United States Department of Transportation, (iv) pay a prevailing wage for employees at that location who are engaged in construction activities, and (v) secure an appropriate level of general liability insurance to protect against catastrophic failure of the fertilizer plant or any of its constituent systems; in addition, the business must agree to enter into a construction project labor agreement including provisions establishing wages, benefits, and other compensation for employees performing work under the project labor agreement at that location; for the purposes of this Section, "fertilizer plant" means a newly constructed or upgraded plant utilizing gas used in the production of anhydrous ammonia and downstream nitrogen fertilizer products for resale; for the purposes of this Section, "prevailing wage" means the hourly cash wages plus fringe benefits for training and apprenticeship programs approved by the U.S. Department of Labor, Bureau of Apprenticeship and Training, health and welfare, insurance, vacations and pensions paid generally, in the locality in which the work is being performed, to employees engaged in work of a similar character on public works; this paragraph (F) applies only to businesses that submit an application to the Department within 60 days after July 25, 2013 (the effective date of Public Act 98-109) this amendatory Act of the 98th General Assembly; and

(4) no later than 90 days after an application is submitted, the Department shall notify the applicant of the Department's determination of the qualification of the proposed High Impact Business under this Section.

(b) Businesses designated as High Impact Businesses pursuant to subdivision (a)(3)(A) of this Section shall qualify for the credits and exemptions described in the following Acts: Section 9-222 and Section 9-222.1A of the Public Utilities Act, subsection (h) of Section 201 of the Illinois Income Tax Act, and Section 1d of the Retailers' Occupation Tax Act; provided that these credits and exemptions described in these Acts shall not be authorized until the minimum investments set forth in subdivision (a)(3)(A) of this Section have been placed in service in qualified properties and, in the case of the exemptions described in the Public Utilities Act and Section 1d of the Retailers' Occupation Tax Act, the minimum full-time equivalent jobs or full-time retained jobs set forth in subdivision (a)(3)(A) of this Section have been created or retained. Businesses designated as High Impact Businesses under this Section shall also qualify for the exemption described in Section 5l of the Retailers' Occupation Tax Act. The credit provided in subsection (h) of Section 201 of the Illinois Income Tax Act shall be applicable to investments in qualified property as set forth in subdivision (a)(3)(A) of this Section.

(b-5) Businesses designated as High Impact Businesses pursuant to subdivisions (a)(3)(B), (a)(3)(B-5), (a)(3)(C), and (a)(3)(D) of this Section shall qualify for the credits and exemptions described in the following Acts: Section 51 of the Retailers' Occupation Tax Act, Section 9-222 and Section 9-222.1A of the Public Utilities Act, and subsection (h) of Section 201 of the Illinois Income Tax Act; however, the credits and exemptions authorized under Section 9-222 and Section 9-222.1A of the Public Utilities Act, and subsection (h) of Section 201 of the Illinois Income Tax Act shall not be authorized until the new electric generating facility, the new gasification facility, the new transmission facility, or the new, expanded, or reopened coal mine is operational, except that a new electric generating facility whose primary fuel source is natural gas is eligible only for the exemption under Section 5l of the Retailers' Occupation Tax Act.

(b-6) Businesses designated as High Impact Businesses pursuant to subdivision (a)(3)(E) of this Section shall qualify for the exemptions described in Section 5l of the Retailers' Occupation Tax Act; any business so designated as a High Impact Business being, for purposes of this Section, a "Wind Energy Business".

(b-7) Beginning on January 1, 2021, businesses designated as High Impact Businesses by the Department shall qualify for the High Impact Business construction jobs credit under subsection (h-5) of Section 201 of the Illinois Income Tax Act if the business meets the criteria set forth in subsection (i) of this Section. The total aggregate amount of credits awarded under the Blue Collar Jobs Act (Article 20 of Public Act 101-9 this amendatory Act of the 101st General Assembly) shall not exceed $20,000,000 in any State fiscal year.

(c) High Impact Businesses located in federally designated foreign trade zones or sub-zones are also eligible for additional credits, exemptions and deductions as described in the following Acts: Section 9-221 and Section 9-222.1 of the Public Utilities Act; and subsection (g) of Section 201, and Section 203 of the Illinois Income Tax Act.

(d) Except for businesses contemplated under subdivision (a)(3)(E) of this Section, existing Illinois businesses which apply for designation as a High Impact Business must provide the Department with the prospective plan for which 1,500 full-time retained jobs would be eliminated in the event that the business is not designated.

(e) Except for new wind power facilities contemplated under subdivision (a)(3)(E) of this Section, new proposed facilities which apply for designation as High Impact Business must provide the Department with proof of alternative non-Illinois sites which would receive the proposed investment and job creation in the event that the business is not designated as a High Impact Business.

(f) Except for businesses contemplated under subdivision (a)(3)(E) of this Section, in the event that a business is designated a High Impact Business and it is later determined after reasonable notice and an opportunity for a hearing as provided under the Illinois Administrative Procedure Act, that the business would have placed in service in qualified property the investments and created or retained the requisite number of jobs without the benefits of the High Impact Business designation, the Department shall be required to immediately revoke the designation and notify the Director of the Department of Revenue who shall begin proceedings to recover all wrongfully exempted State taxes with interest. The business shall also be ineligible for all State funded Department programs for a period of 10 years.

(g) The Department shall revoke a High Impact Business designation if the participating business fails to comply with the terms and conditions of the designation. However, the penalties for new wind power facilities or Wind Energy Businesses, new utility scale solar power facilities, or new photovoltaic community renewable generation facilities for failure to comply with any of the terms or conditions of the Illinois Prevailing Wage Act shall be only those penalties identified in the Illinois Prevailing Wage Act, and the Department shall not revoke a High Impact Business designation as a result of the failure to comply with any of the terms or conditions of the Illinois Prevailing Wage Act in relation to a new wind power facility or a Wind Energy Business, new utility scale solar power facility, or new photovoltaic community renewable generation facility.

(h) Prior to designating a business, the Department shall provide the members of the General Assembly and Commission on Government Forecasting and Accountability with a report setting forth the terms and conditions of the designation and guarantees that have been received by the Department in relation to the proposed business being designated.

(i) High Impact Business construction jobs credit. Beginning on January 1, 2021, a High Impact Business may receive a tax credit against the tax imposed under subsections (a) and (b) of Section 201 of the Illinois Income Tax Act in an amount equal to 50% of the amount of the incremental income tax attributable to High Impact Business construction jobs credit employees employed in the course of completing a High Impact Business construction jobs project. However, the High Impact Business construction jobs credit may equal 75% of the amount of the incremental income tax attributable to High Impact Business construction jobs credit employees if the High Impact Business construction jobs credit project is located in an underserved area.

The Department shall certify to the Department of Revenue: (1) the identity of taxpayers that are eligible for the High Impact Business construction jobs credit; and (2) the amount of High Impact Business construction jobs credits that are claimed pursuant to subsection (h-5) of Section 201 of the Illinois Income Tax Act in each taxable year. Any business entity that receives a High Impact Business construction jobs credit shall maintain a certified payroll pursuant to subsection (j) of this Section.

As used in this subsection (i):

"High Impact Business construction jobs credit" means an amount equal to 50% (or 75% if the High Impact Business construction project is located in an underserved area) of the incremental income tax attributable to High Impact Business construction job employees. The total aggregate amount of credits awarded under the Blue Collar Jobs Act (Article 20 of Public Act 101-9 this amendatory Act of the 101st General Assembly) shall not exceed $20,000,000 in any State fiscal year

"High Impact Business construction job employee" means a laborer or worker who is employed by an Illinois contractor or subcontractor in the actual construction work on the site of a High Impact Business construction job project.

"High Impact Business construction jobs project" means building a structure or building or making improvements of any kind to real property, undertaken and commissioned by a business that was designated as a High Impact Business by the Department. The term "High Impact Business construction jobs project" does not include the routine operation, routine repair, or routine maintenance of existing structures, buildings, or real property.

"Incremental income tax" means the total amount withheld during the taxable year from the compensation of High Impact Business construction job employees.

"Underserved area" means a geographic area that meets one or more of the following conditions:

(1) the area has a poverty rate of at least 20% according to the latest federal decennial census;

(2) 75% or more of the children in the area participate in the federal free lunch program according to reported statistics from the State Board of Education;

(3) at least 20% of the households in the area receive assistance under the Supplemental Nutrition Assistance Program (SNAP); or

(4) the area has an average unemployment rate, as determined by the Illinois Department of Employment Security, that is more than 120% of the national unemployment average, as determined by the U.S. Department of Labor, for a period of at least 2 consecutive calendar years preceding the date of the application.

(j) Each contractor and subcontractor who is engaged in and executing a High Impact Business Construction jobs project, as defined under subsection (i) of this Section, for a business that is entitled to a credit pursuant to subsection (i) of this Section shall:

(1) make and keep, for a period of 5 years from the date of the last payment made on or after June 5, 2019 (the effective date of Public Act 101-9) this amendatory Act of the 101st General Assembly on a contract or subcontract for a High Impact Business Construction Jobs Project, records for all laborers and other workers employed by the contractor or subcontractor on the project; the records shall include:

(A) the worker's name;

(B) the worker's address;

(C) the worker's telephone number, if available;

(D) the worker's social security number;

(E) the worker's classification or classifications;

(F) the worker's gross and net wages paid in each pay period;

(G) the worker's number of hours worked each day;

(H) the worker's starting and ending times of work each day;

(I) the worker's hourly wage rate; and

(J) the worker's hourly overtime wage rate;

(2) no later than the 15th day of each calendar month, provide a certified payroll for the immediately preceding month to the taxpayer in charge of the High Impact Business construction jobs project; within 5 business days after receiving the certified payroll, the taxpayer shall file the certified payroll with the Department of Labor and the Department of Commerce and Economic Opportunity; a certified payroll must be filed for only those calendar months during which construction on a High Impact Business construction jobs project has occurred; the certified payroll shall consist of a complete copy of the records identified in paragraph (1) of this subsection (j), but may exclude the starting and ending times of work each day; the certified payroll shall be accompanied by a statement signed by the contractor or subcontractor or an officer, employee, or agent of the contractor or subcontractor which avers that:

(A) he or she has examined the certified payroll records required to be submitted by the Act and such records are true and accurate; and

(B) the contractor or subcontractor is aware that filing a certified payroll that he or she knows to be false is a Class A misdemeanor.

A general contractor is not prohibited from relying on a certified payroll of a lower-tier subcontractor, provided the general contractor does not knowingly rely upon a subcontractor's false certification.

Any contractor or subcontractor subject to this subsection, and any officer, employee, or agent of such contractor or subcontractor whose duty as an officer, employee, or agent it is to file a certified payroll under this subsection, who willfully fails to file such a certified payroll on or before the date such certified payroll is required by this paragraph to be filed and any person who willfully files a false certified payroll that is false as to any material fact is in violation of this Act and guilty of a Class A misdemeanor.

The taxpayer in charge of the project shall keep the records submitted in accordance with this subsection on or after June 5, 2019 (the effective date of Public Act 101-9) this amendatory Act of the 101st General Assembly for a period of 5 years from the date of the last payment for work on a contract or subcontract for the High Impact Business construction jobs project.

The records submitted in accordance with this subsection shall be considered public records, except an employee's address, telephone number, and social security number, and made available in accordance with the Freedom of Information Act. The Department of Labor shall accept any reasonable submissions by the contractor that meet the requirements of this subsection (j) and shall share the information with the Department in order to comply with the awarding of a High Impact Business construction jobs credit. A contractor, subcontractor, or public body may retain records required under this Section in paper or electronic format.

(k) Upon 7 business days' notice, each contractor and subcontractor shall make available for inspection and copying at a location within this State during reasonable hours, the records identified in this subsection (j) to the taxpayer in charge of the High Impact Business construction jobs project, its officers and agents, the Director of the Department of Labor and his or her deputies and agents, and to federal, State, or local law enforcement agencies and prosecutors.

(Source: P.A. 101-9, eff. 6-5-19; revised 7-12-19.)

Section 30-18. The Electric Vehicle Act is amended by changing Sections 5, 10, 15, and 20 and by adding Sections 30, 35, 40, 45, and 50 as follows:

(20 ILCS 627/5)

Sec. 5. Findings. The General Assembly finds:

(1) Illinois should increase the adoption of electric vehicles in the State to 1,000,000 by 2030.

(2) Illinois should strive to be the best state in the nation in which to drive and manufacture an electric vehicle.

(3) Widespread adoption of electric vehicles is necessary to electrify the transportation sector, diversify the transportation fuel mix, drive economic development, and protect air quality.

(4) Accelerating the adoption of electric vehicles will drive the decarbonization of Illinois' transportation sector.

(5) Expanded infrastructure investment will help Illinois more rapidly decarbonize the transportation sector.

(6) Statewide adoption of electric vehicles requires increasing access to electrification for all consumers.

(7) Private investments in charging equipment and electric utility investments can assist the growth of electric vehicles and help increase access to electricity for electric vehicle charging.

(8) Widespread adoption of electric vehicles requires increasing public access to charging equipment throughout Illinois, especially in low-income, moderate-income, environmental justice, and equity investment eligible communities, where levels of air pollution burden tend to be higher.

(9) Widespread adoption of electric vehicles and charging equipment has the potential to provide customers with fuel cost savings and electric utility customers with cost-saving benefits.

(10) Widespread adoption of electric vehicles can help Illinois stimulate innovation, create jobs, increase competition, and expand private investments in charging equipment and networks.

(11) Widespread adoption of electric vehicles can improve an electric utility's electric system efficiency and operational flexibility, including the ability of the electric utility to integrate renewable energy resources and make use of off-peak generation resources that support the operation of charging equipment. that the adoption and use of electric vehicles would benefit the State of Illinois by (i) improving the health and environmental quality of the residents of Illinois through reduced pollution, (ii) reducing the operating costs of vehicle transportation, and (iii) shifting the demand for imported petroleum to locally produced electricity.

(Source: P.A. 97-89, eff. 7-11-11.)

(20 ILCS 627/10)

Sec. 10. Definitions.

"Agency" means the Illinois Environmental Protection Agency.

"Commission" means the Illinois Commerce Commission.

"Coordinator" means the Electric Vehicle Coordinator created in Section 15.

"Council" means the Electric Vehicle Advisory Council created in Section 20.

"Electric vehicle" means (i) a vehicle that is exclusively powered by and refueled by electricity (ii) is licensed to drive on public roadways. "Electric vehicle" does not include (A) electric motorcycles, or (B) hybrid electric vehicles and extended-range electric vehicles that are also equipped with conventional fueled propulsion or auxiliary engines. battery-powered electric vehicle operated solely by electricity or (ii) a plug-in hybrid electric vehicle that operates on electricity and gasoline and has a battery that can be recharged from an external source.

"Electric vehicle charging station" means a station that delivers electricity from a source outside an electric vehicle into one or more electric vehicles.

"Equity investment eligible community" or "eligible community" mean people living in geographic areas throughout Illinois who will most benefit from equitable investments by the State that are designed to combat historic inequities and the effects of discrimination. "Eligible community" includes census tracts that meet the following characteristics:

(1) At least 15% of the population or at least 20% of the population 18 or under fall below the federal poverty level; and

(2) falls in the top 25th percentile in the State on measured levels for one or more of the following environmental indicators from the United States Environmental Protection Agency's EJSCREEN screening tool:

(A) Diesel particulate matter level in air.

(B) Air toxics cancer risk.

(C) Air toxics respiratory hazard index.

(D) Indicator for major direct dischargers to water.

(E) Proximity to National Priorities List (NPL) sites.

(F) Proximity to Risk Management Plan (RMP) facilities.

(G) Proximity to Treatment and Storage and Disposal (TSDF) facilities.

(H) Ozone level in air.

(I) PM2.5 (particulate matter with diameters that are 2.5 micrometers and smaller) level in the air.

"Equity investment eligible persons" or "eligible persons" means persons who would most benefit from equitable investments by the State designed to combat discrimination, specifically:

(1) persons whose primary residence is in an equity investment eligible community;

(2) persons whose primary residence is in a municipality or a county with a population under 100,000 where the closure of an electric generating unit or coal mine has been publicly announced, or the electric generating unit or coal mine is in the process of closing or has closed within the last 5 years;

(3) persons who are graduates of or currently enrolled in the foster care system; or

(4) persons who were formerly incarcerated.

"Make-ready infrastructure" means the electrical and construction work necessary between the distribution circuit to the connection point of charging equipment to facilitate private investment in charging equipment.

(Source: P.A. 97-89, eff. 7-11-11.)

(20 ILCS 627/15)

Sec. 15. Electric Vehicle Coordinator. The Governor shall appoint a person within the Illinois Environmental Protection Agency Department of Commerce and Economic Opportunity to serve as the Electric Vehicle Coordinator for the State of Illinois. This person may be an existing employee with other duties. The Coordinator shall act as a point person for electric vehicle-related and electric vehicle charging-related electric vehicle related policies and activities in Illinois, including but not limited to the issuance of electric vehicle rebates for consumers and electric vehicle charging rebates for organizations and companies.

(Source: P.A. 97-89, eff. 7-11-11.)

(20 ILCS 627/20)

Sec. 20. Electric vehicle advisory council.

(a) There is created the Illinois Electric Vehicle Advisory Council. The Council shall investigate and recommend strategies that the Governor and the General Assembly may implement to promote the use of electric vehicles. Strategies shall include, but are not limited to, methods of achieving greater adoption of electric vehicles, rapidly expanding statewide charging infrastructure, electrifying the State fleet, and changing electric utility rates and tariffs related to electric vehicle charging. , including, but not limited to, potential infrastructure improvements, State and local regulatory streamlining, and changes to electric utility rates and tariffs.

(b) The Council shall include all of the following members:

(1) The Electric Vehicle Coordinator to serve as chairperson.

(2) Four members of the General Assembly, one appointed by the Speaker of the House of Representatives, one appointed by the Minority Leader of the House of Representatives, one appointed by the President of the Senate, and one appointed by the Minority Leader of the Senate.

(3) The Director of Commerce and Economic Opportunity or his or her designee.

(4) The Director of the Illinois Environmental Protection Agency or his or her designee.

(5) The Executive Director of the Illinois Commerce Commission or his or her designee.

(6) The Secretary of the Illinois Department of Transportation or his or her designee.

(7) The Director of Central Management Services or his or her designee.

(8) The following (7) Ten at-large members appointed by the Governor as follows:

(A) two representatives of statewide environmental organizations;

(B) two representatives of national or regional environmental organizations;

(C) two representatives of charging companies; one representative of a nonprofit car-sharing organization;

(D) two representatives of automobile manufacturers;

(E) one representative of the City of Chicago; and

(F) two representatives of electric utilities.

(c) The Council shall report its findings to the Governor and General Assembly by December 31, 2022 2011.

(d) The Illinois Environmental Protection Agency Department of Commerce and Economic Opportunity shall provide administrative and other support to the Council.

(Source: P.A. 97-89, eff. 7-11-11.)

(20 ILCS 627/30 new)

Sec. 30. Commercial tariff; electric vehicle charging. Within 90 days after the effective date of this amendatory Act of the 102nd General Assembly, electric utilities serving greater than 500,000 customers in the State shall file a proposal with the Illinois Commerce Commission to establish a commercial tariff utilizing alternatives to traditional demand-based rate structures to facilitate charging for light-duty, heavy-duty, and fleet electric vehicles and charging that supports integration of renewable energy resources.

(20 ILCS 627/35 new)

Sec. 35. Transportation Electrification Plans.

(a) An electric utility serving more than 500,000 customers as of January 1, 2009 shall prepare a Transportation Electrification Plan that meets the requirements of this section and shall file said plan with the Commission no later than July 1, 2022. Within 45 days after the filing of the Transportation Electrification Plan, the Commission shall, with reasonable notice, open an investigation to consider whether the plan meets the objectives and contains the information required by this Section. The Commission shall approve, approve with modifications, or reject the plan within 270 days from the date of filing. The Commission may approve the plan if it finds that the plan will achieve the goals described in this Section and contains the information described in this Section. Proceedings under this Section shall proceed according to the rules provided by Article IX of the Public Utilities Act. Information contained in the approved plan shall be considered part of the record in any Commission proceeding under Section 16-107.6 of the Public Utilities Act, provided that a final order has not been entered prior to the initial filing date.

The Transportation Electrification Plan shall specifically address, at minimum, the following information:

(1) Investments and incentives to facilitate the rapid deployment of charging equipment throughout the State through programs that support make-ready infrastructure and align infrastructure investments with Agency-issued rebates for charging equipment, in accordance with Section 50.

(2) Investments and incentives to facilitate the rapid deployment of charging equipment in eligible communities in order to provide those communities with greater economic investment, transportation opportunities, and a cleaner environment so they can directly benefit from transportation electrification efforts.

(3) Investments and incentives to facilitate the electrification of public transit and other vehicle fleets in the light-duty, medium-duty, and heavy-duty sectors.

(4) Whether to establish standards for charging plugs, and if so, what standards.

(5) Additional rate designs to support public and private electric vehicle charging.

(6) Financial and other challenges to electric vehicle usage in low-income communities and strategies for overcoming those challenges, particularly for people for whom car ownership or electric car ownership is not an option.

(7) Customer education, outreach, and incentive programs that increase awareness of the programs and the benefits of transportation electrification, including direct outreach to eligible communities.

(8) Plans to increase access to Level 3 charging infrastructure located along transportation corridors to serve vehicles that need quicker charging times and vehicles of persons who have no other access to charging infrastructure, regardless of whether those projects participate in optimized charging programs.

(9) Methods of minimizing ratepayer impacts and exempting or minimizing, to the extent possible, low-income ratepayers from the costs associated with facilitating the expansion of electric vehicle charging.

(10) Financial and other challenges to electric vehicle usage in low-income communities and strategies for overcoming those challenges.

(11) The development of optimized charging programs to achieve savings identified, and new contracts and compensation for services in those programs, through signals that allow electric vehicle charging to respond to local system conditions, manage critical peak periods, serve as a demand response or peak resource, and maximize renewable energy use and integration into the grid.

(12) Opportunities for coordination and alignment with electric vehicle and electric vehicle charging equipment incentives established by any agency, department, board, or commission of the State of Illinois, any other unit of government in the State, any national programs, or any unit of the federal government.

(b) The Commission's investigation shall determine if each proposed plan is in the public interest. When considering if the plan is in the public interest and determining appropriate levels of cost recovery for investments and expenditures related to programs proposed by an electric utility, the Commission shall consider whether the investments and other expenditures are designed and reasonably expected to:

(1) increase access to charging equipment and electricity as a transportation fuel throughout the State, including in low-income, moderate-income, and eligible communities;

(2) stimulate innovation, competition, private investment, and increased consumer choices in electric vehicle charging equipment and networks;

(3) contribute to meeting air quality standards, including improving air quality in equity investment eligible communities who disproportionately suffer from emissions from the transportation sector, the consideration of which shall include consultation with the Agency;

(4) support the efficient and cost-effective use of the electric grid in a manner that supports electric vehicle charging operations; and

(5) provide resources to support private investment in charging equipment for uses in public and private charging applications, including residential, multi-family, fleet, transit, community, and corridor applications.

(20 ILCS 627/40 new)

Sec. 40. Plan updates. The utility shall file an update to the plan on July 1, 2024 and every three years thereafter. This update shall describe transportation investments made during the prior plan period, investments planned for the following 24 months, and updates to the information required by this Section. Within 35 days after the utility files its report, the Commission shall, upon its own initiative, open an investigation regarding the utility's plan update to investigate whether the objectives described in this Section are being achieved. If the Commission finds, after notice and hearing, that the utility's plan is materially deficient, the Commission shall issue an order requiring the utility to devise a corrective action plan, subject to Commission approval, to bring the plan into compliance with the goals of this Section. The Commission's order shall be entered within 270 days after the utility files its annual report.

The contents of a plan filed under this Section shall be available for evidence in Commission proceedings. However, omission from an approved plan shall not render any future utility expenditure to be considered unreasonable or imprudent. The Commission may, upon sufficient evidence, allow expenditures that were not part of any particular distribution plan.

(20 ILCS 627/45 new)

Sec. 45. Rulemaking; resources. The Agency shall adopt rules as necessary and dedicate sufficient resources to implement Sections 35 and 50.

(20 ILCS 627/50 new)

Sec. 50. Charging rebate program.

(a) In order to substantially offset the installation costs of electric vehicle charging infrastructure, beginning July 1, 2023, and continuing as long as funds are available, the Agency shall issue rebates, consistent with the provisions of this Act and Commission-approved Transportation Electrification Plans in accordance with Section 35, to public and private organizations and companies to install and maintain Level 2 or Level 3 charging stations at any of the following locations:

(1) Public parking facilities.

(2) Workplaces.

(3) Multifamily apartment buildings.

(4) Public roads and highways.

(5) Ridesharing and taxi charging depots.

(b) The Agency shall award rebates that fund up to 90% of the cost of the charging station, up to $4,000 for Level 2 chargers and up to $5,000 for Level 3 chargers. The Agency shall award an additional $500 per port for every charging station installed in an eligible community and every charging station located to support eligible persons. In order to be eligible to receive a rebate, the organization or company must submit an application to the Agency. The Agency shall by rule provide application requirements. The Agency shall accept applications on a rolling basis and shall award rebates within 60 days of each application.

Section 30-20. The Energy Policy and Planning Act is amended by changing Section 2 as follows:

(20 ILCS 1120/2) (from Ch. 96 1/2, par. 7802)

Sec. 2. (a) The General Assembly finds:

(1) that the reliable provision of adequate amounts of energy in the forms required is of vital importance to the public welfare and to the continued operation of business and industry; and (2) that many problems relating to energy are beyond the ability of the national government to solve, or are such that action by the national government would represent a displacement of prerogatives that are properly those of the State government; and (3) that among these problems is that of climate change; and (4) that there is a need for an organized and comprehensive approach for dealing with energy matters in the State, which can be best served through the adoption of a State energy policy.

(b) It is declared to be the policy of the State of Illinois:

(1) To become energy self-reliant to the greatest extent possible, primarily by the utilization of the energy resources available within the borders of this State, and by the increased conservation of energy; and

(2) To emphasize an approach to energy problems and solutions on a local or regional basis, and to emphasize the use of renewable energy sources wherever possible and practical to do so; and

(2.1) To recognize the detrimental impacts of climate change to the citizens of this State, and to act to reverse these impacts through a transition to 100% clean energy; and

(3) To seek and promote and aid the efforts of private citizens, businesses, and industries in developing individual contributions to energy problems and difficulties that are being encountered, making use of renewable energy sources that are matched in quality to end-use needs; and

(4) The development of a comprehensive master plan for energy that considers available supplies, production and conversion capabilities, levels of demand by each energy type and level of total demand, and the changes in each that are likely to occur over time is a priority that should be developed and implemented immediately.

(c) The General Assembly further declares that the progress towards a comprehensive energy plan should be in accordance with the following guidelines:

(1) The energy problems being faced in the State can be effectively addressed only by a government that accepts responsibility for dealing with them comprehensively, and by an informed public that understands the seriousness and is ready to make the necessary commitment.

(2) Economic growth, employment, and production must be maintained.

(3) Policies for the protection of the environment must be maintained.

(4) The solutions sought as part of the master planning process must be equitable and fair to all regions, sectors and income groups.

(5) The growth of energy demand must be prudently restrained through conservation and improved efficiency of energy usage.

(6) Energy prices should generally reflect the true replacement cost of energy.

(7) Both energy producers and consumers are entitled to reasonable certainty as to governmental energy policy.

(8) Resources in plentiful supply must be used more widely, and the State or locality must begin the process of moderating the use of those in short supply.

(9) Use of nonconventional sources of energy must be vigorously expanded.

(10) The plans developed:

(i) should be realistic and consistent with the basic physical limitations of energy production and utilization processes, and recognize the costs and lead times necessary for implementation of large-scale projects.

(ii) must reflect both the need for early action in implementing near-term programs and the need for early planning of programs having long lead times.

(iii) must allow flexible response and choice of alternatives to accommodate changing requirements as well as presenting uncertainties in future requirements.

(iv) should reflect features that are unique to the State.

(v) should recognize the interdisciplinary aspects of State objectives and provide positive guidance for coordination of various organizations and programs.

(vi) must consider both direct energy flows and indirect energy embodied in the goods and services entering and leaving a region.

(vii) should recognize and include not only long-range aspects, but must also prepare actions to manage the transition from present circumstances to a more manageable energy situation.

(Source: P.A. 81-385.)

Section 30-22. The Illinois Finance Authority Act is amended by changing Sections 801-1, 801-5, 801-10, and 801-40 and by adding the heading of Article 850 and Sections 850-5, 850-10, and 850-15 as follows:

(20 ILCS 3501/801-1)

Sec. 801-1. Short Title. Articles 801 through 850 845 of this Act may be cited as the Illinois Finance Authority Act. References to "this Act" in Articles 801 through 850 845 are references to the Illinois Finance Authority Act.

(Source: P.A. 95-331, eff. 8-21-07.)

(20 ILCS 3501/801-5)

Sec. 801-5. Findings and declaration of policy. The General Assembly hereby finds, determines and declares:

(a) that there are a number of existing State authorities authorized to issue bonds to alleviate the conditions and promote the objectives set forth below; and to provide a stronger, better coordinated development effort, it is determined to be in the interest of promoting the health, safety, morals and general welfare of all the people of the State to consolidate certain of such existing authorities into one finance authority;

(b) that involuntary unemployment affects the health, safety, morals and general welfare of the people of the State of Illinois;

(c) that the economic burdens resulting from involuntary unemployment fall in part upon the State in the form of public assistance and reduced tax revenues, and in the event the unemployed worker and his family migrate elsewhere to find work, may also fall upon the municipalities and other taxing districts within the areas of unemployment in the form of reduced tax revenues, thereby endangering their financial ability to support necessary governmental services for their remaining inhabitants;

(d) that a vigorous growing economy is the basic source of job opportunities;

(e) that protection against involuntary unemployment, its economic burdens and the spread of economic stagnation can best be provided by promoting, attracting, stimulating and revitalizing industry, manufacturing and commerce in the State;

(f) that the State has a responsibility to help create a favorable climate for new and improved job opportunities for its citizens by encouraging the development of commercial businesses and industrial and manufacturing plants within the State;

(g) that increased availability of funds for construction of new facilities and the expansion and improvement of existing facilities for industrial, commercial and manufacturing facilities will provide for new and continued employment in the construction industry and alleviate the burden of unemployment;

(h) that in the absence of direct governmental subsidies the unaided operations of private enterprise do not provide sufficient resources for residential construction, rehabilitation, rental or purchase, and that support from housing related commercial facilities is one means of stimulating residential construction, rehabilitation, rental and purchase;

(i) that it is in the public interest and the policy of this State to foster and promote by all reasonable means the provision of adequate capital markets and facilities for borrowing money by units of local government, and for the financing of their respective public improvements and other governmental purposes within the State from proceeds of bonds or notes issued by those governmental units; and to assist local governmental units in fulfilling their needs for those purposes by use of creation of indebtedness;

(j) that it is in the public interest and the policy of this State to the extent possible, to reduce the costs of indebtedness to taxpayers and residents of this State and to encourage continued investor interest in the purchase of bonds or notes of governmental units as sound and preferred securities for investment; and to encourage governmental units to continue their independent undertakings of public improvements and other governmental purposes and the financing thereof, and to assist them in those activities by making funds available at reduced interest costs for orderly financing of those purposes, especially during periods of restricted credit or money supply, and particularly for those governmental units not otherwise able to borrow for those purposes;

(k) that in this State the following conditions exist: (i) an inadequate supply of funds at interest rates sufficiently low to enable persons engaged in agriculture in this State to pursue agricultural operations at present levels; (ii) that such inability to pursue agricultural operations lessens the supply of agricultural commodities available to fulfill the needs of the citizens of this State; (iii) that such inability to continue operations decreases available employment in the agricultural sector of the State and results in unemployment and its attendant problems; (iv) that such conditions prevent the acquisition of an adequate capital stock of farm equipment and machinery, much of which is manufactured in this State, therefore impairing the productivity of agricultural land and, further, causing unemployment or lack of appropriate increase in employment in such manufacturing; (v) that such conditions are conducive to consolidation of acreage of agricultural land with fewer individuals living and farming on the traditional family farm; (vi) that these conditions result in a loss in population, unemployment and movement of persons from rural to urban areas accompanied by added costs to communities for creation of new public facilities and services; (vii) that there have been recurrent shortages of funds for agricultural purposes from private market sources at reasonable rates of interest; (viii) that these shortages have made the sale and purchase of agricultural land to family farmers a virtual impossibility in many parts of the State; (ix) that the ordinary operations of private enterprise have not in the past corrected these conditions; and (x) that a stable supply of adequate funds for agricultural financing is required to encourage family farmers in an orderly and sustained manner and to reduce the problems described above;

(l) that for the benefit of the people of the State of Illinois, the conduct and increase of their commerce, the protection and enhancement of their welfare, the development of continued prosperity and the improvement of their health and living conditions it is essential that all the people of the State be given the fullest opportunity to learn and to develop their intellectual and mental capacities and skills; that to achieve these ends it is of the utmost importance that private institutions of higher education within the State be provided with appropriate additional means to assist the people of the State in achieving the required levels of learning and development of their intellectual and mental capacities and skills and that cultural institutions within the State be provided with appropriate additional means to expand the services and resources which they offer for the cultural, intellectual, scientific, educational and artistic enrichment of the people of the State;

(m) that in order to foster civic and neighborhood pride, citizens require access to facilities such as educational institutions, recreation, parks and open spaces, entertainment and sports, a reliable transportation network, cultural facilities and theaters and other facilities as authorized by this Act, and that it is in the best interests of the State to lower the costs of all such facilities by providing financing through the State;

(n) that to preserve and protect the health of the citizens of the State, and lower the costs of health care, that financing for health facilities should be provided through the State; and it is hereby declared to be the policy of the State, in the interest of promoting the health, safety, morals and general welfare of all the people of the State, to address the conditions noted above, to increase job opportunities and to retain existing jobs in the State, by making available through the Illinois Finance Authority, hereinafter created, funds for the development, improvement and creation of industrial, housing, local government, educational, health, public purpose and other projects; to issue its bonds and notes to make funds at reduced rates and on more favorable terms for borrowing by local governmental units through the purchase of the bonds or notes of the governmental units; and to make or acquire loans for the acquisition and development of agricultural facilities; to provide financing for private institutions of higher education, cultural institutions, health facilities and other facilities and projects as authorized by this Act; and to grant broad powers to the Illinois Finance Authority to accomplish and to carry out these policies of the State which are in the public interest of the State and of its taxpayers and residents;

(o) that providing financing alternatives for projects that are located outside the State that are owned, operated, leased, managed by, or otherwise affiliated with, institutions located within the State would promote the economy of the State for the benefit of the health, welfare, safety, trade, commerce, industry, and economy of the people of the State by creating employment opportunities in the State and lowering the cost of accessing healthcare, private education, or cultural institutions in the State by reducing the cost of financing or operating those projects; and

(p) that the realization of the objectives of the Authority identified in this Act including, without limitation, those designed (1) to assist and enable veterans, minorities, women and disabled individuals to own and operate small businesses; (2) to assist in the delivery of agricultural assistance; and (3) to aid, assist, and encourage economic growth and development within this State, will be enhanced by empowering the Authority to purchase loan participations from participating lenders;

(q) that climate change threatens the health, welfare and prosperity of all of the residents of the State;

(r) combating climate change is necessary to preserve and enhance the health, welfare and prosperity of all of the residents of the State;

(s) that the promotion of the development and implementation of clean energy is necessary to combat climate change and is hereby declared to be the policy of the State; and

(t) that designating the Authority as the "Climate Bank" to aid in all respects with providing financial products and programs to finance and otherwise develop and implement clean energy in the State to mitigate or adapt to the negative consequences of climate change, will further the clean energy policy of the State.

(Source: P.A. 100-919, eff. 8-17-18.)

(20 ILCS 3501/801-10)

Sec. 801-10. Definitions. The following terms, whenever used or referred to in this Act, shall have the following meanings, except in such instances where the context may clearly indicate otherwise:

(a) The term "Authority" means the Illinois Finance Authority created by this Act.

(b) The term "project" means an industrial project, clean energy project, conservation project, housing project, public purpose project, higher education project, health facility project, cultural institution project, municipal bond program project, PACE Project, agricultural facility or agribusiness, and "project" may include any combination of one or more of the foregoing undertaken jointly by any person with one or more other persons.

(c) The term "public purpose project" means (i) any project or facility, including without limitation land, buildings, structures, machinery, equipment and all other real and personal property, which is authorized or required by law to be acquired, constructed, improved, rehabilitated, reconstructed, replaced or maintained by any unit of government or, in the case of a clean energy project, any person, or any other lawful public purpose, including provision of working capital, which is authorized or required by law to be undertaken by any unit of government or, in the case of a clean energy project, any person, or (ii) costs incurred and other expenditures, including expenditures for management, investment, or working capital costs, incurred in connection with the reform, consolidation, or implementation of the transition process as described in Articles 22B and 22C of the Illinois Pension Code.

(d) The term "industrial project" means the acquisition, construction, refurbishment, creation, development or redevelopment of any facility, equipment, machinery, real property or personal property for use by any instrumentality of the State or its political subdivisions, for use by any person or institution, public or private, for profit or not for profit, or for use in any trade or business, including, but not limited to, any industrial, manufacturing, clean energy, or commercial enterprise that is located within or outside the State, provided that, with respect to a project involving property located outside the State, the property must be owned, operated, leased or managed by an entity located within the State or an entity affiliated with an entity located within the State, and which is (1) a capital project or a clean energy project, including, but not limited to: (i) land and any rights therein, one or more buildings, structures or other improvements, machinery and equipment, whether now existing or hereafter acquired, and whether or not located on the same site or sites; (ii) all appurtenances and facilities incidental to the foregoing, including, but not limited to, utilities, access roads, railroad sidings, track, docking and similar facilities, parking facilities, dockage, wharfage, railroad roadbed, track, trestle, depot, terminal, switching and signaling or related equipment, site preparation and landscaping; and (iii) all non-capital costs and expenses relating thereto or (2) any addition to, renovation, rehabilitation or improvement of a capital project or a clean energy project, or (3) any activity or undertaking within or outside the State, provided that, with respect to a project involving property located outside the State, the property must be owned, operated, leased or managed by an entity located within the State or an entity affiliated with an entity located within the State, which the Authority determines will aid, assist or encourage economic growth, development or redevelopment within the State or any area thereof, will promote the expansion, retention or diversification of employment opportunities within the State or any area thereof or will aid in stabilizing or developing any industry or economic sector of the State economy. The term "industrial project" also means the production of motion pictures.

(e) The term "bond" or "bonds" shall include bonds, notes (including bond, grant or revenue anticipation notes), certificates and/or other evidences of indebtedness representing an obligation to pay money, including refunding bonds.

(f) The terms "lease agreement" and "loan agreement" shall mean: (i) an agreement whereby a project acquired by the Authority by purchase, gift or lease is leased to any person, corporation or unit of local government which will use or cause the project to be used as a project as heretofore defined upon terms providing for lease rental payments at least sufficient to pay when due all principal of, interest and premium, if any, on any bonds of the Authority issued with respect to such project, providing for the maintenance, insuring and operation of the project on terms satisfactory to the Authority, providing for disposition of the project upon termination of the lease term, including purchase options or abandonment of the premises, and such other terms as may be deemed desirable by the Authority, or (ii) any agreement pursuant to which the Authority agrees to loan the proceeds of its bonds issued with respect to a project or other funds of the Authority to any person which will use or cause the project to be used as a project as heretofore defined upon terms providing for loan repayment installments at least sufficient to pay when due all principal of, interest and premium, if any, on any bonds of the Authority, if any, issued with respect to the project, and providing for maintenance, insurance and other matters as may be deemed desirable by the Authority.

(g) The term "financial aid" means the expenditure of Authority funds or funds provided by the Authority through the issuance of its bonds, notes or other evidences of indebtedness or from other sources for the development, construction, acquisition or improvement of a project.

(h) The term "person" means an individual, corporation, unit of government, business trust, estate, trust, partnership or association, 2 or more persons having a joint or common interest, or any other legal entity.

(i) The term "unit of government" means the federal government, the State or unit of local government, a school district, or any agency or instrumentality, office, officer, department, division, bureau, commission, college or university thereof.

(j) The term "health facility" means: (a) any public or private institution, place, building, or agency required to be licensed under the Hospital Licensing Act; (b) any public or private institution, place, building, or agency required to be licensed under the Nursing Home Care Act, the Specialized Mental Health Rehabilitation Act of 2013, the ID/DD Community Care Act, or the MC/DD Act; (c) any public or licensed private hospital as defined in the Mental Health and Developmental Disabilities Code; (d) any such facility exempted from such licensure when the Director of Public Health attests that such exempted facility meets the statutory definition of a facility subject to licensure; (e) any other public or private health service institution, place, building, or agency which the Director of Public Health attests is subject to certification by the Secretary, U.S. Department of Health and Human Services under the Social Security Act, as now or hereafter amended, or which the Director of Public Health attests is subject to standard-setting by a recognized public or voluntary accrediting or standard-setting agency; (f) any public or private institution, place, building or agency engaged in providing one or more supporting services to a health facility; (g) any public or private institution, place, building or agency engaged in providing training in the healing arts, including, but not limited to, schools of medicine, dentistry, osteopathy, optometry, podiatry, pharmacy or nursing, schools for the training of x-ray, laboratory or other health care technicians and schools for the training of para-professionals in the health care field; (h) any public or private congregate, life or extended care or elderly housing facility or any public or private home for the aged or infirm, including, without limitation, any Facility as defined in the Life Care Facilities Act; (i) any public or private mental, emotional or physical rehabilitation facility or any public or private educational, counseling, or rehabilitation facility or home, for those persons with a developmental disability, those who are physically ill or disabled, the emotionally disturbed, those persons with a mental illness or persons with learning or similar disabilities or problems; (j) any public or private alcohol, drug or substance abuse diagnosis, counseling treatment or rehabilitation facility, (k) any public or private institution, place, building or agency licensed by the Department of Children and Family Services or which is not so licensed but which the Director of Children and Family Services attests provides child care, child welfare or other services of the type provided by facilities subject to such licensure; (l) any public or private adoption agency or facility; and (m) any public or private blood bank or blood center. "Health facility" also means a public or private structure or structures suitable primarily for use as a laboratory, laundry, nurses or interns residence or other housing or hotel facility used in whole or in part for staff, employees or students and their families, patients or relatives of patients admitted for treatment or care in a health facility, or persons conducting business with a health facility, physician's facility, surgicenter, administration building, research facility, maintenance, storage or utility facility and all structures or facilities related to any of the foregoing or required or useful for the operation of a health facility, including parking or other facilities or other supporting service structures required or useful for the orderly conduct of such health facility. "Health facility" also means, with respect to a project located outside the State, any public or private institution, place, building, or agency which provides services similar to those described above, provided that such project is owned, operated, leased or managed by a participating health institution located within the State, or a participating health institution affiliated with an entity located within the State.

(k) The term "participating health institution" means (i) a private corporation or association or (ii) a public entity of this State, in either case authorized by the laws of this State or the applicable state to provide or operate a health facility as defined in this Act and which, pursuant to the provisions of this Act, undertakes the financing, construction or acquisition of a project or undertakes the refunding or refinancing of obligations, loans, indebtedness or advances as provided in this Act.

(l) The term "health facility project", means a specific health facility work or improvement to be financed or refinanced (including without limitation through reimbursement of prior expenditures), acquired, constructed, enlarged, remodeled, renovated, improved, furnished, or equipped, with funds provided in whole or in part hereunder, any accounts receivable, working capital, liability or insurance cost or operating expense financing or refinancing program of a health facility with or involving funds provided in whole or in part hereunder, or any combination thereof.

(m) The term "bond resolution" means the resolution or resolutions authorizing the issuance of, or providing terms and conditions related to, bonds issued under this Act and includes, where appropriate, any trust agreement, trust indenture, indenture of mortgage or deed of trust providing terms and conditions for such bonds.

(n) The term "property" means any real, personal or mixed property, whether tangible or intangible, or any interest therein, including, without limitation, any real estate, leasehold interests, appurtenances, buildings, easements, equipment, furnishings, furniture, improvements, machinery, rights of way, structures, accounts, contract rights or any interest therein.

(o) The term "revenues" means, with respect to any project, the rents, fees, charges, interest, principal repayments, collections and other income or profit derived therefrom.

(p) The term "higher education project" means, in the case of a private institution of higher education, an educational facility to be acquired, constructed, enlarged, remodeled, renovated, improved, furnished, or equipped, or any combination thereof.

(q) The term "cultural institution project" means, in the case of a cultural institution, a cultural facility to be acquired, constructed, enlarged, remodeled, renovated, improved, furnished, or equipped, or any combination thereof.

(r) The term "educational facility" means any property located within the State, or any property located outside the State, provided that, if the property is located outside the State, it must be owned, operated, leased or managed by an entity located within the State or an entity affiliated with an entity located within the State, in each case constructed or acquired before or after the effective date of this Act, which is or will be, in whole or in part, suitable for the instruction, feeding, recreation or housing of students, the conducting of research or other work of a private institution of higher education, the use by a private institution of higher education in connection with any educational, research or related or incidental activities then being or to be conducted by it, or any combination of the foregoing, including, without limitation, any such property suitable for use as or in connection with any one or more of the following: an academic facility, administrative facility, agricultural facility, assembly hall, athletic facility, auditorium, boating facility, campus, communication facility, computer facility, continuing education facility, classroom, dining hall, dormitory, exhibition hall, fire fighting facility, fire prevention facility, food service and preparation facility, gymnasium, greenhouse, health care facility, hospital, housing, instructional facility, laboratory, library, maintenance facility, medical facility, museum, offices, parking area, physical education facility, recreational facility, research facility, stadium, storage facility, student union, study facility, theatre or utility.

(s) The term "cultural facility" means any property located within the State, or any property located outside the State, provided that, if the property is located outside the State, it must be owned, operated, leased or managed by an entity located within the State or an entity affiliated with an entity located within the State, in each case constructed or acquired before or after the effective date of this Act, which is or will be, in whole or in part, suitable for the particular purposes or needs of a cultural institution, including, without limitation, any such property suitable for use as or in connection with any one or more of the following: an administrative facility, aquarium, assembly hall, auditorium, botanical garden, exhibition hall, gallery, greenhouse, library, museum, scientific laboratory, theater or zoological facility, and shall also include, without limitation, books, works of art or music, animal, plant or aquatic life or other items for display, exhibition or performance. The term "cultural facility" includes buildings on the National Register of Historic Places which are owned or operated by nonprofit entities.

(t) "Private institution of higher education" means a not-for-profit educational institution which is not owned by the State or any political subdivision, agency, instrumentality, district or municipality thereof, which is authorized by law to provide a program of education beyond the high school level and which:

(1) Admits as regular students only individuals having a certificate of graduation from a high school, or the recognized equivalent of such a certificate;

(2) Provides an educational program for which it awards a bachelor's degree, or provides an educational program, admission into which is conditioned upon the prior attainment of a bachelor's degree or its equivalent, for which it awards a postgraduate degree, or provides not less than a 2-year program which is acceptable for full credit toward such a degree, or offers a 2-year program in engineering, mathematics, or the physical or biological sciences which is designed to prepare the student to work as a technician and at a semiprofessional level in engineering, scientific, or other technological fields which require the understanding and application of basic engineering, scientific, or mathematical principles or knowledge;

(3) Is accredited by a nationally recognized accrediting agency or association or, if not so accredited, is an institution whose credits are accepted, on transfer, by not less than 3 institutions which are so accredited, for credit on the same basis as if transferred from an institution so accredited, and holds an unrevoked certificate of approval under the Private College Act from the Board of Higher Education, or is qualified as a "degree granting institution" under the Academic Degree Act; and

(4) Does not discriminate in the admission of students on the basis of race or color. "Private institution of higher education" also includes any "academic institution".

(u) The term "academic institution" means any not-for-profit institution which is not owned by the State or any political subdivision, agency, instrumentality, district or municipality thereof, which institution engages in, or facilitates academic, scientific, educational or professional research or learning in a field or fields of study taught at a private institution of higher education. Academic institutions include, without limitation, libraries, archives, academic, scientific, educational or professional societies, institutions, associations or foundations having such purposes.

(v) The term "cultural institution" means any not-for-profit institution which is not owned by the State or any political subdivision, agency, instrumentality, district or municipality thereof, which institution engages in the cultural, intellectual, scientific, educational or artistic enrichment of the people of the State. Cultural institutions include, without limitation, aquaria, botanical societies, historical societies, libraries, museums, performing arts associations or societies, scientific societies and zoological societies.

(w) The term "affiliate" means, with respect to financing of an agricultural facility or an agribusiness, any lender, any person, firm or corporation controlled by, or under common control with, such lender, and any person, firm or corporation controlling such lender.

(x) The term "agricultural facility" means land, any building or other improvement thereon or thereto, and any personal properties deemed necessary or suitable for use, whether or not now in existence, in farming, ranching, the production of agricultural commodities (including, without limitation, the products of aquaculture, hydroponics and silviculture) or the treating, processing or storing of such agricultural commodities when such activities are customarily engaged in by farmers as a part of farming and which land, building, improvement or personal property is located within the State, or is located outside the State, provided that, if such property is located outside the State, it must be owned, operated, leased, or managed by an entity located within the State or an entity affiliated with an entity located within the State.

(y) The term "lender" with respect to financing of an agricultural facility or an agribusiness, means any federal or State chartered bank, Federal Land Bank, Production Credit Association, Bank for Cooperatives, federal or State chartered savings and loan association or building and loan association, Small Business Investment Company or any other institution qualified within this State to originate and service loans, including, but without limitation to, insurance companies, credit unions and mortgage loan companies. "Lender" also means a wholly owned subsidiary of a manufacturer, seller or distributor of goods or services that makes loans to businesses or individuals, commonly known as a "captive finance company".

(z) The term "agribusiness" means any sole proprietorship, limited partnership, co-partnership, joint venture, corporation or cooperative which operates or will operate a facility located within the State or outside the State, provided that, if any facility is located outside the State, it must be owned, operated, leased, or managed by an entity located within the State or an entity affiliated with an entity located within the State, that is related to the processing of agricultural commodities (including, without limitation, the products of aquaculture, hydroponics and silviculture) or the manufacturing, production or construction of agricultural buildings, structures, equipment, implements, and supplies, or any other facilities or processes used in agricultural production. Agribusiness includes but is not limited to the following:

(1) grain handling and processing, including grain storage, drying, treatment, conditioning, mailing and packaging;

(2) seed and feed grain development and processing;

(3) fruit and vegetable processing, including preparation, canning and packaging;

(4) processing of livestock and livestock products, dairy products, poultry and poultry products, fish or apiarian products, including slaughter, shearing, collecting, preparation, canning and packaging;

(5) fertilizer and agricultural chemical manufacturing, processing, application and supplying;

(6) farm machinery, equipment and implement manufacturing and supplying;

(7) manufacturing and supplying of agricultural commodity processing machinery and equipment, including machinery and equipment used in slaughter, treatment, handling, collecting, preparation, canning or packaging of agricultural commodities;

(8) farm building and farm structure manufacturing, construction and supplying;

(9) construction, manufacturing, implementation, supplying or servicing of irrigation, drainage and soil and water conservation devices or equipment;

(10) fuel processing and development facilities that produce fuel from agricultural commodities or byproducts;

(11) facilities and equipment for processing and packaging agricultural commodities specifically for export;

(12) facilities and equipment for forestry product processing and supplying, including sawmilling operations, wood chip operations, timber harvesting operations, and manufacturing of prefabricated buildings, paper, furniture or other goods from forestry products;

(13) facilities and equipment for research and development of products, processes and equipment for the production, processing, preparation or packaging of agricultural commodities and byproducts.

(aa) The term "asset" with respect to financing of any agricultural facility or any agribusiness, means, but is not limited to the following: cash crops or feed on hand; livestock held for sale; breeding stock; marketable bonds and securities; securities not readily marketable; accounts receivable; notes receivable; cash invested in growing crops; net cash value of life insurance; machinery and equipment; cars and trucks; farm and other real estate including life estates and personal residence; value of beneficial interests in trusts; government payments or grants; and any other assets.

(bb) The term "liability" with respect to financing of any agricultural facility or any agribusiness shall include, but not be limited to the following: accounts payable; notes or other indebtedness owed to any source; taxes; rent; amounts owed on real estate contracts or real estate mortgages; judgments; accrued interest payable; and any other liability.

(cc) The term "Predecessor Authorities" means those authorities as described in Section 845-75.

(dd) The term "housing project" means a specific work or improvement located within the State or outside the State and undertaken to provide residential dwelling accommodations, including the acquisition, construction or rehabilitation of lands, buildings and community facilities and in connection therewith to provide nonhousing facilities which are part of the housing project, including land, buildings, improvements, equipment and all ancillary facilities for use for offices, stores, retirement homes, hotels, financial institutions, service, health care, education, recreation or research establishments, or any other commercial purpose which are or are to be related to a housing development, provided that any work or improvement located outside the State is owned, operated, leased or managed by an entity located within the State, or any entity affiliated with an entity located within the State.

(ee) The term "conservation project" means any project including the acquisition, construction, rehabilitation, maintenance, operation, or upgrade that is intended to create or expand open space or to reduce energy usage through efficiency measures. For the purpose of this definition, "open space" has the definition set forth under Section 10 of the Illinois Open Land Trust Act.

(ff) The term "significant presence" means the existence within the State of the national or regional headquarters of an entity or group or such other facility of an entity or group of entities where a significant amount of the business functions are performed for such entity or group of entities.

(gg) The term "municipal bond issuer" means the State or any other state or commonwealth of the United States, or any unit of local government, school district, agency or instrumentality, office, department, division, bureau, commission, college or university thereof located in the State or any other state or commonwealth of the United States.

(hh) The term "municipal bond program project" means a program for the funding of the purchase of bonds, notes or other obligations issued by or on behalf of a municipal bond issuer.

(ii) The term "participating lender" means any trust company, bank, savings bank, credit union, merchant bank, investment bank, broker, investment trust, pension fund, building and loan association, savings and loan association, insurance company, venture capital company, or other institution approved by the Authority which provides a portion of the financing for a project.

(jj) The term "loan participation" means any loan in which the Authority co-operates with a participating lender to provide all or a portion of the financing for a project.

(kk) The term "PACE Project" means an energy project as defined in Section 5 of the Property Assessed Clean Energy Act.

(ll) The term "clean energy" means energy generation that is substantially free (90% or more) of carbon dioxide emissions by design or operations, or which otherwise contributes to the reduction in emissions of environmentally-hazardous materials or reduces the volume of environmentally-dangerous materials.

(mm) The term "clean energy project" means the acquisition, construction, refurbishment, creation, development or redevelopment of any facility, equipment, machinery, real property or personal property for use by the State or any unit of local government, school district, agency or instrumentality, office, department, division, bureau, commission, college or university of the State, for use by any person or institution, public or private, for profit or not for profit, or for use in any trade or business, which the Authority determines will aid, assist or encourage the development or implementation of clean energy in the State, or as otherwise contemplated by Article 850.

(nn) The term "Climate Bank" means the Authority in the exercise of those powers conferred on it by this Act related to clean energy or clean water, drinking water, or wastewater treatment.

(Source: P.A. 100-919, eff. 8-17-18; 101-610, eff. 1-1-20.)

(20 ILCS 3501/801-40)

Sec. 801-40. In addition to the powers otherwise authorized by law and in addition to the foregoing general corporate powers, the Authority shall also have the following additional specific powers to be exercised in furtherance of the purposes of this Act.

(a) The Authority shall have power (i) to accept grants, loans or appropriations from the federal government or the State, or any agency or instrumentality thereof, or, in the case of clean energy projects, any not for profit, philanthropic or other charitable organization, public or private, to be used for the operating expenses of the Authority, or for any purposes of the Authority, including the making of direct loans of such funds with respect to projects, and (ii) to enter into any agreement with the federal government or the State, or any agency or instrumentality thereof, in relationship to such grants, loans or appropriations.

(b) The Authority shall have power to procure and enter into contracts for any type of insurance and indemnity agreements covering loss or damage to property from any cause, including loss of use and occupancy, or covering any other insurable risk.

(c) The Authority shall have the continuing power to issue bonds for its corporate purposes. Bonds may be issued by the Authority in one or more series and may provide for the payment of any interest deemed necessary on such bonds, of the costs of issuance of such bonds, of any premium on any insurance, or of the cost of any guarantees, letters of credit or other similar documents, may provide for the funding of the reserves deemed necessary in connection with such bonds, and may provide for the refunding or advance refunding of any bonds or for accounts deemed necessary in connection with any purpose of the Authority. The bonds may bear interest payable at any time or times and at any rate or rates, notwithstanding any other provision of law to the contrary, and such rate or rates may be established by an index or formula which may be implemented or established by persons appointed or retained therefor by the Authority, or may bear no interest or may bear interest payable at maturity or upon redemption prior to maturity, may bear such date or dates, may be payable at such time or times and at such place or places, may mature at any time or times not later than 40 years from the date of issuance, may be sold at public or private sale at such time or times and at such price or prices, may be secured by such pledges, reserves, guarantees, letters of credit, insurance contracts or other similar credit support or liquidity instruments, may be executed in such manner, may be subject to redemption prior to maturity, may provide for the registration of the bonds, and may be subject to such other terms and conditions all as may be provided by the resolution or indenture authorizing the issuance of such bonds. The holder or holders of any bonds issued by the Authority may bring suits at law or proceedings in equity to compel the performance and observance by any person or by the Authority or any of its agents or employees of any contract or covenant made with the holders of such bonds and to compel such person or the Authority and any of its agents or employees to perform any duties required to be performed for the benefit of the holders of any such bonds by the provision of the resolution authorizing their issuance, and to enjoin such person or the Authority and any of its agents or employees from taking any action in conflict with any such contract or covenant. Notwithstanding the form and tenor of any such bonds and in the absence of any express recital on the face thereof that it is non-negotiable, all such bonds shall be negotiable instruments. Pending the preparation and execution of any such bonds, temporary bonds may be issued as provided by the resolution. The bonds shall be sold by the Authority in such manner as it shall determine. The bonds may be secured as provided in the authorizing resolution by the receipts, revenues, income and other available funds of the Authority and by any amounts derived by the Authority from the loan agreement or lease agreement with respect to the project or projects; and bonds may be issued as general obligations of the Authority payable from such revenues, funds and obligations of the Authority as the bond resolution shall provide, or may be issued as limited obligations with a claim for payment solely from such revenues, funds and obligations as the bond resolution shall provide. The Authority may grant a specific pledge or assignment of and lien on or security interest in such rights, revenues, income, or amounts and may grant a specific pledge or assignment of and lien on or security interest in any reserves, funds or accounts established in the resolution authorizing the issuance of bonds. Any such pledge, assignment, lien or security interest for the benefit of the holders of the Authority's bonds shall be valid and binding from the time the bonds are issued without any physical delivery or further act, and shall be valid and binding as against and prior to the claims of all other parties having claims against the Authority or any other person irrespective of whether the other parties have notice of the pledge, assignment, lien or security interest. As evidence of such pledge, assignment, lien and security interest, the Authority may execute and deliver a mortgage, trust agreement, indenture or security agreement or an assignment thereof. A remedy for any breach or default of the terms of any such agreement by the Authority may be by mandamus proceedings in any court of competent jurisdiction to compel the performance and compliance therewith, but the agreement may prescribe by whom or on whose behalf such action may be instituted. It is expressly understood that the Authority may, but need not, acquire title to any project with respect to which it exercises its authority.

(d) With respect to the powers granted by this Act, the Authority may adopt rules and regulations prescribing the procedures by which persons may apply for assistance under this Act. Nothing herein shall be deemed to preclude the Authority, prior to the filing of any formal application, from conducting preliminary discussions and investigations with respect to the subject matter of any prospective application.

(e) The Authority shall have power to acquire by purchase, lease, gift or otherwise any property or rights therein from any person useful for its purposes, whether improved for the purposes of any prospective project, or unimproved. The Authority may also accept any donation of funds for its purposes from any such source. The Authority shall have no independent power of condemnation but may acquire any property or rights therein obtained upon condemnation by any other authority, governmental entity or unit of local government with such power.

(f) The Authority shall have power to develop, construct and improve either under its own direction, or through collaboration with any approved applicant, or to acquire through purchase or otherwise, any project, using for such purpose the proceeds derived from the sale of its bonds or from governmental loans or grants, and to hold title in the name of the Authority to such projects.

(g) The Authority shall have power to lease pursuant to a lease agreement any project so developed and constructed or acquired to the approved tenant on such terms and conditions as may be appropriate to further the purposes of this Act and to maintain the credit of the Authority. Any such lease may provide for either the Authority or the approved tenant to assume initially, in whole or in part, the costs of maintenance, repair and improvements during the leasehold period. In no case, however, shall the total rentals from any project during any initial leasehold period or the total loan repayments to be made pursuant to any loan agreement, be less than an amount necessary to return over such lease or loan period (1) all costs incurred in connection with the development, construction, acquisition or improvement of the project and for repair, maintenance and improvements thereto during the period of the lease or loan; provided, however, that the rentals or loan repayments need not include costs met through the use of funds other than those obtained by the Authority through the issuance of its bonds or governmental loans; (2) a reasonable percentage additive to be agreed upon by the Authority and the borrower or tenant to cover a properly allocable portion of the Authority's general expenses, including, but not limited to, administrative expenses, salaries and general insurance, and (3) an amount sufficient to pay when due all principal of, interest and premium, if any on, any bonds issued by the Authority with respect to the project. The portion of total rentals payable under clause (3) of this subsection (g) shall be deposited in such special accounts, including all sinking funds, acquisition or construction funds, debt service and other funds as provided by any resolution, mortgage or trust agreement of the Authority pursuant to which any bond is issued.

(h) The Authority has the power, upon the termination of any leasehold period of any project, to sell or lease for a further term or terms such project on such terms and conditions as the Authority shall deem reasonable and consistent with the purposes of the Act. The net proceeds from all such sales and the revenues or income from such leases shall be used to satisfy any indebtedness of the Authority with respect to such project and any balance may be used to pay any expenses of the Authority or be used for the further development, construction, acquisition or improvement of projects. In the event any project is vacated by a tenant prior to the termination of the initial leasehold period, the Authority shall sell or lease the facilities of the project on the most advantageous terms available. The net proceeds of any such disposition shall be treated in the same manner as the proceeds from sales or the revenues or income from leases subsequent to the termination of any initial leasehold period.

(i) The Authority shall have the power to make loans, or to purchase loan participations in loans made, to persons to finance a project, to enter into loan agreements or agreements with participating lenders with respect thereto, and to accept guarantees from persons of its loans or the resultant evidences of obligations of the Authority.

(j) The Authority may fix, determine, charge and collect any premiums, fees, charges, costs and expenses, including, without limitation, any application fees, commitment fees, program fees, financing charges or publication fees from any person in connection with its activities under this Act.

(k) In addition to the funds established as provided herein, the Authority shall have the power to create and establish such reserve funds and accounts as may be necessary or desirable to accomplish its purposes under this Act and to deposit its available monies into the funds and accounts.

(l) At the request of the governing body of any unit of local government, the Authority is authorized to market such local government's revenue bond offerings by preparing bond issues for sale, advertising for sealed bids, receiving bids at its offices, making the award to the bidder that offers the most favorable terms or arranging for negotiated placements or underwritings of such securities. The Authority may, at its discretion, offer for concurrent sale the revenue bonds of several local governments. Sales by the Authority of revenue bonds under this Section shall in no way imply State guarantee of such debt issue. The Authority may require such financial information from participating local governments as it deems necessary in order to carry out the purposes of this subsection (1).

(m) The Authority may make grants to any county to which Division 5-37 of the Counties Code is applicable to assist in the financing of capital development, construction and renovation of new or existing facilities for hospitals and health care facilities under that Act. Such grants may only be made from funds appropriated for such purposes from the Build Illinois Bond Fund.

(n) The Authority may establish an urban development action grant program for the purpose of assisting municipalities in Illinois which are experiencing severe economic distress to help stimulate economic development activities needed to aid in economic recovery. The Authority shall determine the types of activities and projects for which the urban development action grants may be used, provided that such projects and activities are broadly defined to include all reasonable projects and activities the primary objectives of which are the development of viable urban communities, including decent housing and a suitable living environment, and expansion of economic opportunity, principally for persons of low and moderate incomes. The Authority shall enter into grant agreements from monies appropriated for such purposes from the Build Illinois Bond Fund. The Authority shall monitor the use of the grants, and shall provide for audits of the funds as well as recovery by the Authority of any funds determined to have been spent in violation of this subsection (n) or any rule or regulation promulgated hereunder. The Authority shall provide technical assistance with regard to the effective use of the urban development action grants. The Authority shall file an annual report to the General Assembly concerning the progress of the grant program.

(o) The Authority may establish a Housing Partnership Program whereby the Authority provides zero-interest loans to municipalities for the purpose of assisting in the financing of projects for the rehabilitation of affordable multi-family housing for low and moderate income residents. The Authority may provide such loans only upon a municipality's providing evidence that it has obtained private funding for the rehabilitation project. The Authority shall provide 3 State dollars for every 7 dollars obtained by the municipality from sources other than the State of Illinois. The loans shall be made from monies appropriated for such purpose from the Build Illinois Bond Fund. The total amount of loans available under the Housing Partnership Program shall not exceed $30,000,000. State loan monies under this subsection shall be used only for the acquisition and rehabilitation of existing buildings containing 4 or more dwelling units. The terms of any loan made by the municipality under this subsection shall require repayment of the loan to the municipality upon any sale or other transfer of the project. In addition, the Authority may use any moneys appropriated for such purpose from the Build Illinois Bond Fund, including funds loaned under this subsection and repaid as principal or interest, and investment income on such funds, to make the loans authorized by subsection (z), without regard to any restrictions or limitations provided in this subsection.

(p) The Authority may award grants to universities and research institutions, research consortiums and other not-for-profit entities for the purposes of: remodeling or otherwise physically altering existing laboratory or research facilities, expansion or physical additions to existing laboratory or research facilities, construction of new laboratory or research facilities or acquisition of modern equipment to support laboratory or research operations provided that such grants (i) be used solely in support of project and equipment acquisitions which enhance technology transfer, and (ii) not constitute more than 60 percent of the total project or acquisition cost.

(q) Grants may be awarded by the Authority to units of local government for the purpose of developing the appropriate infrastructure or defraying other costs to the local government in support of laboratory or research facilities provided that such grants may not exceed 40% of the cost to the unit of local government.

(r) In addition to the powers granted to the Authority under subsection (i), and in all cases supplemental to it, the Authority may establish a direct loan program to make loans to, or may purchase participations in loans made by participating lenders to, individuals, partnerships, corporations, or other business entities for the purpose of financing an industrial project, as defined in Section 801-10 of this Act. For the purposes of such program and not by way of limitation on any other program of the Authority, including, without limitation, programs established under subsection (i), the Authority shall have the power to issue bonds, notes, or other evidences of indebtedness including commercial paper for purposes of providing a fund of capital from which it may make such loans. The Authority shall have the power to use any appropriations from the State made especially for the Authority's direct loan program, or moneys at any time held by the Authority under this Act outside the State treasury in the custody of either the Treasurer of the Authority or a trustee or depository appointed by the Authority, for additional capital to make such loans or purchase such loan participations, or for the purposes of reserve funds or pledged funds which secure the Authority's obligations of repayment of any bond, note or other form of indebtedness established for the purpose of providing capital for which it intends to make such loans or purchase such loan participations. For the purpose of obtaining such capital, the Authority may also enter into agreements with financial institutions, participating lenders, and other persons for the purpose of administering a loan participation program, selling loans or developing a secondary market for such loans or loan participations. Loans made under the direct loan program specifically established under this subsection (r), including loans under such program made by participating lenders in which the Authority purchases a participation, may be in an amount not to exceed $600,000 and shall be made for a portion of an industrial project which does not exceed 50% of the total project. No loan may be made by the Authority unless approved by the affirmative vote of at least 8 members of the board. The Authority shall establish procedures and publish rules which shall provide for the submission, review, and analysis of each direct loan and loan participation application and which shall preserve the ability of each board member and the Executive Director, as applicable, to reach an individual business judgment regarding the propriety of each direct loan or loan participation. The collective discretion of the board to approve or disapprove each loan shall be unencumbered. The Authority may establish and collect such fees and charges, determine and enforce such terms and conditions, and charge such interest rates as it determines to be necessary and appropriate to the successful administration of the direct loan program, including purchasing loan participations. The Authority may require such interests in collateral and such guarantees as it determines are necessary to protect the Authority's interest in the repayment of the principal and interest of each loan and loan participation made under the direct loan program. The restrictions established under this subsection (r) shall not be applicable to any loan or loan participation made under subsection (i) or to any loan or loan participation made under any other Section of this Act.

(s) The Authority may guarantee private loans to third parties up to a specified dollar amount in order to promote economic development in this State.

(t) The Authority may adopt rules and regulations as may be necessary or advisable to implement the powers conferred by this Act.

(u) The Authority shall have the power to issue bonds, notes or other evidences of indebtedness, which may be used to make loans to units of local government which are authorized to enter into loan agreements and other documents and to issue bonds, notes and other evidences of indebtedness for the purpose of financing the protection of storm sewer outfalls, the construction of adequate storm sewer outfalls, and the provision for flood protection of sanitary sewage treatment plans, in counties that have established a stormwater management planning committee in accordance with Section 5-1062 of the Counties Code. Any such loan shall be made by the Authority pursuant to the provisions of Section 820-5 to 820-60 of this Act. The unit of local government shall pay back to the Authority the principal amount of the loan, plus annual interest as determined by the Authority. The Authority shall have the power, subject to appropriations by the General Assembly, to subsidize or buy down a portion of the interest on such loans, up to 4% per annum.

(v) The Authority may accept security interests as provided in Sections 11-3 and 11-3.3 of the Illinois Public Aid Code.

(w) Moral Obligation. In the event that the Authority determines that monies of the Authority will not be sufficient for the payment of the principal of and interest on its bonds during the next State fiscal year, the Chairperson, as soon as practicable, shall certify to the Governor the amount required by the Authority to enable it to pay such principal of and interest on the bonds. The Governor shall submit the amount so certified to the General Assembly as soon as practicable, but no later than the end of the current State fiscal year. This subsection shall apply only to any bonds or notes as to which the Authority shall have determined, in the resolution authorizing the issuance of the bonds or notes, that this subsection shall apply. Whenever the Authority makes such a determination, that fact shall be plainly stated on the face of the bonds or notes and that fact shall also be reported to the Governor. In the event of a withdrawal of moneys from a reserve fund established with respect to any issue or issues of bonds of the Authority to pay principal or interest on those bonds, the Chairperson of the Authority, as soon as practicable, shall certify to the Governor the amount required to restore the reserve fund to the level required in the resolution or indenture securing those bonds. The Governor shall submit the amount so certified to the General Assembly as soon as practicable, but no later than the end of the current State fiscal year. The Authority shall obtain written approval from the Governor for any bonds and notes to be issued under this Section. In addition to any other bonds authorized to be issued under Sections 825-60, 825-65(e), 830-25 and 845-5, the principal amount of Authority bonds outstanding issued under this Section 801-40(w) or under 20 ILCS 3850/1-80 or 30 ILCS 360/2-6(c), which have been assumed by the Authority, shall not exceed $150,000,000. This subsection (w) shall in no way be applied to any bonds issued by the Authority on behalf of the Illinois Power Agency under Section 825-90 of this Act.

(x) The Authority may enter into agreements or contracts with any person necessary or appropriate to place the payment obligations of the Authority under any of its bonds in whole or in part on any interest rate basis, cash flow basis, or other basis desired by the Authority, including without limitation agreements or contracts commonly known as "interest rate swap agreements", "forward payment conversion agreements", and "futures", or agreements or contracts to exchange cash flows or a series of payments, or agreements or contracts, including without limitation agreements or contracts commonly known as "options", "puts", or "calls", to hedge payment, rate spread, or similar exposure; provided that any such agreement or contract shall not constitute an obligation for borrowed money and shall not be taken into account under Section 845-5 of this Act or any other debt limit of the Authority or the State of Illinois.

(y) The Authority shall publish summaries of projects and actions approved by the members of the Authority on its website. These summaries shall include, but not be limited to, information regarding the:

(1) project;

(2) Board's action or actions;

(3) purpose of the project;

(4) Authority's program and contribution;

(5) volume cap;

(6) jobs retained;

(7) projected new jobs;

(8) construction jobs created;

(9) estimated sources and uses of funds;

(10) financing summary;

(11) project summary;

(12) business summary;

(13) ownership or economic disclosure statement;

(14) professional and financial information;

(15) service area; and

(16) legislative district.

The disclosure of information pursuant to this subsection shall comply with the Freedom of Information Act.

(z) Consistent with the findings and declaration of policy set forth in item (j) of Section 801-5 of this Act, the Authority shall have the power to make loans to the Police Officers' Pension Investment Fund authorized by Section 22B-120 of the Illinois Pension Code and to make loans to the Firefighters' Pension Investment Fund authorized by Section 22C-120 of the Illinois Pension Code. Notwithstanding anything in this Act to the contrary, loans authorized by Section 22B-120 and Section 22C-120 of the Illinois Pension Code may be made from any of the Authority's funds, including, but not limited to, funds in its Illinois Housing Partnership Program Fund, its Industrial Project Insurance Fund, or its Illinois Venture Investment Fund.

(Source: P.A. 100-919, eff. 8-17-18; 101-610, eff. 1-1-20.)

(20 ILCS 3501/Art. 850 heading new)

ARTICLE 850 GENERAL PROVISIONS

(20 ILCS 3501/850-5 new)

Sec. 850-5. Climate Bank. The General Assembly designates the Authority as the Climate Bank to aid in all respects with providing financial products and programs to finance and otherwise develop and implement clean energy and the provision of clean water, drinking water and wastewater treatment in the State. Nothing in this Section 850-5 shall be deemed to supersede powers and regulatory duties conferred to other State agencies or governmental units.

(20 ILCS 3501/850-10 new)

Sec. 850-10. Powers and Duties.

(a) The Authority shall have the powers enumerated in this Act to assist in the development and implementation of clean energy in the State. The powers enumerated in this Article 850 shall in addition to all other powers with respect to clean energy and the provision of clean water, drinking water and wastewater treatment conferred elsewhere in the Act.

(b) In its role as the Climate Bank of the State, the Authority shall have the power to (i) finance and otherwise support clean energy projects and investment in the State, including for residential, municipal, small business and larger commercial projects as it may determine, (ii) support and otherwise promote investment in clean energy projects to foster the growth, development and commercialization of clean energy projects and related enterprises, and (iii) stimulate demand for clean energy and the development of clean energy projects within the State.

(c) In addition to, and not in limitation of, any other power of the Authority set forth in this Section or any other provisions of the general statutes, the Authority shall have and may exercise the following powers in furtherance of or in carrying out its clean energy powers and purposes:

(1) To enter into joint ventures and invest in, and participate with any person, including, without limitation, government entities and private corporations, in the formation, ownership, management and operation of business entities, including stock and nonstock corporations, limited liability companies and general or limited partnerships, formed to advance the purposes of clean energy, provided that members of the Authority or officers may serve as directors, members or officers of any such business entity, and such service shall be deemed to be in the discharge of the duties or within the scope of the employment of any such member or officer, or Authority or officers, as the case may be, so long as such member or officer does not receive any compensation or direct or indirect financial benefit as a result of serving in such role.

(2) To do all other acts and things necessary or convenient to carry out the clean energy purposes and powers of the Authority.

(3) To utilize funding sources including but not limited to:

(A) funds repurposed from existing programs providing financing support for clean energy projects, provided any transfer of funds from such existing programs shall be subject to approval by the General Assembly and shall be used for expenses of financing, grants and loans;

(B) any federal funds that can be used for clean energy purposes;

(C) charitable gifts, grants, contributions as well as loans from individuals, corporations, university endowments and philanthropic foundations for clean energy projects or for the provision of clean water, drinking water and wastewater treatment;

(D) earnings and interest derived from financing support activities for clean energy projects financed by the Authority; and

(E) if and to the extent that the Authority qualifies as a Community Development Financial Institution under Section 4702 of the United States Code, funding from the Community Development Financial Institution Fund administered by the United States Department of Treasury, as well as loans from and investments by depository institutions seeking to comply with their obligations under the United States Community Reinvestment Act of 1977.

(4) The Authority may enter into contracts with private sources to raise capital.

(f) The Authority may finance working capital, refinance outstanding indebtedness of any person, and otherwise assist in the investment of equity from any source, public or private, in connection with a clean energy project.

(g) The Authority may assess reasonable fees on its financing activities to cover its reasonable costs and expenses, as determined by it.

(h) The Authority shall make information regarding the rates, terms and conditions for all of its financing support transactions available to the public for inspection, including formal annual reviews by both a private auditor and the Comptroller, and providing details to the public on the internet, provided public disclosure shall be restricted for patentable ideas, trade secrets, proprietary or confidential commercial or financial information, disclosure of which may cause commercial harm to a nongovernmental recipient of such financing support and for other information exempt from public records disclosure pursuant to Section 1-210.

(20 ILCS 3501/850-15 new)

Sec. 850-15. Purposes. In its role as the Climate Bank for the State, the Authority shall consider the following purposes:

(a) the equitable distribution of the benefits of clean energy;

(b) making clean energy accessible to all through financing opportunities and grants for Minority Business Enterprises, as defined in the Business Enterprise Act, and for low-income communities, environmental justice communities, and the businesses that serve these communities; and

(c) accelerating the investment of private capital into clean energy projects in an equitable fashion in order to reflect the geographic, racial, ethnic, gender, and income-level diversity of the State.

Section 30-23. The Energy Efficient Building Act is amended by changing Sections 10, 15, 20, 30, and 45 and by adding Section 55 as follows:

(20 ILCS 3125/10)

Sec. 10. Definitions.

"Board" means the Capital Development Board.

"Building" includes both residential buildings and commercial buildings.

"Code" means the latest published edition of the International Code Council's International Energy Conservation Code as adopted by the Board, including any published supplements adopted by the Board and any amendments and adaptations to the Code that are made by the Board.

"Commercial building" means any building except a building that is a residential building, as defined in this Section.

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

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

"Residential building" means (i) a detached one-family or 2-family dwelling or (ii) any building that is 3 stories or less in height above grade that contains multiple dwelling units, in which the occupants reside on a primarily permanent basis, such as a townhouse, a row house, an apartment house, a convent, a monastery, a rectory, a fraternity or sorority house, a dormitory, and a rooming house; provided, however, that when applied to a building located within the boundaries of a municipality having a population of 1,000,000 or more, the term "residential building" means a building containing one or more dwelling units, not exceeding 4 stories above grade, where occupants are primarily permanent.

"Site energy index" means a scalar published by the Pacific Northwest National Laboratories representing the ratio of the site energy performance of an evaluated code compared to the site energy performance of the 2006 International Energy Conservation Code. A "site energy index" includes only conservation measures and excludes net energy credit for any on-site or off-site energy production.

(Source: P.A. 101-144, eff. 7-26-19.)

(20 ILCS 3125/15)

Sec. 15. Energy Efficient Building Code. The Board, in consultation with the Department, shall adopt the Code as minimum requirements for commercial buildings, applying to the construction of, renovations to, and additions to all commercial buildings in the State. The Board, in consultation with the Department, shall also adopt the Code as the minimum and maximum requirements for residential buildings, applying to the construction of, renovations to, and additions to all residential buildings in the State, except as provided for in Section 45 of this Act. The Board may appropriately adapt the International Energy Conservation Code to apply to the particular economy, population distribution, geography, and climate of the State and construction therein, consistent with the public policy objectives of this Act.

(Source: P.A. 96-778, eff. 8-28-09.)

(20 ILCS 3125/20)

Sec. 20. Applicability.

(a) The Board shall review and adopt the Code within one year after its publication. The Code shall take effect within 6 months after it is adopted by the Board, except that, beginning January 1, 2012, the Code adopted in 2012 shall take effect on January 1, 2013. Except as otherwise provided in this Act, the Code shall apply to (i) any new building or structure in this State for which a building permit application is received by a municipality or county and (ii) beginning on the effective date of this amendatory Act of the 100th General Assembly, each State facility specified in Section 4.01 of the Capital Development Board Act. In the case of any addition, alteration, renovation, or repair to an existing residential or commercial structure, the Code adopted under this Act applies only to the portions of that structure that are being added, altered, renovated, or repaired. The changes made to this Section by this amendatory Act of the 97th General Assembly shall in no way invalidate or otherwise affect contracts entered into on or before the effective date of this amendatory Act of the 97th General Assembly.

(b) The following buildings shall be exempt from the Code:

(1) Buildings otherwise exempt from the provisions of a locally adopted building code and buildings that do not contain a conditioned space.

(2) Buildings that do not use either electricity or fossil fuel for comfort conditioning. For purposes of determining whether this exemption applies, a building will be presumed to be heated by electricity, even in the absence of equipment used for electric comfort heating, whenever the building is provided with electrical service in excess of 100 amps, unless the code enforcement official determines that this electrical service is necessary for purposes other than providing electric comfort heating.

(3) Historic buildings. This exemption shall apply to those buildings that are listed on the National Register of Historic Places or the Illinois Register of Historic Places, and to those buildings that have been designated as historically significant by a local governing body that is authorized to make such designations.

(4) (Blank).

(5) Other buildings specified as exempt by the International Energy Conservation Code.

(c) Additions, alterations, renovations, or repairs to an existing building, building system, or portion thereof shall conform to the provisions of the Code as they relate to new construction without requiring the unaltered portion of the existing building or building system to comply with the Code. The following need not comply with the Code, provided that the energy use of the building is not increased: (i) storm windows installed over existing fenestration, (ii) glass-only replacements in an existing sash and frame, (iii) existing ceiling, wall, or floor cavities exposed during construction, provided that these cavities are filled with insulation, and (iv) construction where the existing roof, wall, or floor is not exposed.

(d) A unit of local government that does not regulate energy efficient building standards is not required to adopt, enforce, or administer the Code; however, any energy efficient building standards adopted by a unit of local government must comply with this Act. If a unit of local government does not regulate energy efficient building standards, any construction, renovation, or addition to buildings or structures is subject to the provisions contained in this Act.

(Source: P.A. 100-729, eff. 8-3-18.)

(20 ILCS 3125/30)

Sec. 30. Enforcement. The Board, in consultation with the Department, shall determine procedures for compliance with the Code. These procedures may include but need not be limited to certification by a national, State, or local accredited energy conservation program or inspections from private Code-certified inspectors using the Code. For purposes of the Illinois Stretch Energy Code under Section 55, the Board shall allow and encourage, as an alternative compliance mechanism, project certification by a nationally recognized nonprofit certification organization specializing in high-performance passive buildings and offering climate-specific building energy standards that require equal or better energy performance than the Illinois Stretch Energy Code.

(Source: P.A. 93-936, eff. 8-13-04.)

(20 ILCS 3125/45)

Sec. 45. Home rule.

(a) (Blank). No unit of local government, including any home rule unit, may regulate energy efficient building standards for commercial buildings in a manner that is less stringent than the provisions contained in this Act.

(b) No unit of local government, including any home rule unit, may regulate energy efficient building standards for residential buildings in a manner that is either less or more stringent than the standards established pursuant to this Act; provided, however, that the following entities may regulate energy efficient building standards for residential or commercial buildings in a manner that is more stringent than the provisions contained in this Act: (i) a unit of local government, including a home rule unit, that has, on or before May 15, 2009, adopted or incorporated by reference energy efficient building standards for residential or commercial buildings that are equivalent to or more stringent than the 2006 International Energy Conservation Code, (ii) a unit of local government, including a home rule unit, that has, on or before May 15, 2009, provided to the Capital Development Board, as required by Section 10.18 of the Capital Development Board Act, an identification of an energy efficient building code or amendment that is equivalent to or more stringent than the 2006 International Energy Conservation Code, (ii-5) a municipality that has adopted the Illinois Stretch Energy Code, and (iii) a municipality with a population of 1,000,000 or more.

(c) No unit of local government, including any home rule unit or unit of local government that is subject to State regulation under the Code as provided in Section 15 of this Act, may hereafter enact any annexation ordinance or resolution, or require or enter into any annexation agreement, that imposes energy efficient building standards for residential or commercial buildings that are either less or more stringent than the energy efficiency standards in effect, at the time of construction, throughout the unit of local government, except for the Illinois Stretch Energy Code.

(d) This Section is a denial and limitation of home rule powers and functions under subsection (i) of Section 6 of Article VII of the Illinois Constitution on the concurrent exercise by home rule units of powers and functions exercised by the State. Nothing in this Section, however, prevents a unit of local government from adopting an energy efficiency code or standards for commercial buildings that are more stringent than the Code under this Act.

(Source: P.A. 99-639, eff. 7-28-16.)

(20 ILCS 3125/55 new)

Sec. 55. Illinois Stretch Energy Code.

(a) The Board, in consultation with the Department, shall create and adopt the Illinois Stretch Energy Code, to allow municipalities and projects authorized or funded by the Board to achieve more energy efficiency in buildings than the Illinois Energy Conservation Code through a consistent pathway across the State. The Illinois Stretch Energy Code shall be available for adoption by any municipality and shall set The Illinois Stretch Energy Code shall be available for adoption by any municipality and shall set minimum energy efficiency requirements, taking the place of the Illinois Energy Conservation Code within any municipality that adopts the Illinois Stretch Energy Code.

(b) The Illinois Stretch Energy Code shall have separate components for commercial and residential buildings, which may be adopted by the municipality jointly or separately.

(c) The Illinois Stretch Energy Code shall apply to all projects to which an energy conservation code is applicable that are authorized or funded in any part by the Board after January 1, 2023.

(d) Development of the Illinois Stretch Energy Code shall be completed and available for adoption by municipalities by December 31, 2022.

(e) Consistent with the requirements under paragraph (2.5) of subsection (g) of Section 8-103B of the Public Utilities Act and under paragraph (2) of subsection (j) of Section 8-104.1 of the Public Utilities Act, municipalities that adopt the Illinois Stretch Energy Code may use utility programs to support compliance with the Illinois Stretch Energy Code. The amount of savings from such utility efforts that may be counted toward achievement of their cumulative persisting annual savings goals shall be based on reasonable estimates of the increase in savings resulting from the utility efforts, relative to reasonable approximations of what would have occurred absent the utility involvement.

(f) The Illinois Stretch Energy Code's residential components shall:

(1) apply to residential buildings as defined under Section 10;

(2) set performance targets using a site energy index with reductions relative to the 2006 International Energy Conservation Code; and

(3) include stretch energy codes with site energy index standards and adoption dates as follows: by no later than December 31, 2022, the Board shall create and adopt a stretch energy code with a site energy index no greater than 0.50 of the 2006 International Energy Conservation Code; by no later than December 31, 2025, the Board shall create and adopt a stretch energy code with a site energy index no greater than 0.40 of the 2006 International Energy Conservation Code, unless the Board identifies unanticipated burdens associated with the stretch energy code adopted in 2022, in which case the Board may adopt a stretch energy code with a site energy index no greater than 0.42 of the 2006 International Energy Conservation Code, provided that the more relaxed standard has a site energy index that is at least 0.05 more restrictive than the 2024 International Energy Conservation Code; by no later than December 31, 2028, the Board shall create and adopt a stretch energy code with a site energy index no greater than 0.33 of the 2006 International Energy Conservation Code, unless the Board identifies unanticipated burdens associated with the stretch energy code adopted in 2025, in which case the Board may adopt a stretch energy code with a site energy index no greater than 0.35 of the 2006 International Energy Conservation Code, but only if that more relaxed standard has a site energy index that is at least 0.05 more restrictive than the 2027 International Energy Conservation Code; and by no later than December 31, 2031, the Board shall create and adopt a stretch energy code with a site energy index no greater than 0.25 of the 2006 International Energy Conservation Code.

(g) The Illinois Stretch Energy Code's commercial components shall:

(1) apply to commercial buildings as defined under Section 10;

(2) set performance targets using a site energy index with reductions relative to the 2006 International Energy Conservation Code; and

(3) include stretch energy codes with site energy index standards and adoption dates as follows: by no later than December 31, 2022, the Board shall create and adopt a stretch energy code with a site energy index no greater than 0.60 of the 2006 International Energy Conservation Code; by no later than December 31, 2025, the Board shall create and adopt a stretch energy code with a site energy index no greater than 0.50 of the 2006 International Energy Conservation Code; by no later than December 31, 2028, the Board shall create and adopt a stretch energy code with a site energy index no greater than 0.44 of the 2006 International Energy Conservation Code; and by no later than December 31, 2031, the Board shall create and adopt a stretch energy code with a site energy index no greater than 0.39 of the 2006 International Energy Conservation Code.

(h) The process for the creation of the Illinois Stretch Energy Code includes:

(1) within 60 days after the effective date of this amendatory Act of the 102nd General Assembly, the Capital Development Board shall establish an Illinois Stretch Energy Code Task Force to advise and provide technical assistance and recommendations to the Capital Development Board for the Illinois Stretch Energy Code, which shall:

(A) advise the Capital Development Board on creation of interim performance targets, code requirements, and an implementation plan for the Illinois Stretch Energy Code;

(B) recommend amendments to proposed rules issued by the Capital Development Board;

(C) recommend complementary programs or policies;

(D) complete recommendations and development for the Illinois Stretch Energy Code elements and requirements by July 31, 2022;

(E) be composed of, but not limited to, representatives, or their designees, from the following entities:

(i) a representative from a group that represents environmental justice;

(ii) a representative of a nonprofit or professional association advocating for the environment;

(iii) a representative of an organization representing local governments in the metropolitan Chicago region;

(iv) a representative of the City of Chicago;

(v) a representative of an organization representing local governments outside the metropolitan Chicago region;

(vi) a representative for the investor-owned utilities of Illinois;\

(vii) an energy-efficiency advocate with technical expertise in single-family residential buildings;

(viii) an energy-efficiency advocate with technical expertise in commercial buildings;

(ix) an energy-efficiency advocate with technical expertise in multifamily buildings, such as an affordable housing developer;

(x) a representative from the architecture or engineering industry;

(xi) a representative from a home builders association;

(xii) a representative from the commercial building industry;

(xiii) a representative of the enforcement industry, such as a code official or energy rater;

(xiv) a representative of organized labor; and

(xv) other experts or organizations deemed necessary by the Capital Development Board; and

(F) be co-chaired by:

(i) a representative of the environmental community;

(ii) a representative of the environmental justice community; and

(iii) a municipal representative.

(2) As part of its deliberations, the Illinois Stretch Energy Code Task Force shall actively solicit input from other energy code stakeholders and interested parties.

Section 30-25. The Illinois Power Agency Act is amended by changing Sections 1-5, 1-10, 1-35, 1-56, 1-70, 1-75, 1-92, and 1-125 and by adding Sections 1-135 and 1-140 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) In order to provide for the highest quality of life for the citizens of Illinois, and to provide for a healthy environment and prosperity for Illinois citizens through a clean energy economy, it is the policy of the State of Illinois to transition to 100% clean energy by 2050. For purposes of this Section, "clean energy" means energy generation that is substantially free (90% or greater) of carbon dioxide emissions.

(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.

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 3855/1-10)

Sec. 1-10. Definitions.

"Agency" means the Illinois Power Agency.

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

"Authority" means the Illinois Finance Authority.

"Brownfield site photovoltaic project" means photovoltaics that are:

(1) interconnected to an electric utility as defined in this Section, a municipal utility as defined in this Section, a public utility as defined in Section 3-105 of the Public Utilities Act, or an electric cooperative, as defined in Section 3-119 of the Public Utilities Act; and

(2) located at a site that is regulated by any of the following entities under the following programs:

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

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

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

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

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

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

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

"Commission" means the Illinois Commerce Commission.

"Community renewable generation project" means an electric generating facility that:

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

(2) is interconnected at the distribution system level of an electric utility as defined in this Section, a municipal utility as defined in this Section that owns or operates electric distribution facilities, a public utility as defined in Section 3-105 of the Public Utilities Act, or an electric cooperative, as defined in Section 3-119 of the Public Utilities Act;

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

(4) is limited in nameplate capacity to less than or equal to 10,000 2,000 kilowatts.

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

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

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

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

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

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

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

"Delivery year" means the consecutive 12-month period beginning June 1 of a given year and ending May 31 of the following year.

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

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

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

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

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

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

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

(4) limited in nameplate capacity to less than or equal to 2,000 kilowatts.

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

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

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

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

"Index Price" means the real-time settlement price at the applicable Illinois trading hub, such as PJM-NIHUB or MISO-IL, for a given settlement period.

"Indexed REC Buyer" means as public utility that serves as a Buyer under a REC delivery contract executed pursuant to item (v) of subparagraph (G) of paragraph (1) of subsection (c) of Section 1-75 of this Act.

"Indexed renewable energy credit" or "Indexed REC" means a renewable energy credit featuring a purchase price calculated by subtracting the strike price originally offered by a new utility scale wind project or a new utility scale photovoltaic project from the index price in a given settlement period.

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

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

"Municipal utility" means a public utility owned and operated by any subdivision or municipal corporation of this State.

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

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

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

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

"Qualified combined heat and power systems" means systems that, either simultaneously or sequentially, produce electricity and useful thermal energy from a single fuel source. Such systems are eligible for renewable energy credits in an amount equal to their total energy output (electric and thermal) where a renewable fuel is consumed or, where a non-renewable fuel is consumed, a percent equal to the displaced fuel use and CO₂ emissions attributable to the operation of the combined heat and power system as calculated based on the United States Environmental Protection Agency's fuel and carbon dioxide emissions savings calculation methodology for combined heat and power systems.

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

"Renewable energy credit" or "REC" means a tradable credit that represents the environmental attributes of one megawatt hour of energy produced from a renewable energy resource.

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

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

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

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

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

"Settlement period" means the period of time utilized by MISO, PJM, and their successor organizations as the basis for settlement calculations in the real-time market.

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

"Strike price" means a contract price for energy and renewable energy credits from a new utility-scale wind project or a new utility-scale photovoltaic project.

"Subscriber" means a person who (i) takes delivery service from an electric utility, and (ii) has a subscription of no less than 200 watts to a community renewable generation project that is located in the electric utility's service area. No subscriber's subscriptions may total more than 40% of the nameplate capacity of an individual community renewable generation project. Entities that are affiliated by virtue of a common parent shall not represent multiple subscriptions that total more than 40% of the nameplate capacity of an individual community renewable generation project.

"Subscription" means an interest in a community renewable generation project expressed in kilowatts, which is sized primarily to offset part or all of the subscriber's electricity usage.

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

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

"Utility-scale solar project" means an electric generating facility that:

(1) generates electricity using photovoltaic cells; and

(2) has a nameplate capacity that is greater than 10,000 2,000 kilowatts.

"Utility-scale wind project" means an electric generating facility that:

(1) generates electricity using wind; and

(2) has a nameplate capacity that is greater than 10,000 2,000 kilowatts.

"Waste heat to power systems" means systems that capture and generate electricity from energy that would otherwise be lost to the atmosphere without the use of additional fuel.

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

"Zero emission facility" means a facility that: (1) is fueled by nuclear power; and (2) is interconnected with PJM Interconnection, LLC or the Midcontinent Independent System Operator, Inc., or their successors.

(Source: P.A. 98-90, eff. 7-15-13; 99-906, eff. 6-1-17.)

(20 ILCS 3855/1-35)

Sec. 1-35. Agency rules. The Agency shall adopt rules as may be necessary and appropriate for the operation of the Agency. In addition to other rules relevant to the operation of the Agency, the Agency shall adopt rules that accomplish each of the following:

(1) Establish procedures for monitoring the administration of any contract administered directly or indirectly by the Agency; except that the procedures shall not extend to executed contracts between electric utilities and their suppliers.

(2) If deemed necessary by the Agency, establish Establish procedures for the recovery of costs incurred in connection with the development and construction of a facility should the Agency cancel a project, provided that no such costs shall be passed on to public utilities or their customers or paid from the Illinois Power Agency Operations Fund.

(3) Implement accounting rules and a system of accounts, in accordance with State law, permitting all reporting (i) required by the State, (ii) required under this Act, (iii) required by the Authority, or (iv) required under the Public Utilities Act.

The Agency shall not adopt any rules that infringe upon the authority granted to the Commission.

(Source: P.A. 95-481, eff. 8-28-07.)

(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 provides shall include incentives for low-income distributed generation and community solar projects and other qualifying projects and initiatives, and other associated approved expenditures made in connection with the Illinois Solar for All Program. The objectives of the Illinois Solar for All Program are to bring photovoltaics to low-income communities, nonprofit facilities, and public facilities in this State in an effort a manner that maximizes the development of new photovoltaic generating facilities, to create a long-term, low-income solar marketplace. The Illinois Solar for All Program shall be implemented in a manner that seeks to minimize administrative costs, and maximize efficiencies and synergies available through coordination with similar initiatives, including the Adjustable Block Program described in subparagraphs (K) through (M) of paragraph (1) of subsection (c) of Section 1-75, energy efficiency programs, job training programs, and community action agencies throughout this State, to integrate, through interaction with stakeholders, with existing energy efficiency initiatives, and to minimize administrative costs. The Illinois Solar for All Program shall be implemented to ensure that the physical location of all supported projects features geographic and demographic diversity, and that participating projects are not concentrated only in select areas. 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. To incentivize the development of applicant projects, the The Agency or electric utility, as applicable, shall purchase renewable energy credits from participating photovoltaic projects under contracts subject to approval of the Illinois Commerce Commission as required by subparagraph (iii) of paragraph (5) of subsection (b) of Section 16-111.5 of the Public Utilities Act 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 (E) (D) of this paragraph (2), which the Agency shall implement through renewable energy credit delivery contracts with program participants 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, as well as funding authorized pursuant to Section 1-75(c)(1)(O) of this Act, shall initially be allocated among the programs described in this paragraph (2), as follows: 40% 22.5% of these funds shall be allocated to programs described in subparagraph (A) of this paragraph (2), 40% 37.5% of these funds shall be allocated to programs described in subparagraph (B) of this paragraph (2), 20% 15% of these funds shall be allocated to programs described in subparagraph (C) of this paragraph (2) and no more than $20 million , 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). The allocation of funds among subparagraphs (A), (B), or (C), and (D) of this paragraph (2) may be changed if the Agency, after receiving input through a stakeholder process, or administrator, through delegated authority, determines incentives in subparagraphs (A), (B), or (C), or (D) of this paragraph (2) have not been or unlikely to be adequately subscribed to fully utilize available Illinois Solar for All Program Funds the Illinois Power Agency Renewable Energy Resources Fund. The determination shall include 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, to be set 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, with the specific level of trainee usage to be determined through the Agency's long-term renewable resources procurement plan, and the Illinois Solar for All Program Administrator shall endeavor to coordinate with the administrator of job training programs described in paragraph (1) of subsection (a) of Section 16-108.12 of the Public Utilities Act to help ensure that program participants can be connected with the graduates of these and other job training programs.

(A) Low-income distributed generation incentive. This program will provide incentives to projects benefiting 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. 40% of the incentives for this program shall be allocated to projects that are 1-4 unit residential facilities, although the Agency may consider a standalone program for residential facilities as provided for in paragraph (2). 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. To be eligible for these incentives, the applicable facility of that not-for-profit or public sector customer must provide services that primarily serve low-income customers. 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. Participants may combine incentive funding available through the Illinois Solar for All Program with funding available through other initiatives, including federal tax credits if such credits are available, but the Agency may adjust renewable energy credit prices applicable to projects benefiting from such funding to reflect offset costs.

(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 ratebase.

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).

In addition to the programs outlined in paragraphs (A) through (D), the Agency and other parties may propose additional programs through the Long-Term Renewable Resources Procurement Plan developed and approved under paragraph (5) of subsection (b) of Section 16-111.5 of the Public Utilities Act. Additional programs may target market segments not specified above and may also include incentives targeted to increase the uptake of non-photovoltaic technologies by low-income customers, including energy storage paired with photovoltaics, if the Commission determines that the Illinois Solar for All Program would provide greater benefits to the public health and well-being of low-income residents through also supporting that additional program versus supporting programs already authorized.

(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, including costs related to income verification and facilitating customer participation in the program 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 and funds allocated pursuant to subparagraph (O) of paragraph (1) of subsection (c) of Section 1-75, but the Agency or program administrator shall strive to minimize costs in the implementation of the program. The Agency or contracting electric utility 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 interconnecting utility and verified as and is energized by the Program Administrator. Payments for renewable energy credits The payment shall be in exchange for an assignment of all renewable energy credits generated by the participating project system during the first 15 years of its 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 additional capital necessary to successfully access targeted market segments 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 or contracting electric utility shall retire any renewable energy credits purchased under 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, if applicable.

The Agency shall direct 5% of the funds available under the Illinois Solar for All Program to community-based groups and other qualifying organizations to assist in community-driven education efforts related to the Illinois Solar for All Program, including general energy education, job training program outreach efforts, and other activities deemed to be qualified by the Agency. Grassroots education funding shall not be used to support the marketing by solar project development firms and organizations, unless such education provides equal opportunities for all applicable firms and organizations.

(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 requirements applicable to participating entities and project applications, 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. Renewable energy credit prices may be fixed or determined through a formula. 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. Those changes may be implemented between long-term renewable resources procurement plan approval processes if accompanied by a stakeholder review and comment, and the The Commission shall otherwise 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. The third-party program administrator may be, but need not be, the same administrator as for the Adjustable Block Program described in subparagraphs (K) through (M) of paragraph (1) of subsection (c) of Section 1-75.

The third-party administrator's responsibilities shall also include facilitating placement for graduates of Illinois-based renewable energy-specific job training programs, including the Clean Jobs Workforce Network Program administered by the Department of Commerce and Economic Opportunity and programs administered under Section 16-108.12 of the Public Utilities Act. To increase the uptake of trainees by participating firms, the administrator shall also develop a web-based clearinghouse for information available to both job training program graduates and firms participating, directly or indirectly, in Illinois solar incentive programs. The program administrator shall also coordinate its activities with entities implementing electric and natural gas income-qualified energy efficiency programs, including customer referrals to and from such programs, and connect prospective low-income solar customers with any existing deferred maintenance programs where applicable.

(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, an the Agency shall select an independent evaluator shall 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.

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 2 5 years.

For the purposes of this subsection (b), the Agency shall define "environmental justice community" 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 3855/1-70)

Sec. 1-70. Agency officials.

(a) The Agency shall have a Director who meets the qualifications specified in Section 5-222 of the Civil Administrative Code of Illinois.

(b) Within the Illinois Power Agency, the Agency shall establish a Planning and Procurement Bureau and may establish a Resource Development Bureau. Each Bureau shall report to the Director.

(c) The Chief of the Planning and Procurement Bureau shall be appointed by the Director, at the Director's sole discretion, and (i) shall have at least 5 years of direct experience in electricity supply planning and procurement and (ii) shall also hold an advanced degree in risk management, law, business, or a related field.

(d) The Chief of the Resource Development Bureau may be appointed by the Director and (i) shall have at least 5 years of direct experience in electric generating project development and (ii) shall also hold an advanced degree in economics, engineering, law, business, or a related field.

(e) For terms ending before December 31, 2019, the Director shall receive an annual salary of $100,000 or as set by the Executive Ethics Commission based on a review of comparable State agency director salaries Compensation Review Board, whichever is higher. For terms ending before December 31, 2019, the Bureau Chiefs shall each receive an annual salary of $85,000 or as set by the Compensation Review Board, whichever is higher. For terms beginning after the effective date of this amendatory Act of the 100th General Assembly, the annual salaries for the Director and the Bureau Chiefs shall be an amount equal to 15% more than the respective position's annual salary as of December 31, 2018. The calculation of the 2018 salary base for this adjustment shall not include any cost of living adjustments, as authorized by Senate Joint Resolution 192 of the 86th General Assembly, for the period beginning July 1, 2009 to June 30, 2019. Beginning July 1, 2019 and each July 1 thereafter, the Director and the Bureau Chiefs shall receive an increase in salary based on a cost of living adjustment as authorized by Senate Joint Resolution 192 of the 86th General Assembly.

(f) The Director and Bureau Chiefs shall not, for 2 years prior to appointment or for 2 years after he or she leaves his or her position, be employed by an electric utility, independent power producer, power marketer, or alternative retail electric supplier regulated by the Commission or the Federal Energy Regulatory Commission.

(g) The Director and Bureau Chiefs are prohibited from: (i) owning, directly or indirectly, 5% or more of the voting capital stock of an electric utility, independent power producer, power marketer, or alternative retail electric supplier; (ii) being in any chain of successive ownership of 5% or more of the voting capital stock of any electric utility, independent power producer, power marketer, or alternative retail electric supplier; (iii) receiving any form of compensation, fee, payment, or other consideration from an electric utility, independent power producer, power marketer, or alternative retail electric supplier, including legal fees, consulting fees, bonuses, or other sums. These limitations do not apply to any compensation received pursuant to a defined benefit plan or other form of deferred compensation, provided that the individual has otherwise severed all ties to the utility, power producer, power marketer, or alternative retail electric supplier.

(Source: P.A. 99-536, eff. 7-8-16; 100-1179, eff. 1-18-19.)

(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 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), and a second revised long-term renewable resources procurement plan shall be released for comment no later than 120 days after the effective date of this amendatory Act of the 102nd General Assembly. 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 attempt to meet include the goals for procurement of renewable energy credits at levels of 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 2.5% each delivery year thereafter to at least 40% by the 2030 delivery year; and continuing at no less than 40% 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) 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) of this paragraph (1) over the annual percentage targets described in this subparagraph (B).

For the delivery year beginning June 1, 2017, the procurement plan shall attempt to include, subject to the prioritization outlined above, 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 attempt to include, subject to the prioritization outlined above, 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 attempt to include, subject to the prioritization outlined above, 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 2.5% each delivery year thereafter to at least 40% by June 1, 2030 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 from new projects in amounts equal to at least the following:

(i) 10,000,000 renewable energy credits under contract to be delivered annually from new wind and solar projects by the end of delivery year 2021, and (i) By the end of the 2020 delivery year:

increasing ratably to reach 45,000,000 renewable energy credits under contract to be delivered annually from new renewable energy projects by the end of delivery year 2031 such that the goals in subsection (b) of this Section (1) are met entirely by procurements of renewable energy credits from new projects. 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 to the extent possible, and subject to revision by the Commission through its approval of the Agency's long-term renewable resources procurement plan, the Agency shall procure 50% from wind projects and 50% from photovoltaic projects. Of the amount procured from solar projects, the Agency shall endeavor to procure: 40% 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; and 8% at least 2% from brownfield site photovoltaic projects that are not community renewable generation. Programs or competitive procurements used to incentivize the development of new projects utilizing technologies other than wind or photovoltaics may also be proposed as part of the Agency's long-term renewable resources procurement plan, and if successfully procured, shall count toward these targets. projects; and the remainder shall be determined through the long-term planning process described in subparagraph (A) of this paragraph (1).

(ii) In any given delivery year, if forecasted expenses are less than the maximum budget available under subparagraph (E), the Agency shall continue to procure renewable credits until that budget is exhausted in the manner outlined in item (i) of this subparagraph (C). (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).

(iii) 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).

(iv) For purposes of this subparagraph (C), "Brownfield site photovoltaic project" shall generally refer to photovoltaic projects that are:

(I) interconnected to an electric utility as defined in this Section, a public utility as defined in Section 3-105 of the Public Utilities Act, or an electric cooperative as defined in Section 3-199 of the Public Utilities Act; and

(II) located at a site that meets one of the following criteria:

is or was recently regulated by the United States Environmental Protection Agency under the federal Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended;

is or was recently regulated by the United States Environmental Protection Agency under the Corrective Action Program of the federal Resource Conservation and Recovery Act, as amended;

is or was recently regulated by the Illinois Environmental Protection Agency under the Illinois Site Remediation Program;

is or was recently regulated by the Illinois Environmental Protection Agency under the Illinois Solid Waste Program; or

is primarily physically located on the same parcel or adjacent parcel to a parcel of land on which an electric generating facility that burned coal as its primary fuel source as of January 1, 2019 is located.

As necessary to maximize the State's interest in the health, safety, and welfare of its residents, this brownfield site photovoltaic project definition may be further refined, including narrowed, through the development and approval of the Illinois Power Agency's Long-Term Renewable Resources Plan produced by the Illinois Power Agency pursuant to Section 16-111.5(b)(5) of the Public Utilities Act. If no further refinements to this definition have been made prior to the Agency conducting a brownfield site photovoltaic project procurement event, the Agency and its Procurement Administrator may, after stakeholder comment, adopt participation requirements more restrictive than this definition for brownfield site photovoltaic project procurement events.

In developing its long-term renewable resources procurement plan, the Agency may consider approaches other than competitive procurements for the procurement of renewable energy credits from brownfield site photovoltaic projects. The Commission may approve an alternative procurement approach for renewable energy credits from brownfield site photovoltaic projects if it demonstrates that the alternative procurement approach is likely to more effectively return blighted or contaminated land to productive use while enhancing public health and well-being of Illinois residents, taking into account any benefits of cost-efficiencies.

(v) The Agency shall ensure that costs associated with renewable energy credit contracts executed by counterparty electric utilities match with that electric utility's anticipated budget under subparagraph (E). However, in approving the Agency's long-term renewable resources procurement plan, the Agency may propose and the Commission may consider requirements associated with the physical location of new wind projects and new solar projects that reflect needs specific to each electric utility's service territory, including known or anticipated retirements of other electric generating facilities and imports of energy from other states into that utility's service territory.

(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. Confidential benchmarks 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, capacity, 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 the percentage limitations as included in paragraphs (1), (2), and (3) of subsection (m) of Section 8-103B of the Public Utilities Act 2.015% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009, however the limitation in paragraph (3) shall continue on without end 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.

(E-5) If the limitation on the amount of renewable energy resources procured in subparagraph (E) of this paragraph (1) would prevent the Agency from meeting all of the goals in this subsection (c), the Agency shall procure additional renewable energy resources using additional funds collected pursuant to Section 16-108(k) of the Public Utilities Act if so authorized by the Illinois Commerce Commission in approving the Agency's long-term renewable resources procurement plan, but only if required to (I) ensure that any contractual obligations existing at the time of that determination are fully met or (II) to ensure that program and procurement activity would not be subject to prolonged cessation. The utilities shall be entitled to recover the total cost associated with procuring renewable energy credits required by this Section regardless of whether the costs are subject to the limitations described in subparagraph (E) of this paragraph (1) through the automatic adjustment clause tariff under subsection (k) of Section 16-108 of the Public Utilities Act.

(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 existing as of June 1, 2021;

(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

(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, 2023 2021, unless the project has delays in the establishment of an operating interconnection with the applicable transmission or distribution system as a result of the actions or inactions of the transmission or distribution provider, or other causes for force majeure as outlined in the procurement contract, in which case, not later than June 1, 2022. 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, 2023 2021, unless the project has delays in the establishment of an operating interconnection with the applicable transmission or distribution system as a result of the actions or inactions of the transmission or distribution provider, or other causes for force majeure as outlined in the procurement contract, in which case, not later than June 1, 2022. 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) Notwithstanding the current Commission-approved long-term renewable resources procurement plan revision described in Section 16-111.5 of the Public Utilities Act, the Agency shall conduct at least one subsequent forward procurement for renewable energy credits from new utility scale wind projects, new utility scale solar projects, and new brownfield site photovoltaic projects within 240 days after the effective date of this amendatory Act of the 102nd General Assembly in quantities needed to meet the requirements of subparagraph (C) of this subsection (c).

(iv) Notwithstanding the current Commission-approved long-term renewable resources procurement plan revision described in Section 16-111.5 of the Public Utilities Act, the Agency shall open capacity for each category in the Adjustable Block Program within 90 days after the effective date of this amendatory Act of the 102nd General Assembly. Blocks shall be sized as necessary to meet the requirements of subparagraph (C) of this subsection (c), and shall be opened in the following manner:

(I) The Agency shall open the next block of capacity for the category described in item (i) of subparagraph (K) this subsection (c). The price of renewable energy credits for this new block of capacity shall be 6% less than the price of the last open block in this category. Projects on a waitlist shall be awarded contracts first in the order in which they appear on the waitlist.

(II) The Agency shall open the next block of capacity for the category described in item (ii) of subparagraph (K) of this subsection (c). The price of the renewable energy credits for this new block of capacity shall be 12% less than the price of the last open block in this category. Projects on a waitlist shall be awarded contracts first in the order in which they appear on the waitlist.

(III) The Agency shall open the next block of capacity for the category described in item (iii)(I) of subparagraph (K) of this subsection (c). The price of the renewable energy credits for this new block of capacity shall be 20% less than the price of the last open block of this category. For this initial block, the capacity shall be allocated to waitlisted projects in a manner consistent with ordinal waitlists established by the Agency.

(IV) Blocks of capacity for the category described in item (iii)(II) of subparagraph (K) of this subsection (c) shall not be opened until after the Commission's review and approval of the Agency's next revised long-term renewable resources procurement plan.

(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) Upon the effective date of this Act, for any procurements of renewable energy credits from new utility-scale wind and new utility-scale photovoltaic projects, the Agency shall procure indexed renewable energy credits and direct respondents to offer a strike price.

(I) The value of the indexed renewable energy credit payment shall be calculated for each settlement period. That payment, for any settlement period, shall be equal to the difference resulting from subtracting the strike price from the index price for that settlement period. If this difference results in a negative number, the indexed REC counterparty shall owe the seller the absolute value multiplied by the quantity of energy produced in the relevant settlement period. If this difference results in a positive number, the seller shall owe the indexed REC counterparty this amount multiplied by the quantity of energy produced in the relevant settlement period.

(II) Parties shall cash settle every month, summing up all settlements (both positive and negative, if applicable) for the prior month.

(III) To ensure funding in the annual budget established under subparagraph (E) of this subsection (c) for indexed renewable energy credit procurements for each year of the term of such contracts, which must have a minimum tenor of 15 calendar years, the procurement administrator, Agency, Commission staff, and procurement monitor shall quantify the annual cost of the contract by utilizing an industry-standard, third-party forward price curve for energy at the appropriate hub or load zone, including the estimated magnitude and timing of the price effects related to federal carbon controls. Each forward price curve shall contain a specific value of the forecasted market price of electricity for each annual delivery year of the contract. For procurement planning purposes, the impact on the annual budget for the cost of indexed renewable energy credits for each delivery year shall be determined as the difference between the expected annual contract expenditures for that year (the sum of the strike price multiplied by quantity of contracts for all relevant contracts) and the total target quantity of contracts multiplied by the forward price curve for each respective load zone for that year. The contracting utility shall not assume an obligation in excess of the estimated annual cost of the contracts for indexed renewable energy credits. Forward curves shall be revised on an annual basis as updated forward price curves are released and filed with the Commission in the proceeding approving the Agency's most recent long-term renewable resources procurement plan. If the expected contract spend is higher or lower than the total quantity of renewable energy credits multiplied by the forward price curve value for that year, the forward price curve shall be updated by the procurement administrator, in consultation with the Agency, Commission staff, and procurement monitors, using then-currently available price forecast data and additional budget dollars shall be obligated or reobligated as appropriate.

(IV) To ensure that indexed renewable energy credit prices remain reasonably predictable and affordable, the Agency may consider the institution of a price collar on REC prices paid under indexed renewable energy credit procurements establishing floor and ceiling REC prices applicable to indexed REC contract prices. Any price collars applicable to indexed REC procurements shall be proposed by the Agency through its long-term renewable resources procurement plan.

(vi) (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 generally be designed to provide for the predictable, sustainable growth of new solar photovoltaic development in Illinois, while also ensuring that any unnecessary costs and margins are minimized. The Agency shall design the program, the prices, terms and conditions, and consumer protections to ensure projects are able to be financed. To this end, and unless otherwise required by the Illinois Commerce Commission, the Adjustable Block program shall provide a transparent annual 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. If administratively established, the 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 for each delivery year: a single block of nameplate capacity, a price for renewable energy credits within that block, and the terms and conditions for securing a spot on a waitlist once the block is : 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. Except as outlined below, the waitlist of projects in a given year will carry over to apply to the subsequent year when another block is opened. Only projects energized on or after June 1, 2017 shall be eligible for the Adjustable Block program. For each category for each delivery year 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 categories block groups shall be sufficient to meet the goals in this subsection (c). The Agency shall strive to issue a single block sized to provide for stability and market growth. The Agency shall establish program eligibility requirements that ensure that projects that enter the program are sufficiently mature to indicate a demonstrable path to completion. 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 Agency may also consider and propose alternative pricing and participation procedures for projects participating in item (iii) of this subparagraph (K), including competitive procurement processes or other approaches used to ensure that renewable energy credit prices remain low, with any such alternative pricing and participation procedures subject to approval of the Illinois Commerce Commission.

The Adjustable Block program shall include at least the following categories 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 25 10 kilowatts. Any projects sized 10 kilowatts to 25 kilowatts on a waitlist for capacity in item (ii) of this subparagraph (K) as of the effective date of this amendatory Act of the 102nd General Assembly shall not need to reapply to the program or pay additional application fees. The Agency may by rule create sub-categories within this category to ensure adequate levels of residential customer participation.

(ii) At least 30% 25% from distributed renewable energy generation devices with a nameplate capacity of more than 25 10 kilowatts and no more than 5,000 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 40% 25% from photovoltaic community renewable generation projects described in items (I) and (II) of this item (iii) of this subparagraph (K): .

(I) 75% of renewable energy credits from projects selected to maximize cost efficiencies in community solar project development and provide cost-effective subscription costs. For the first three delivery years after the Amendatory date of this Act (including the delivery year in which this Amendatory Act is enacted), projects shall be selected from existing ordinal waitlists as established by the Agency and shall be no greater than 2,000 kilowatts in size. For all delivery years thereafter, projects may be up to 10,000 kilowatts in size and shall be selected in accordance with a new project application process determined through the Agency's long-term renewable resources procurement plan. The Agency may also propose and the Commission may consider, as part of the Agency's long-term renewable resources procurement plan, alternative methods for determining the renewable energy credit prices applicable to projects participating in this subparagraph, including competitive procurements if so warranted.

(II) 5% of renewable energy credits from projects selected intended to increase the variety of community solar locations, models, and options in Illinois, with those projects required to provide more direct and tangible benefits to the communities in which they operate. As part of its long-term renewable resources procurement plan, the Agency shall develop selection criteria for projects participating in this category and shall propose administratively established renewable energy credit prices reflecting any increases in a project's cost structure resultant from identified beneficial project attributes. Selection criteria may include, but need not be limited to, development density of the community in which the project is physically located, whether the project was developed in response to a site-specific RFP issued by a municipality or community group, planned subscriber proximity to the project's physical location, and other direct benefits to the community in which the project is physically located. Projects participating in this subparagraph shall be no greater than 500 kilowatts in size.

(iv) The remaining 25% shall be allocated as specified by the Agency in the long-term renewable resources procurement plan. The IPA shall allocate any discretionary capacity prior to the beginning of each delivery year.

(v) To the extent there is uncontracted capacity from any block in any of categories (i)-(iii) above at the end of a delivery year, the Agency may redistribute that capacity to one or more other categories. The redistributed capacity shall be added to the annual capacity in the subsequent delivery year, and the applicable price for renewable energy credits for that category shall be the price for the new delivery year.

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 and are not concentrated in a few regional geographic areas.

(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 delivery contract value purchase price shall be paid in full, based upon the estimated generation during the first 15 years of operation, 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 verified as energized and compliant by the Program Administrator and energized. The electric utility shall receive and retire all renewable energy credits generated by the project for the first 15 years of operation. Renewable energy credits generated by the project thereafter shall not be transferred under the renewable energy credit delivery contract with the counterparty electric utility.

(iii) For those renewable energy credits that qualify and are procured under item (ii) and (iii)(b) of subparagraph (K) of this paragraph (1), 15 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 delivery contract value, based upon the estimated generation during the first 15 years of operation, 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 verified as and energized and compliant by the Program Administrator. 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. Renewable energy credits generated by the project thereafter shall not be transferred under the renewable energy credit delivery contract with the counterparty electric utility.

(iv) For those renewable energy credits that qualify and are procured under item (iii)(a) of subparagraph (K) of this paragraph (1), the renewable energy credit delivery contract shall be paid over the delivery term based on actual deliveries up to an annual cap based upon the estimated generation during the first 15 years of operation, adjusted for actual subscription levels calculated on an annual basis. The electric utility shall receive and retire all renewable energy credits generated by the project during the first 15 years of operation. Renewable energy credits generated by the project thereafter shall not be transferred under the renewable energy credit delivery contract with the counterparty electric utility.

(v) (iv) Each contract shall include provisions to ensure the delivery of the estimated quantity of renewable energy credits including ongoing collateral requirements and other contract provisions deemed appropriate by the Agency for the full term of the contract.

(vi) (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.

(vii) (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 may 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.

(viii) (vii) Nothing in this Section shall require the utility to advance any payment or pay any amounts that exceed the actual amount of revenues anticipated to be collected by the utility under paragraph (6) of this subsection (c) and subsection (k) of Section 16-108 of the Public Utilities Act, inclusive of eligible funds collected in prior years and alternative compliance payments available for use by the utility, and contracts executed under this Section shall expressly incorporate this limitation.

(ix) Notwithstanding other requirements of this subparagraph (L), no modification shall be required to Adjustable Block Program renewable energy credit delivery contracts if those contracts were executed before new contract forms reflecting changes resultant from this amendatory Act of the 102nd General Assembly are finalized.

(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. Funds needed to cover the administrative expenses for the implementation of the Adjustable Block program shall not be included as part of the limitations described in subparagraph (E) of this subsection (c). Participating electric utilities shall be entitled to recover any costs detailed in this subparagraph (M) applicable to those utilities through the automatic adjustment clause tariff under subsection (k) of Section 16-108 of the Public Utilities Act, regardless of whether the costs are subject to the limitations described in subparagraph (E) of this subsection (c).

The Program Administrator may also charge application fees to participating firms to cover the cost of program administration. Any application fee amounts shall initially be determined through the long-term renewable resources procurement plan, and modifications to any application fee that deviate more than 25% from the Commission's approved value must be approved by the Commission as a long-term plan revision under Section 16-111.5 of the Public Utilities Act. The Agency shall consider stakeholder feedback when making adjustments to application fees and shall notify stakeholders in advance of any planned changes.

In addition to covering the costs of program administration, the Agency, in conjunction with its Program Administrator, may also use the proceeds of such fees charged to participating firms to support public education and ongoing regional and national coordination with nonprofit organizations, public bodies, and others engaged in the implementation of renewable energy incentive programs or similar initiatives. This work may include developing papers and reports, hosting regional and national conferences, and other work deemed necessary by the Agency to position the State of Illinois as a national leader in renewable energy incentive program development and administration.

The Agency and its consultant or consultants shall monitor block activity, share program activity with stakeholders and conduct quarterly 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 block price, capacity block, or other program element that do not deviate from the Commission's approved value by more than 10% 25% shall take effect immediately and are not subject to Commission review and approval. Program modifications to any block price, capacity block, or other program element that deviate more than 10% 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.

The Agency and its program administrator shall, consistent with the requirements of this subsection (c), propose the Adjustable Block Program terms, conditions, and requirements, including the prices to be paid for renewable energy credits, where applicable, and requirements applicable to participating entities and project applications, 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 paragraph (5) of subsection (b) of Section 16-111.5 of the Public Utilities Act. Revisions to program terms, conditions, and requirements may be made by the Agency between long-term renewable resource procurement plan approval proceedings if accompanied by a stakeholder review and comment process.

(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 photovoltaic 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. Subject to reasonable limitations, any 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.

Through the development of its long-term renewable resources procurement plan, the Agency may consider whether community renewable generation projects utilizing technologies other than photovoltaics should be supported through State-administered incentive funding, and may issue requests for information to gauge market demand.

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 project shall be deemed to be fully subscribed and the contracting utility shall purchase all of the renewable energy credits from a photovoltaic community renewable generation project as long as a minimum of 90% of the project is subscribed. 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 $50,000,000 per delivery year 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, 2024 2025, June 1, 2027, and June 1, 2030, an additional $30,000,000 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 provided to the Department of Commerce and Economic Opportunity to implement the workforce development programs and reporting as outlined in 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. Funds allocated under this subparagraph (O) shall not be included as part of the limitations described in subparagraph (E) of this subsection (c). The utilities shall be entitled to recover the total cost associated with procuring renewable energy credits detailed in this subparagraph (O) regardless of whether the costs are subject to the limitations described in subparagraph (E) of this subsection (c) through the automatic adjustment clause tariff under subsection (k) of Section 16-108 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) All programs and procurements under this subsection (c) shall be designed to encourage participating projects to use a diverse and equitable workforce and a diverse set of contractors, including minority-owned businesses, disadvantaged businesses, trade unions, graduates of any workforce training programs administered under this statute, and small businesses. As part of its Long-Term Renewable Resources Procurement Plan, the Agency shall create baseline labor standards for firms participating in programs and procurements under this subsection (c), including but not limited to project labor agreements as required by Section 1-135. Additionally, where applicable, the Agency shall incorporate an equity points scoring system into its project participation and selection processes conducted under this subsection (c), as required by Section 1-145. Participants determined to fail to meet those baseline standards may be at risk of termination of renewable energy credit delivery contracts or restrictions on participation in any future programs and competitive procurements conducted under this subsection or under subsection (b) of Section 1-56 of this Act.

(2) (Blank).

(3) (Blank).

(4) The counterparty 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. The administrative costs associated with implementing procurement programs, including, but not limited to, the costs of administering and evaluating the Adjustable Block program shall not be included as part of the limitations described in subparagraph (E) of this subsection (c).

(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.

(8) For the purposes of this Section, "install" means to complete the electrical wiring and connections necessary to interconnect the distributed generation facility with the electric utility's distribution system at the point of interconnection between the facility and the utility. "Install" does not include:

(i) electrical wiring and connections to interconnect the distributed generation facility performed by utility workers on the electric utility's distribution system;

(ii) electrical wiring and connections internal to the distributed generation facility performed by the manufacturer; or

(iii) tasks not associated with the electrical interconnection of the distributed generation facility and the utility, including those relating to planning and project management performed by individuals such as an inspector, management planner, consultant, project designer, contractor or supervisor for the project.

(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 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, 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; 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 and, after January 1, 2015, renewable energy credits from photovoltaic distributed generation projects in procurement events held under subsection (c) of this Section.

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 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.

(Source: P.A. 100-863, eff. 8-14-18; 101-81, eff. 7-12-19; 101-113, eff. 1-1-20.)

(20 ILCS 3855/1-92)

Sec. 1-92. Aggregation of electrical load by municipalities, townships, and counties.

(a) The corporate authorities of a municipality, township board, or county board of a county may adopt an ordinance under which it may aggregate in accordance with this Section residential and small commercial retail electrical loads located, respectively, within the municipality, the township, or the unincorporated areas of the county and, for that purpose, may solicit bids and enter into service agreements to facilitate for those loads the sale and purchase of electricity and related services and equipment.

The corporate authorities, township board, or county board may also exercise such authority jointly with any other municipality, township, or county. Two or more municipalities, townships, or counties, or a combination of both, may initiate a process jointly to authorize aggregation by a majority vote of each particular municipality, township, or county as required by this Section.

If the corporate authorities, township board, or the county board seek to operate the aggregation program as an opt-out program for residential and small commercial retail customers, then prior to the adoption of an ordinance with respect to aggregation of residential and small commercial retail electric loads, the corporate authorities of a municipality, the township board, or the county board of a county shall submit a referendum to its residents to determine whether or not the aggregation program shall operate as an opt-out program for residential and small commercial retail customers. Any county board that seeks to submit such a referendum to its residents shall do so only in unincorporated areas of the county where no electric aggregation ordinance has been adopted.

In addition to the notice and conduct requirements of the general election law, notice of the referendum shall state briefly the purpose of the referendum. The question of whether the corporate authorities, the township board, or the county board shall adopt an opt-out aggregation program for residential and small commercial retail customers shall be submitted to the electors of the municipality, township board, or county board at a regular election and approved by a majority of the electors voting on the question. The corporate authorities, township board, or county board must certify to the proper election authority, which must submit the question at an election in accordance with the Election Code.

The election authority must submit the question in substantially the following form:

Shall the (municipality, township, or county in which the question is being voted upon) have the authority to arrange for the supply of electricity for its residential and small commercial retail customers who have not opted out of such program? The election authority must record the votes as "Yes" or "No".

If a majority of the electors voting on the question vote in the affirmative, then the corporate authorities, township board, or county board may implement an opt-out aggregation program for residential and small commercial retail customers.

A referendum must pass in each particular municipality, township, or county that is engaged in the aggregation program. If the referendum fails, then the corporate authorities, township board, or county board shall operate the aggregation program as an opt-in program for residential and small commercial retail customers.

An ordinance under this Section shall specify whether the aggregation will occur only with the prior consent of each person owning, occupying, controlling, or using an electric load center proposed to be aggregated. Nothing in this Section, however, authorizes the aggregation of electric loads that are served or authorized to be served by an electric cooperative as defined by and pursuant to the Electric Supplier Act or loads served by a municipality that owns and operates its own electric distribution system. No aggregation shall take effect unless approved by a majority of the members of the corporate authority, township board, or county board voting upon the ordinance.

A governmental aggregator under this Section is not a public utility or an alternative retail electric supplier.

For purposes of this Section, "township" means the portion of a township that is an unincorporated portion of a county that is not otherwise a part of a municipality. In addition to such other limitations as are included in this Section, a township board shall only have authority to aggregate residential and small commercial customer loads in accordance with this Section if the county board of the county in which the township is located (i) is not also submitting a referendum to its residents at the same general election that the township board proposes to submit a referendum under this subsection (a), (ii) has not received authorization through passage of a referendum to operate an opt-out aggregation program for residential and small commercial retail customers under this subsection (a), and (iii) has not otherwise enacted an ordinance under this subsection (a) authorizing the operation of an opt-in aggregation program for residential and small commercial retail customers as described in this Section.

(b) Upon the applicable requisite authority under this Section, the corporate authorities, the township board, or the county board, with assistance from the Illinois Power Agency, shall develop a plan of operation and governance for the aggregation program so authorized. Before adopting a plan under this Section, the corporate authorities, township board, or county board shall hold at least 2 public hearings on the plan. Before the first hearing, the corporate authorities, township board, or county board shall publish notice of the hearings once a week for 2 consecutive weeks in a newspaper of general circulation in the jurisdiction. The notice shall summarize the plan and state the date, time, and location of each hearing. Any load aggregation plan established pursuant to this Section shall:

(1) provide for universal access to all applicable residential customers and equitable treatment of applicable residential customers;

(2) describe demand management and energy efficiency services to be provided to each class of customers; and

(3) meet any requirements established by law concerning aggregated service offered pursuant to this Section.

(c) The process for soliciting bids for electricity and other related services and awarding proposed agreements for the purchase of electricity and other related services shall be conducted in the following order:

(1) The corporate authorities, township board, or county board may solicit bids for electricity and other related services. The bid specifications may include a provision requiring the bidder to disclose the fuel type of electricity to be procured or generated on behalf of the aggregation program customers. The corporate authorities, township board, or county board may consider the proposed source of electricity to be procured or generated to be put into the grid on behalf of aggregation program customers in the competitive bidding process. The Agency and Commission may collaborate to issue joint guidance on voluntary uniform standards for bidder disclosures of the source of electricity to be procured or generated to be put into the grid on behalf of aggregation program customers.

(1.5) A township board shall request from the electric utility those residential and small commercial customers within their aggregate area either by zip code or zip codes or other means as determined by the electric utility. The electric utility shall then provide to the township board the residential and small commercial customers, including the names and addresses of residential and small commercial customers, electronically. The township board shall be responsible for authenticating the residential and small commercial customers contained in this listing and providing edits of the data to affirm, add, or delete the residential and small commercial customers located within its jurisdiction. The township board shall provide the edited list to the electric utility in an electronic format or other means selected by the electric utility and certify that the information is accurate.

(2) Notwithstanding Section 16-122 of the Public Utilities Act and Section 2HH of the Consumer Fraud and Deceptive Business Practices Act, an electric utility that provides residential and small commercial retail electric service in the aggregate area must, upon request of the corporate authorities, township board, or the county board in the aggregate area, submit to the requesting party, in an electronic format, those account numbers, names, and addresses of residential and small commercial retail customers in the aggregate area that are reflected in the electric utility's records at the time of the request; provided, however, that any township board has first provided an accurate customer list to the electric utility as provided for herein.

Any corporate authority, township board, or county board receiving customer information from an electric utility shall be subject to the limitations on the disclosure of the information described in Section 16-122 of the Public Utilities Act and Section 2HH of the Consumer Fraud and Deceptive Business Practices Act, and an electric utility shall not be held liable for any claims arising out of the provision of information pursuant to this item (2).

(d) If the corporate authorities, township board, or county board operate under an opt-in program for residential and small commercial retail customers, then the corporate authorities, township board, or county board shall comply with all of the following:

(1) Within 60 days after receiving the bids, the corporate authorities, township board, or county board shall allow residential and small commercial retail customers to commit to the terms and conditions of a bid that has been selected by the corporate authorities, township board, or county board.

(2) If (A) the corporate authorities, township board, or county board award proposed agreements for the purchase of electricity and other related services and (B) an agreement is reached between the corporate authorities, township board, or county board for those services, then customers committed to the terms and conditions according to item (1) of this subsection (d) shall be committed to the agreement.

(e) If the corporate authorities, township board, or county board operate as an opt-out program for residential and small commercial retail customers, then it shall be the duty of the aggregated entity to fully inform residential and small commercial retail customers in advance that they have the right to opt out of the aggregation program. The disclosure shall prominently state all charges to be made and shall include full disclosure of the cost to obtain service pursuant to Section 16-103 of the Public Utilities Act, how to access it, and the fact that it is available to them without penalty, if they are currently receiving service under that Section. The Illinois Power Agency shall furnish, without charge, to any citizen a list of all supply options available to them in a format that allows comparison of prices and products.

(f) Any person or entity retained by a municipality or county, or jointly by more than one such unit of local government, to provide input, guidance, or advice in the selection of an electricity supplier for an aggregation program shall disclose in writing to the involved units of local government the nature of any relationship through which the person or entity may receive, either directly or indirectly, commissions or other remuneration as a result of the selection of any particular electricity supplier. The written disclosure must be made prior to formal approval by the involved units of local government of any professional services agreement with the person or entity, or no later than October 1, 2012 with respect to any such professional services agreement entered into prior to the effective date of this amendatory Act of the 97th General Assembly. The disclosure shall cover all direct and indirect relationships through which commissions or remuneration may result, including the pooling of commissions or remuneration among multiple persons or entities, and shall identify all involved electricity suppliers. The disclosure requirements in this subsection (f) are to be liberally construed to ensure that the nature of financial interests are fully revealed, and these disclosure requirements shall apply regardless of whether the involved person or entity is licensed under Section 16-115C of the Public Utilities Act. Any person or entity that fails to make the disclosure required under this subsection (f) is liable to the involved units of local government in an amount equal to all compensation paid to such person or entity by the units of local government for the input, guidance, or advice in the selection of an electricity supplier, plus reasonable attorneys fees and court costs incurred by the units of local government in connection with obtaining such amount.

(g) The Illinois Power Agency shall provide assistance to municipalities, townships, counties, or associations working with municipalities to help complete the plan and bidding process.

(h) This Section does not prohibit municipalities or counties from entering into an intergovernmental agreement to aggregate residential and small commercial retail electric loads.

(i) No later than December 31, 2022, the Illinois Power Agency shall produce a report assessing how aggregation of electrical load by municipalities, townships, and counties can be used to help meet the renewable energy goals outlined in this Act. This report shall contain, at minimum, an assessment of other states' utilization of load aggregation in meeting renewable energy goals, any known or expected barriers in utilizing load aggregation for meeting renewable energy goals, and recommendations for possible changes in State law necessary for electrical load aggregation to be a driver of new renewable energy project development. This report shall be published on the Agency's website and delivered to the Governor and General Assembly. To assist with developing this report, the Agency may retain the services of its expert consulting firm used to develop its procurement plans as outlined in Section 1-75(a)(1) of this Act.

(Source: P.A. 97-338, eff. 8-12-11; 97-823, eff. 7-18-12; 97-1067, eff. 8-24-12; 98-404, eff. 1-1-14; 98-434, eff. 1-1-14; 98-463, eff. 8-16-13; 98-756, eff. 7-16-14.)

(20 ILCS 3855/1-125)

Sec. 1-125. Agency annual reports.

(a) By February 15 of each year, the Agency shall report annually to the Governor and the General Assembly on the operations and transactions of the Agency. The annual report shall include, but not be limited to, each of the following:

(1) The average quantity, price, and term of all contracts for electricity procured under the procurement plans for electric utilities.

(2) (Blank).

(3) The quantity, price, and rate impact of all energy efficiency and demand response measures purchased for electric utilities, and any measures included in the procurement plan pursuant to Section 16-111.5B of the Public Utilities Act.

(4) The amount of power and energy produced by each Agency facility.

(5) The quantity of electricity supplied by each Agency facility to municipal electric systems, governmental aggregators, or rural electric cooperatives in Illinois.

(6) The revenues as allocated by the Agency to each facility.

(7) The costs as allocated by the Agency to each facility.

(8) The accumulated depreciation for each facility.

(9) The status of any projects under development.

(10) Basic financial and operating information specifically detailed for the reporting year and including, but not limited to, income and expense statements, balance sheets, and changes in financial position, all in accordance with generally accepted accounting principles, debt structure, and a summary of funds on a cash basis.

(11) The average quantity, price, contract type and term, and rate impact of all renewable resources procured purchased under the long-term renewable resources electricity procurement plans for electric utilities.

(12) A comparison of the costs associated with the Agency's procurement of renewable energy resources to (A) the Agency's costs associated with electricity generated by other types of generation facilities and (B) the benefits associated with the Agency's procurement of renewable energy resources.

(13) An analysis of the rate impacts associated with the Illinois Power Agency's procurement of renewable resources, including, but not limited to, any long-term contracts, on the eligible retail customers of electric utilities. The analysis shall include the Agency's estimate of the total dollar impact that the Agency's procurement of renewable resources has had on the annual electricity bills of the customer classes that comprise each eligible retail customer class taking service from an electric utility.

(14) (Blank). An analysis of how the operation of the alternative compliance payment mechanism, any long-term contracts, or other aspects of the applicable renewable portfolio standards impacts the rates of customers of alternative retail electric suppliers.

(b) In addition to reporting on the transactions and operations of the Agency, the Agency shall also endeavor to report on the following items through its annual report, recognizing that full and accurate information may not be available for certain items:

(1) The overall nameplate capacity amount of installed and scheduled renewable energy generation capacity physically located in Illinois.

(2) The percentage of installed and scheduled renewable energy generation capacity as a share of overall electricity generation capacity physically located in Illinois.

(3) The amount of megawatt hours produced by renewable energy generation capacity physically located in Illinois for the preceding delivery year.

(4) The percentage of megawatt hours produced by renewable energy generation capacity physically located in Illinois as a share of overall electricity generation from facilities physically located in Illinois for the preceding delivery year.

The Agency may seek assistance from the Illinois Commerce Commission in developing its annual report and may also retain the services of its expert consulting firm used to develop its procurement plans as outlined in paragraph (1) of subsection (a) of Section 1-75. Confidential or commercially sensitive business information provided by retail customers, alternative retail electric suppliers, or other parties shall be kept confidential by the Agency consistent with Section 1-120, but may be publicly reported in aggregate form.

(Source: P.A. 99-536, eff. 7-8-16.)

(20 ILCS 3855/1-135 new)

Sec. 1-135. Project labor agreements. Projects greater than 10,000 kilowatts in nameplate capacity shall include a project labor agreement as defined by Section 1-75.

(a) The project labor agreement must include the following:

(1) provisions establishing the minimum hourly wage for each class of labor organization employee;

(2) provisions establishing the benefits and other compensation for each class of labor organization employee;

(3) provisions establishing that no strike or disputes will be engaged in by the labor organization employees; and

(4) provisions for minorities and women as defined under the Business Enterprise for Minorities, Women, and Persons with Disabilities Act, setting forth goals for apprenticeship hours to be performed by minorities and women and setting forth goals for total hours to be performed by underrepresented minorities and women.

The owner of the facility and the labor organizations shall have the authority to include other terms and conditions as they deem necessary.

(b) The project labor agreement shall be filed with the Director in accordance with procedures established by the Illinois Power Agency. At a minimum, the project labor agreement must provide the names, addresses, and occupations of the owner of the plant and the individuals representing the labor organization employees participating in the project labor agreement consistent with the Project Labor Agreements Act. The agreement must also specify the terms and conditions required in subsection (a).

(20 ILCS 3855/1-140 new)

Sec. 1-140. Equity points system.

(a) As used in this Section:

"Equity investment eligible community" or "eligible community" mean people living in geographic areas throughout Illinois who will most benefit from equitable investments by the State that are designed to combat historic inequities and the effects of discrimination. "Eligible community" includes census tracts that meet the following characteristics:

(1) At least 15% of the population or at least 20% of the population 18 or under fall below the federal poverty level; and

(2) falls in the top 25th percentile in the State on measured levels for one or more of the following environmental indicators from the United States Environmental Protection Agency's EJSCREEN screening tool:

(A) Diesel particulate matter level in air.

(B) Air toxics cancer risk.

(C) Air toxics respiratory hazard index.

(D) Indicator for major direct dischargers to water.

(E) Proximity to National Priorities List (NPL) sites.

(F) Proximity to Risk Management Plan (RMP) facilities.

(G) Proximity to Treatment and Storage and Disposal (TSDF) facilities.

(H) Ozone level in air.

(I) PM2.5 (particulate matter with diameters that are 2.5 micrometers and smaller) level in the air.

"Equity investment eligible persons" or "eligible persons" means persons who would most benefit from equitable investments by the State designed to combat discrimination, specifically:

(1) persons whose primary residence is in an equity investment eligible community;

(2) persons whose primary residence is in a municipality or a county with a population under 100,000 where the closure of an electric generating unit or coal mine has been publicly announced, or the electric generating unit or coal mine is in the process of closing or has closed within the last 5 years;

(3) persons who are graduates of or currently enrolled in the foster care system; or

(4) persons who were formerly incarcerated.

"Labor peace agreement" means an agreement between an entity and any labor organization recognized under the federal National Labor Relations Act, that may prohibit the labor organization and members from engaging in picketing, work stoppages, boycotts, and any other economic interference with the entity on photovoltaic distributed generation and photovoltaic community renewable generation projects participating in the Adjustable Block Program. Such an agreement also provides that the entity has agreed not to disrupt efforts by the labor organization to communicate with, and attempt to organize and represent, the entity's employees and affords the labor organization access at reasonable times to areas in which the entity's employees work, for the purpose of meeting with employees to discuss their right to representation, employment rights under State law, and terms and conditions of employment.

(b) Utility-scale wind and solar.

(1) The Illinois Power Agency shall revise the long-term renewable resources procurement plan as provided for in subparagraph (a) of paragraph (1) of subsection (c) of Section 1-75 to implement this subsection. The Illinois Power Agency, using alternative bidding procedures as provided for in subsection (i) of Section 20-10 of the Illinois Procurement Code, shall award equity action points for the evaluation of bids in competitive procurements for renewable energy credits delivered from utility-scale wind, utility-scale solar, and brownfield site photovoltaic projects, where applicable, as described in this paragraph (1). Each company or entity may receive up to a maximum of 20 points for each equity action. The maximum number of points that can be awarded is 80 points. This equity points system shall consider equity actions and bid prices. As part of its bid, each company or entity must agree that they will demonstrate to the Agency that they met each of the equity commitments as described in subsection (g).

(2) Equity action points shall be assigned as follows:

(A) Equity eligible communities equity action. Awarded based on a commitment that a percentage of the workforce on the project, including the workforce of contractors and subcontractors (measured by full-time equivalents as defined by the Government Accountability Office of the United States Congress), will live in eligible communities. One point shall be awarded for each 5% of the workforce composed of workers who live in equity eligible communities and one point to an entity that is majority-owned by one or more eligible persons, up to a maximum of 20 points.

(B) Clean energy economy workforce participants equity action. Awarded based on a commitment that a percentage of the workforce on the project, including the workforce of contractors and vendors, will be reserved for workers who participated in the Department of Commerce and Economic Opportunity's Clean Jobs Workforce Hubs Network or Energy Transition Barrier Reduction Program. One point shall be awarded for each 5% of the workforce composed of current or former participants of those programs, up to a maximum of 20 points.

(C) Project labor agreement equity action. Awarded based on a commitment to enter into a pre-hire collective bargaining or project labor agreement consistent with the Project Labor Agreements Act. Up to a maximum of 20 points shall be awarded for a project labor agreement on a utility-scale wind or solar project.

(D) Contracting equity action. Awarded based on a commitment that a percentage of the company's or entity's subcontractors or vendors for the project will be businesses owned by one or more eligible persons or that a percentage of the subcontractors' or vendors' workforce on the project will be composed of workers who live in eligible communities. Five points shall be awarded for each 10% of subcontractors or vendors that are businesses majority-owned by one or more eligible persons or for each 10% of the subcontractors' or vendors' workforce who live in equity eligible communities, up to a maximum of 20 points. Bidders are not eligible for points under this subsection unless they plan to use subcontractors.

(3) Competitive procurements 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 with the following additional provisions for the evaluation of bids. Bids shall be placed into tiers based upon the number of equity action points awarded. Bids shall first be selected from the top tier based upon price, subject to a confidential benchmark. If the bids in the top tier do not fill the procurement target, then the process shall be repeated for the next tier until either the procurement target is met, or all bids under the benchmark are selected. The methodology to determine tier sizes and allocations shall be established in the Long-Term Renewable Resources Procurement Plan.

(4) Upon request, the Agency shall provide unsuccessful bidders with an explanation of how their bid was scored and modifications that could be made in the future to improve the score. This explanation shall not reveal competitor bid information or other confidential bid information.

(c) Adjustable block program.

(1) The Illinois Power Agency shall revise the long-term renewable resources procurement plan as provided for in subparagraph (a) of paragraph (1) of subsection (c) of Section 1-75 to implement this subsection. The Agency, using procedures as provided for in the Long-Term Renewable Resources Procurement Plan, shall award equity action points to score applications for projects seeking contracts for the delivery of renewable energy credits through the adjustable block program. Each applicant may receive up to a maximum of 20 points for each equity action. The maximum number of points that can be awarded is 80 points. This equity points system shall consider equity actions and bid prices. As part of its bid, each company or entity must agree that they will demonstrate to the Agency that they met each of the equity commitments as described in subsection (g).

(2) Equity action points shall be assigned as follows:

(A) Living wage equity action. Awarded based on a commitment that a percentage of the workforce on the project, including the workforce of contractors and vendors, (measured by full-time equivalents as defined by the Government Accountability Office of the United States Congress) will be paid at or above a living wage. One point shall be awarded for each 5% of the workforce composed of workers paid at or above a living wage, up to a maximum of 20 points. For purposes of this Section, a living wage shall be defined as twice the minimum wage in effect pursuant to the Minimum Wage Law or any applicable minimum wage set by the municipality in which the work is performed, whichever is greater.

(B) Equity eligible communities equity action. Awarded based on a commitment that a percentage of the workforce on the project, including the workforce of contractors and vendors, (measured by full-time equivalents) will live in eligible communities. One point shall be awarded for each 5% of the workforce that the company or entity commits will be composed of workers who live in equity eligible Communities. As an alternative, up to 20 points may be awarded to an entity that is majority-owned by eligible persons.

(C) Clean energy economy workforce participants equity action. Awarded based on a commitment that a percentage of the workforce on the project, including the workforce of contractors and vendors, (measured by full-time equivalents) will be workers who participated in the Department of Commerce and Economic Opportunity's Clean Jobs Workforce Hubs Network or Energy Transition Barrier Reduction Program. One point shall be awarded for each 5% of the workforce that the company or entity commits will be composed of current or former participants of those programs, up to a maximum of 20 points.

(D) Labor peace agreement action. Awarded based on one of the following: (i) the bidder attests that the bidder has entered into a labor peace agreement applicable to the renewable energy project, will abide by the terms of the agreement, and will submit a copy of the page of the labor peace agreement to the Agency; or (ii) the bidder submits an attestation to the Agency affirming its commitment to enter into a labor peace agreement if approached by a bona fide labor organization that is actively seeking to represent workers in Illinois on the renewable energy project that is the subject of this procurement.

(3) The adjustable block program shall reserve 40% of each block's capacity to be available for project applications that score no less than 40 points in the equity points system. The Agency shall establish in its Long-Term Renewable Resource Procurement Plan a process for allocating the block capacity if applications scoring 40 or more points do not fill the 40% set-aside until all contracts for that enrollment period are awarded. Beginning with the update to the Long-Term Renewable Resources Procurement Plan that commences in 2023, the Agency shall review the reserved capacity level for future blocks. In developing its annual block capacity, the Agency shall project the amount of development in each block, at the prices of each block, expected to occur in the timeframe.

(d) Accountability in the equity points system.

(1) Purpose. It is the purpose of this subsection to ensure the equity points system is successful in advancing equity across Illinois by providing access to the clean energy economy for businesses and workers from communities that have been historically excluded from economic opportunities in the energy sector, have been subject to disproportionate levels of pollution, and have disproportionately experienced negative public health outcomes.

(2) Modifications to the equity points system. As part of the update of the Long-Term Renewable Resources Procurement Plan to be initiated in 2023, or sooner if the Agency deems necessary, the Agency shall determine to what extent the equity points system described in this Section resulted in the procurement of renewable energy credits from projects in eligible communities. If the Agency finds that the equity points system failed to meet that goal, the Agency may propose in that updated Long-Term Renewable Resources Procurement Plan to revise the following criteria for future Agency procurements, notwithstanding the criteria established in subsections (b) and (c): (i) the number of points allocated for each equity action; (ii) definitions for equity investment eligible persons and equity investment eligible community; and (iii) the number of points required for qualified vendors to be eligible for the 40% capacity reservation of each block's price in the adjustable block program. Such revised criteria may also establish a distinct equity points system for different types of procurements if the Agency finds that doing so will further the purpose of such programs.

(e) Racial discrimination elimination powers and process.

(1) Purpose. It is the purpose of this subsection to empower the Agency to assess and begin to reduce racial discrimination in Illinois' clean energy economy, including through the use of race-conscious remedies, such as race-conscious contracting and hiring goals, consistent with State and federal law.

(2) Racial disparity and discrimination review process.

(A) Within one year of the awarding of contracts using the equity actions processes established in this Section, the Agency shall publish a report evaluating the effectiveness of the equity actions point criteria of this Section in increasing participation of equity investment eligible individuals. Such report shall be forwarded to the Governor, the General Assembly, and the Illinois Commerce Commission.

(B) At any point thereafter, the Agency may commission and publish a disparity and availability study that measures the impact of discrimination on minority businesses and workers. The Agency may hire consultants and experts to conduct the disparity and availability study, with the retention of those consultants and experts exempt from the requirements of Section 20-10 of the Illinois Procurement Code. The study shall: (i) evaluate whether using the equity points system described in this Section result in discrimination in the State's renewable energy industry; and (ii) if so, evaluate the impact of such discrimination on the State and include recommendations for reducing or eliminating any identified barriers to entry in the renewable energy industry. The Illinois Power Agency shall forward a copy of its findings and recommendations to the Governor, the General Assembly, and the Illinois Commerce Commission.

Should the disparity and availability study demonstrate that using the equity points system described in this Section result in discrimination in the State's renewable energy industry, the Agency shall utilize the recommendations to inform its modification of the equity points system as described in paragraph (2) of subsection (d). Any modifications shall be designed to address disparities in the renewable energy industry.

(f) Program data collection.

(1) Purpose. Data collection, data analysis, and reporting are critical to ensure that the benefits of the clean energy economy provided to Illinois residents and businesses are equitably distributed across the State. Thus, the Agency requires proper authority to collect data from program applicants in order to track and improve equitable distribution of benefits across Illinois communities for all procurements the Agency conducts. The Agency shall use this data to, among other things, measure any potential impact of racial discrimination on the distribution of benefits and provide information necessary to correct any discrimination through methods consistent with State and federal law as described in subsection (e).

(2) Agency authority to collect program data. The Agency shall collect demographic and geographic data for each entity awarded contracts under any Agency-administered program.

(3) Required information to be collected. The Agency shall collect the following information from applicants and program participants where applicable:

(A) demographic information, including racial or ethnic identity for real persons employed, contracted, or subcontracted through the program and owners of businesses or entities that apply to receive renewable energy credits from the Agency;

(B) geographic location of the residency of real persons employed, contracted, or subcontracted through the program and geographic location of the headquarters of the business or entity that applies to receive renewable energy credits from the Agency; and

(C) any other information the Agency determines is necessary for the purpose of achieving the purpose of this subsection (f).

(4) Publication of collected information. The Agency shall publish, at least annually, information on the demographics of program participants on an aggregate basis.

(5) Nothing in this subsection (f) shall be interpreted to limit the authority of the Agency, or other agency or department of the State, to require or collect demographic information from applicants of other State programs.

(g) Enforcement of equity commitments in procurement agreements.

(1) Any applicant awarded a REC contract under procurement programs administered by the Agency that use the equity points system shall be required to maintain, for the duration of the contract, any activities and commitments for which they obtained equity points at the time of application. The Agency shall establish processes and procedures for enforcement and monitoring of such commitments, as set forth in this Section, in the Long-Term Renewable Resources Procurement Plan.

(2) Any applicable contracts entered into as a result of procurements by the Agency shall have provisions for the monitoring and enforcement of the applicant's equity commitments by the Agency, to be set forth in the Long-Term Renewal Resources Procurement Plan, including provisions for entering into a corrective action plan, return of payments or reduction or suspension of future payments if the Agency determines that the company or entity has failed to maintain any equity commitments it made at the time of application. Such contracts shall also provide the following:

(A) that the company or entity receiving points for equity points actions will provide the Agency with an annual report demonstrating compliance with each of the equity commitments contained in their bid;

(B) if at any point the Agency concludes that the company or entity has not maintained the commitments they provided at the time of their application, the Agency may require the company or entity to enter into a corrective action plan. A corrective action plan may require changes in hiring and contracting practices, contributions to the Clean Jobs Workforce Hubs Network or Energy Transition Barrier Reduction Program, a halt or reduction of future payments, or other remedies to ensure the company or entity maintains its equity commitments; and

(C) if, at the conclusion of the REC contract period, the Agency determines that the company or entity failed to meet the commitments provided at the time of their application, the Agency may require the return of payment or other remedies.

(h) All applicants shall be required to maintain all pertinent documents, employment records, and other relevant information about the activities and commitments for which they obtained equity points. The Agency may require periodic reports from each vendor that describes the status of each equity action.

(i) If the Agency concludes that a company or entity failed to achieve the equity commitments at the conclusion of the renewable energy contract period, the Agency may preclude that company from being awarded renewable energy credit procurement contracts in subsequent procurement cycles or open enrollment periods.

Section 30-28. The State Finance Act is amended by adding Sections 5.938 and 5.939 as follows:

(30 ILCS 105/5.938 new)

Sec. 5.938. The Energy Transition Assistance Fund.

(30 ILCS 105/5.939 new)

Sec. 5.939. The Greenhouse Gas Emissions Reinvestment Fund.

Section 30-30. The Illinois Procurement Code is amended by changing Section 1-10 as follows:

(30 ILCS 500/1-10)

Sec. 1-10. Application.

(a) This Code applies only to procurements for which bidders, offerors, potential contractors, or contractors were first solicited on or after July 1, 1998. This Code shall not be construed to affect or impair any contract, or any provision of a contract, entered into based on a solicitation prior to the implementation date of this Code as described in Article 99, including, but not limited to, any covenant entered into with respect to any revenue bonds or similar instruments. All procurements for which contracts are solicited between the effective date of Articles 50 and 99 and July 1, 1998 shall be substantially in accordance with this Code and its intent.

(b) This Code shall apply regardless of the source of the funds with which the contracts are paid, including federal assistance moneys. This Code shall not apply to:

(1) Contracts between the State and its political subdivisions or other governments, or between State governmental bodies, except as specifically provided in this Code.

(2) Grants, except for the filing requirements of Section 20-80.

(3) Purchase of care, except as provided in Section 5-30.6 of the Illinois Public Aid Code and this Section.

(4) Hiring of an individual as employee and not as an independent contractor, whether pursuant to an employment code or policy or by contract directly with that individual.

(5) Collective bargaining contracts.

(6) Purchase of real estate, except that notice of this type of contract with a value of more than $25,000 must be published in the Procurement Bulletin within 10 calendar days after the deed is recorded in the county of jurisdiction. The notice shall identify the real estate purchased, the names of all parties to the contract, the value of the contract, and the effective date of the contract.

(7) Contracts necessary to prepare for anticipated litigation, enforcement actions, or investigations, provided that the chief legal counsel to the Governor shall give his or her prior approval when the procuring agency is one subject to the jurisdiction of the Governor, and provided that the chief legal counsel of any other procuring entity subject to this Code shall give his or her prior approval when the procuring entity is not one subject to the jurisdiction of the Governor.

(8) (Blank).

(9) Procurement expenditures by the Illinois Conservation Foundation when only private funds are used.

(10) (Blank).

(11) Public-private agreements entered into according to the procurement requirements of Section 20 of the Public-Private Partnerships for Transportation Act and design-build agreements entered into according to the procurement requirements of Section 25 of the Public-Private Partnerships for Transportation Act.

(12) Contracts for legal, financial, and other professional and artistic services entered into on or before December 31, 2018 by the Illinois Finance Authority in which the State of Illinois is not obligated. Such contracts shall be awarded through a competitive process authorized by the Board of the Illinois Finance Authority and are subject to Sections 5-30, 20-160, 50-13, 50-20, 50-35, and 50-37 of this Code, as well as the final approval by the Board of the Illinois Finance Authority of the terms of the contract.

(13) Contracts for services, commodities, and equipment to support the delivery of timely forensic science services in consultation with and subject to the approval of the Chief Procurement Officer as provided in subsection (d) of Section 5-4-3a of the Unified Code of Corrections, except for the requirements of Sections 20-60, 20-65, 20-70, and 20-160 and Article 50 of this Code; however, the Chief Procurement Officer may, in writing with justification, waive any certification required under Article 50 of this Code. For any contracts for services which are currently provided by members of a collective bargaining agreement, the applicable terms of the collective bargaining agreement concerning subcontracting shall be followed.

On and after January 1, 2019, this paragraph (13), except for this sentence, is inoperative.

(14) Contracts for participation expenditures required by a domestic or international trade show or exhibition of an exhibitor, member, or sponsor.

(15) Contracts with a railroad or utility that requires the State to reimburse the railroad or utilities for the relocation of utilities for construction or other public purpose. Contracts included within this paragraph (15) shall include, but not be limited to, those associated with: relocations, crossings, installations, and maintenance. For the purposes of this paragraph (15), "railroad" means any form of non-highway ground transportation that runs on rails or electromagnetic guideways and "utility" means: (1) public utilities as defined in Section 3-105 of the Public Utilities Act, (2) telecommunications carriers as defined in Section 13-202 of the Public Utilities Act, (3) electric cooperatives as defined in Section 3.4 of the Electric Supplier Act, (4) telephone or telecommunications cooperatives as defined in Section 13-212 of the Public Utilities Act, (5) rural water or waste water systems with 10,000 connections or less, (6) a holder as defined in Section 21-201 of the Public Utilities Act, and (7) municipalities owning or operating utility systems consisting of public utilities as that term is defined in Section 11-117-2 of the Illinois Municipal Code.

(16) Procurement expenditures necessary for the Department of Public Health to provide the delivery of timely newborn screening services in accordance with the Newborn Metabolic Screening Act.

(17) Procurement expenditures necessary for the Department of Agriculture, the Department of Financial and Professional Regulation, the Department of Human Services, and the Department of Public Health to implement the Compassionate Use of Medical Cannabis Program and Opioid Alternative Pilot Program requirements and ensure access to medical cannabis for patients with debilitating medical conditions in accordance with the Compassionate Use of Medical Cannabis Program Act.

(18) This Code does not apply to any procurements necessary for the Department of Agriculture, the Department of Financial and Professional Regulation, the Department of Human Services, the Department of Commerce and Economic Opportunity, and the Department of Public Health to implement the Cannabis Regulation and Tax Act if the applicable agency has made a good faith determination that it is necessary and appropriate for the expenditure to fall within this exemption and if the process is conducted in a manner substantially in accordance with the requirements of Sections 20-160, 25-60, 30-22, 50-5, 50-10, 50-10.5, 50-12, 50-13, 50-15, 50-20, 50-21, 50-35, 50-36, 50-37, 50-38, and 50-50 of this Code; however, for Section 50-35, compliance applies only to contracts or subcontracts over $100,000. Notice of each contract entered into under this paragraph (18) that is related to the procurement of goods and services identified in paragraph (1) through (9) of this subsection shall be published in the Procurement Bulletin within 14 calendar days after contract execution. The Chief Procurement Officer shall prescribe the form and content of the notice. Each agency shall provide the Chief Procurement Officer, on a monthly basis, in the form and content prescribed by the Chief Procurement Officer, a report of contracts that are related to the procurement of goods and services identified in this subsection. At a minimum, this report shall include the name of the contractor, a description of the supply or service provided, the total amount of the contract, the term of the contract, and the exception to this Code utilized. A copy of any or all of these contracts shall be made available to the Chief Procurement Officer immediately upon request. The Chief Procurement Officer shall submit a report to the Governor and General Assembly no later than November 1 of each year that includes, at a minimum, an annual summary of the monthly information reported to the Chief Procurement Officer. This exemption becomes inoperative 5 years after June 25, 2019 (the effective date of Public Act 101-27) this amendatory Act of the 101st General Assembly.

(19) Procurement expenditures necessary for the Illinois Environmental Protection Agency to contract with a firm to perform audits pursuant to Section 8-201.2 of the Public Utilities Act.

(20) The retention of expert consulting firms necessary for the Illinois Power Agency to conduct disparity and availability studies regarding participants in and beneficiaries of renewable energy programs and procurements conducted pursuant to the Illinois Power Agency Act.

Notwithstanding any other provision of law, for contracts entered into on or after October 1, 2017 under an exemption provided in any paragraph of this subsection (b), except paragraph (1), (2), or (5), each State agency shall post to the appropriate procurement bulletin the name of the contractor, a description of the supply or service provided, the total amount of the contract, the term of the contract, and the exception to the Code utilized. The chief procurement officer shall submit a report to the Governor and General Assembly no later than November 1 of each year that shall include, at a minimum, an annual summary of the monthly information reported to the chief procurement officer.

(c) This Code does not apply to the electric power procurement process provided for under Section 1-75 of the Illinois Power Agency Act and Section 16-111.5 of the Public Utilities Act.

(d) Except for Section 20-160 and Article 50 of this Code, and as expressly required by Section 9.1 of the Illinois Lottery Law, the provisions of this Code do not apply to the procurement process provided for under Section 9.1 of the Illinois Lottery Law.

(e) This Code does not apply to the process used by the Capital Development Board to retain a person or entity to assist the Capital Development Board with its duties related to the determination of costs of a clean coal SNG brownfield facility, as defined by Section 1-10 of the Illinois Power Agency Act, as required in subsection (h-3) of Section 9-220 of the Public Utilities Act, including calculating the range of capital costs, the range of operating and maintenance costs, or the sequestration costs or monitoring the construction of clean coal SNG brownfield facility for the full duration of construction.

(f) (Blank).

(g) (Blank).

(h) This Code does not apply to the process to procure or contracts entered into in accordance with Sections 11-5.2 and 11-5.3 of the Illinois Public Aid Code.

(i) Each chief procurement officer may access records necessary to review whether a contract, purchase, or other expenditure is or is not subject to the provisions of this Code, unless such records would be subject to attorney-client privilege.

(j) This Code does not apply to the process used by the Capital Development Board to retain an artist or work or works of art as required in Section 14 of the Capital Development Board Act.

(k) This Code does not apply to the process to procure contracts, or contracts entered into, by the State Board of Elections or the State Electoral Board for hearing officers appointed pursuant to the Election Code.

(l) This Code does not apply to the processes used by the Illinois Student Assistance Commission to procure supplies and services paid for from the private funds of the Illinois Prepaid Tuition Fund. As used in this subsection (l), "private funds" means funds derived from deposits paid into the Illinois Prepaid Tuition Trust Fund and the earnings thereon.

(Source: P.A. 100-43, eff. 8-9-17; 100-580, eff. 3-12-18; 100-757, eff. 8-10-18; 100-1114, eff. 8-28-18; 101-27, eff. 6-25-19; 101-81, eff. 7-12-19; 101-363, eff. 8-9-19; revised 9-17-19.)

Section 30-33. The Counties Code is amended by changing Section 5-12020 and by adding Section 5-12022 as follows:

(55 ILCS 5/5-12020)

Sec. 5-12020. Wind farms, electric-generating wind devices, and commercial wind energy facilities.

(a) Definitions. As used in this Section:

"Commercial wind energy facility" has the meaning provided by Section 10 of the Renewable Energy Facilities Agricultural Impact Mitigation Act.

"Facility owner" means: (i) a person with a direct ownership interest in a commercial wind energy facility, regardless of whether the person was involved in acquiring the necessary rights, permits and approvals or otherwise planning for the construction and operation of a wind energy system; and (ii) at the time a wind energy system is being developed, a person who is acting as a wind energy system developer by acquiring the necessary rights, permits and approvals for or by planning for the construction and operation of a wind energy system, regardless of whether the person will own or operate the wind energy system.

"Nonparticipating property" means real property that is not participating property.

"Nonparticipating residence" means an occupied residence on nonparticipating property that is existing and occupied as of the date of filing of a permit application by the commercial wind energy facility.

"Occupied community building" means an existing structure occupied as of the date of filing of a permit application by the commercial wind energy facility, including,207 but not limited to, a school, place of worship, daycare facility, public library, community center, or commercial building.

"Participating Property" means real property that is the subject of a written agreement between the facility owner and the owner of such real property which provides the facility owner an easement, option, lease license or other agreement for the purpose of constructing a wind tower or supporting facilities on such real property.

"Participating residence" means a residence on participating property occupied as of the date of filing of a permit application.

"Shadow flicker" means shadows that are given off by wind turbines when they are in full rotating motion.

"Supporting facilities" means the associated transmission lines, substations, access roads located on private property, meteorological towers, and other equipment related to the generation of electricity from the commercial wind energy facility.

"Wind tower" means the wind turbine tower, nacelle, and blades.

(b) Notwithstanding any other provision of law or whether the county has formed a zoning commission and adopted formal zoning under Section 5-12007, a county may establish standards for commercial wind energy facilities. wind farms and electric-generating wind devices. The standards may include, without limitation, the height of the devices and the number of devices that may be located within a geographic area. A county may also regulate the siting of commercial wind energy facilities wind farms and electric-generating wind devices in unincorporated areas of the county outside of the zoning jurisdiction of a municipality and the 1.5 mile radius surrounding the zoning jurisdiction of a municipality. A county that establishes standards for items specified in subsections (e) through (j) for ground mounted solar energy systems shall do so in accordance with this Section. This Section applies to home rule and non-home rule counties and is a limitation under subsection (i) of Section 6 of Article VII of the Illinois Constitution on the concurrent exercise by home rule units of powers and functions exercised by the State.

(c) There shall be at least one public hearing during which public comment shall be taken regarding the application for siting approval or a special use permit for a commercial wind energy facility. The first public hearing shall be noticed and shall commence not more than 75 days after the filing of an application for siting approval or a special use permit for a commercial wind energy facility, and the final public hearing shall conclude not more than 90 days following the filing. The county board or its designee shall make its siting decision not more than 45 days after the conclusion of the final public hearing or the conclusion of the special use permit hearing by the zoning board of appeals. not more than 30 days prior to a siting decision by the county board. Notice of the hearing shall be published in a newspaper of general circulation in the county or on a municipality's or county's website. A commercial wind energy facility owner, as defined in the Renewable Energy Facilities Agricultural Impact Mitigation Act, shall must enter into an agricultural impact mitigation agreement with the Department of Agriculture prior to the date of the required public hearing. A commercial wind energy facility owner seeking an extension of a permit granted by a county prior to July 24, 2015 (the effective date of Public Act 99-132) must enter into an agricultural impact mitigation agreement with the Department of Agriculture prior to a decision by the county to grant the permit extension. Counties may allow test wind towers to be sited without formal approval by the county board. Any provision of a county zoning ordinance pertaining to wind farms that is in effect before August 16, 2007 (the effective date of Public Act 95-203) may continue in effect notwithstanding any requirements of this Section.

(d) A county with an existing zoning ordinance in conflict with this Section shall amend such zoning ordinance to be in compliance with this section within 180 days after the effective date of this amendatory Act of the 102nd General Assembly.

(e) This Section does not apply to a commercial wind energy facility that began construction or was approved by a political subdivision before the effective date of this amendatory Act of the 102nd General Assembly.

A county may not require:

(1) a commercial wind energy facility to be sited with setback distances measured from the center of the base of the wind tower as follows:

Occupied Community Buildings: 2.1 times the maximum blade tip height from the nearest point on the outside wall of the structure.

Participating Residences: 1.1 times the maximum blade tip height to the nearest point on the outside wall of the structure.

Nonparticipating Residences: 2.1 times the maximum blade tip height to the nearest point on the outside wall of the structure.

Participating Property Lines: None.

Nonparticipating Property Lines: 1.1 times the maximum blade tip height to the nearest point on the property line.

Public Road Right-of-Way: 1.1 times the maximum blade tip height to the center point of the public road right-of-way.

Overhead Communication and Electric Transmission — Not including utility service lines to individual houses or out- buildings: 1.1 times the maximum blade tip height to the center point of the easement containing the overhead line.

Overhead Utility Service Lines — Lines to individual houses or outbuildings: None.

(2) a wind tower to be sited in a manner such that industry standard computer modeling indicates that any occupied community building or nonparticipating residence will not experience more than 30 hours per year of shadow flicker under planned operating conditions.

(3) The requirements set forth in this subsection (e) may be waived subject to the written consent of the owner of the affected nonparticipating property. a wind tower or other renewable energy system that is used exclusively by an end user to be setback more than 1.1 times the height of the renewable energy system from the end user's property line.

(f) A county may not set a blade tip height limitation that is more restrictive than the height allowed under a Determination of No Hazard to Air Navigation by the Federal Aviation Administration under 14 CFR Part 77.

(g) A county may not set a sound limitation that is more restrictive than the sound limitations established by the Illinois Pollution Control Board under 35 Ill. Adm. Code 900, 901, and 910.

(h) A county may not establish standards for items listed in this Section, either directly or in effect, on the installation or use of a commercial wind energy facility except by adopting an ordinance that complies with this Section and may not establish siting standards which are less restrictive than any terms and conditions included in the standard agricultural impact mitigation agreement available from the Department of Agriculture in accordance with subsection (f) of Section 15 of the Renewable Energy Facilities Agricultural Impact Mitigation Act.

(i) A county may not require a wind tower or other renewable energy system that is used exclusively by an end user to be setback more than 1.1 times the height of the renewable energy system from the user's property line.

(j) Only a county may establish standards for wind farms, electric-generating wind devices, wind towers, supporting facilities, and commercial wind energy facilities, as that term is defined in Section 10 of the Renewable Energy Facilities Agricultural Impact Mitigation Act, in unincorporated areas of the county outside of the zoning jurisdiction of a municipality and outside the 1.5 mile radius surrounding the zoning jurisdiction of a municipality.

(Source: P.A. 100-598, eff. 6-29-18; 101-4, eff. 4-19-19.)

(55 ILCS 5/5-12022 new)

Sec. 5-12022. Ground mounted solar energy systems.

(a) Definitions. As used in this Section:

"Commercial solar energy system" or "CSE system" means a system that captures and converts solar energy into electricity that is generated primarily: (1) for the purpose of selling the electricity at wholesale; and (2) for use in locations other than where it is generated.

"Dwelling" means any building, structure, or part of a building or structure that is occupied as, or is designed or intended for occupancy as, a residence by one (1) or more families or individuals.

"Ground mounted solar energy system" means a solar energy system mounted on a rack or pole that is attached to the ground, and includes either a commercial solar energy system or a community renewable generation project, as that term is defined in Section 1-10 of the Illinois Power Agency Act. "Ground mounted solar energy system" includes transmission lines, substations, ancillary buildings, solar monitoring stations, and accessory equipment or structures that are associated with the ground mounted solar energy system.

"Nonparticipating property" means real property that is not participating property.

"Nonparticipating residence" means an occupied residence on nonparticipating property that is existing and occupied as of the date of filing of a permit application by the permit applicant.

"Participating property" means real property that is the subject of a written agreement between the facility owner and the owner of such real property which provides the facility owner an easement, option, lease license or other agreement for the purpose of constructing a ground mounted solar energy system on such real property.

"Participating residence" means an occupied residence on participating property.

"Permit applicant" means a person who: (1) will own one or more ground mounted solar energy systems; (2) owns one or more round mounted solar energy systems; or (3) an agent or a representative of a person described in item (1) or (2).

"Solar energy system" means a device, or array of devices, whose purpose is to convert solar energy into electricity.

(b) Notwithstanding any other provision of law or whether the county has formed a zoning commission and adopted formal zoning under Section 5-12007, a county may establish standards for ground mounted solar energy systems. The standards may include without limitation all of the requirements specified in subsections (f) through (q), but may not include requirements for ground mounted solar energy systems that are more restrictive than specified in subsections (f) through (q) unless the restrictions apply to all other uses in the same zoning classification. A county may also regulate the siting of ground mounted solar energy systems in unincorporated areas of the county outside of the zoning jurisdiction of a municipality and the 1.5 mile radius surrounding the zoning jurisdiction of a municipality. A county that establishes standards for items specified in subsections (f) through (q) for ground mounted solar energy systems shall do so in accordance with this Section. This Section applies to home rule and non-home rule counties and is a limitation under subsection (i) of Section 6 of Article VII of the Illinois Constitution on the concurrent exercise by home rule units of powers and functions exercised by the State.

(c) There shall be at least one public hearing during which public comment shall be taken regarding the application for siting approval or a special use permit for a ground mounted solar energy system. The first public hearing shall be noticed and commenced not more than 75 days after the filing of an application for siting approval or a special use permit for a ground mounted solar energy system, and the final public hearing shall be concluded not more than 90 days following the filing. The county board or its designee shall make its siting decision not more than 45 days after the conclusion of the public hearing or the conclusion of the special use permit hearing by the zoning board of appeals. Notice of the hearing shall be published in a newspaper of general circulation in the county.

(d) A county with an existing zoning ordinance in conflict with this Section shall amend such zoning ordinance to be in compliance with this Section within 180 days from the effective date of this amendatory Act of the 102nd General Assembly.

(e) This Section does not apply to a ground mounted solar energy system that began construction or was approved by a political subdivision before the effective date of this amendatory Act of the 102nd General Assembly.

(f) A permit applicant may not install a ground mounted solar energy system unless the distance measured from the nearest outer edge of the ground mounted solar energy system is as follows (subject to State and Federal setback requirements):

Roadway - federal interstate highway, federal highway, State highway, or county highway: at least 40 feet from the right-of-way.

Roadway - collector road: at least 30 feet from the right-of-way.

Roadway - local road: at least 10 feet from the right-of-way.

Nonparticipating Residences: at least 150 feet from the nearest point on the outside wall of a dwelling.

Nonparticipating Property Lines: at least 50 feet from nearest point on the property line.

(g) A permit applicant shall install a landscape buffer when the nearest outer edge of the ground mounted solar energy system is within a distance of 250 feet of the nearest point on the outer wall of a dwelling located on a nonparticipating property. The permit applicant shall install a landscape buffer in the area between the nearest outer edge of the ground mounted solar energy system and the outer wall of the dwelling located on the nonparticipating property: (i) in a location; and (ii) constructed from such materials, as set forth in a site plan submitted to the county, if required.

(h) The requirements set forth in subsection (g) may be waived subject to the written consent of the owner of the affected nonparticipating property.

(i) A permit applicant shall not install or locate a ground mounted solar energy system that is more than 25 feet above ground level when the ground mounted solar energy system's arrays are at full tilt. However, a county may not impose a clearance requirement between the ground and the bottom edge of a ground mounted solar energy system's solar panels.

(j) A permit applicant shall control weeds and vegetation on the land where a ground mounted solar energy system is located in accordance with the Agricultural Impact Mitigation Agreement the permit applicant is required to sign by the Renewable Energy Facilities Agricultural Impact Mitigation Act. The use of pollinator seed mixes in the planting of ground cover shall conform to the Pollinator-Friendly Solar Site Act.

(k) A permit applicant shall completely enclose the ground mounted solar energy system with fencing that is at least 6 feet high.

(l) A permit applicant shall install and maintain support structures, aboveground facilities, guy wires and anchors, and underground cabling in accordance with the Agricultural Impact Mitigation Agreement the permit applicant is required to sign by the Renewable Energy Facilities Agricultural Impact Mitigation Act.

(m) A ground mounted solar energy system is to be designed and constructed to: (i) minimize glare on adjacent properties and roadways; and (ii) not interfere with vehicular traffic, including air traffic.

(n) A ground mounted solar energy system shall not interfere with: (i) television signals; (ii) microwave signals; (iii) agricultural global positioning systems; (iv) military defense radar; or (v) radio reception.

(o) A permit applicant is to operate a ground mounted solar energy system in a manner such that the sound attributable to the ground mounted solar energy system will not exceed the sound limitations established by the Illinois Pollution Control Board under 35 Ill. Adm. Code 900, 901, and 910.

(p) A permit applicant will comply with local road load limits and will apply for permits to use overweight vehicles, if necessary.

(q) A county may not establish standards for items listed in subsections (f) through (p), either directly or in effect, on the installation or use of a ground mounted solar energy system except by adopting an ordinance that complies with this Section and may not establish siting standards that effectively preclude development of ground mounted solar energy systems in the county.

(r) Only a county may establish standards for ground mounted solar energy systems and Commercial Solar Energy Facilities, as that term is defined in Section 10 of the Renewable Energy Facilities Agricultural Impact Mitigation Act, in unincorporated areas of the county outside of the zoning jurisdiction of a municipality and outside the 1.5 mile radius surrounding the zoning jurisdiction of a municipality.

Section 30-35. The Illinois Municipal Code is amended by adding Section 8-11-2.7 as follows:

(65 ILCS 5/8-11-2.7 new)

Sec. 8-11-2.7. Non-Home Rule Municipal Gas Use Tax.

(a) This Section may be cited as the Non-Home Rule Municipal Gas Use Tax Law.

(b) As used in this Section:

"Delivering supplier" means a person engaged in the business of delivering gas to another person for use or consumption and not for resale, and who, in any case where more than one person participates in the delivery of gas to a specific purchaser, is the last of the suppliers engaged in delivering the gas prior to its receipt by the purchaser.

"Delivering supplier maintaining a place of business in this State" means any delivering supplier having or maintaining within this State, directly or by a subsidiary, an office, distribution facility, sales office, or other place of business, or any employee, agent, or other representative operating within this State under the authority of the delivering supplier or the delivering supplier's subsidiary, irrespective of whether the place of business or agent or other representative is located in this State permanently or temporarily, or whether the delivering supplier or the delivering supplier's subsidiary is licensed to do business in this State.

"Gas" means any gaseous fuel distributed through a pipeline system.

"Person" means any natural individual, firm, trust, estate, partnership, association, joint stock company, joint adventure, corporation, or limited liability company, any receiver, trustee, guardian, or other representative appointed by order of any court, or any city, town, county, or other political subdivision of this State.

"Purchase of out-of-state gas" means a transaction for the purchase of gas from any supplier in a manner that does not subject the seller of that gas to liability for a tax imposed under paragraph 2 of Section 8-11-2 of the Illinois Municipal Code.

"Purchase price" means the consideration paid for the distribution, supply, furnishing, sale, transportation, or delivery of gas to a person for use or consumption and not for resale, and for all services directly related to the production, transportation, or distribution of gas distributed, supplied, furnished, sold, transmitted, or delivered for use or consumption, including cash, services, and property of every kind and nature. "Purchase price" does not include consideration paid for:

(1) a charge for a dishonored check;

(2) a finance or credit charge, penalty, charge for delayed payment, or discount for prompt payment;

(3) a charge for reconnection of service or for replacement or relocation of facilities;

(4) an advance or contribution in aid of construction;

(5) repair, inspection, or servicing of equipment located on customer premises;

(6) leasing or rental of equipment, the leasing or rental of which is not necessary to furnishing, supplying, or selling gas;

(7) a purchase by a purchaser if the supplier is prohibited by a federal or State constitution, treaty, convention, statute, or court decision from recovering the related tax liability from such purchaser; or

(8) an amount added to a purchaser's bill because of changes made pursuant to the tax imposed by the municipality.

(c) The privilege of using or consuming gas acquired in a purchase at retail and used or consumed within the corporate limits of a non-home rule municipality may be taxed at rates not to exceed the maximum rates, calculated on a monthly basis for each purchaser, as provided in this Section.

(d) Beginning January 1, 2022, a non-home rule municipality may impose upon the privilege of using in the municipality gas obtained in a purchase of out-of-state gas at the rate per therm established by the non-home rule municipality or 5% of the purchase price for the billing period, whichever is the lower rate. This tax rate is the self-assessing purchaser tax rate. Beginning with bills issued by delivering suppliers on and after January 1, 2022 to purchasers within a municipality imposing a tax pursuant to this Section, purchasers may elect an alternate tax rate per therm established by the non-home rule municipality to be paid under the provisions of subsection (e) to a delivering supplier maintaining a place of business in this State. The non-home rule municipality shall establish this alternate tax rate, not less than annually, a rate per therm that would not exceed a tax imposed at the rate of 5% of the gross receipts for the purchase price for the billing period.

(e) Beginning with bills issued on and after January 1, 2022, a delivering supplier maintaining a place of business in this State shall collect from the purchasers within a municipality imposing a tax pursuant to this Section who have elected the alternate tax rate provided in subsection (d) the tax that is imposed by the municipality at the alternate tax rate. The tax imposed at the alternate tax rate shall, when collected, be stated as a distinct and separate item apart from the selling price of the gas. The tax collected by a delivering supplier shall constitute a debt owed by that person to the municipality imposing the tax. Upon receipt by a delivering supplier of a copy of a certificate of registration issued to a self-assessing purchaser under subsection (f), the delivering supplier is relieved of the duty to collect the alternate tax from that self-assessing purchaser beginning with bills issued to that self-assessing purchaser 30 or more days after receipt of the copy of that certificate of registration.

(f) Any purchaser who does not elect the alternate tax rate to be paid to a delivering supplier shall register with the municipality imposing the tax as a self-assessing purchaser and pay the tax imposed directly to the municipality imposing the tax at the self-assessing purchaser rate.

Application for a certificate of registration as a self-assessing purchaser shall be made to the municipality imposing the tax on forms furnished by the municipality and shall contain any reasonable information that the municipality requires. The self-assessing purchaser shall disclose the name of the delivering supplier or suppliers who are delivering the gas upon which the self-assessing purchaser will be paying tax to the municipality imposing the tax.

Upon receipt of an application for a certificate of registration in proper form, the municipality imposing the tax shall issue to the applicant a certificate of registration as a self-assessing purchaser. The applicant shall provide a copy of the certificate of registration as a self-assessing purchaser to the applicant's delivering supplier or suppliers. A purchaser registering as a self-assessing purchaser may not revoke the registration for at least one year after registration.

(g) Except for purchasers who have chosen the alternate tax rate to be paid to a delivering supplier maintaining a place of business in this State, the tax imposed by the municipality pursuant to subsection (d) shall be paid to the municipality imposing the tax directly by each self-assessing purchaser that is subject to the tax imposed by the municipality. Each self-assessing purchaser shall, on or before the 15th day of each month, make a return to the municipality imposing the tax for the preceding calendar month, stating the following:

(1) the self-assessing purchaser's name and principal address;

(2) the total number of therms used by the self-assessing purchaser during the preceding calendar month and upon the basis of which the tax is imposed;

(3) the purchase price of gas used by the self-assessing purchaser during the preceding calendar month and upon the basis of which the tax is imposed;

(4) amount of tax (computed upon items (2) and (3)); and

(5) any other reasonable information the municipality imposing the tax may require.

(h) A delivering supplier maintaining a place of business in this State who engages in the delivery of gas to customers within a municipality imposing the tax in this State shall register with the municipality imposing the tax. A delivering supplier, if required to otherwise register pursuant to a tax imposed under Section 8-11-2 of this Code, need not obtain an additional certificate of registration under this Section, but shall be deemed to be sufficiently registered by virtue of that registration with the municipality imposing the tax.

Application for a certificate of registration shall be made to the municipality imposing the tax on forms furnished by the municipality and shall contain any reasonable information the municipality may require. Upon receipt of a completed application for a certificate of registration, the municipality imposing the tax shall issue to the applicant a certificate of registration. The municipality imposing the tax may deny a certificate of registration to any applicant if the applicant is in default for moneys due under this Section. A person aggrieved by a decision of the municipality imposing the tax under this subsection may, within 20 days after notice of the decision, protest and request a hearing, whereupon the municipality imposing the tax shall give notice to the person of the time and place fixed for the hearing, shall hold a hearing in conformity with the provisions of this Section, and then issue its final administrative decision in the matter to the person. In the absence of a protest within 20 days, the municipality's decision shall become final without any further determination being made or notice given.

(i) A delivering supplier who is required under subsection (e) to collect the tax imposed by the municipality shall make a return to the municipality imposing the tax on or before the 15th day of each month for the preceding calendar month stating the following:

(1) the delivering supplier's name;

(2) the address of the delivering supplier's principal place of business and the address of the principal place of business (if that is a different address) from which the delivering supplier engages in the business of delivering gas to persons for use or consumption and not for resale;

(3) the total number of therms of gas delivered to purchasers within a municipality imposing a tax pursuant to this Section during the preceding calendar month and upon the basis of which the tax is imposed;

(4) the amount of tax computed upon item (3); and

(5) any other reasonable information as the municipality imposing the tax may require.

In making the return, the delivering supplier engaged in the business of delivering gas to persons for use or consumption and not for resale may use any reasonable method to derive reportable therms from the delivering supplier's billing and payment records.

Notwithstanding any other provision in this Section concerning the time within which a delivering supplier may file its return, in the case of a delivering supplier who ceases to engage in a kind of business that makes it responsible for filing returns with a municipality imposing a tax under this Section, the delivering supplier shall file a final return under this Section with the affected municipality not more than one month after discontinuing a kind of business that makes it responsible for filing returns with a municipality.

The delivering supplier making the return provided for in this Section shall, at the time of making the return, pay to the municipality the amount of tax imposed by the municipality.

Section 30-40. The Public Utilities Act is amended by changing Sections 3-105, 5-117, 8-103B, 8-406, 9-201, 9-220.3, 9-221, 9-227, 9-229, 9-241, 16-107.5, 16-107.6, 16-108, 16-108.5, 16-111.5, 16-111.8, 16-115, 16-115C, 19-110, and 19-145 and by adding Sections 4-604, 8-103C, 8-104.1, 8-201.7, 8-201.8, 8-201.9, 8-201.10, 8-201.11, 8-201.12, 8-201.13, 8-201.14, 8-512, 16-108.17, 16-108.18, 16-108.19, 16-108.20, 16-108.21, and 16-108.22 as follows:

(220 ILCS 5/3-105) (from Ch. 111 2/3, par. 3-105)

Sec. 3-105. Public utility.

(a) "Public utility" means and includes, except where otherwise expressly provided in this Section, every corporation, company, limited liability company, association, joint stock company or association, firm, partnership or individual, their lessees, trustees, or receivers appointed by any court whatsoever that now or hereafter owns, controls, operates or manages, within this State, directly or indirectly, for public use, any plant, equipment or property used or to be used for or in connection with, or now owns or controls or currently seeks Commission approval to own or control any franchise, license, permit or right to engage in:

(1) the production, storage, transmission, sale, delivery or furnishing of heat, cold, power, electricity, water, or light, except when used solely for communications purposes;

(2) the disposal of sewerage; or

(3) the conveyance of oil or gas by pipe line.

(b) "Public utility" does not include, however:

(1) public utilities that are owned and operated by any political subdivision, public institution of higher education or municipal corporation of this State, or public utilities that are owned by such political subdivision, public institution of higher education, or municipal corporation and operated by any of its lessees or operating agents;

(2) water companies which are purely mutual concerns, having no rates or charges for services, but paying the operating expenses by assessment upon the members of such a company and no other person;

(3) electric cooperatives as defined in Section 3-119;

(4) the following natural gas cooperatives:

(A) residential natural gas cooperatives that are not-for-profit corporations established for the purpose of administering and operating, on a cooperative basis, the furnishing of natural gas to residences for the benefit of their members who are residential consumers of natural gas. For entities qualifying as residential natural gas cooperatives and recognized by the Illinois Commerce Commission as such, the State shall guarantee legally binding contracts entered into by residential natural gas cooperatives for the express purpose of acquiring natural gas supplies for their members. The Illinois Commerce Commission shall establish rules and regulations providing for such guarantees. The total liability of the State in providing all such guarantees shall not at any time exceed $1,000,000, nor shall the State provide such a guarantee to a residential natural gas cooperative for more than 3 consecutive years; and

(B) natural gas cooperatives that are not-for-profit corporations operated for the purpose of administering, on a cooperative basis, the furnishing of natural gas for the benefit of their members and that, prior to 90 days after the effective date of this amendatory Act of the 94th General Assembly, either had acquired or had entered into an asset purchase agreement to acquire all or substantially all of the operating assets of a public utility or natural gas cooperative with the intention of operating those assets as a natural gas cooperative;

(5) sewage disposal companies which provide sewage disposal services on a mutual basis without establishing rates or charges for services, but paying the operating expenses by assessment upon the members of the company and no others;

(6) (blank);

(7) cogeneration facilities, small power production facilities, and other qualifying facilities, as defined in the Public Utility Regulatory Policies Act and regulations promulgated thereunder, except to the extent State regulatory jurisdiction and action is required or authorized by federal law, regulations, regulatory decisions or the decisions of federal or State courts of competent jurisdiction;

(8) the ownership or operation of a facility that sells compressed natural gas at retail to the public for use only as a motor vehicle fuel and the selling of compressed natural gas at retail to the public for use only as a motor vehicle fuel;

(9) alternative retail electric suppliers as defined in Article XVI; and

(10) the Illinois Power Agency.

(c) An entity that furnishes the service of charging electric vehicles does not and shall not be deemed to sell electricity and is not and shall not be deemed a public utility notwithstanding the basis on which the service is provided or billed. If, however, the entity is otherwise deemed a public utility under this Act, or is otherwise subject to regulation under this Act, then that entity is not exempt from and remains subject to the otherwise applicable provisions of this Act. The installation, maintenance, and repair of an electric vehicle charging station shall comply with the requirements of subsection (a) of Section 16-128 and Section 16-128A of this Act.

For purposes of this subsection, the term "electric vehicles" has the meaning ascribed to that term in Section 10 of the Electric Vehicle Act.

(Source: P.A. 97-1128, eff. 8-28-12.)

(220 ILCS 5/4-604 new)

Sec. 4-604. Restitution for misconduct.

(a) It is the policy of this State that public utility ethical and criminal misconduct shall not be tolerated. The General Assembly finds it necessary to collect restitution, to be distributed as described in subsection (e), from a public utility that has been found guilty of violations of criminal law or that has entered into a Deferred Prosecution Agreement that details violations of criminal law that result in harm to ratepayers.

(b) In light of such violations, the Illinois Commerce Commission shall, within 150 days after the effective date of this amendatory Act of the 102nd General Assembly, initiate an investigation as to whether Commonwealth Edison collected, spent, allocated, transferred, remitted, or caused in any other way to be expended ratepayer funds in connection with the conduct detailed in the Deferred Prosecution Agreement of July 16, 2020 between the United States Attorney for the Northern District of Illinois and Commonwealth Edison. The investigation shall also determine whether any ratepayer funds were used to pay the criminal penalty agreed to in the Deferred Prosecution Agreement. The investigation shall determine whether the public utility collected, spent, allocated, transferred, remitted, or caused in any other way to be expended ratepayer funds that were not lawfully recoverable through rates, and which should accordingly be refunded to ratepayers and calculate such benefits to initiate a refund to ratepayers as a result of such conduct. The investigation shall conclude no later than 330 days following initiation and shall be conducted as a "contested case" as defined in Section 1-30 of the Illinois Administrative Procedure Act.

(c) In the event that regulated entities are found guilty of criminal conduct, the Commission may initiate an investigation, impose penalties, order restitution and such other remedies it deems necessary, and initiate refunds to ratepayers as described in subsection (b). Such investigation and proceeding may commence within 150 days of a finding of guilt. Any funds collected pursuant to this subsection shall be distributed as described in subsection (e). The Commission may order any other remedies it deems necessary.

(d) Pursuant to subsection (e), the investigation shall calculate a schedule for remittance to State funds and to ratepayers, over a period of no more than 4 years, to be paid by the public utility from profits, returns, or shareholder dollars. No costs related to the investigation or contested proceeding authorized by this Section, restitution, or refunds may be recoverable through rates.

(e) Funds collected pursuant to this Section, for the purposes of restitution, shall be repaid by the public utility in the following manner: (1) 25% shall be contributed to expand the Percentage of Income Payment Program; (2) 25% shall be contributed to funding to assist intervenors in Commission dockets; and (3) the remaining percentage of funds collected shall be provided as a per therm or per-kilowatt-hour credit to the public utility's ratepayers.

(f) No public utility may use ratepayer funds to pay a criminal penalty imposed by any local, State or federal law enforcement entity or court.

(220 ILCS 5/5-117)

Sec. 5-117. Supplier diversity goals.

(a) The public policy of this State is to collaboratively work with companies that serve Illinois residents to improve their supplier diversity in a non-antagonistic manner.

(b) The Commission shall require all gas, electric, and water utilities serving companies with at least 100,000 customers under its authority, holders of Certificates in Good Standing under Section 15-401 of this Act, Alternative Retail Electric Suppliers, Alternative Gas Suppliers, and utility-scale generators as well as suppliers of wind energy, solar energy, hydroelectricity, nuclear energy, and any other supplier of energy within this State, to submit annually an annual report by April 15, 2015 and every April 15 thereafter, in a searchable Adobe PDF format and other formats as designated by Commission staff, a report containing all information set forth in subsection (c) of this Section. For purposes of this Section, the terms "minority person", "woman", "person with a disability", "minority-owned business", "women-owned business", and "business owned by a person with a disability" have the meanings given to those terms in Section 2 of the Business Enterprise for Minorities, Women, and Persons with Disabilities Act. For purposes of this Section, "veteran-owned business" means a business that is at least 51% owned by one or more veterans, in the case of a corporation, at least 51% of the stock of which is owned by one or more veterans, or in the case of a limited liability company, at least 51% of the membership interest of which is owned by one or more veterans. , on all procurement goals and actual spending for female-owned, minority-owned, veteran-owned, and small business enterprises in the previous calendar year. These goals shall be expressed as a percentage of the total work performed by the entity submitting the report, and the actual spending for all female-owned, minority-owned, veteran-owned, and small business enterprises shall also be expressed as a percentage of the total work performed by the entity submitting the report.

(c) Each reporting entity shall include in its annual report participating company in its annual report shall include the following information:

(0.5) procurement goals and actual spending for women-owned, minority-owned, veteran-owned, and small businesses in the previous calendar year, which shall be expressed as a percentage of the total work performed by the entity submitting the report, and the actual spending for all women-owned, minority-owned, veteran-owned, and small businesses, and business owned by a person with a disability, which shall:

(A) be expressed as a percentage of the total work performed by the entity submitting the report, and the actual spending for all women-owned, minority-owned, veteran-owned, and small businesses, and businesses owned a person with a disability; and

(B) indicate the types of services provided by category, including but not limited to professional services, financial services, construction, installation, maintenance, other services;

(1) an explanation of the plan for the next year to increase participation;

(2) an explanation of the plan to increase the goals;

(3) the areas of procurement each reporting entity company shall be actively seeking more participation in in the next year;

(4) an outline of the plan to alert and encourage potential vendors in that area to seek business from the reporting entity company;

(5) an explanation of the challenges faced in finding quality vendors and offer any suggestions for what the Commission could do to be helpful to identify those vendors;

(6) a list of the certifications the reporting entity company recognizes;

(7) the point of contact for any potential vendor who wishes to do business with the reporting entity company and explain the process for a vendor to enroll with the company as a minority-owned, women-owned, or veteran-owned company; and

(8) any particular success stories to encourage other entities companies to emulate as best practices;

(9) if the reporting entity is a corporation, the number of minority persons, women and persons with a disability who are directors or officers of the corporation, and the percentage of the total number of directors and officers that minority persons, women and persons with a disability constitute; and

(10) if the reporting entity is a limited liability company, the number of minority persons, women and persons with a disability who are members or managers of the limited liability company, and the percentage of the total number of members and managers that minority persons, women and persons with a disability constitute.

(d) Each annual report shall provide include as much State-specific data in reporting the information required in subsection (c) as possible. If the submitting entity does not submit State-specific data, then the company shall include any national data it does have and explain why it could not submit State-specific data and how it intends to do so in future reports, if possible.

(e) Each annual report shall include the rules, regulations, and definitions used for the procurement goals in the company's annual report.

(e-5) If any entity required to submit an annual report under this Section fails to submit its report as prescribed in subsection (b), the Commission shall assess a penalty of $100 per day for each day that the entity fails to submit its report after the date upon which it is due to be filed. If the entity fails to submit an annual report within 120 days after the date upon which it is due, the Commission may suspend or revoke any license, certificate or other authority issued by the Commission that the entity holds or possesses.

(f) The Commission and all reporting participating entities shall hold an annual workshop open to the public in 2015 and every year thereafter on the state of supplier diversity to collaboratively seek solutions to structural impediments to achieving stated goals, including testimony from each participating entity as well as subject matter experts and advocates. The Commission shall publish a database on its website of the point of contact for each participating entity for supplier diversity, along with a list of certifications each company recognizes from the information submitted in each annual report. The Commission shall publish each annual report on its website and shall maintain each annual report for at least 5 years.

(Source: P.A. 98-1056, eff. 8-26-14; 99-906, eff. 6-1-17; revised 7-22-19.)

(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 have opted out of are exempt from subsections (a) through (j) of this Section under paragraph (1) of 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.

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 have opted out of are exempt from subsections (a) through (j) of this Section under paragraph (1) of 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.

(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 have opted out of are exempt from subsections (a) through (j) of this Section under paragraph (1) of 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.

(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 have opted out of are exempt from subsections (a) through (j) of this Section under paragraph (1) of 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.

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.

Within 270 days after June 1, 2017 (the effective date of Public Act 99-906), 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.

(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 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, 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 specifically dedicated to 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 25% of the total portfolio budget $25,000,000 per year for electric utilities that serve more than 3,000,000 retail customers in the State and no less than 25% of the total portfolio budget $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. The 25% budget shall exclude any portfolio-level and research and development budget costs.

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

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

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

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

(d) 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); 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), 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), 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 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.

(3) No later than March 1, 2025, each electric utility shall file a 5-year energy efficiency plan commencing on January 1, 2026 that is designed to achieve the cumulative persisting annual savings goals specified in paragraphs (9) through (13) of subsection (b-5) of this Section or in paragraphs (9) through (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 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 5-year plan period. Except as provided in subsection (m) of this Section, annual increases in cumulative persisting annual savings goals during the applicable 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 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.

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. 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 105 days after June 1, 2017 (the effective date of Public Act 99-906). For those plans commencing after December 31, 2021, the Commission shall seek public comment on the utility's plan and shall issue an order approving or disapproving each plan within 6 months after its submission. If the Commission disapproves a plan, the Commission shall, within 30 days, describe in detail the reasons for the disapproval and describe a path by which the utility may file a revised draft of the plan to address the Commission's concerns satisfactorily. If the utility does not refile with the Commission within 60 days, the utility shall be subject to penalties at a rate of $100,000 per day until the plan is filed. This process shall continue, and penalties shall accrue, until the utility has successfully filed a portfolio of energy efficiency and demand-response measures. Penalties shall be deposited into the Energy Efficiency Trust Fund.

(g) In submitting proposed plans and funding levels 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.

(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;

(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, 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.

(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).

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

(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), 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) 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 eligible large private energy customers that have chosen to opt out of multi-year plans consistent with this subsection.

(1) For purposes of this subsection, an "eligible large private energy customer" is defined as any retail customers, except for federal, State, municipal and other public customers, of an electric utility that serves more than 3,000,000 retail customers, except for federal, State, municipal and other public 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.

(2) The Commission shall prescribe the form for notice required for opting out of energy efficiency programs. The notice must be submitted to the retail utility 12 months before the next energy efficiency planning cycle and shall include all of the following:

(A) A statement indicating that the customer has elected to opt out;

(B) The account number for the customer account to which the opt out shall apply;

(C) The mailing address associated with the customer account identified under subparagraph (B);

(D) An American Society of Heating, Refrigerating, and Air-Conditioning Engineers (ASHRAE) level 2 or higher audit report conducted by an independent third party expert identifying cost-effective energy efficiency project opportunities that could be invested in over the next 10 years;

(E) A description of the customer's plans to reallocate the funds toward internal energy efficiency efforts identified in the subparagraph (D) report, including but not limited to: (i) strategic energy management or other programs, including descriptions of targeted buildings, equipment and operations; (ii) eligible energy efficiency measures; and (iii) expected energy savings, itemized by technology; and

(F) The effective date of the opt out, which will be the next January 1 following notice of the opt out.

(3) Upon receipt of a properly and timely noticed request for opt out submitted by an eligible large private energy customer, the retail utility shall grant the request, file the request with the Commission and, beginning January 1 of the following year, the opted out customer shall no longer be assessed the costs of the plan and shall be prohibited from participating in that four-year plan cycle to give the retail utility the certainty to design program plan proposals.

(4) Upon a customer's election to opt out under paragraphs (1) and (2) of this subsection (l) and commencing on the effective date of said opt out, the account properly identified in the customer's notice under paragraph (2) shall not be subject to any cost recovery and shall not be eligible to participate in, or directly benefit from, compliance with energy efficiency cumulative persisting savings requirements under subsections (a) through (j).

(5) A utility's cumulative persisting annual savings targets will exclude any opted out load.

(6) The request to opt out is only valid for the requested plan cycle. An eligible large private energy customer must also request to opt out for future energy plan cycles, otherwise the customer will be included in the future energy plan cycle.

(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, 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 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, of the average amount paid per kilowatthour by residential eligible retail customers during calendar year 2015. 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 have opted out of are exempt from subsections (a) through (j) of this Section under paragraph (1) of 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. 100-840, eff. 8-13-18; 101-81, eff. 7-12-19.)

(220 ILCS 5/8-103C new)

Sec. 8-103C. Demand response.

(a) The General Assembly finds that strengthening utility programs for demand response will lead to greater grid optimization, enhancement of rate design, less energy demand, reduced peak demand, and lower costs for ratepayers.

(b) No later than December 31, 2021, the Commission shall initiate a docket on strategies for expansion of demand response by utilities that serve more than 300,000 customers. Such docket shall explore at a minimum:

(1) Demand response programs for all customer classes.

(2) Utility investment in infrastructure to support demand response.

(3) Rate design options, including but not limited to time of use rates and critical peak pricing.

(4) Potential for peak load reductions.

(5) Greater utilization of devices such as smart thermostats that will provide more efficiency gains.

(6) Customer education on opportunities for demand response, pricing options and efficiency-inducing devices.

(7) Interaction between the docket findings and Integrated Distribution Planning and Performance Based Regulation, as set forth in this Act.

(8) Alignment between demand response programs and the clean energy goals of the State.

(c) The Commission, as a result of the docket findings, shall have the authority to order the utilities to submit a demand response plan for consideration on a schedule to be determined by the Commission.

(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) As used in this Section:

"Black, indigenous, and people of color" and "BIPOC" means people who are members of the groups described in subparagraphs (a) through (e) of paragraph (A) of subsection (1) of Section 2 of the Business Enterprise for Minorities, Women, and Persons with Disabilities Act.

"Cost-effective" means that the measures satisfy the total resource cost test that, 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, 2022, that are still operational and providing savings in that year because the measures have not yet reached the end of their useful lives.

"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.

(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, 2022.

(d) Beginning in 2023, 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 throughput in 2016 through 2020 through the implementation of energy efficiency measures during the applicable year and in prior years, but no earlier than January 1, 2023:

(1) 1.2% cumulative persisting annual savings for the year ending December 31, 2023;

(2) 2.1% cumulative persisting annual savings for the year ending December 31, 2024;

(3) 3.0% cumulative persisting annual savings for the year ending December 31, 2025;

(4) 3.9% cumulative persisting annual savings for the year ending December 31, 2026;

(5) 4.8% cumulative persisting annual savings for the year ending December 31, 2027;

(6) 5.7% cumulative persisting annual savings for the year ending December 31, 2028;

(7) 6.6% cumulative persisting annual savings for the year ending December 31, 2029;

(8) 7.4% cumulative persisting annual savings for the year ending December 31, 2030;

(9) 8.2% cumulative persisting annual savings for the year ending December 31, 2031;

(10) 9.0% cumulative persisting annual savings for the year ending December 31, 2032;

(11) 9.8% cumulative persisting annual savings for the year ending December 31, 2033;

(12) 10.6% cumulative persisting annual savings for the year ending December 31, 2034;

(13) 11.4% cumulative persisting annual savings for the year ending December 31, 2035;

(14) 12.1% cumulative persisting annual savings for the year ending December 31, 2036; and

(15) 12.8% cumulative persisting annual savings for the year ending December 31, 2037.

No later than December 31, 2025, the Illinois Commerce Commission shall establish additional cumulative persisting annual savings goals for the years 2037 through 2041. 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.

(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 multifamily households, which, as used in this Section, means households at or below 80% of area median income, and expenditures to implement the measures shall be no less than 25% of the utility's total efficiency portfolio budget. At least 70% of spending on programs targeted at low-income households shall go toward integrated whole building efficiency programs, as defined in subsection (g), or individual measures that reduce space heating needs through improvements to the building envelope, heating distribution systems, or heating system controls. In implementing these programs, utilities shall ensure that thermal insulating materials used in the building envelope do not contain any substance that is a Category 1 respiratory sensitizer as defined by Appendix A to 29 CFR 1910.1200 (Health Hazard Criteria: A.4 Respiratory or Skin Sensitization) that was intentionally added or is present at greater than 0.1% (1000 ppm) by weight in the product. Programs targeted at low-income households, which address single-family and multifamily buildings shall be treated such that forecast savings to be achieved 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). Each gas utility shall also track the types and quantities or volumes of insulation and air sealing materials, and their associated energy saving benefits, installed in energy efficiency programs targeted at low-income single-family and multifamily households. Each gas utility shall implement a health and safety fund of a minimum of 0.5% 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 multifamily 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 by 89 Ill. Adm. Code Part 406, 407, or 408, respectively. The gas utilities shall participate in a low-income energy efficiency accountability committee ("the committee"), which will directly inform the design, implementation, and evaluation of the low-income and public-housing energy efficiency programs. The committee shall be composed 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, public-housing organizations, and representatives of community-based organizations, especially those living in or working with environmental justice communities and BIPOC communities. The committee shall be composed of a statewide leadership committee and 2 geographically differentiated subcommittees: one for stakeholders in northern Illinois and one for stakeholders in central and southern Illinois. The subcommittees shall meet together at least twice per year. There shall be a statewide leadership committee led by and composed of community-based organizations that are representative of BIPOC and environmental justice communities and that includes equitable representation from BIPOC communities. The leadership committee shall be composed of an equal number of representatives from the 2 subcommittees. The subcommittees shall address specific programs and issues, with the leadership committee convening targeted workgroups as needed. The leadership committee may elect to work with an independent facilitator to solicit and organize feedback, recommendations and meeting participation from a wide variety of community-based stakeholders. If a facilitator is used, they shall be fair and responsive to the needs of all stakeholders involved in the committee. All committee meetings must be accessible, with rotating locations if meetings are held in-person, virtual participation options, and materials and agendas circulated well in advance. There shall also be opportunities for direct input by committee members outside of committee meetings, such as via individual meetings, surveys, emails and calls, to ensure robust participation by stakeholders with limited capacity and ability to attend committee meetings. Committee meetings shall emphasize opportunities to bundle and coordinate delivery of low-income energy efficiency with other programs that serve low-income communities, such as Solar for All and bill payment assistance programs. Meetings shall include educational opportunities for stakeholders to learn more about these additional offerings, and the committee shall assist in figuring out the best methods for coordinated delivery and implementation of offerings when serving low-income communities. The committee shall directly and equitably influence and inform utility low-income and public-housing energy efficiency programs and priorities. Participating utilities shall implement recommendations from the committee whenever possible. Participating utilities shall track and report how input from the committee has led to new approaches and changes in their energy efficiency portfolios. This reporting shall occur at committee meetings and in quarterly energy efficiency reports to the Stakeholder Advisory Group and Illinois Commerce Commission, and other relevant reporting mechanisms. Participating utilities shall also report on relevant equity data and metrics requested by the committee, such as energy burden data, geographic, racial, and other relevant demographic data on where programs are being delivered and what populations programs are serving. The Illinois Commerce Commission shall oversee and have relevant staff participate in the committee. The committee shall have a budget of 0.25% of each utility's entire efficiency portfolio funding for a given year. The budget shall be overseen by the Commission. The budget shall be used to provide grants for community-based organizations serving on the leadership committee, stipends for community-based organizations participating in the committee, grants for community-based organizations to do energy efficiency outreach and education, and relevant meeting needs as determined by the leadership committee. The education and outreach shall include, but is not limited to, basic energy efficiency education, information about low-income energy efficiency programs, and information on the committee's purpose, structure, and activities.

(g) At least 50% of the entire efficiency program portfolio budget shall be spent on any combination of:

(1) heating energy savings from integrated, residential or nonresidential, new or existing whole building efficiency programs; and

(2) individual heating measures in residential or nonresidential buildings, new or existing, 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), improvements to systems for distributing heat (including, but not limited to, duct leakage reduction, duct insulation or pipe insulation) in buildings, improvements to ventilation systems (including, but not limited to heat recovery ventilation and demand control ventilation measures) or improvements to controls of heating equipment (including, but not limited to, advanced thermostats). Spending on efficient furnaces, efficient boilers, or other efficient heating equipment measures outside of or separate from integrated whole building efficiency programs is permitted within the efficiency program portfolio, but does not count toward the minimum spending requirement in this subsection (g). Spending on integrated whole building efficiency programs targeted to low-income customers, as well as spending on individual building envelope, heating distribution system, ventilation system and heating system control measures installed in low-income homes 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 and delivery of integrated whole building efficiency programs or installation of individual building envelope, heating distribution system, ventilation system or heating system control 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.

As used in this subsection (g), "integrated whole building efficiency programs" means programs designed to optimize the heating efficiency of buildings by comprehensively and simultaneously addressing cost-effective energy-savings opportunities associated with heating equipment, heating distribution systems, heating system controls, ventilation systems and building envelopes; such programs may be targeted to existing buildings or to construction of new buildings.

(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 distribution system customers, provided that nothing in this subsection (h) permits the double recovery of such costs from customers.

(i) Beginning in 2022, 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 March 1, 2022, each gas utility shall file a 3-year energy efficiency plan commencing on January 1, 2023 that is designed to achieve the cumulative persisting annual savings goals specified in paragraphs (1) through (3) of subsection (d) of this Section through implementation of energy efficiency measures; however, the goals may be reduced if 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. Annual increases in cumulative persisting annual savings goals during the applicable 3-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 3-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, 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 (4) through (7) 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 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. 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.

(3) 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 (8) through (11) 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 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. 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.

(4) No later than March 1, beginning in 2033 and each year thereafter, each gas utility shall file a 4-year energy efficiency plan commencing on January 1, beginning in 2034 and each 4-year period thereafter, that is designed to achieve the cumulative persisting annual savings goals specified in paragraphs (12) through (15) of subsection (d), as well as goals for subsequent years that are 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 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. 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 (d). 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) Demonstrate consideration of program options for:

(A) advancing new building codes, appliance standards, and municipal regulations governing existing and new building efficiency improvements; and

(B) supporting efforts to improve compliance with new building codes, appliance standards and municipal regulations, as potentially cost-effective means of acquiring energy savings to count toward savings goals.

(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, 2024, 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 the multi-year plans commencing on January 1, 2023, the utility shall conduct a solicitation process during 2023 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 last 2 years of the 2023 to 2025 plan period. For the solicitation process, the utility shall identify the sector, technology, or a geographic 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 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) For multi-year plans commencing on January 1, 2026, January 1, 2030, and every 4 years thereafter, the utility shall conduct a solicitation process during 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 geographic 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 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.

(D) 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.

(E) 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) (Reserved.)

(8) (Reserved.)

(9) A utility providing approved energy efficiency and demand-response measures in the State shall be permitted to recover costs of those measures through an automatic adjustment clause tariff filed with and approved by the Commission. The tariff shall be established outside the context of a general rate case. Each year the Commission shall initiate a review to reconcile any amounts collected with the actual costs and to determine the required adjustment to the annual tariff factor to match annual expenditures.

(9.5) The utility must demonstrate how it will ensure that program implementation contractors and energy efficiency installation vendors will promote workforce equity and quality jobs.

(9.6) Utilities shall collect data necessary to ensure compliance with paragraph (9.5) no less than quarterly and shall communicate progress toward compliance with paragraph (9.5) to program implementation contractors and energy efficiency installation vendors no less than quarterly. When it seems unlikely that the criteria in paragraph (9.5) will be met, utilities shall work with relevant vendors, providing education, training, and other resources needed to ensure compliance and, where necessary, adjusting or terminating work with vendors that cannot assist with compliance.

(10) A utility required to implement efficiency programs under this Section 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, including data on the implementation of paragraphs (9.5) and (9.6). If the utility is not meeting the requirements of paragraphs (9.5) and (9.6), the utility shall submit a plan to adjust their activities so that they meet the requirements of paragraphs (9.5) and (9.6) within the following year.

(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 5/8-201.7 new)

Sec. 8-201.7. Prohibition on Deposits for Low-Income Residential Customers or Applicants.

(a) On and after the effective date of this amendatory Act of the 102nd General Assembly, no public utility shall as a condition for standard service require a low-income residential customer or applicant to provide a deposit as security against potential non-payment for service except when the utility has proof that the customer engaged in tampering of the public utility equipment during the previous 5 years. Within 60 days after the effective date of this amendatory Act of the 102nd General Assembly, a utility shall refund all deposits collected from low-income customers as security against potential nonpayment for standard service to such residential customers except when the utility has proof that the customer benefited from tampering. Proof that the customer for whom the deposit is being required engaged in tampering shall be the burden of the utility and the utility shall provide the customer the opportunity to contest the finding that the customer engaged in tampering.

(b) As used in this Section:

"Low-income residential customer or applicant" means: (i) a member of a household at or below 80% of the latest median household income as reported by the United States Census Bureau for the most applicable community or county; (ii) a member of a household at or below 150% of the federal poverty level; (iii) a person who is eligible for the Illinois Low Income Home Energy Assistance Program (LIHEAP) as defined in the Energy Assistance Act; (iv) a person who is eligible to participate in the Percentage of Income Payment Plan (PIPP or PIP Plan) as defined in the Energy Assistance Act; or (v) a person who is eligible to receive Lifeline service as defined in the Universal Service Telephone Service Protection Law of 1985.

"Tampering" means any unauthorized alteration of utility equipment or facilities by which a benefit is achieved for which the utility is not compensated, including customer self-restoration of utility service.

(220 ILCS 5/8-201.8 new)

Sec. 8-201.8. Prohibition on Late Payment Fees for Low-Income Residential Customers or Applicants.

(a) Notwithstanding any other provision of this Act, as of the effective date of this amendatory Act of the 102nd General Assembly, a utility shall not charge a low-income residential customer or applicant a fee, charge or penalty for late payment of any utility bill or invoice.

(b) As used in this Section, "low-income residential customer or applicant" means: (i) a member of a household at or below 80% of the latest median household income as reported by the United States Census Bureau for the most applicable community or county; (ii) a member of a household at or below 150% of the federal poverty level; (iii) a person who is eligible for the Illinois Low Income Home Energy Assistance Program (LIHEAP) as defined in the Energy Assistance Act; (iv) a person who is eligible to participate in the Percentage of Income Payment Plan (PIPP or PIP Plan) as defined in the Energy Assistance Act; or (v) a person who is eligible to receive Lifeline service as defined in the Universal Service Telephone Service Protection Law of 1985.

(220 ILCS 5/8-201.9 new)

Sec. 8-201.9. Prohibition on Credit Card Convenience Fees.

(a) No public utility shall assess any convenience fee, surcharge, or other fee to any customer who elects to pay for service using a credit card that the public utility would not assess to the customer if the customer paid by other available methods acceptable to the utility. The Commission may consider as an operating expense, for the purpose of determining whether a rate or other charge or classification is sufficient, costs incurred by a utility to process payments described in this Section so long as those costs are determined to be prudent, just, and reasonable.

(b) As used in this Section, "credit card" means an instrument or device, whether known as a credit card, bank card, charge card, debit card, automated teller machine card, secured credit card, smart card, electronic purse, prepaid card, affinity card, or by any other name, issued with or without fee by an issuer for the use of the holder to obtain credit, money, goods, services, or anything else of value.

(220 ILCS 5/8-201.10 new)

Sec. 8-201.10. Disconnection and Credit and Collections Reporting.

(a) The Commission shall require all gas, electric, water and sewer public utilities under its authority to submit an annual report by May 1, 2022 and every May 1 thereafter, reporting and making publicly available in executable, electronic spreadsheet format, by zip code, on the number of disconnections for nonpayment and reconnections that occurred in the immediately preceding calendar year.

(b) Each such public utility in its annual report shall report to the Commission and make publicly available in executable, electronic spreadsheet format the following information, by zip code, for the immediately preceding calendar year:

(1) the number of customers, by customer class and type of utility service provided, during each month;

(2) the number of customers, by customer class and type of utility service, receiving disconnection notices during each month;

(3) the number of customers, by customer class and type of utility service, disconnected for nonpayment during each month;

(4) the number of customers, by customer class and type of utility service, reconnected because they have paid in full or set up payment arrangements during each month;

(5) the number of new deferred payment agreements, by customer class and type of utility service, each month;

(6) the number of customers, by customer class and type of utility service, taking service at the beginning of the month under existing deferred payment arrangements;

(7) the number of customers, by customer class and type of utility service, completing deferred payment arrangements during the month;

(8) the number of payment agreements, by customer class and type of utility service, that failed during each month;

(9) the number of customers, by customer class and type of utility service, renegotiating deferred payment arrangements during the month;

(10) the number of customers, by customer class and type of utility service, assessed late payment fees or charges during the month;

(11) the number of customers, by customer class and type of utility service, taking service at the beginning of the month under existing medical payment arrangements;

(12) the number of customers, by utility service, completing medical payment arrangements during the month;

(13) the number of customers, by utility service, enrolling in new medical payment arrangements during the month;

(14) the number of customers, by utility service, renegotiating medical payment arrangements plans during the month;

(15) the number of customers, by customer class and utility service, with required deposits with the company at the beginning of the month;

(16) the number of customers, by customer class and utility service, required to submit new deposits or increased deposits during the month;

(17) the number of customers, by customer class and utility service, whose required deposits were reduced in part or forgone during the month;

(18) the number of customers, by customer class and utility service, whose deposits were returned in full during the month;

(19) the number of customers, by customer class and utility service, with past due amounts greater than 30 days past due at the beginning of the month and taking service at the beginning of the month under existing deferred payment arrangements;

(20) the dollar volume of past due accounts, by customer class and utility service, for customers with past due amounts greater than 30 days past due at the beginning of the month and taking service at the beginning of the month under existing deferred payment arrangements;

(21) the number of customers, by customer class and utility service, with past due amounts greater than 30 days past due at the beginning of the month and not taking service at the beginning of the month under existing deferred payment arrangements; and

(22) the dollar volume of past due accounts, by customer class and utility service, for customers with past due amounts greater than 30 days past due at the beginning of the month and not taking service at the beginning of the month under existing deferred payment arrangements.

(c) The Commission may specify the executable, electronic spreadsheet format that utilities must adhere to when submitting the information required by this Section. Notwithstanding the requirements of this Section, the Commission may establish an online reporting system and require each public utility to report using the online reporting system instead of filing information in executable, electronic spreadsheet format. The Commission shall make each annual report submitted by each public utility publicly available on its website within 30 days of receipt.

(d) The Commission shall require all gas, electric, water and sewer public utilities under its authority to submit an annual report by May 1, 2022 and every May 1 thereafter, detailing the number of disconnections for nonpayment and reconnections that occurred in the immediately preceding calendar year.

(e) Each such public utility in its annual report shall include the following information for the immediately preceding calendar year:

(1) the number of customers, by customer class, during each month;

(2) the number of customers, by customer class, disconnected for nonpayment during each month;

(3) the number of customers, by customer class, reconnected because they have paid in full or set up payment arrangements during each month; and

(4) the number of customers, by customer class, who have set up payment arrangements each month.

(f) The Commission shall make each annual report submitted by each public utility publicly available on its website within 30 days of receipt.

(220 ILCS 5/8-201.11 new)

Sec. 8-201.11. Accelerated Repayment of Excess Deferred Income Tax.

(a) The General Assembly finds:

(1) That a portion of each utility's compensation from ratepayers is attributable to reimbursement for federal taxes paid by the utility.

(2) Due to the enactment of the 2017 Tax Cut and Jobs Act, the federal income tax rate for corporations was lowered, resulting in Excess Deferred Income Tax for distribution utilities in the State that serve more than 100,000 customers.

(3) In proceedings before the Commission, it was determined that the repayment period to ratepayers by the utilities which serve more than 100,000 customers in this State for this EDIT would be 39.5 years.

(4) The COVID-19 pandemic has harmed many customers of all rate classes in the State, and resulted in the Commission adopting a number of measures to provide relief for customers.

(5) It would be in the interest of the State for the repayment of the Excess Deferred Income Tax referenced in Commission Dockets 19-0436, 19-0387, 20-0381 and 20-0393 to be paid back to ratepayers on a timetable greatly accelerated from that set forth in the above-mentioned dockets.

(b) Notwithstanding the Commission Orders in Dockets 19-0436, 19-0387, 20-0381 and 20-0383, the Excess Deferred Income Tax referenced in those dockets shall be fully refunded to ratepayers by the respective utilities no later than December 31, 2025.

(c) The Commission shall initiate a docket to provide for the refunding of these excess deferred income taxes to ratepayers of the utilities referenced in those dockets, and shall set forth any necessary provisions to accomplish the reimbursement on the schedule delineated in subsection (b), above.

(220 ILCS 5/8-201.12 new)

Sec. 8-201.12. Auditing the finances of nuclear power plants.

(a) The General Assembly finds and declares:

(1) Nuclear plants produce zero-carbon, baseload power and thus offer value to the people of the State of Illinois by furthering the State's goals to reduce greenhouse gas emissions and reach 100% clean energy;

(2) Nuclear plants support communities through job creation, economic investments, and property taxes paid to local counties, which support schools, libraries, and fire departments;

(3) In the near term, the closure of nuclear plants in Illinois is likely to result in a generation gap that will be filled by dirty energy, namely fossil fuels;

(4) As the State conducts an ongoing assessment of how and over what period of time Illinois can meet its clean energy goals, an understanding of the schedule of plant closures is required;

(5) Announced closures of a large percentage of Illinois' electric generation would have a substantial impact on the State budget and electric reliability for Illinois residents;

(6) Any financial support for nuclear plants should be short-term and based on clearly demonstrated need;

(7) That need should be demonstrated in a transparent and formulaic manner and should minimize costs to ratepayers to the extent possible; and

(8) The Office of the Governor, the Illinois Environmental Protection Agency, and the General Assembly must be adequately informed in order to take any necessary action to prevent or minimize serious economic and energy disruption to critical State services.

The General Assembly therefore finds that it is necessary to audit the finances of nuclear power plants operating in Illinois on an annual basis, beginning on January 1, 2022 and occurring every year thereafter so long as such plants receive Zero Emission Credits.

(b) By January 31, 2022 the Illinois Environmental Protection Agency shall select an independent firm to conduct an in-depth analysis of each nuclear power plant's financial information. Within 90 days of selection, the firm shall conduct an analysis of the health of Illinois nuclear power plants and deliver a report to the Governor and the Illinois Environmental Protection Agency. The firm shall also develop and deliver a non-confidential summary, which redacts proprietary information, for the General Assembly. The report shall assess actual costs and revenues and attempt to quantify the range and distribution of possible outcomes (negative and positive) for the nuclear plants. The report shall make findings that include, but are not limited to, the following:

(1) The operating costs and risk of the plants, measured against assumptions of market conditions in capacity and energy markets;

(2) The amount of State support, if any, needed to cover the operational and risk costs of the plants, looking forward over the next five-year and ten-year periods;

(3) Any known operating and risk cost differences between the Illinois nuclear power plants and other nuclear power plants located in the PJM footprint; and

(4) The overall financial health of Illinois nuclear power plants, including any near-term growth or risk potential, as well as any evaluation of the health of individual nuclear power plants if some of the Illinois nuclear fleet is decommissioned.

(c) The firm's analyses and conclusions in subsection (b) shall be based on:

(1) Revenues at each plant, which shall include, at a minimum, the following information: (i) energy revenues, including forward market energy prices and spot-market energy prices, and (ii) capacity revenues, including expected capacity revenues for each plant based on the forecasted capacity price. Total revenue shall be calculated as the sum of energy revenue, capacity revenue, and ancillary revenue.

(2) Expenses at each plant, which shall include, at a minimum, the following information: (i) operations and maintenance (or O&M), including Site Non-Outage Production Costs and Site Non-Outage Non-Production Costs, (ii) overhead costs, including property tax, direct BSC, nuclear corporate overhead-direct charge to site, nuclear corporate overhead-Institute of Nuclear Power Operations (INPO) allocated to site, and non-nuclear overhead, (iii) outage costs, including O&M expenditures for unscheduled outages, and indirect outage costs, (iv) capital expenditures, including non-fuel capital expenditures and fuel capital expenditures, and (v) spent fuel costs in the form of the U.S. Department of Energy's spent nuclear fuel disposal fee.

(3) Income tax, which shall estimate net income by removing the capital expenditures from costs, replacing them with capital depreciation and fuel amortization, and calculating income tax as the product of the tax rate and net income.

(4) Net cash flow, which shall be determined as the difference between revenues and expenses in each year.

(220 ILCS 5/8-201.13 new)

Sec. 8-201.13. Customer data.

(a) The General Assembly finds:

(1) Utility customers in all rate classes are taking a more active interest in their energy usage and how the power they use is generated.

(2) As a result of advanced metering technology being installed throughout Illinois, there is substantially more data available than ever before.

(3) This data, if properly utilized, could lead to substantial innovation in products and services available to customers.

(4) At least one report has suggested that a substantial number of Illinois electricity customers could save money through time of use pricing programs that would require utilization of customer data in their development.

(5) This innovation could lead to greater energy efficiency, reduced emissions, and cost savings for customers.

(6) While aggregated data may be helpful to providers of energy services and programs, customer privacy must be protected. Customers should have the ability to control the dissemination of their individual data.

(b) No later than December 31, 2021, the Illinois Commerce Commission shall open a docket on customer data, to be concluded no later than June 30, 2022. The Commission process should include involvement from stakeholders, consumer advocates and the public, as well as experts in this field. At a minimum, the Commission process shall consider:

(1) the scope of the data currently collected or capable of being collected through advanced metering and other means;

(2) how data is currently collected stored and disseminated, and to whom it is disseminated;

(3) customer rights associated with their data, including access, opt-outs, and ability to share with third parties;

(4) potential improvements that date collection can bring to pricing methods, grid optimization, peak shaving, energy efficiency and other policies consistent with the goals of the State;

(5) potential third-parties with whom data could be shared, and the purposes for sharing such data;

(6) consumer protections, including technology and policy changes needed to ensure that customers control the ability for individual data to be released;

(7) educational programs for consumers about data collection and sharing practices;

(8) utility capabilities for different or expanded methods of data collection, storage and dissemination, and utility technology and personnel needed to facilitate various options;

(9) methods for resolving resolving consumer complaints about data collection practices; and

(10) data security practices and policies necessary to ensure the confidentiality of consumer data and personal information, including practices and policies necessary to notify consumers of data breaches.

(c) At the conclusion of the process, the Commission shall:

(1) report recommendations to the General Assembly and the Governor for suggested legislative changes, if any; and

(2) identify and recommend other possible changes to data collection and dissemination practices and policies which do not require legislative approval.

(d) The Commission shall have the authority to require public utilities to submit plans to the Commission regarding data collection, data security, data storage, and data sharing practices.

(e) Nothing in this Section shall prohibit the Commission from exercising existing authority with respect to matters of data collection, including implementation of pilot or other programs authorized or created under this Act.

(220 ILCS 5/8-201.14 new)

Sec. 8-201.14. Right to self-generate electricity.

(a) As used in this Section:

"Electric cooperative" has the meaning set forth in Section 3.4 of the Electric Supplier Act.

"Municipal utility" means a public utility that is owned and operated by any political subdivision or municipal corporation of this State or owned by such an entity and operated by any lessee or any operating agent thereof.

"Public utility" has the definition set forth in Section 3-105 of this Act.

(b) Customers have the right to, and the Commission shall protect the rights of customers to, produce, consume, and store their own renewable energy without discriminatory repercussions from a public utility, electric cooperative, or municipal utility, regardless of whether that energy is produced via a system that is owned outright, leased, or financed through a behind-the-meter solar power-purchase agreement or other means. This includes customers' rights to:

(1) generate, consume, and export renewable energy and reduce his or her use of electricity obtained from the grid;

(2) use technology to store energy at his or her residence;

(3) connect his or her electrical system that generates renewable energy, stores energy, or any combination thereof, with the electricity meter on the customer's premises that is provided by a public utility, electric cooperative, or municipal utility:

(A) in a timely manner;

(B) in accordance with requirements established by the electric utility to ensure the safety of utility workers; and

(C) after providing written notice to the electric utility providing service in the service territory, installing a nomenclature plate on the electrical meter panel and meeting all applicable State and local safety and electrical code requirements associated with installing a parallel distributed generation system; and

(4) receive fair credit for energy exported to the grid.

(c) A public utility, electric cooperative, or municipal utility customer who produces, consumes, and stores his or her own renewable energy shall not face discriminatory rate design, fees, treatment, or excessive compliance requirements as provided by paragraph (3) of subsection (n) of Section 16-107.5.

(d) A public utility, electric cooperative, or municipal utility customer shall have a right to appeal any decision related to self-generation and storage that violates these rights to self-generation and non-discrimination pursuant to the provisions of this Section through a complaint process.

(e) The Illinois Commerce Commission shall adopt all rules necessary for the administration of this Section.

(220 ILCS 5/8-406) (from Ch. 111 2/3, par. 8-406)

Sec. 8-406. Certificate of public convenience and necessity.

(a) No public utility not owning any city or village franchise nor engaged in performing any public service or in furnishing any product or commodity within this State as of July 1, 1921 and not possessing a certificate of public convenience and necessity from the Illinois Commerce Commission, the State Public Utilities Commission or the Public Utilities Commission, at the time this amendatory Act of 1985 goes into effect, shall transact any business in this State until it shall have obtained a certificate from the Commission that public convenience and necessity require the transaction of such business.

(b) No public utility shall begin the construction of any new plant, equipment, property or facility which is not in substitution of any existing plant, equipment, property or facility or any extension or alteration thereof or in addition thereto, unless and until it shall have obtained from the Commission a certificate that public convenience and necessity require such construction. Whenever after a hearing the Commission determines that any new construction or the transaction of any business by a public utility will promote the public convenience and is necessary thereto, it shall have the power to issue certificates of public convenience and necessity. The Commission shall determine that proposed construction will promote the public convenience and necessity only if the utility demonstrates: (1) that the proposed construction is necessary to provide adequate, reliable, and efficient service to its customers and is the least-cost means of satisfying the service needs of its customers or that the proposed construction will promote the development of an effectively competitive electricity market that operates efficiently, is equitable to all customers, and is the least cost means of satisfying those objectives; (2) that the utility is capable of efficiently managing and supervising the construction process and has taken sufficient action to ensure adequate and efficient construction and supervision thereof; and (3) that the utility is capable of financing the proposed construction without significant adverse financial consequences for the utility or its customers.

(c) After the effective date of this amendatory Act of 1987, no construction shall commence on any new nuclear power plant to be located within this State, and no certificate of public convenience and necessity or other authorization shall be issued therefor by the Commission, until the Director of the Illinois Environmental Protection Agency finds that the United States Government, through its authorized agency, has identified and approved a demonstrable technology or means for the disposal of high level nuclear waste, or until such construction has been specifically approved by a statute enacted by the General Assembly.

As used in this Section, "high level nuclear waste" means those aqueous wastes resulting from the operation of the first cycle of the solvent extraction system or equivalent and the concentrated wastes of the subsequent extraction cycles or equivalent in a facility for reprocessing irradiated reactor fuel and shall include spent fuel assemblies prior to fuel reprocessing.

(d) In making its determination, the Commission shall attach primary weight to the cost or cost savings to the customers of the utility. The Commission may consider any or all factors which will or may affect such cost or cost savings, including the public utility's engineering judgment regarding the materials used for construction.

(e) The Commission may issue a temporary certificate which shall remain in force not to exceed one year in cases of emergency, to assure maintenance of adequate service or to serve particular customers, without notice or hearing, pending the determination of an application for a certificate, and may by regulation exempt from the requirements of this Section temporary acts or operations for which the issuance of a certificate will not be required in the public interest.

A public utility shall not be required to obtain but may apply for and obtain a certificate of public convenience and necessity pursuant to this Section with respect to any matter as to which it has received the authorization or order of the Commission under the Electric Supplier Act, and any such authorization or order granted a public utility by the Commission under that Act shall as between public utilities be deemed to be, and shall have except as provided in that Act the same force and effect as, a certificate of public convenience and necessity issued pursuant to this Section.

No electric cooperative shall be made or shall become a party to or shall be entitled to be heard or to otherwise appear or participate in any proceeding initiated under this Section for authorization of power plant construction and as to matters as to which a remedy is available under The Electric Supplier Act.

(f) Such certificates may be altered or modified by the Commission, upon its own motion or upon application by the person or corporation affected. Unless exercised within a period of 2 years from the grant thereof authority conferred by a certificate of convenience and necessity issued by the Commission shall be null and void.

No certificate of public convenience and necessity shall be construed as granting a monopoly or an exclusive privilege, immunity or franchise.

(g) A public utility that undertakes any of the actions described in items (1) through (3) of this subsection (g) or that has obtained approval pursuant to Section 8-406.1 of this Act shall not be required to comply with the requirements of this Section to the extent such requirements otherwise would apply. For purposes of this Section and Section 8-406.1 of this Act, "high voltage electric service line" means an electric line having a design voltage of 100,000 or more. For purposes of this subsection (g), a public utility may do any of the following:

(1) replace or upgrade any existing high voltage electric service line and related facilities, notwithstanding its length;

(2) relocate any existing high voltage electric service line and related facilities, notwithstanding its length, to accommodate construction or expansion of a roadway or other transportation infrastructure; or

(3) construct a high voltage electric service line and related facilities that is constructed solely to serve a single customer's premises or to provide a generator interconnection to the public utility's transmission system and that will pass under or over the premises owned by the customer or generator to be served or under or over premises for which the customer or generator has secured the necessary right of way.

(h) A public utility seeking to construct a high-voltage electric service line and related facilities (Project) must show that the utility has held a minimum of 2 pre-filing public meetings to receive public comment concerning the Project in each county where the Project is to be located, no earlier than 6 months prior to filing an application for a certificate of public convenience and necessity from the Commission. Notice of the public meeting shall be published in a newspaper of general circulation within the affected county once a week for 3 consecutive weeks, beginning no earlier than one month prior to the first public meeting. If the Project traverses 2 contiguous counties and where in one county the transmission line mileage and number of landowners over whose property the proposed route traverses is one-fifth or less of the transmission line mileage and number of such landowners of the other county, then the utility may combine the 2 pre-filing meetings in the county with the greater transmission line mileage and affected landowners. All other requirements regarding pre-filing meetings shall apply in both counties. Notice of the public meeting, including a description of the Project, must be provided in writing to the clerk of each county where the Project is to be located. A representative of the Commission shall be invited to each pre-filing public meeting.

(i) For applications filed after the effective date of this amendatory Act of the 99th General Assembly, the Commission shall by registered mail notify each owner of record of land, as identified in the records of the relevant county tax assessor, included in the right-of-way over which the utility seeks in its application to construct a high-voltage electric line of the time and place scheduled for the initial hearing on the public utility's application. The utility shall reimburse the Commission for the cost of the postage and supplies incurred for mailing the notice.

(j) A certificate or approval under this Section shall not be modified or denied on the basis of the common law doctrine of first in the field if the plant, equipment, property, or facility is subject to a competitive process under the authority of the Federal Energy Regulatory Commission.

(Source: P.A. 99-399, eff. 8-18-15.)

(220 ILCS 5/8-512 new)

Sec. 8-512. Renewable energy access plan.

(a) It is the policy of this State to promote cost-effective transmission system development that ensures reliability of the electric transmission system, lowers carbon emissions, minimizes long-term costs for consumers, and supports the electric policy goals of this State. The General Assembly finds that:

(1) Transmission planning, primarily for reliability purposes, but also for economic and public policy reasons is conducted by regional transmission organizations in which transmission-owning Illinois utilities and other stakeholders are members.

(2) Order No. 1000 of the Federal Energy Regulatory Commission requires regional transmission organizations to plan for transmission system needs in light of State public policies, and to accept input from states during the transmission system planning processes.

(3) The State of Illinois does not currently have a comprehensive power and environmental policy planning process to identify transmission infrastructure needs that can serve as a vital input into the regional and inter-regional transmission organization planning processes conducted under Order No. 1000 and other laws and regulations.

(4) This State is an electricity generation and power transmission hub, and can leverage that position to invest in infrastructure that enables new and existing Illinois generators to meet the public policy goals of the State of Illinois and of interconnected states while cost-effectively supporting tens of thousands of jobs in the renewable energy sector in this State.

(5) The nation has a need to readily access this State's low-cost, clean electric power, and this State also desires access to clean energy resources in other states to develop and support its low-carbon economy and keep electricity prices low in Illinois and interconnected states.

(6) Existing transmission infrastructure may constrain the State's achievement of 100% renewable energy by 2050, the accelerated adoption of electric vehicles in a just and equitable way, and electrification of additional sectors of the Illinois economy.

(7) Transmission system congestion within this State and the regional transmission organizations serving this State limits the ability of this State's existing and new electric generation facilities that do not emit carbon dioxide, including renewable energy resources and zero emission facilities, to serve the public policy goals of this State and other states, which constrains investment in this State.

(8) Investment in infrastructure to support existing and new electric generation facilities that do not emit carbon dioxide, including renewable energy resources and zero emission facilities, stimulates significant economic development and job growth in this State, as well as creates environmental and public health benefits in this State.

(9) Creating a forward-looking plan for this State's electric transmission infrastructure, as opposed to relying on case-by-case development and repeated marginal upgrades, will achieve a lower-cost system for Illinois' electricity customers. A forward-looking plan can also help integrate and achieve a comprehensive set of objectives and multiple state, regional, and national policy goals.

(10) Alternatives to overhead electric transmission lines can achieve cost-effective resolution of system impacts, and warrant investigation of the circumstances under which those alternatives should be considered and approved. The alternatives are likely to be beneficial as investment in electric transmission infrastructure moves forward.

(b) Consistent with the findings identified in subsection (a), the Commission shall open an investigation to develop and adopt a renewable energy access plan no later than December 31, 2022. To assist and support the Commission in the development of the plan, the Commission shall retain the services of technical and policy experts with relevant fields of expertise, solicit technical and policy analysis from the public, and provide for a 120-day open public comment period after publication of a draft report, which shall be published no later than 90 days after the comment period ends. The plan shall, at a minimum, do the following:

(1) designate renewable energy access plan zones throughout this State in areas in which renewable energy resources and suitable land areas are sufficient for developing generating capacity from renewable energy technologies;

(2) develop a plan to achieve transmission capacity necessary to deliver the electric output from renewable energy technologies in the renewable energy access plan zones to customers in Illinois and other states in a manner that is most beneficial and cost-effective to customers;

(3) use this State's position as an electricity generation and power transmission hub to create new investment in this State's renewable energy resources;

(4) consider programs, policies, and electric transmission projects that can be adopted within this State that promote the cost-effective delivery of power from renewable energy resources interconnected to the bulk electric system to meet the renewable portfolio standard targets under subsection (c) of Section 1-75 of the Illinois Power Agency Act;

(5) consider proposals to improve regional transmission organizations' regional and interregional system planning processes and an analysis of how those proposals would improve reliability and cost-effective delivery of electricity in Illinois and the region;

(6) make findings and policy recommendations based on technical and policy analysis regarding locations of renewable energy access plan zones and the transmission system developments needed to cost-effectively achieve the public policy goals identified herein; and

(7) present the Commission's conclusions and proposed recommendations based on its analysis.

(c) No later than December 31, 2025, and every other year thereafter, the Commission shall open an investigation to develop and adopt an updated renewable energy access plan that, at a minimum, evaluates the implementation and effectiveness of the renewable energy access plan, recommends improvements to the renewable energy access plan, and provides changes to transmission capacity necessary to deliver electric output from the renewable energy access plan zones.

(220 ILCS 5/9-201) (from Ch. 111 2/3, par. 9-201)

Sec. 9-201. (a) Unless the Commission otherwise orders, and except as otherwise provided in this Section, no change shall be made by any public utility in any rate or other charge or classification, or in any rule, regulation, practice or contract relating to or affecting any rate or other charge, classification or service, or in any privilege or facility, except after 45 days' notice to the Commission and to the public as herein provided. Such notice shall be given by filing with the Commission and keeping open for public inspection new schedules or supplements stating plainly the change or changes to be made in the schedule or schedules then in force, and the time when the change or changes will go into effect, and by publication in a newspaper of general circulation or such other notice to persons affected by such change as may be prescribed by rule of the Commission. The Commission, for good cause shown, may allow changes without requiring the 45 days' notice herein provided for, by an order specifying the changes so to be made and the time when they shall take effect and the manner in which they shall be filed and published.

When any change is proposed in any rate or other charge, or classification, or in any rule, regulation, practice, or contract relating to or affecting any rate or other charge, classification or service, or in any privilege or facility, such proposed change shall be plainly indicated on the new schedule filed with the Commission, by some character to be designated by the Commission, immediately preceding or following the item.

When any public utility providing water or sewer service proposes any change in any rate or other charge, or classification, or in any rule, regulation, practice, or contract relating to or affecting any rate or other charge, classification or service, or in any privilege or facility, such utility shall, in addition to the other notice requirements of this Act, provide notice of such change to all customers potentially affected by including a notice and description of such change, and of Commission procedures for intervention, in the first bill sent to each such customer after the filing of the proposed change.

For water or sewer utilities with greater than 15,000 total customers, the following notice requirements are applicable, in addition to the other notice requirements of this Act:

(1) As a separate bill insert, an initial notice in the first bill sent to all customers potentially affected by the proposed change after the filing of the proposed change shall include:

(A) the approximate date when the change or changes shall go into effect assuming the Commission utilizes the 11-month process as described in this Section;

(B) a statement indicating that the estimated bill impact may vary based on multiple factors, including, but not limited to, meter size, usage volume, and the fire protection district;

(C) the water or sewer utility's customer service number or other number as may be appropriate where an authorized agent of the water or sewer utility can explain how the proposed increase might impact an individual customer's bill;

(D) if the proposed change involves a change from a flat to a volumetric rate, an explanation of volumetric rate;

(E) a reference to the water or sewer utility's website where customers can find tips on water conservation; and

(F) for customers receiving both water and sewer service from a utility and if the customer has an option to install a separate meter for irrigation to mitigate sewer charges, an explanation of the water and sewer utility's and the customer's responsibilities for installation of a separate meter if such a change is approved.

(2) A second notice to all customers shall be included on the first bill after the Commission suspends the tariffs initiating the rate case.

(3) Final notice of such change shall be sent to all customers potentially affected by the proposed change by including information required under this paragraph (3) with the first bill after the effective date of the rates approved by the Final Order of the Commission in a rate case. The notice shall include the following:

(A) the date when the change or changes went into effect;

(B) the water or sewer utility's customer service number or other number as may be appropriate where an authorized agent of the water or sewer utility can explain how the proposed increase might impact an individual customer's bill;

(C) an explanation that usage shall now be charged at a volumetric rate rather than a flat rate, if applicable;

(D) a reference to the water or sewer utility's website where the customer can find tips on water conservation; and

(E) for customers receiving both water and sewer service from a utility and if the customer has an option to install a separate meter for irrigation to mitigate sewer charges, an explanation of the water and sewer utility's and the customer's responsibilities for installation of a separate meter if such a change is approved.

(b) Whenever there shall be filed with the Commission any schedule stating an individual or joint rate or other charge, classification, contract, practice, rule or regulation, the Commission shall have power, and it is hereby given authority, either upon complaint or upon its own initiative without complaint, at once, and if it so orders, without answer or other formal pleadings by the interested public utility or utilities, but upon reasonable notice, to enter upon a hearing concerning the propriety of such rate or other charge, classification, contract, practice, rule or regulation, and pending the hearing and decision thereon, such rate or other charge, classification, contract, practice, rule or regulation shall not go into effect. The period of suspension of such rate or other charge, classification, contract, practice, rule or regulation shall not extend more than 105 days beyond the time when such rate or other charge, classification, contract, practice, rule or regulation would otherwise go into effect unless the Commission, in its discretion, extends the period of suspension for a further period not exceeding 6 months.

All rates or other charges, classifications, contracts, practices, rules or regulations not so suspended shall, on the expiration of 45 days from the time of filing the same with the Commission, or of such lesser time as the Commission may grant, go into effect and be the established and effective rates or other charges, classifications, contracts, practices, rules and regulations, subject to the power of the Commission, after a hearing had on its own motion or upon complaint, as herein provided, to alter or modify the same.

Within 30 days after such changes have been authorized by the Commission, copies of the new or revised schedules shall be posted or filed in accordance with the terms of Section 9-103 of this Act, in such a manner that all changes shall be plainly indicated. The Commission shall incorporate into the period of suspension a review period of 4 business days during which the Commission may review and determine whether the new or revised schedules comply with the Commission's decision approving a change to the public utility's rates. Such review period shall not extend the suspension period by more than 2 days. Absent notification to the contrary within the 4 business day period, the new or revised schedules shall be deemed approved.

(c) If the Commission enters upon a hearing concerning the propriety of any proposed rate or other charge, classification, contract, practice, rule or regulation, the Commission shall establish the rates or other charges, classifications, contracts, practices, rules or regulations proposed, in whole or in part, or others in lieu thereof, which it shall find to be just and reasonable. In such hearing, the burden of proof to establish the justness and reasonableness of the proposed rates or other charges, classifications, contracts, practices, rules or regulations, in whole and in part, shall be upon the utility. The utility, the staff of the Commission, the Attorney General, or any party to a proceeding initiated under this Section who has been granted intervenor status and submitted a post-hearing brief must be given the opportunity to present oral argument, if requested no later than the date for filing exceptions, on the propriety of any proposed rate or other charge, classification, contract, practice, rule, or regulation. No rate or other charge, classification, contract, practice, rule or regulation shall be found just and reasonable unless it is consistent with Sections of this Article.

(d) Except where compliance with Section 8-401 of this Act is of urgent and immediate concern, no representative of a public utility may discuss with a commissioner, commissioner's assistant, or administrative law judge in a non-public setting a planned filing for a general rate increase. If a public utility makes a filing under this Section, then no substantive communication by any such person with a commissioner, commissioner's assistant, or administrative law judge concerning the filing is permitted until a notice of hearing has been issued. After the notice of hearing has been issued, the only communications by any such person with a commissioner, commissioner's assistant, or administrative law judge concerning the filing permitted are communications permitted under Section 10-103 of this Act. If any such communication does occur, then within 5 days of the docket being initiated all details relating to the communication shall be placed on the public record of the proceeding. The record shall include any materials, whether written, recorded, filmed, or graphic in nature, produced or reproduced on any media, used in connection with the communication. The record shall reflect the names of all persons who transmitted, received, or were otherwise involved in the communication, the duration of the communication, and whether the communication occurred in person or by other means. In the case of an oral communication, the record shall also reflect the location or locations of all persons involved in the communication and, if the communication occurred by telephone, the telephone numbers for the callers and recipients of the communication. A commissioner, commissioner's assistant, or administrative law judge who is involved in any such communication shall be recused from the affected proceeding. The Commission, or any commissioner or administrative law judge presiding over the proceeding shall, in the event of a violation of this Section, take action necessary to ensure that such violation does not prejudice any party or adversely affect the fairness of the proceedings including dismissing the affected proceeding. Nothing in this subsection (d) is intended to preclude otherwise allowable updates on issues that may be indirectly related to a general rate case filing because cost recovery for the underlying activity may be requested. Such updates may include, without limitation, issues related to outages and restoration, credit ratings, security issuances, reliability, Federal Energy Regulatory Commission matters, Federal Communications Commission matters, regional reliability organizations, consumer education, or labor matters, provided that such updates may not include cost recovery in a planned rate case.

(Source: P.A. 100-840, eff. 8-13-18.)

(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) This Section is repealed and tariffs authorized by this Section will terminate on December 31, 2021 December 31, 2023.

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

(220 ILCS 5/9-221) (from Ch. 111 2/3, par. 9-221)

Sec. 9-221. Whenever a municipality pursuant to Section 8-11-2 or 8-11-2.7 of the Illinois Municipal Code, as heretofore and hereafter amended, imposes a tax on any public utility, such utility may charge its customers, other than customers who are certified business enterprises under paragraph (e) of Section 8-11-2 of the Illinois Municipal Code or are exempted from those taxes under paragraph (f) of that Section, to the extent of such exemption and during the period in which such exemption is in effect, in addition to any rate authorized by this Act, an additional charge equal to the sum of (1) an amount equal to such municipal tax, or any part thereof (2) 3% of such tax, or any part thereof, as the case may be, to cover costs of accounting, and (3) an amount equal to the increase in taxes and other payments to governmental bodies resulting from the amount of such additional charge. Such utility shall file with the Commission a true and correct copy of the municipal ordinance imposing such tax; and also shall file with the Commission a supplemental schedule applicable to such municipality which shall specify such additional charge and which shall become effective upon filing without further notice. Such additional charge shall be shown separately on the utility bill to each customer. The Commission shall have power to investigate whether or not such supplemental schedule correctly specifies such additional charge, but shall have no power to suspend such supplemental schedule. If the Commission finds, after a hearing, that such supplemental schedule does not correctly specify such additional charge, it shall by order require a refund to the appropriate customers of the excess, if any, with interest, in such manner as it shall deem just and reasonable, and in and by such order shall require the utility to file an amended supplemental schedule corresponding to the finding and order of the Commission.

(Source: P.A. 87-895; 88-132.)

(220 ILCS 5/9-227) (from Ch. 111 2/3, par. 9-227)

Sec. 9-227. Charitable contributions by public utilities. It shall not be proper for the Commission to consider as an operating expense, for the purpose of determining whether a rate or other charge or classification is sufficient, donations made by a public utility for the public welfare or for charitable scientific, religious or educational purposes, provided that such donations are reasonable in amount. In determining the reasonableness of such donations, the Commission may not establish, by rule, a presumption that any particular portion of an otherwise reasonable amount may not be considered as an operating expense. The Commission shall disallow be prohibited from disallowing by rule, as an operating expense, any portion of a reasonable donation for public welfare or charitable purposes.

(Source: P.A. 85-122.)

(220 ILCS 5/9-229)

Sec. 9-229. Consideration of attorney and expert compensation as an expense and intervenor compensation fund.

(a) The Commission shall specifically assess the justness and reasonableness of any amount expended by a public utility to compensate attorneys or technical experts to prepare and litigate a general rate case filing. This issue shall be expressly addressed in the Commission's final order.

(b) The State of Illinois shall create a Consumer Intervenor Compensation Fund subject to the following:

(1) Legislative Intent. Provision of compensation for Consumer Interest Representatives that intervene in Illinois Commerce Commission proceedings will increase public engagement, encourage additional transparency, expand the information available to the Commission, and improve decision-making.

(2) Definition. Consumer interest representative means:

(A) a residential utility customer or group of residential utility customers;

(B) representatives of not-for-profit groups or organizations whose membership is limited to residential utility customers;

(C) representatives of not-for-profit groups or organizations whose membership includes Illinois residents and that address the community, economic, environmental, or social welfare of Illinois residents; or

(D) not-for-profit organizations that are authorized to represent the interests of residential utility customers or small commercial utility customers that receive utility service from a public utility whose tariffs must be approved by the Commission pursuant to their articles of incorporation or bylaws.

(3) Eligibility for Compensation. A consumer interest representative is eligible to receive compensation from the consumer intervenor compensation fund if its participation included lay or expert testimony or legal briefing and argument concerning the expenses, investments, rate design, rate impact, or other matters affecting the pricing, rates, costs or other charges associated with utility service, the Commission addresses or adopts in whole or in part one or more factual contentions, legal contentions, or policy or procedural recommendations presented by the consumer interest representative, the participant provided a significant contribution to the record, and participation caused a significant financial hardship to the participant.

(4) Consumer Intervenor Compensation Fund. Within 30 days after the effective date of this Act, each utility that files a request for an increase in rates under Article IX or Article XVI shall deposit an amount equal to one half of the rate case attorney and expert expense allowed by the Commission into the fund within 35 days of the date of the Commission's final Order in the rate case or 20 days after the denial of rehearing under Section 10-113 of this Act, whichever is later. The Consumer Intervenor Compensation Fund shall be used to provide payment to consumer interest representatives as described in this Section.

(5)(A) Initial Funding of Consumer Intervenor Compensation Fund. An electric public utility with 3,000,000 or more retail customers shall contribute $450,000 to the Consumer Intervenor Compensation Fund within 60 days after the effective date of this Act. A combined electric and gas public utility serving fewer than 3,000,000 but more than 500,000 retail customers shall contribute $225,000 to the Consumer Intervenor Compensation Fund within 60 days after the effective date of this Act. A gas public utility with 1,500,000 or more retail customers that is not a combined electric and gas public utility shall contribute $225,000 to the Consumer Intervenor Compensation Fund within 60 days after the effective date of this Act. A gas public utility with fewer than 1,500,000 retail customers but more than 300,000 retail customers that is not a combined electric and gas public utility shall contribute $80,000 to the Consumer Intervenor Compensation Fund within 60 days after the effective date of this Act. A gas public utility with fewer than 300,000 retail customers that is not a combined electric and gas public utility shall contribute $20,000 to the Consumer Intervenor Compensation Fund within 60 days after the effective date of this Act. A combined electric and gas public utility serving fewer than 500,000 retail customers shall contribute $20,000 to the Consumer Intervenor Compensation Fund within 60 days after the effective date of this Act. A water and/or sewer public utility serving more than 100,000 retail customers shall contribute $80,000, and a water and/or sewer public utility serving fewer than 100,000 but more than 10,000 retail customers shall contribute $20,000.

(6)(A) Pre-Order Funding. Prior to the entry of a Final Order in a docketed case, the Commission Administrator shall provide a payment to a consumer interest representative that demonstrates through a verified application for funding that the consumer interest representative's participation or intervention without an award of fees or costs imposes a significant financial hardship based on a schedule to be developed by the Commission. The initial payment shall be no less than $20,000 for a request for an increase in rates, and may be up to $20,000 for other dockets, investigations, rulemakings, or proceedings. The Administrator may require verification of costs incurred, including statements of hours spent, as a condition to paying the consumer interest representative prior to the entry of a Final Order in a docketed case.

(B) Post Order Funding. If the Commission addresses or adopts in whole or in part one or more factual contentions, legal contentions, or policy or procedural recommendations presented by the consumer interest representative, the participant provided a contribution to the record, and participation caused a financial hardship to the participant then the consumer interest representative shall be allowed payment for some or all of the consumer interest representative's reasonable attorney's or advocate's fees, reasonable expert witness fees, and other reasonable costs of preparation for and participation in a hearing or proceeding. Expenses related to travel or meals shall not be compensable. The Administrator shall award compensation to maximize intervenor participation.

(C) Request for Funding. The consumer interest representative shall submit an itemized request for compensation to the Consumer Intervenor Compensation Fund, including the advocate's or attorney's reasonable fee rate, the number of hours expended, reasonable expert and expert witness fees, and other reasonable costs for the preparation for and participation in the hearing and briefing within 30 days of the Commission's final order after denial or decision on rehearing, if any.

(7) Administration of the Fund.

(A) The Consumer Intervenor Compensation Fund is created as a special fund in the State treasury. All disbursements from the Consumer Intervenor Compensation Fund shall be made only upon warrants of the Comptroller drawn upon the Treasurer as custodian of the Fund upon vouchers signed by the Executive Director of the Commission 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. The Consumer Intervenor Compensation Fund shall be administered by an Administrator that is a person or entity that is independent of the Commission. The administrator will be responsible for the prudent management of the Consumer Intervenor Compensation Fund and for recommendations for the award of consumer intervenor compensation from the Consumer Intervenor Compensation Fund. The Commission shall issue a request for qualifications for a third-party program administrator to administer the Consumer Intervenor Compensation Fund. The third-party administrator shall be chosen through a competitive bid process based on selection criteria and requirements developed by the Commission. The Illinois Procurement Code does not apply to the hiring or payment of the Administrator. All Administrator costs may be paid for using monies from the Consumer Intervenor Compensation Fund, but the Program Administrator shall strive to minimize costs in the implementation of the program. The Consumer Intervenor Compensation 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.

(B) The computation of compensation awarded from the fund shall take into consideration the market rates paid to persons of comparable training and experience who offer similar services, but may not exceed the comparable market rate for services paid by the public utility as part of its rate case expense.

(C)(1) Recommendations on the award of compensation by the administrator shall include consideration of whether the Commission addressed or adopted in whole or in part one or more factual contentions, legal contentions, or policy or procedural recommendations presented by the consumer interest representative; whether the participant provided a to the record; and whether that participation caused a financial hardship to the participant and the payment of compensation is fair, just and reasonable.

(2) Recommendations on the award of compensation by the administrator shall be submitted to the Commission for approval. Unless the Commission initiates and investigation within 45 days after the notice to the Commission, the award of compensation shall be allowed 45 days after notice to the Commission. Such notice shall be given by filing with the Commission on the Commission's e-docket system, and keeping open for public inspection the award for compensation proposed by the Administrator. The Commission shall have power, and it is hereby given authority, either upon complaint or upon its own initiative without complaint, at once, and if it so orders, without answer or other formal pleadings, but upon reasonable notice, to enter upon a hearing concerning the propriety of the award. The investigation shall not extend more than 105 days after the Commission initiates the investigation.

(c) The Commission may adopt rules to implement this Section.

(Source: P.A. 96-33, eff. 7-10-09.)

(220 ILCS 5/9-241) (from Ch. 111 2/3, par. 9-241)

Sec. 9-241. No public utility shall, as to rates or other charges, services, facilities or in other respect, make or grant any preference or advantage to any corporation or person or subject any corporation or person to any prejudice or disadvantage. No public utility shall establish or maintain any unreasonable difference as to rates or other charges, services, facilities, or in any other respect, either as between localities or as between classes of service.

However, nothing in this Section shall be construed as limiting the authority of the Commission to permit the establishment of economic development rates as incentives to economic development either in enterprise zones as designated by the State of Illinois or in other areas of a utility's service area. Such rates should be available to existing businesses which demonstrate an increase to existing load as well as new businesses which create new load for a utility so as to create a more balanced utilization of generating capacity. The Commission shall ensure that such rates are established at a level which provides a net benefit to customers within a public utility's service area.

The Commission shall require that public utilities provide low-income discount rates for customers whose income falls at or below 80% of area median income, and file tariffs to reflect said discounts with the discounts tiered and decreased as income increases. In its review of the tariffs, the Commission shall ensure recovery of any cost associated with the tariffs be reflected in the rates charged to all customer classes, with charges and credits under the tariff allocated and collected through existing volumetric charges for delivery services. The tariff may be established outside the context of a general rate case filing and shall specify the terms of any applicable audit. The Commission shall review and by order approve, or approve as modified, the proposed tariff within 180 days after the date on which it is filed.

Upon approval of the tariff, the utility shall apply the appropriate credit or charge over a 12-month period beginning with the June billing period and ending with the May billing period, with the first such billing period beginning June 2022.

Eligibility for the low-income discount rates described in this subsection shall be established upon verification of a low-income customer's receipt of any means tested public benefit, or verification of eligibility for the low-income home energy assistance program. Said public benefits may include, but are not limited to, assistance from any government entity which provides cash, housing, food, or medical care, including, but not limited to, transitional assistance for needy families, supplemental security income, emergency assistance to elders, disabled, and children, supplemental nutrition assistance program, public housing, federally-subsidized or state-subsidized housing, the low-income home energy assistance program, veterans' benefits, and similar benefits. The Department of Human Services shall make available to distribution companies the eligibility guidelines for said public benefit programs.

Each distribution company shall conduct substantial outreach efforts to make said low-income discount available to eligible customers and shall report the Commission, at least annually, as to its outreach activities and results. Outreach may include establishing an automated program of matching customer accounts with lists of recipients of said means tested public benefit programs and based on the results of said matching program, to presumptively offer a low-income discount rate to eligible customers so identified; provided, however, that the distribution company, within 60 days of said presumptive enrollment, informs any such low-income customer of said presumptive enrollment and all rights and obligations of a customer under said program, including the right to withdraw from said program without penalty.

A residential customer eligible for low-income discount rates shall receive the service upon request and proof of eligibility. Each distribution company shall periodically notify all customers of the availability and method of obtaining low-income discount rates.

A utility shall file tariffs consistent with this subsection within 180 days of the enactment of this provision. The Commission shall promulgate rules and regulations requiring utility companies to produce information, in the form of a mailing, and other approved method of distribution, to their consumers, to inform them of available rebates, discounts, credits, and other cost-saving mechanisms that can help them lower their monthly utility bills, and send out such information semi-annually, unless otherwise provided by this chapter.

Prior to October 1, 1989, no public utility providing electrical or gas service shall consider the use of solar or other nonconventional renewable sources of energy by a customer as a basis for establishing higher rates or charges for any service or commodity sold to such customer; nor shall a public utility subject any customer utilizing such energy source or sources to any other prejudice or disadvantage on account of such use. No public utility shall without the consent of the Commission, charge or receive any greater compensation in the aggregate for a lesser commodity, product, or service than for a greater commodity, product or service of like character.

The Commission, in order to expedite the determination of rate questions, or to avoid unnecessary and unreasonable expense, or to avoid unjust or unreasonable discrimination between classes of customers, or, whenever in the judgment of the Commission public interest so requires, may, for rate making and accounting purposes, or either of them, consider one or more municipalities either with or without the adjacent or intervening rural territory as a regional unit where the same public utility serves such region under substantially similar conditions, and may within such region prescribe uniform rates for consumers or patrons of the same class.

Any public utility, with the consent and approval of the Commission, may as a basis for the determination of the charges made by it classify its service according to the amount used, the time when used, the purpose for which used, and other relevant factors.

(Source: P.A. 91-357, eff. 7-29-99.)

(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. Further, to achieve the goals of this Act that robust options for customer-site distributed generation continue to thrive in Illinois, the General Assembly finds that a predictable transition must be ensured for customers between full net metering at the retail electricity rate to the distribution generation rebate described in Section 16-107.6.

(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, hosts, or operates, including any third-party owned systems, a solar, wind, or other eligible renewable electrical generating facility with a rated alternating current capacity of not more than 5,000 2,000 kilowatts that is located on the customer's premises or customer's side of the billing meter and is intended primarily to offset the customer's own current or future electrical requirements; (iii) "electricity provider" means an electric utility or alternative retail electric supplier; (iv) "eligible renewable electrical generating facility" means a generator which may include the co-location of an energy storage system 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; (viii) "energy storage system" means commercially available technology that is capable of absorbing energy and storing it for a period of time for use at a later time including but not limited to electrochemical, thermal and electromechanical technologies and may be interconnected behind the customer's meter or interconnected behind its own meter; and (ix) "future electrical requirements" means a reasonable approximation of the annual load of two electric vehicles and, for non-electric heating customers, a reasonable approximation of the incremental electric load association with fuel switching. The approximations shall be applied to the appropriate net metering tariff, and do not need to be unique to each individual eligible customer. The utility shall submit these approximations to the Commission for review, modification, and approval.

(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 or time of use rates in the following manner:

(1) If the amount of electricity used by the customer during any hourly period or time of use 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 or time of use period exceeds the amount of electricity used by the customer during that hourly period or time of use 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 or time of use period. The delivery credit shall be equal to the net kilowatt-hours produced in such hourly period or time of use 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) Within 90 days of the effective date of this amendatory Act of the 102nd General Assembly, the Commission shall: All electricity providers shall begin to offer net metering no later than April 1, 2008.

(1) establish an Interconnection Working Group. The working group shall include representatives from electric utilities, developers of renewable electric generating facilities, other industries that regularly apply for interconnection with the electric utilities, representatives of distributed generation customers, the Commission Staff and such other stakeholders with a substantial interest in the topics addressed by the working group. The working group shall address at least the following issues:

(A) cost and best available technology for interconnection and metering, including the standardization and publication of standard costs;

(B) transparency, accuracy and use of the distribution interconnection queue and hosting capacity maps;

(C) distribution system upgrade cost avoidance through use of advanced inverter functions;

(D) predictability of the queue management process and enforcement of timelines;

(E) benefits and challenges associated with group studies and cost sharing;

(F) minimum requirements for application to the interconnection process and throughout the interconnection process to avoid queue clogging behavior;

(G) process and customer service for interconnecting customers adopting distributed energy resources, including energy storage;

(H) options for metering distributed energy resources, including energy storage;

(I) interconnection of new technologies, including smart inverters and energy storage; and

(K) without limitation, such other technical, policy, and tariff issues related to and affecting interconnection performance and customer service, as determined by the working group.

The Commission may create working group subcommittees of the working group to focus on specific issues of importance, as appropriate. The working group shall report to the Commission on recommended improvements to interconnection rules and tariffs and policies as determined by the working group at least every 6 months. Such reports shall include consensus recommendations of the working group and, if applicable, additional recommendations for which consensus was not reached. The Commission shall use the report from the working group to determine whether processes should be commenced to formally codify or implement the recommendations;

(2) create or contract for an Ombudsman to resolve disputes through non-binding arbitration. The Ombudsman shall be paid in full or in part through fees levied on the initiators of the dispute; and

(3) determine a single standardized cost for Level 1 interconnections that shall not exceed $200.

(j) An electricity provider shall provide net metering to eligible customers according to subsections (d), (d-5), and (e) until December 31, 2024 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, eligible customers that begin taking net metering shall only be eligible for netting of energy. An eligible customer according to subsections (d), (d-5), and (e) that registered for net metering before December 31, 2024 shall be allowed to stay under the tariff for the lifetime of the system. After December 31, 2024 any eligible customer that applies for net metering shall only be eligible for net metering as described in subsection (n).

(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, provided that only electric utilities shall provide net metering for subparagraph (C) of this paragraph (1):

(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 and regardless of whether a subscriber receives power and energy service from the electric utility or an alternative retail electric supplier, the electric utility an electricity provider shall provide the monetary credits to a subscriber's subsequent bill for the electricity produced by community renewable generation projects the projects described in paragraph (1) of this subsection (l). The electric utility electricity provider shall provide monetary credits to a subscriber's subsequent bill at the utility's total price to compare 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). For the purposes of this subsection, "total price to compare" means the rate or rates published by the Illinois Commerce Commission for energy supply for eligible customers receiving supply service from the electric utility, and includes energy, capacity, transmission, and the purchased energy adjustment. Notwithstanding anything to the contrary, customers on payment plans or participating in budget billing programs shall have credits applied on a monthly basis. Any applicable credit or reduction in load obligation from the production of the community renewable generating projects receiving a credit under this subsection shall be credited to the electric utility to offset the cost of providing the credit. To the extent that the credit or load obligation reduction does not completely offset the cost of providing the credit to subscribers of community renewable generation projects as described in this subsection the electric utility may recover the remaining costs through the process established in Section 16-111.8.

(3) If requested by the owner or operator of a community renewable generating project, an electric utility shall enter into a net crediting agreement with the owner or operator to include a subscriber's subscription fee on the subscriber's monthly electric bill and provide the subscriber with a net credit equivalent to the total bill credit value for that generation period minus the subscription fee, provided the subscription fee is structured as a fixed percentage of bill credit value. The net crediting agreement shall set forth payment terms from the electric utility to the owner or operator of the community renewable generating project, and the electric utility may charge a net crediting fee to the owner or operator of a community renewable generating project that may not exceed 1% of the bill credit value.

(4) (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 102nd 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 in projects described in subparagraphs (A) and (B) of this paragraph (4) of subsection (l) 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 102nd 99th General Assembly, each electric utility subject to this Section shall file a tariff or tariffs 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 102nd 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) After December 31, 2024 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), and (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 whom shall continue to receive net metering services described in subsections (d), (d-5), and (e) of this Section for lifetime of system, regardless of if those retail customers change electricity providers. The electricity utility is responsible for ensuring billing credits continue without lapse for the lifetime of systems, as required in subsection (o). 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 monthly 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 monthly 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 monetary 1:1 kilowatt-hour energy credit equivalent to the kilowatt hour supply charges to the customer's subsequent bill. For the purposes of this subsection, "kilowatt-hour supply charges" means the kilowatt-hour equivalent values for energy, capacity, transmission, and the purchased energy adjustment, if applicable. Notwithstanding anything to the contrary, customers on payment plans or participating in budget billing programs shall have credits applied on a monthly basis 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 monetary 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) (Blank). 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, and shall apply that credit as a monetary credit to the customer's subsequent bill. 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, and shall also include values for capacity, and transmission.

(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.

(o) Within 90 days after the effective date of this amendatory Act of the 102nd General Assembly, each electric utility subject to this Section and Section 16-107.5 shall file a tariff which shall, consistent with the provisions of this Section, propose the terms and conditions under which a customer may participate in net metering. The tariff shall also provide a streamlined and transparent bill crediting system for net metering to be managed by the electric utilities. The terms and conditions shall include, but are not limited to, that an electricity utility shall manage and maintain billing of net metering credits and charges regardless of if the eligible customer takes net metering under electricity utility or alternative retail electricity supplier. The electricity utility will process and approve all net metering applications, even if an eligible customer is served by an alternative retail electricity supplier; and the utility will forward application approval to the appropriate alternative retail electricity supplier. Eligibility for net metering shall remain with the owner of the utility billing address such that if a premise changes ownership the net metering eligibility transfers to the new owner. The electricity utility will manage net metering billing for eligible customers to ensure full crediting occurs on electricity bills, including but not limited to ensuring net metering crediting begins upon commercial operation date, net metering billing transfers immediately if an eligible customer switches from an electricity utility to alternative retail electricity supplier or vice versa, and net metering billing transfers between ownership of a valid billing address. This includes transfer of all banked credits.

(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:

"Additive grid services" means the services, as determined by the Commission, that distributed generation provides the grid in addition to system-wide grid services. Additive grid services may include geographic, locational, geographic, time-based, and performance-based benefits, technological capabilities and present and future grid needs.

"Energy storage system" means commercially available technology that is capable of absorbing energy and storing it for a period of time for use at a later time including but not limited to electrochemical, thermal, and electromechanical technologies and may be interconnected behind the customer's meter or interconnected behind its own meter.

"Nameplate capacity" means the kilowatt-hour of rated AC capacity of the installed system.

"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, and communication systems with ability to accept external commands, and other functions from the electric utility.

"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.

"System-wide grid services" means the basic services a distributed generation project that installs a smart inverter provides to the grid for a minimum of 25 years. Those basic services are delineated in the definition of smart inverter above.

"Threshold date" means December 31, 2024 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 the owner or operator of a retail customer who owns or operates distributed generation, including third-party owned systems, that meets the following criteria:

(1) has a nameplate generating capacity no greater than 5,000 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 include a base payment for system-wide grid services and an additional payment for additive grid services. The tariff shall provide that the base payment as outlined in (c) below is in exchange for system-wide grid services, and that the utility shall be permitted to send signals to utilize operate and control the smart inverter associated with the distributed generation that receives a base payment is the subject of the rebate for the purpose of preserving reliability during distribution system reliability events. The tariff 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 additive grid services additional uses of the smart inverter that shall be separately compensated from system-wide grid services. Such additive grid services and which may include, but are not limited to, voltage and VAR support, voltage watt, frequency watt, 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 additive grid additional uses or services. If the Commission determines that an additive grid additional use or service would be beneficial, the Commission shall determine the terms and conditions of the operation of such additive grid service and shall approve the value of such additive grid service 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 for 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 additional payment for additive grid services as rebate values established by the Commission under subsection (e) of this Section, the owner or operator of distributed generation that services 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 base payment rebate shall be $250 per kilowatt of nameplate generating capacity, measured as nominal DC power output, of a non-residential customer's distributed generation. After the utility files a tariff or tariffs making the additional payment for additive grid services as established under subsection (e) of this Section, non-residential customers may apply for a rebate in the amount of the base payment as outlined in this Section and may opt to apply for the additional payment for additive grid services if the system chooses to provide such services. To the extent the distributed generation system also has a storage device as part of the system, and said storage uses the same smart inverter as the distributed generation, then the storage shall be separately compensated at a base payment of $350 per kilowatt-hour of nameplate capacity.

(2) After the threshold date and until December 31, 2029, the owner of distributed generation that, before the threshold date, would have been eligible for net metering under subsection (d), (d-5), or (e) of Section 16-107.5, may apply for a rebate in the amount of the base payment for system-wide grid services as provided for in this Section. The value of the base payment shall be $350 per kilowatt of nameplate generating capacity, measured as nominal DC power output, of the distributed generation. After the utility files a tariff or tariffs making the additional payment for additive grid services as established under subsection (e) of this Section, owners or operators may apply for a rebate in the amount of the base payment as outlined in this Section, and may opt to apply for the additional payment for additive grid services, if the system chooses to provide such services To the extent the distributed generation system also has a storage device as part of the system, and said storage uses the same smart inverter as the distributed generation, then the storage shall be separately compensated at a base payment of $350 per kilowatt-hour of nameplate capacity. 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), the owner or operator of the distributed generation 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 installed and in operation on the 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. Upon the effective date of this amendatory Act of the 102nd General Assembly, an electric utility shall file a petition with the Commission to amend and update any existing tariffs to comply with subsections (b) and (c).

(e) Upon the effective date of this amendatory Act of the 102nd General Assembly, if When the total generating capacity of the electricity provider's net metering customers is equal to 3%, the Commission has not already opened an investigation, it shall open an investigation into a an annual process and formula for calculating the additional payment associated with additive grid services 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 process for identifying additive grid services and the formula for calculating the additional payment for those additive grid services shall be updated every 5 years, and shall promote expansion of, and continuity in, the distributed generation competitive market. The value of the additional payment for additive grid services shall be set no more frequently than annually using the established process and formula established by the Commission. The investigation shall include diverse sets of stakeholders, calculations for valuing additive grid services distributed generation provides energy resource benefits to the grid based on best practices, and assessments of present and future technological capabilities of distributed generation energy resources. The value of such additional payments 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, locational, time-based, and performance-based benefits, as well as technological capabilities and present and future grid needs. As such, different locations within the utility territory may have different additive grid services and associated additional payments. The investigation shall take a long-term look at the benefits and values of such additive grid services. No later than 60 10 days after the Commission enters its final order under this subsection (e), the utility shall file its updated tariff or tariffs in compliance with the order, and the Commission shall approve, or approve with modification, the tariff or tariffs within 90 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.

(f) Notwithstanding any provision of this Act to the contrary, the owner, developer, or subscriber of a distributed generation facility that is a community renewable energy generation facility as defined in Section 1-75(c) of the Illinois Power Agency Act 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. The owner or operator of A subscriber to the generation facility may apply for a rebate in the amount of the subscriber's subscription only if the owner or operator, or previous owner or operator of the community renewable energy generation facility, 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) The owner of the distributed generation may apply for the tariff or tariffs approved under this Section at the time of execution of an interconnection agreement with the distribution utility and shall receive the value of the base payment and additional payment available at that time of execution of the interconnection agreement, provided the project reaches mechanical completion within 24 months of execution of the interconnection agreement. The utility shall issue the rebate no No later than 60 days after the project is energized 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 5/16-108)

Sec. 16-108. Recovery of costs associated with the provision of delivery and other services.

(a) An electric utility shall file a delivery services tariff with the Commission at least 210 days prior to the date that it is required to begin offering such services pursuant to this Act. An electric utility shall provide the components of delivery services that are subject to the jurisdiction of the Federal Energy Regulatory Commission at the same prices, terms and conditions set forth in its applicable tariff as approved or allowed into effect by that Commission. The Commission shall otherwise have the authority pursuant to Article IX to review, approve, and modify the prices, terms and conditions of those components of delivery services not subject to the jurisdiction of the Federal Energy Regulatory Commission, including the authority to determine the extent to which such delivery services should be offered on an unbundled basis. In making any such determination the Commission shall consider, at a minimum, the effect of additional unbundling on (i) the objective of just and reasonable rates, (ii) electric utility employees, and (iii) the development of competitive markets for electric energy services in Illinois.

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

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

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

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

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

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

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

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

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

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

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

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

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

(j) If a retail customer that obtains electric power and energy from cogeneration or self-generation facilities installed for its own use on or before January 1, 1997, subsequently takes service from an alternative retail electric supplier or an electric utility other than the electric utility in whose service area the customer is located for any portion of the customer's electric power and energy requirements formerly obtained from those facilities (including that amount purchased from the utility in lieu of such generation and not as standby power purchases, under a cogeneration displacement tariff in effect as of the effective date of this amendatory Act of 1997), the transition charges otherwise applicable pursuant to subsections (f), (g), or (h) of this Section shall not be applicable in any year to that portion of the customer's electric power and energy requirements formerly obtained from those facilities, provided, that for purposes of this subsection (j), such portion shall not exceed the average number of kilowatt-hours per year obtained from the cogeneration or self-generation facilities during the 3 years prior to the date on which the customer became eligible for delivery services, except as provided in subsection (f) of Section 16-110.

(k) The electric utility shall be entitled to recover through tariffed charges all of the costs associated with the purchase of zero emission credits from zero emission facilities to meet the requirements of subsection (d-5) of Section 1-75 of the Illinois Power Agency Act. Such costs shall include the costs of procuring the zero emission credits, as well as the reasonable costs that the utility incurs as part of the procurement processes and to implement and comply with plans and processes approved by the Commission under such subsection (d-5). The costs shall be allocated across all retail customers through a single, uniform cents per kilowatt-hour charge applicable to all retail customers, which shall appear as a separate line item on each customer's bill. Beginning June 1, 2017, the electric utility shall be entitled to recover through tariffed charges all of the costs associated with the purchase of renewable energy resources to meet the renewable energy resource standards of subsection (c) of Section 1-75 of the Illinois Power Agency Act, under procurement plans as approved in accordance with that Section and Section 16-111.5 of this Act. Such costs shall include the costs of procuring the renewable energy resources, as well as the reasonable costs that the utility incurs as part of the procurement processes and to implement and comply with plans and processes approved by the Commission under such Sections. The costs associated with the purchase of renewable energy resources shall be allocated across all retail customers in proportion to the amount of renewable energy resources the utility procures for such customers through a single, uniform cents per kilowatt-hour charge applicable to such retail customers, which shall appear as a separate line item on each such customer's bill.

Notwithstanding whether the Commission has approved the initial long-term renewable resources procurement plan as of June 1, 2017, an electric utility shall place new tariffed charges into effect beginning with the June 2017 monthly billing period, to the extent practicable, to begin recovering the costs of procuring renewable energy resources, as those charges are calculated under the limitations described in subparagraph (E) of paragraph (1) of subsection (c) of Section 1-75 of the Illinois Power Agency Act. Notwithstanding the date on which the utility places such new tariffed charges into effect, the utility shall be permitted to collect the charges under such tariff as if the tariff had been in effect beginning with the first day of the June 2017 monthly billing period. For the delivery years commencing June 1, 2017, June 1, 2018, and June 1, 2019, June 1, 2020, June 1, 2021, and June 1, 2022, the electric utility shall deposit into a separate interest bearing account of a financial institution the monies collected under the tariffed charges. Any interest earned shall be credited back to retail customers under the reconciliation proceeding provided for in this subsection (k), provided that the electric utility shall first be reimbursed from the interest for the administrative costs that it incurs to administer and manage the account. Any taxes due on the funds in the account, or interest earned on it, will be paid from the account or, if insufficient monies are available in the account, from the monies collected under the tariffed charges to recover the costs of procuring renewable energy resources. Monies deposited in the account shall be subject to the review, reconciliation, and true-up process described in this subsection (k) that is applicable to the funds collected and costs incurred for the procurement of renewable energy resources.

The electric utility shall be entitled to recover all of the costs identified in this subsection (k) through automatic adjustment clause tariffs applicable to all of the utility's retail customers that allow the electric utility to adjust its tariffed charges consistent with this subsection (k). The determination as to whether any excess funds were collected during a given delivery year for the purchase of renewable energy resources, and the crediting of any excess funds back to retail customers, shall not be made until after the close of the delivery year, which will ensure that the maximum amount of funds is available to implement the approved long-term renewable resources procurement plan during a given delivery year. The amount of excess funds credited back to retail customers shall be reduced by an amount equal to the payment obligations required by any contracts entered into by an electric utility under described in Sections 1-56(b) and 1-75(c) of the Illinois Power Agency Act, even if such payments have not yet been made. The electric utility's collections under such automatic adjustment clause tariffs to recover the costs of renewable energy resources and zero emission credits from zero emission facilities shall be subject to separate annual review, reconciliation, and true-up against actual costs by the Commission under a procedure that shall be specified in the electric utility's automatic adjustment clause tariffs and that shall be approved by the Commission in connection with its approval of such tariffs. The procedure shall provide that any difference between the electric utility's collections under the automatic adjustment charges for an annual period and the electric utility's actual costs of renewable energy resources and zero emission credits from zero emission facilities for that same annual period shall be refunded to or collected from, as applicable, the electric utility's retail customers in subsequent periods.

Nothing in this subsection (k) is intended to affect, limit, or change the right of the electric utility to recover the costs associated with the procurement of renewable energy resources for periods commencing before, on, or after June 1, 2017, as otherwise provided in the Illinois Power Agency Act.

Notwithstanding anything to the contrary, the Commission shall not conduct an annual review, reconciliation, and true-up associated with renewable energy resources' collections and costs for the delivery years commencing June 1, 2017, June 1, 2018, June 1, 2019, and June 1, 2020, June 1, 2021, and June 1, 2022, and shall instead conduct a single review, reconciliation, and true-up associated with renewable energy resources' collections and costs for the 6-year 4-year period beginning June 1, 2017 and ending May 31, 2023 2021, provided that the review, reconciliation, and true-up shall not be initiated until after August 31, 2023 2021. During the 6-year 4-year period, the utility shall be permitted to collect and retain funds under this subsection (k) and to purchase renewable energy resources under an approved long-term renewable resources procurement plan using those funds regardless of the delivery year in which the funds were collected during the 6-year 4-year period.

If the amount of funds collected during the delivery year commencing June 1, 2017, exceeds the costs incurred during that delivery year, then up to half of this excess amount, as calculated on June 1, 2018, may be used to fund the programs under subsection (b) of Section 1-56 of the Illinois Power Agency Act in the same proportion the programs are funded under that subsection (b). However, any amount identified under this subsection (k) to fund programs under subsection (b) of Section 1-56 of the Illinois Power Agency Act shall be reduced if it exceeds the funding shortfall. For purposes of this Section, "funding shortfall" means the difference between $200,000,000 and the amount appropriated by the General Assembly to the Illinois Power Agency Renewable Energy Resources Fund during the period that commences on the effective date of this amendatory act of the 99th General Assembly and ends on August 1, 2018.

If the amount of funds collected during the delivery year commencing June 1, 2018, exceeds the costs incurred during that delivery year, then up to half of this excess amount, as calculated on June 1, 2019, may be used to fund the programs under subsection (b) of Section 1-56 of the Illinois Power Agency Act in the same proportion the programs are funded under that subsection (b). However, any amount identified under this subsection (k) to fund programs under subsection (b) of Section 1-56 of the Illinois Power Agency Act shall be reduced if it exceeds the funding shortfall.

If the amount of funds collected during the delivery year commencing June 1, 2019, exceeds the costs incurred during that delivery year, then up to half of this excess amount, as calculated on June 1, 2020, may be used to fund the programs under subsection (b) of Section 1-56 of the Illinois Power Agency Act in the same proportion the programs are funded under that subsection (b). However, any amount identified under this subsection (k) to fund programs under subsection (b) of Section 1-56 of the Illinois Power Agency Act shall be reduced if it exceeds the funding shortfall.

The funding available under this subsection (k), if any, for the programs described under subsection (b) of Section 1-56 of the Illinois Power Agency Act shall not reduce the amount of funding for the programs described in subparagraph (O) of paragraph (1) of subsection (c) of Section 1-75 of the Illinois Power Agency Act. If funding is available under this subsection (k) for programs described under subsection (b) of Section 1-56 of the Illinois Power Agency Act, then the long-term renewable resources plan shall provide for the Agency to procure contracts in an amount that does not exceed the funding, and the contracts approved by the Commission shall be executed by the applicable utility or utilities.

(l) A utility that has terminated any contract executed under subsection (d-5) of Section 1-75 of the Illinois Power Agency Act shall be entitled to recover any remaining balance associated with the purchase of zero emission credits prior to such termination, and such utility shall also apply a credit to its retail customer bills in the event of any over-collection.

(m)(1) An electric utility that recovers its costs of procuring zero emission credits from zero emission facilities through a cents-per-kilowatthour charge under to subsection (k) of this Section shall be subject to the requirements of this subsection (m). Notwithstanding anything to the contrary, such electric utility shall, beginning on April 30, 2018, and each April 30 thereafter until April 30, 2026, calculate whether any reduction must be applied to such cents-per-kilowatthour charge that is paid by retail customers of the electric utility that are exempt from subsections (a) through (j) of Section 8-103B of this Act under subsection (l) of Section 8-103B. Such charge shall be reduced for such customers for the next delivery year commencing on June 1 based on the amount necessary, if any, to limit the annual estimated average net increase for the prior calendar year due to the future energy investment costs to no more than 1.3% of 5.98 cents per kilowatt-hour, which is the average amount paid per kilowatthour for electric service during the year ending December 31, 2015 by Illinois industrial retail customers, as reported to the Edison Electric Institute.

The calculations required by this subsection (m) shall be made only once for each year, and no subsequent rate impact determinations shall be made.

(2) For purposes of this Section, "future energy investment costs" shall be calculated by subtracting the cents-per-kilowatthour charge identified in subparagraph (A) of this paragraph (2) from the sum of the cents-per-kilowatthour charges identified in subparagraph (B) of this paragraph (2):

(A) The cents-per-kilowatthour charge identified in the electric utility's tariff placed into effect under Section 8-103 of the Public Utilities Act that, on December 1, 2016, was applicable to those retail customers that are exempt from subsections (a) through (j) of Section 8-103B of this Act under subsection (l) of Section 8-103B.

(B) The sum of the following cents-per-kilowatthour charges applicable to those retail customers that are exempt from subsections (a) through (j) of Section 8-103B of this Act under subsection (l) of Section 8-103B, provided that if one or more of the following charges has been in effect and applied to such customers for more than one calendar year, then each charge shall be equal to the average of the charges applied over a period that commences with the calendar year ending December 31, 2017 and ends with the most recently completed calendar year prior to the calculation required by this subsection (m):

(i) the cents-per-kilowatthour charge to recover the costs incurred by the utility under subsection (d-5) of Section 1-75 of the Illinois Power Agency Act, adjusted for any reductions required under this subsection (m); and

(ii) the cents-per-kilowatthour charge to recover the costs incurred by the utility under Section 16-107.6 of the Public Utilities Act.

If no charge was applied for a given calendar year under item (i) or (ii) of this subparagraph (B), then the value of the charge for that year shall be zero.

(3) If a reduction is required by the calculation performed under this subsection (m), then the amount of the reduction shall be multiplied by the number of years reflected in the averages calculated under subparagraph (B) of paragraph (2) of this subsection (m). Such reduction shall be applied to the cents-per-kilowatthour charge that is applicable to those retail customers that are exempt from subsections (a) through (j) of Section 8-103B of this Act under subsection (l) of Section 8-103B beginning with the next delivery year commencing after the date of the calculation required by this subsection (m).

(4) The electric utility shall file a notice with the Commission on May 1 of 2018 and each May 1 thereafter until May 1, 2026 containing the reduction, if any, which must be applied for the delivery year which begins in the year of the filing. The notice shall contain the calculations made pursuant to this Section. By October 1 of each year beginning in 2018, each electric utility shall notify the Commission if it appears, based on an estimate of the calculation required in this subsection (m), that a reduction will be required in the next year.

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

(220 ILCS 5/16-108.5)

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

(a) (Blank).

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

During the infrastructure investment program's peak program year, a participating utility other than a combination utility shall create 2,000 full-time equivalent jobs in Illinois, and a participating utility that is a combination utility shall create 450 full-time equivalent jobs in Illinois related to the provision of electric service. These jobs shall include direct jobs, contractor positions, and induced jobs, but shall not include any portion of a job commitment, not specifically contingent on an amendatory Act of the 97th General Assembly becoming law, between a participating utility and a labor union that existed on December 30, 2011 (the effective date of Public Act 97-646) and that has not yet been fulfilled. A portion of the full-time equivalent jobs created by each participating utility shall include incremental personnel hired subsequent to December 30, 2011 (the effective date of Public Act 97-646). For purposes of this Section, "peak program year" means the consecutive 12-month period with the highest number of full-time equivalent jobs that occurs between the beginning of investment year 2 and the end of investment year 4.

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

(1) Beginning no later than 180 days after a participating utility other than a combination utility files a performance-based formula rate tariff pursuant to subsection (c) of this Section, or, beginning no later than January 1, 2012 if such utility files such performance-based formula rate tariff within 14 days of October 26, 2011 (the effective date of Public Act 97-616), the participating utility shall, except as provided in subsection (b-5):

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

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

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

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

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

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

(i) additional smart meters;

(ii) distribution automation;

(iii) associated cyber secure data communication network; and

(iv) substation micro-processor relay upgrades.

(2) Beginning no later than 180 days after a participating utility that is a combination utility files a performance-based formula rate tariff pursuant to subsection (c) of this Section, or, beginning no later than January 1, 2012 if such utility files such performance-based formula rate tariff within 14 days of October 26, 2011 (the effective date of Public Act 97-616), the participating utility shall, except as provided in subsection (b-5):

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

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

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

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

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

(i) additional smart meters;

(ii) distribution automation;

(iii) associated cyber secure data communication network; and

(iv) substation micro-processor relay upgrades.

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

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

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

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

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

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

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

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

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

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

(b-10) All participating utilities shall make contributions for an energy low-income and support program in accordance with this subsection. Beginning no later than 180 days after a participating utility files a performance-based formula rate tariff pursuant to subsection (c) of this Section, or beginning no later than January 1, 2012 if such utility files such performance-based formula rate tariff within 14 days of December 30, 2011 (the effective date of Public Act 97-646), and without obtaining any approvals from the Commission or any other agency other than as set forth in this Section, regardless of whether any such approval would otherwise be required, a participating utility other than a combination utility shall pay $23,500,000 $10,000,000 per year for 5 years and a participating utility that is a combination utility shall pay $1,000,000 per year for 10 years to the energy low-income and support program, which is intended to fund customer assistance programs with the primary purpose being avoidance of imminent disconnection. Such programs may include:

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

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

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

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

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

The payments made by a participating utility pursuant to this subsection (b-10) shall not be a recoverable expense. A participating utility may elect to fund either new or existing customer assistance programs, including, but not limited to, those that are administered by the utility.

Programs that use funds that are provided by a participating utility to reduce utility bills may be implemented through tariffs that are filed with and reviewed by the Commission. If a utility elects to file tariffs with the Commission to implement all or a portion of the programs, those tariffs shall, regardless of the date actually filed, be deemed accepted and approved, and shall become effective on December 30, 2011 (the effective date of Public Act 97-646). The participating utilities whose customers benefit from the funds that are disbursed as contemplated in this Section shall file annual reports documenting the disbursement of those funds with the Commission. The Commission has the authority to audit disbursement of the funds to ensure they were disbursed consistently with this Section.

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

(c) A participating utility may elect to recover its delivery services costs through a performance-based formula rate approved by the Commission, which shall specify the cost components that form the basis of the rate charged to customers with sufficient specificity to operate in a standardized manner and be updated annually with transparent information that reflects the utility's actual costs to be recovered during the applicable rate year, which is the period beginning with the first billing day of January and extending through the last billing day of the following December. In the event the utility recovers a portion of its costs through automatic adjustment clause tariffs on October 26, 2011 (the effective date of Public Act 97-616), the utility may elect to continue to recover these costs through such tariffs, but then these costs shall not be recovered through the performance-based formula rate. In the event the participating utility, prior to December 30, 2011 (the effective date of Public Act 97-646), filed electric delivery services tariffs with the Commission pursuant to Section 9-201 of this Act that are related to the recovery of its electric delivery services costs that are still pending on December 30, 2011 (the effective date of Public Act 97-646), the participating utility shall, at the time it files its performance-based formula rate tariff with the Commission, also file a notice of withdrawal with the Commission to withdraw the electric delivery services tariffs previously filed pursuant to Section 9-201 of this Act. Upon receipt of such notice, the Commission shall dismiss with prejudice any docket that had been initiated to investigate the electric delivery services tariffs filed pursuant to Section 9-201 of this Act, and such tariffs and the record related thereto shall not be the subject of any further hearing, investigation, or proceeding of any kind related to rates for electric delivery services.

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

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

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

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

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

(B) 580 basis points.

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

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

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

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

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

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

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

(F) amortization over a 5-year period of the full amount of each charge or credit that exceeds $3,700,000 for a participating utility that is a combination utility or $10,000,000 for a participating utility that serves more than 3 million retail customers in the applicable calendar year and that relates to a workforce reduction program's severance costs, changes in accounting rules, changes in law, compliance with any Commission-initiated audit, or a single storm or other similar expense, provided that any unamortized balance shall be reflected in rate base. For purposes of this subparagraph (F), changes in law includes any enactment, repeal, or amendment in a law, ordinance, rule, regulation, interpretation, permit, license, consent, or order, including those relating to taxes, accounting, or to environmental matters, or in the interpretation or application thereof by any governmental authority occurring after October 26, 2011 (the effective date of Public Act 97-616);

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

(H) historical weather normalized billing determinants; and

(I) allocation methods for common costs.

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

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

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

After the utility files its proposed performance-based formula rate structure and protocols and initial rates, the Commission shall initiate a docket to review the filing. The Commission shall enter an order approving, or approving as modified, the performance-based formula rate, including the initial rates, as just and reasonable within 270 days after the date on which the tariff was filed, or, if the tariff is filed within 14 days after October 26, 2011 (the effective date of Public Act 97-616), then by May 31, 2012. Such review shall be based on the same evidentiary standards, including, but not limited to, those concerning the prudence and reasonableness of the costs incurred by the utility, the Commission applies in a hearing to review a filing for a general increase in rates under Article IX of this Act. The initial rates shall take effect within 30 days after the Commission's order approving the performance-based formula rate tariff.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

For purposes of this Section, the amount per kilowatthour means the total amount paid for electric service expressed on a per kilowatthour basis, and the total amount paid for electric service includes without limitation amounts paid for supply, transmission, distribution, surcharges, and add-on taxes exclusive of any increases in taxes or new taxes imposed after October 26, 2011 (the effective date of Public Act 97-616). For purposes of this Section, "eligible retail customers" shall have the meaning set forth in Section 16-111.5 of this Act.

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

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

Sections 16-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act, other than this subsection (h), are inoperative after December 31, 2021 2022 for every participating utility, after which time a participating utility shall no longer be eligible to annually update the performance-based formula rate tariff pursuant to subsection (d) of this Section. At such time, the then current rates shall remain in effect until such time as new rates are set pursuant to Article IX of this Act, subject to retroactive adjustment, with interest, to reconcile rates charged with actual costs.

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

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

(j) Nothing in this Section is intended to legislatively overturn the opinion issued in Commonwealth Edison Co. v. Ill. Commerce Comm'n, Nos. 2-08-0959, 2-08-1037, 2-08-1137, 1-08-3008, 1-08-3030, 1-08-3054, 1-08-3313 cons. (Ill. App. Ct. 2d Dist. Sept. 30, 2010). Public Act 97-616 shall not be construed as creating a contract between the General Assembly and the participating utility, and shall not establish a property right in the participating utility.

(k) The changes made in subsections (c) and (d) of this Section by Public Act 98-15 are intended to be a restatement and clarification of existing law, and intended to give binding effect to the provisions of House Resolution 1157 adopted by the House of Representatives of the 97th General Assembly and Senate Resolution 821 adopted by the Senate of the 97th General Assembly that are reflected in paragraph (3) of this subsection. In addition, Public Act 98-15 preempts and supersedes any final Commission orders entered in Docket Nos. 11-0721, 12-0001, 12-0293, and 12-0321 to the extent inconsistent with the amendatory language added to subsections (c) and (d).

(1) No earlier than 5 business days after May 22, 2013 (the effective date of Public Act 98-15), each participating utility shall file any tariff changes necessary to implement the amendatory language set forth in subsections (c) and (d) of this Section by Public Act 98-15 and a revised revenue requirement under the participating utility's performance-based formula rate. The Commission shall enter a final order approving such tariff changes and revised revenue requirement within 21 days after the participating utility's filing.

(2) Notwithstanding anything that may be to the contrary, a participating utility may file a tariff to retroactively recover its previously unrecovered actual costs of delivery service that are no longer subject to recovery through a reconciliation adjustment under subsection (d) of this Section. This retroactive recovery shall include any derivative adjustments resulting from the changes to subsections (c) and (d) of this Section by Public Act 98-15. Such tariff shall allow the utility to assess, on current customer bills over a period of 12 monthly billing periods, a charge or credit related to those unrecovered costs with interest at the utility's weighted average cost of capital during the period in which those costs were unrecovered. A participating utility may file a tariff that implements a retroactive charge or credit as described in this paragraph for amounts not otherwise included in the tariff filing provided for in paragraph (1) of this subsection (k). The Commission shall enter a final order approving such tariff within 21 days after the participating utility's filing.

(3) The tariff changes described in paragraphs (1) and (2) of this subsection (k) shall relate only to, and be consistent with, the following provisions of Public Act 98-15: paragraph (2) of subsection (c) regarding year-end capital structure, subparagraph (D) of paragraph (4) of subsection (c) regarding pension assets, and subsection (d) regarding the reconciliation components related to year-end rate base and interest calculated at a rate equal to the utility's weighted average cost of capital.

(4) Nothing in this subsection is intended to effect a dismissal of or otherwise affect an appeal from any final Commission orders entered in Docket Nos. 11-0721, 12-0001, 12-0293, and 12-0321 other than to the extent of the amendatory language contained in subsections (c) and (d) of this Section of Public Act 98-15.

(l) Each participating utility shall be deemed to have been in full compliance with all requirements of subsection (b) of this Section, subsection (c) of this Section, Section 16-108.6 of this Act, and all Commission orders entered pursuant to Sections 16-108.5 and 16-108.6 of this Act, up to and including May 22, 2013 (the effective date of Public Act 98-15). The Commission shall not undertake any investigation of such compliance and no penalty shall be assessed or adverse action taken against a participating utility for noncompliance with Commission orders associated with subsection (b) of this Section, subsection (c) of this Section, and Section 16-108.6 of this Act prior to such date. Each participating utility other than a combination utility shall be permitted, without penalty, a period of 12 months after such effective date to take actions required to ensure its infrastructure investment program is in compliance with subsection (b) of this Section and with Section 16-108.6 of this Act. Provided further, the following subparagraphs shall apply to a participating utility other than a combination utility:

(A) if the Commission has initiated a proceeding pursuant to subsection (e) of Section 16-108.6 of this Act that is pending as of May 22, 2013 (the effective date of Public Act 98-15), then the order entered in such proceeding shall, after notice and hearing, accelerate the commencement of the meter deployment schedule approved in the final Commission order on rehearing entered in Docket No. 12-0298;

(B) if the Commission has entered an order pursuant to subsection (e) of Section 16-108.6 of this Act prior to May 22, 2013 (the effective date of Public Act 98-15) that does not accelerate the commencement of the meter deployment schedule approved in the final Commission order on rehearing entered in Docket No. 12-0298, then the utility shall file with the Commission, within 45 days after such effective date, a plan for accelerating the commencement of the utility's meter deployment schedule approved in the final Commission order on rehearing entered in Docket No. 12-0298; the Commission shall reopen the proceeding in which it entered its order pursuant to subsection (e) of Section 16-108.6 of this Act and shall, after notice and hearing, enter an amendatory order that approves or approves as modified such accelerated plan within 90 days after the utility's filing; or

(C) if the Commission has not initiated a proceeding pursuant to subsection (e) of Section 16-108.6 of this Act prior to May 22, 2013 (the effective date of Public Act 98-15), then the utility shall file with the Commission, within 45 days after such effective date, a plan for accelerating the commencement of the utility's meter deployment schedule approved in the final Commission order on rehearing entered in Docket No. 12-0298 and the Commission shall, after notice and hearing, approve or approve as modified such plan within 90 days after the utility's filing.

Any schedule for meter deployment approved by the Commission pursuant to this subsection (l) shall take into consideration procurement times for meters and other equipment and operational issues. Nothing in Public Act 98-15 shall shorten or extend the end dates for the 5-year or 10-year periods set forth in subsection (b) of this Section or Section 16-108.6 of this Act. Nothing in this subsection is intended to address whether a participating utility has, or has not, satisfied any or all of the metrics and performance goals established pursuant to subsection (f) of this Section.

(m) The provisions of Public Act 98-15 are severable under Section 1.31 of the Statute on Statutes.

(Source: P.A. 99-143, eff. 7-27-15; 99-642, eff. 7-28-16; 99-906, eff. 6-1-17; 100-840, eff. 8-13-18.)

(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 clean 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 clean energy policies.

(3) A distribution system planning process can minimize distribution system costs to consumers while advancing other Illinois clean 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 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 and 16-107.6.

(c) An electric utility serving more than 100,000 customers on January 1, 2009 shall prepare a distribution system investment plan that meets the requirements of this Section, and shall file said plan with the Commission no later than July 1, 2022.

(d) The distribution system investment plan shall be designed to:

(1) optimize 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 improvements;

(7) to the maximum extent possible, achieve or support the achievement of reduction of greenhouse gas emissions; and

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

(e) The distribution investment system plan shall provide, at a minimum, 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) a summary of the meetings with stakeholders conducted prior to filing of the plan with the Commission. Such meetings shall number at least two, and should be held at times and in places to maximize, to the extent possible, stakeholder and public participation, including representatives of environmental justice and low-income communities. The summary shall include at a minimum, the participants in meetings, the material covered in the meetings, and a summary of questions asked and answers provided;

(C) a description of other internal planning processes; and

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

(2) Baseline distribution system data. A discussion detailing the current operating conditions for the distribution 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 line 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 maximum desired peak demand given contingency or redundancies desired); maximum historic peak demand, including specific days and hours of the days 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; including information on percentage of the system with each level of visibility (such as maximum and minimum, daytime and nighttime, monthly and daily reads, automated or 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 (including, but not limited to, opportunities and constraints related to interoperability).

(3) Financial data:

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

(B) projected distribution system spending for ten years into the future for the categories listed in paragraph (1) of this subsection (e), itemizing any non-traditional distribution projects, including: planned distribution capital projects, cost drivers for the project, and summary of anticipated changes in historic spending; and 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 resources deployment.

(A) Discussion of how the impacts of the utility's energy efficiency programs are factored into load forecasts at the substation or circuit level.

(B) Discussion of how other distributed energy resources are factored into load forecasts and any expected changes in load forecasting methodology.

(C) Total costs spent on distributed energy resource generation installation in the prior year.

(D) Total charges to installers for distributed energy resource generation installation in the prior year.

(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.

(H) Information on geographic areas of existing or forecast low, moderate and high distributed energy resource penetration.

(I) List of geographic areas with existing or forecast abnormal voltage or frequency issues that may benefit from advanced inverter technology.

(5) Hosting capacity and interconnection requirements. A hosting capacity analysis, made available to the public on the Illinois Commerce Commission's website with mapping and GIS capability, 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 resources 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 the impact of utility investments over the next five years; and

(C) a narrative describing how the hosting capacity analysis advances customer-sited distributed energy resources (including PV and electric storage systems), and how the identification of interconnection points on the distribution system will support the continued development of distributed generation resources.

(6) Scenario analysis and forecasting. The plan shall include load forecasts over the next ten 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 of 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 and 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 necessary to accommodate the specified levels of distributed energy resource adoption, including an analysis of the sufficiency of existing tools. 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 system upgrades 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, and a discussion of potential impacts from the related FERC Docket No. RM18-9-000.

(E) Discussion of how the distribution system planning is consistent 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 ten years that are anticipated to have a total cost of greater than $5,000,000. For these projects, provide an analysis of the viability, price, and long-term value of non-wires alternatives (including increased local energy efficiency beyond what will occur through system-wide programs), demand response, distributed generation, and storage. Such analysis 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 benefit from non-traditional solutions (for example, load relief or reliability).

(C) Timelines needed to consider alternatives to any project types that would benefit from non-traditional solutions (including time for any requests for proposals, 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.

(9) Cybersecurity. The Plan shall include a high-level summary of the utility's planning process for addressing cyber and physical security risks. As part of the summary, the qualifying retail utility is not required to report any confidential, proprietary or other information in the plan that could in any way compromise or decrease the utility's ability to prevent, mitigate, or recover from potential system disruptions caused by physical events or cyberattacks.

(f) Within 45 days after the filing of the distribution system investment plan, the Commission shall, with reasonable notice, open an investigation to consider whether the plan meets the objectives of and contains the information required by this Section. The Commission shall approve, approve with modifications, or reject the plan within 270 days from the date of filing. The Commission may approve the plan if it finds that the plan will achieve the goals described in subsection (d) of this Section and contains the information described in subsection (e) of this Section. Proceedings under this Section shall proceed according to the rules provided by Article IX of this Act. Information contained in the approved plan shall be considered part of the record in any Commission proceeding under Section 16-107.6 of this Act, provided that a final order has not been entered prior to the initial filing date referenced in subsection (c).

(g) Plan updates: the utility shall file an update to the plan on June 1, 2024, 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 report, the Commission shall, upon its own initiative, open 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, the Commission shall issue an order requiring the utility to devise a corrective action plan, subject to Commission approval, to bring the plan into compliance with the goals of this Section. The Commission's order shall be entered within 270 days after the utility files its annual report.

(h) The plan is designed to provide information to the Commission, stakeholders and the public concerning the distribution grid, and should provide a guide for future utility investment in the distribution grid. Therefore, the contents of a plan filed under this Section shall be available for evidence in Commission proceedings. However, omission from an approved plan shall not render any future utility expenditure to be considered unreasonable or imprudent. The Commission may, upon sufficient evidence, allow expenditures that were not part of any particular distribution plan.

(220 ILCS 5/16-108.18 new)

Sec. 16-108.18. Independent audit.

(a) Prior to the filing of the initial distribution system investment plan described in Section 16-108.17, an independent audit of the current state of the grid, and of the expenditures made since 2011, will need to be made.

The General Assembly makes the following findings:

(1) Pursuant to the Energy Infrastructure Modernization Act and subsequent clarifying legislation, utilities in this State that serve over 100,000 customers have made substantial investments to the grid and to advanced metering infrastructure.

(2) It is necessary to understand the benefits to the grid and to customers from these expenditures.

(3) Before a distribution system investment plan is filed under Section 16-108.17, it is necessary to understand the current condition of the distribution grid.

(4) It is also necessary for utilities, the Commission, and stakeholders to have an independent set of data to establish the baseline for future distribution grid spending.

(5) The Commission has authority and jurisdiction for the requirements of this Section under Section 8-102.

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

(c) Within 30 days after the adoption of this Act, the Commission shall order an audit of each public utility serving over 100,000 customers in the State examining the following:

(1) An assessment of the distribution grid, as described in paragraph (3) of subsection (a), with the exception that the data referenced in paragraph (3) of subsection (a) shall be for the preceding 10 years. The Commission shall have the authority to require additional items which it deems necessary.

(2) An analysis of the utility's capital projects in the preceding ten years, with respect to the value of such spending for grid optimization and customer value, such projects to include advanced meter installation and related programs.

(3) An analysis of the utility management of the distribution grid, including initiatives to optimize reliability and efficiency of the grid, other than through capital spending.

(4) An analysis of the utility's existing policies, including their performance in implementation, concerning the planning and execution of grid projects.

(5) Creation of a data baseline to inform the beginning of the distribution planning process described in Section 16-108.17.

(6) Identification of any deficiencies in data which may impact the distribution planning process.

(d) The audit described above should be reflected in a report delivered to the Commission, describing the information specified above, and any recommendations for the distribution planning process. Such report is to be delivered no later than 180 days after the Commission Order. It is understood that any public report may not contain items that are confidential or proprietary.

(e) The costs of this audit shall be borne by the respective utilities, such costs not to exceed $250,000 for each utility. Such costs are not deemed to be a recoverable expense.

(f) The Commission shall have the authority to retain the services of the auditor to assist with the distribution planning process, as well as in docketed proceedings. Such expenses for these activities are to be compensated by the Commission.

(220 ILCS 5/16-108.19 new)

Sec. 16-108.19. Division of Integrated Distribution Planning.

(a) The Commission shall establish the Division of Integrated Distribution Planning within the Bureau of Public Utilities. The Division shall be staffed by no less than 13 professionals, including 4 engineers, 1 rate analyst, 2 accountants, 1 policy analyst, 1 utility research and analysis analyst, 1 cybersecurity analyst, 1 information technology specialist, and 2 lawyers to review and evaluate distribution system investment plans, updates to distribution system investment plans, audits, and other duties as assigned by the Chief of the Public Utilities Bureau.

(b) The Division of Integrated Distribution Planning shall be established by July 1, 2022.

(220 ILCS 5/16-108.20 new)

Sec. 16-108.20. Performance incentive mechanisms.

(a) Findings and Purpose. The General Assembly finds:

(1) That improving the alignment of utility customer and company interests is critical to ensuring the expected rapid growth of distributed energy resources, electric vehicles, and other new technologies that substantially change the makeup of the grid is done in efficiently and transparently.

(2) There is urgency around addressing increasing threats from climate change and assisting communities that have borne disproportionate impacts from climate change, including air pollution, greenhouse gas emissions, and energy burdens. Addressing this problem requires changes to the business model under which utilities in Illinois have traditionally functioned.

(3) Providing targeted incentives to support change through a new performance-based structure to enhance ratemaking is intended to enable alignment of utility, customer, community, and environmental goals.

(4) Though Illinois has taken some measures to move utilities to performance-based ratemaking through the establishment of performance incentives and a performance-based formula rate under the Energy Infrastructure Modernization Act, these measures have not been transformative in urgently moving electric utilities toward the State's ambitious clean energy policy goals: protecting a healthy environment and climate, improving public health, and creating quality jobs and statewide economic opportunities, including wealth building, especially in economically disadvantaged communities and communities of color.

(5) These measures were not developed through a process which sought to understand first what needed to be measured and then worked to ensure that the measures and penalties associated with the measures would help drive the sought-after behavior by the utilities.

(6) These measures have resulted in excess utility spending and profits without meaningful improvements in customer experience, rates, or equity.

(7) Discussions of performance incentive mechanisms must always take into account the affordability of customer rates and bills.

(8) The General Assembly therefore directs the Illinois Commerce Commission to develop performance incentive mechanisms for electric utilities with more than 300,000 customers to further specified goals and objectives.

(b) Definitions. As used in this Section:

"Commission" means the Illinois Commerce Commission.

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

"Distributed energy resources" or "DER" means a wide range of technologies that are located on the customer side of the customer's electric meter and can provide value to the distribution system, including, but not limited to, distributed generation, energy storage, electric vehicles, and demand response technologies.

"Economically disadvantaged communities" means areas of one or more census tracts where average household income does not exceed 80% of area median income.

"Environmental justice communities" means the definition of that term as used and as may be updated in the Long-Term Renewable Resources Procurement Plan by the Illinois Power Agency and its Program Administrator in the Illinois Solar for All Program.

"Performance incentive mechanism" or "PIM" means an instrument by which utility performance is incentivized, which could include a monetary reward or penalty.

"Performance Metric" means a manner of measurement for a particular utility activity.

(c) Objectives. Performance incentive mechanisms should be designed to accomplish the following objectives:

(1) maintain and improve service reliability and safety;

(2) enable least cost interconnection to enable decarbonize utility systems at a pace that meets or exceeds the State's climate goals;

(3) choose the most cost-effective expenditures for assets or services, whether self-supplied by the utility or through third-party contracting, to deliver high-quality service to customers at least cost and eliminate utility preference for rate base investments that increase profits;

(4) maintain the affordability of electric delivery and supply services;

(5) achieve high-quality customer service, affordable and a variety of rate options, including demand response, time of use rates for delivery and supply, real-time pricing rates for supply, comprehensive and predictable net metering, utilize the benefits of grid modernization and clean energy for ratepayers;

(6) address the particular burdens faced by consumers in environmental justice and economically disadvantaged communities, including shareholder, consumer, and publicly funded bill payment assistance and credit and collection policies; and

(7) maintain and grow a diverse workforce, diverse supplier procurement base and, for relevant programs, diverse approved-vendor pools.

(d) Performance incentive mechanisms.

(1) The Commission may establish performance incentive mechanisms in order to better tie utility revenues to performance and customer benefits, accelerate progress on Illinois energy and other goals, and hold utilities publicly accountable. The Commission shall develop metrics, which are observable and measurable indicators of system or utility performance, in order to create performance incentive mechanisms independent of its rate making function. Specifically, the Commission may establish tracking metrics, to be used for measuring and reporting utility performance.

(A) Tracking metrics, if adopted, shall entail a description of the metric, a calculation method, a data collection method, and measure achievement of at least one of the outcomes set forth in paragraph (2) of this subsection.

(B) The Commission may adopt tracking metrics that are supported by stakeholder consensus.

(C) The Commission shall first identify the tracking metrics that are already in place and then make a determination of their effectiveness with respect to the program goals described in this section.

(D) The tracking metric shall include a description of the metric, a calculation method, a data collection method, annual binding performance targets, and may include monetary incentives (rewards or penalties or both, depending on the metric) for utilities' achievement of or failure to achieve their performance targets. For metrics where progressive improvement is desirable, performance targets shall increase annually and shall require utilities to perform beyond business as usual, as determined by baseline tracking data and high-confidence projections. Increases to a target shall be considered in light of other metrics, cost-effectiveness, and other factors the Commission deems appropriate.

(E) Metrics shall include one year of tracking data collected in a consistent manner, verifiable by an independent evaluator in order to establish a baseline and measure outcomes and actual results against projections where possible.

(2) Outcomes of Metrics. The Commission may approve tracking and performance metrics that encourage cost-effective, equitable utility achievement of the following outcomes:

(A) Affordability. Achieve affordable customer energy costs and utility bills, with particular emphasis on keeping lower-income households' bills within a manageable portion of their income.

(B) Pollution Reduction. Minimize emissions of greenhouse gases and pollutants that harm human health, particularly in environmental justice and economically disadvantaged communities, through minimizing total emissions, including by accelerating electrification of transportation, buildings and industries where such electrification results in net reductions, across all fuels and over the life of electrification measures, of greenhouse gases and other pollutants, taking into consideration the fuel mix used to produce electricity at the relevant hour and the effect of accelerating electrification on electricity supply prices and peak demand.

(C) Flexibility. Enhance the grid's ability to incorporate increased deployment of nondispatchable resources; improve the predictability and cost-effectiveness of interconnection processes; improve load balancing; and offer a variety of rate plans to suit consumer consumption patterns to lower consumer bills for electricity delivery and supply.

(D) Reliability. Meet high standards of overall and locational reliability, including the standards and processes described in Section 16-125 of this Act.

(E) Customer Experience. Cost-effectively deliver customer service quality, customer engagement, and customer access to utility system information according to consumer demand and interest.

(F) Equity. Maximize and prioritize the low-income assistance and allocation of grid planning benefits to environmental justice and economically disadvantaged customers and communities. Sustain a diverse workforce, supplier procurement base and, for relevant programs, approved vendor pools.

(G) Cost-effectiveness. Ensure rates reflect cost savings attributable to grid modernization and integration of distributed energy resources and identify circumstances that allow the utility to reduce expenditures by deferring or forgoing traditional grid investments that would otherwise be required and increase customer charges.

It is the intent of the General Assembly that these outcomes shall guide the development of metrics even as the grid, along with its associated technologies and policies, evolves. It is also the intent of the General Assembly that the limitation of total costs to customers and the promotion of ethical and transparent practices by utilities, as well as the role that flexible load and distributed energy resources can play in advancing the outcomes, are objectives in the establishment of metrics.

(3) Performance incentives. The Commission shall determine whether and to what extent each performance metric shall offer a reward, penalty, or both to a utility. For metrics where a reward is offered, and that reward is a cash payment, the reward shall be calculated as a percentage of net benefits from the outcome, net of costs to customers.

(A) The Commission shall develop a methodology to calculate net benefits that includes the cost to consumers, societal costs, and benefits. In determining the appropriate level of a reward or penalty, the Commission shall consider: the extent to which the result is included in the utility's obligation to serve, whether the amount is likely to encourage the utility to achieve the performance target in the least cost manner; the value of benefits to customers, the grid, and the environment from achievement of the performance target, including in particular benefits to environmental justice and economically disadvantaged communities; the effect on customer bill affordability; the effect on the utility's revenue requirement; the effect on whether the utility's earnings remain just and reasonable and not in excess of a reasonable return on equity; and other such factors that the Commission deems appropriate.

(B) The consideration of these factors shall result in an incentive level that ensures benefits exceed costs for customers. In determining the specific rewards or penalties, the Commission shall give weight to the following goals: (i) affordability, (ii) cost-effectiveness, (iii) pollution reduction, (iv) rate flexibility, (v) customer experience, (vi) reliability, and (vii) equity.

(C) It is the intent of the General Assembly that over time the utility's return on equity remains just and reasonable and that the return on equity embedded in base rates and surcharges shall be progressively reduced while the opportunity to grow earnings as a result of achieving performance targets shall be progressively increased as the Commission establishes new performance metrics.

(e) Initial Metrics.

(1) The Commission shall initiate a 6-month workshop process no later than March 1, 2022 for the purpose of informing the enactment of metrics. The workshop shall be facilitated by Staff of the Illinois Commerce Commission and shall be organized and facilitated in a manner that encourages representation from diverse stakeholders, ensuring equitable opportunities for participation, without requiring formal intervention or representation by an attorney. Following the workshop, the Commission shall establish initial tracking and performance metrics in a docketed proceeding that shall be filed by the electric utility by September 2, 2022. The proceeding shall conclude, and the Commission shall issue an order in the matter, no later than December 1, 2023.

(2) The Commission shall approve metrics consistent with this Section, and it shall establish calculations and goals for the tracking metrics and calculations, targets, and incentives for the tracking metrics set forth in this Section. Initial Performance Metrics shall include at a minimum, but not limited to, the following: (A) system Average Interruption Frequency Index; (B) customer Average Interruption Duration Index; and (C) peak load reductions enabled by demand response programs.

(f) Future Metrics. The Commission shall establish new tracking and performance metrics in future Annual Performance Evaluation proceedings to further measure achievement of the outcomes, goals, and requirements of this Section. The Commission shall also evaluate metrics that were established in prior Annual Performance Evaluation proceedings under the procedures set forth in subsection (g) to determine if adjustments are required to improve the likelihood of the outcomes described in paragraph (2) of subsection (d). For metrics that were established in prior Annual Performance Evaluation proceedings and that the Commission elects to continue, the design of these metrics, including the goals of tracking metrics and the targets and incentive levels and structures of performance metrics, may be adjusted pursuant to the requirements in this Section. The Commission may also phase out tracking and performance metrics that were established in prior Annual Performance Evaluation proceedings if these metrics no longer meet the requirements of this Section or if they are rendered obsolete by the changing needs and technology of an evolving grid. Additionally, performance metrics that no longer require an incentive to create improved utility performance may become tracking metrics. In service of the outcomes set forth in paragraph (2) of subsection (d), it is the intent of the General Assembly that the Commission in future Annual Performance Evaluation proceedings establish the tracking metrics and performance metrics set forth in subparagraph (A) and subparagraph (B) of paragraph (3) of subsection (d) of this Section when these metrics would be compliant with the requirements set forth in this Section.

(g) Annual Performance Evaluation. On June 1 of each year following the order establishing the performance metrics, the Commission shall open an Annual Performance Evaluation proceeding to evaluate the utilities' performance on their metric targets during the delivery year just completed and accordingly determine rewards or penalties or both to be reflected in rates in the following calendar year.

(1) Utility Reporting. On April 1 of each year, prior to the Annual Performance Evaluation proceeding, each participating utility shall file a Performance Evaluation Report with the Commission that includes a description of and all data supporting how the participating utility performed under each tracking and performance metric and an identification of any extraordinary events that adversely impacted the utility's performance. The Performance Evaluation Report shall be verified by an independent evaluator as set out in paragraph (3) of this subsection (g) and shall include both a report made to the Commission and a short, public-facing scorecard that makes this information publicly accessible and easily understandable. The Commission shall post each scorecard upon receipt on the Commission's web page in an easily accessible location. The format of the report and the scorecard shall be developed by the Commission, be consistent across utilities, and shall include, but not be limited to:

(A) a list of metrics to which the utility is subject;

(B) the previous delivery year's calculation methods and performance on metrics if applicable;

(C) the current delivery year's calculation methods and a detailed description of the effect of any differences;

(D) the current-year goals for tracking metrics and current-year targets for performance metrics;

(E) the current year's performance on metrics targets; and

(F) a summary of the investments and programs undertaken in order to achieve those metrics targets; and within 30 days after the Commission's Order in the utility's Annual Performance Evaluation and Adjustment filing, the utility shall update the public scorecard with any changes required by the Commission and the revised scorecard shall be posted on the Commission's website.

(2) Public Workshops. Upon the filing of each Performance Evaluation Report, but no later than May 7 each year, the Commission shall initiate a four-month workshop process. The workshops shall be facilitated by Staff of the Illinois Commerce Commission and shall be organized and facilitated in a manner that encourages representation from diverse stakeholders, ensuring equitable opportunities for participation, without requiring formal intervention or representation by an attorney. During these workshops, each electric utility shall publicly present its performance on tracking and performance metrics following the requirements set forth in paragraph (1) of this subsection (g). The electric utility shall also explain how it has holistically considered the plans, programs, tariffs and policies in order to achieve its metric targets. Members of the public shall have the opportunity to request additional relevant information and submit comment and feedback to the Commission. A summary of that feedback shall be provided in an exhibit submitted by Staff of the Illinois Commerce Commission in the Annual Performance Evaluation.

(3) Independent Evaluation. The Commission shall provide for an annual independent evaluation of the electric utility's performance on metrics, and the cost of the independent evaluation shall be treated as a cost of service. The independent evaluator shall review the utility's assumptions, baselines, targets, calculation methodologies, and other relevant information, especially ensuring that the utility's data for establishing baselines matches actual performance, and shall provide a Report to the Commission no later than May 1 describing the results. The independent evaluator shall present this Report as evidence as a nonparty participant in each Annual Performance Evaluation. The independent evaluator shall be hired by the Commission through a competitive bidding process. The Commission shall post the Report on its website no fewer than 5 business days before the first Public Workshop described in subsection (2) of this subsection (g), and shall consider the Report of the independent evaluator in determining the utility's achievement of performance targets. Discrepancies between the utility's assumptions, baselines, targets, or calculations and those of the independent evaluator shall be closely scrutinized by the Commission and may be the bases for rejecting the utility's conclusion about its performance. If the Commission finds that the utility's reported data for any metric or metrics significantly deviates from the data reported by the independent evaluator, then the Commission shall order the utility to revise its data collection and calculation process within 60 days, with specifications where appropriate, and no performance incentive shall be allowed.

(4) Performance Adjustment. The Commission shall, after notice and hearing in the Annual Performance Evaluation proceeding, enter an order approving the utility's performance adjustment based on its achievement of or failure to achieve its performance targets no later than December 31 each year. The Commission-approved penalties or rewards shall be itemized and the annual cost to consumers or to the utility shall be reported. The penalties or rewards shall be collected or credited beginning with the next calendar year.

(5) Revisions to Metrics. Tracking and performance metrics, along with their associated goals, targets, and incentives, may be changed as part of the Annual Performance Evaluation. In addition, the Commission may open a separate investigation into whether the metric should be continued, modified, or discontinued, and whether the methodology, including assumptions and calculations used to measure or quantify progress toward goals and targets in the Annual Performance Evaluation should be continued, modified, or discontinued, at the request of an intervening party.

(220 ILCS 5/16-108.21 new)

Sec. 16-108.21. Energy storage program.

(a) Findings. The Illinois General Assembly hereby finds and declares that:

(1) Energy storage systems provide opportunities to:

(A) reduce costs to ratepayers directly or indirectly by avoiding or deferring the need for investment in new generation and for upgrades to systems for the transmission and distribution of electricity;

(B) reduce the use of fossil fuels for meeting demand during peak load periods;

(C) provide ancillary services such as frequency response, load following, and voltage support;

(D) assist electric utilities with integrating sources of renewable energy into the grid for the transmission and distribution of electricity, and with maintaining grid stability;

(E) support diversification of energy resources;

(F) enhance the resilience and reliability of the electric grid; and

(G) reduce greenhouse gas emissions and other air pollutants resulting from power generation, thereby minimizing public health impacts that result from power generation.

(2) There are significant barriers to obtaining the benefits of energy storage systems, including inadequate valuation of the services that energy storage can provide to the grid and the public.

(3) It is in the public interest to:

(A) develop a robust competitive market for existing and new providers of energy storage systems in order to leverage Illinois' position as a leader in advanced energy and to capture the potential for economic development;

(B) implement targets and programs to achieve deployment of energy storage systems; and

(C) modernize distributed energy resource programs and interconnection standards to lower costs and efficiently deploy energy storage systems in order to increase economic development and job creation within the State's clean energy economy.

(b) Definitions. As used in this Section:

"Deployment" means the installation of energy storage systems through a variety of mechanisms, including utility procurement, customer installation, or other processes.

"Electric utility" has the meaning as provided in Section 16-102.

"Energy storage peak standard" means a percentage of annual retail electricity sales during peak hours that an electric utility must derive from electricity discharged from eligible energy storage systems.

"Energy storage system" means a technology that is capable of absorbing zero-carbon energy, storing it for a period of time, and redelivering that energy after it has been stored in order to provide direct or indirect benefits to the broader electricity system. "Energy storage system" includes, but is not limited to, electrochemical, thermal, and electromechanical technologies.

"Non-wires alternatives solicitation" means a utility solicitation for third-party-owned or utility-owned distributed energy resources that uses non-traditional solutions to defer or replace planned investment on the distribution or transmission system.

"Total peak demand" means the highest hourly electricity demand for an electric utility in a given year, measured in megawatts, from all of the electric utility's customers of distribution service.

(c) Energy storage proceeding.

(1) The Commission, in consultation with the Illinois Power Agency, shall initiate a proceeding to examine specific programs, mechanisms, and policies that could support the deployment of energy storage systems. The Illinois Commerce Commission shall engage a broad group of Illinois stakeholders, including electric utilities, the energy storage industry, the renewable energy industry, and others to inform the proceeding.

(2) The proceeding must, at minimum:

(A) Develop a framework to identify and measure the potential costs, benefits, that deployment of energy storage could produce, as well as barriers to realizing such benefits, including, but not limited to:

(i) avoided cost and deferred investments in generation, transmission, and distribution facilities;

(ii) reduced ancillary services costs;

(iii) reduced transmission and distribution congestion;

(iv) lower peak power costs and reduced capacity costs;

(v) reduced costs for emergency power supplies during outages;

(vi) reduced curtailment of renewable energy generators;

(vii) reduced greenhouse gas emissions and other criteria air pollutants;

(viii) increased grid hosting capacity of renewable energy generators that produce energy on an intermittent basis;

(ix) increased reliability and resilience of the electric grid;

(x) increased resource diversification; and

(xi) increased economic development.

(B) Analyze and estimate:

(i) the impact on the system's ability to integrate renewable resources;

(ii) the benefits of addition of storage at specific locations, such as at existing peaking units or locations on the grid close to large load centers;

(iii) the impact on grid reliability and power quality; and

(iv) the effect on retail electric rates and supply rates over the useful life of a given energy storage system.

(C) Evaluate and identify cost-effective policies and programs to support the deployment of energy storage systems, including, but not limited to:

(i) incentive programs;

(ii) energy storage peak standards;

(iii) non-wires alternative solicitation;

(iv) peak demand reduction programs for behind-the-meter storage for all customer classes;

(v) value of distributed energy resources programs;

(vi) tax incentives;

(vii) time-varying rates;

(viii) updating of interconnection processes and metering standards;and

(ix) procurement by the Illinois Power Agency of energy storage resources.

(3) The Commission shall, no later than May 31, 2022, submit to the General Assembly and the Governor any recommendations for additional legislative, regulatory or executive actions based on the findings of the proceeding.

(4) At the conclusion of the proceeding required under subsection (c), the Commission shall consider and recommend to the Governor and General Assembly energy storage deployment targets, if any, for each electric utility that serves more than 200,000 customers to be achieved by December 31, 2032, including recommended interim targets.

(5) In setting recommendations for energy storage deployment targets, the Commission shall:

(A) take into account the costs and benefits of procuring energy storage according to the framework developed in the proceeding under subsection (c); and

(B) consider establishing specific sub-categories of deployment of systems by point of interconnection or application in addition to any requirement for behind the meter storage.

(220 ILCS 5/16-108.22 new)

Sec. 16-108.22. Nuclear plant assistance.

(a) The General Assembly finds:

(1)It is in the interest of the State to support large employers who bring needed jobs, tax base and ancillary benefits to our State.

(2)The nuclear power generation facilities located in Illinois provide the benefits listed in subsection (a) of Section 8-201.12, as well as provide energy with zero carbon emissions.

(3)The clean energy attributes of the nuclear generation facilities support the State in its efforts to achieve 100% clean energy.

(4)The State currently invests in various forms of clean energy including, but not limited to, renewable energy, energy efficiency, low-emission vehicles, among others.

In addition to the economic benefits described in subsection (a) of Section 8-201.12, nuclear plants provide clean energy, which helps to avoid many health related negative impacts.

(b) Beginning with calendar year 2021, and concluding with calendar year 2025, the State shall incentivize the retention of workers at the Byron and Dresden nuclear generation facilities by compensating their parent corporation as follows:

(1) For Byron, an amount equal to the sum of $1 per megawatt hour of nameplate capacity for each of the 5 years as set forth in this subsection (b).

(2) For Dresden, an amount equal to the sum of $3.50 per megawatt hour of nameplate capacity for each of the 5 years as set forth in this subsection (b).

(3) Initial payments shall occur on or before September 1, 2021, and in each subsequent year, on or before July 1.

(4) Payment in any given calendar year is conditioned upon a determination of need from an independent audit of the parent corporation, as set forth in Section 16-108.18.

(c) If the result of the independent audit shows that the operation of the nuclear facility in question is not in need of the level of assistance set forth in paragraphs (1) and (2) of subsection (b) to have a positive net present value, then the amount of assistance shall be reduced to the level of assistance necessary.

(d) In the event of reduction in assistance in any given year, the difference in the actual amount of funds provided and the funds contemplated in paragraphs (1) and (2) of subsection (b) shall be deposited in the Greenhouse Gas Emissions Reinvestment Fund, as described in paragraph (4) of subsection (c) of Section 9.18 of the Illinois Environmental Protection Act.

(e) In exchange for acceptance of the assistance described in this Section, the owner of the nuclear generation facilities shall agree to keep the plants in operation through the period ending December 31, 2025.

(f) If the owner of a nuclear generation facility that has received assistance under this chapter retires the plant in violation of subsection (e), the owner shall reimburse the State for any funds received up to the date of retirement, unless the Commission has determined that the owner of the nuclear generation facility made a good faith effort to sell the facility to another entity prior to its retirement and that the owner did not refuse a reasonable offer to purchase the facility or the commission determines that, if a reasonable offer was received, the sale was not completed for a reason beyond the reasonable control of the public utility.

(g) In determining whether the nuclear generation facility owner made a good faith effort to sell the facility under this Section the Commission shall consider:

(1) whether the owner provided sufficient time prior to the facility's retirement for potential purchasers to evaluate purchasing the facility;

(2) whether the owner used reasonable efforts to make potential purchasers aware of the opportunity to purchase the facility;

(3) whether the owner reasonably evaluated any offers received for the purchase of the facility; and

(4) any other factor deemed appropriate by the Commission.

(h) In determining whether an offer to purchase a nuclear generation facility under this Section was reasonable the Commission shall consider whether accepting the offer to purchase the facility would have been in the public interest.

(i) The assistance described in this Section shall be provided to subsequent owners of the facilities, subject to the same audit requirements as described in paragraph (4) of subsection (g).

(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. 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 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, including but not limited to monthly 5 x 16 peak period block energy, monthly off-peak wrap energy, monthly 7 x 24 energy, annual 5 x 16 energy, annual off-peak wrap energy, annual 7 x 24 energy, monthly capacity, annual capacity, peak load capacity obligations, capacity purchase plan, and ancillary services;

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

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

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

(5) 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. Any disputes regarding implementation of the programs authorized in the Plan shall be resolved in an expedited manner 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.

(r) For the procurement of standard wholesale products, 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. For procurements conducted to meet the requirements of Section 1-56(b) or Section 1-75(c) of the Illinois Power Agency Act governed by the provisions of this Section, the address and nameplate capacity of the new renewable energy generating facility proposed by a winning bidder shall also be made available to the public at the time of Commission approval of a procurement event, along with the business address and contact information for any winning bidder. An estimate or approximation of the nameplate capacity of the new renewable energy generating facility may be disclosed if necessary to protect the confidentiality of individual bid prices.

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.

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 5/16-111.8)

Sec. 16-111.8. Automatic adjustment clause tariff; uncollectibles.

(a) An electric utility shall be permitted, at its election, to recover through an automatic adjustment clause tariff the incremental difference between its actual uncollectible amount as set forth in Account 904 in the utility's most recent annual FERC Form 1 and the uncollectible amount included in the utility's rates for the period reported in such annual FERC Form 1. The Commission may, in a proceeding to review a general rate case filed subsequent to the effective date of the tariff established under this Section, prospectively switch from using the actual uncollectible amount set forth in Account 904 to using net write-offs in such tariff, but only if net write-offs are also used to determine the utility's uncollectible amount in rates. In the event the Commission requires such a change, it shall be made effective at the beginning of the first full calendar year after the new rates approved in such proceeding are first placed in effect and an adjustment shall be made, if necessary, to ensure the change does not result in double-recovery or unrecovered uncollectible amounts for any year. For purposes of this Section, "uncollectible amount" means the expense set forth in Account 904 of the utility's FERC Form 1 or cost of net write-offs as appropriate. In the event the utility's rates change during the period of time reported in its most recent annual FERC Form 1, the uncollectible amount included in the utility's rates during such period of time for purposes of this Section will be a weighted average, based on revenues earned during such period by the utility under each set of rates, of the uncollectible amount included in the utility's rates at the beginning of such period and at the end of such period. This difference may either be a charge or a credit to customers depending on whether the uncollectible amount is more or less than the uncollectible amount then included in the utility's rates.

(b) The tariff may be established outside the context of a general rate case filing and shall specify the terms of any applicable audit. The Commission shall review and by order approve, or approve as modified, the proposed tariff within 180 days after the date on which it is filed. Charges and credits under the tariff shall be allocated to the appropriate customer class or classes. In addition, customers who purchase their electric supply from an alternative retail electric supplier shall not be charged by the utility for uncollectible amounts associated with electric supply provided by the utility to the utility's customers, provided that nothing in this Section is intended to affect or alter the rights and obligations imposed pursuant to Section 16-118 of this Act and any Commission order issued thereunder. Upon approval of the tariff, the utility shall, based on the 2008 FERC Form 1, apply the appropriate credit or charge based on the full year 2008 amounts for the remainder of the 2010 calendar year. Starting with the 2009 FERC Form 1 reporting period and each subsequent period, the utility shall apply the appropriate credit or charge over a 12-month period beginning with the June billing period and ending with the May billing period, with the first such billing period beginning June 2010.

(c) The approved tariff shall provide that the utility shall file a petition with the Commission annually, no later than August 31st, seeking initiation of an annual review to reconcile all amounts collected with the actual uncollectible amount in the prior period. As part of its review, the Commission shall verify that the utility collects no more and no less than its actual uncollectible amount in each applicable FERC Form 1 reporting period, and that the utility has demonstrated actions to make its rates more affordable, minimize disconnections, and preserve the availability of utility services to all customers, consistent with item (viii) of subsection (d) of Section 1-102. The Commission shall review the prudence and reasonableness of the utility's actions to pursue minimization and collection of uncollectibles and preserve the availability of utility services to all customers, which shall include, at a minimum, the 6 enumerated criteria set forth in this Section. The Commission shall determine any required adjustments and may include suggestions for prospective changes in current practices. Nothing in this Section or the implementing tariffs shall affect or alter the electric utility's existing obligation to pursue collection of uncollectibles or the electric utility's right to disconnect service. A utility that has in effect a tariff authorized by this Section shall pursue minimization of and collection of uncollectibles through the following activities, including, but not limited to:

(1) contacting the customers in an effort to obtain payment;

(2) providing delinquent customers with information about possible options, including payment plans and assistance programs, and how to reach agencies and community-based organizations that provide assistance;

(3) specific action to limit disconnections in zip code areas that would otherwise be disproportionately impacted by the utility's credit and collection policies;

(4) community outreach in areas demonstrating higher than average arrearages to help inform customers about available assistance programs;

(5) providing bill payment assistance funds in an amount that equals 50% of its total uncollectibles for calendar year 2019, the funding of which shall be recovered through the automatic adjustment clause that is the subject of this subsection;

(6) demonstrating that the bill payment assistance funds reduced the number of disconnections in the reconciliation year;

(7) the offering of a Commission-approved discount rate tariff pursuant to Section 9-241, tiered by income level, for customers whose income falls at or below 80% of area median income; and

(8) an arrearage reduction program for low income discount rate customers that eliminates customer arrearages in ratable proportion for each month that plan participants timely pay their utility bill.

(1) identifying customers with late payments;

(2) contacting the customers in an effort to obtain payment;

(3) providing delinquent customers with information about possible options, including payment plans and assistance programs;

(4) serving disconnection notices;

(5) implementing disconnections based on the level of uncollectibles; and

(6) pursuing collection activities based on the level of uncollectibles.

(d) Nothing in this Section shall be construed to require a utility to immediately disconnect service for nonpayment.

(Source: P.A. 96-33, eff. 7-10-09; 96-1000, eff. 7-2-10.)

(220 ILCS 5/16-115)

Sec. 16-115. Certification of alternative retail electric suppliers.

(a) Any alternative retail electric supplier must obtain a certificate of service authority from the Commission in accordance with this Section before serving any retail customer or other user located in this State. An alternative retail electric supplier may request, and the Commission may grant, a certificate of service authority for the entire State or for a specified geographic area of the State. A license granted pursuant to this Section is not property and the grant of a license to an entity does not create a property interest in the license.

(b) An alternative retail electric supplier seeking a certificate of service authority shall file with the Commission a verified application containing information showing that the applicant meets the requirements of this Section. The alternative retail electric supplier shall publish notice of its application in the official State newspaper within 10 days following the date of its filing. No later than 45 days after the application is properly filed with the Commission, and such notice is published, the Commission shall issue its order granting or denying the application.

(c) An application for a certificate of service authority shall identify the area or areas in which the applicant intends to offer service and the types of services it intends to offer. Applicants that seek to serve residential or small commercial retail customers within a geographic area that is smaller than an electric utility's service area shall submit evidence demonstrating that the designation of this smaller area does not violate Section 16-115A. An applicant that seeks to serve residential or small commercial retail customers may state in its application for certification any limitations that will be imposed on the number of customers or maximum load to be served.

(d) The Commission shall grant the application for a certificate of service authority if it makes the findings set forth in this subsection based on the verified application and such other information as the applicant may submit:

(1) That the applicant possesses sufficient technical, financial and managerial resources and abilities to provide the service for which it seeks a certificate of service authority. In determining the level of technical, financial and managerial resources and abilities which the applicant must demonstrate, the Commission shall consider (i) the characteristics, including the size and financial sophistication, of the customers that the applicant seeks to serve, and (ii) whether the applicant seeks to provide electric power and energy using property, plant and equipment which it owns, controls or operates;

(2) That the applicant will comply with all applicable federal, State, regional and industry rules, policies, practices and procedures for the use, operation, and maintenance of the safety, integrity and reliability, of the interconnected electric transmission system;

(3) That the applicant will only provide service to retail customers in an electric utility's service area that are eligible to take delivery services under this Act;

(4) That the applicant will comply with such informational or reporting requirements as the Commission may by rule establish and provide the information required by Section 16-112. Any data related to contracts for the purchase and sale of electric power and energy shall be made available for review by the Staff of the Commission on a confidential and proprietary basis and only to the extent and for the purposes which the Commission determines are reasonably necessary in order to carry out the purposes of this Act;

(5) That the applicant will procure renewable energy resources in accordance with Section 16-115D of this Act, and will source electricity from clean coal facilities, as defined in Section 1-10 of the Illinois Power Agency Act, in amounts at least equal to the percentages set forth in subsections (c) and (d) of Section 1-75 of the Illinois Power Agency Act. For purposes of this Section:

(i) (blank);

(ii) (blank);

(iii) the required sourcing of electricity generated by clean coal facilities, other than the initial clean coal facility, shall be limited to the amount of electricity that can be procured or sourced at a price at or below the benchmarks approved by the Commission each year in accordance with item (1) of subsection (c) and items (1) and (5) of subsection (d) of Section 1-75 of the Illinois Power Agency Act;

(iv) all alternative retail electric suppliers shall execute a sourcing agreement to source electricity from the initial clean coal facility, on the terms set forth in paragraphs (3) and (4) of subsection (d) of Section 1-75 of the Illinois Power Agency Act, except that in lieu of the requirements in subparagraphs (A)(v), (B)(i), (C)(v), and (C)(vi) of paragraph (3) of that subsection (d), the applicant shall execute one or more of the following:

(1) if the sourcing agreement is a power purchase agreement, a contract with the initial clean coal facility to purchase in each hour an amount of electricity equal to all clean coal energy made available from the initial clean coal facility during such hour, which the utilities are not required to procure under the terms of subsection (d) of Section 1-75 of the Illinois Power Agency Act, multiplied by a fraction, the numerator of which is the alternative retail electric supplier'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 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 paragraph (5) of subsection (d) of this Section and subsection (d) of Section 1-75 of the Illinois Power Agency Act plus the total sales of electricity (expressed in kilowatthours sold) by utilities outside of their service areas during such prior month, pursuant to subsection (c) of Section 16-116 of this Act; or

(2) if the sourcing agreement is a contract for differences, a contract with the initial clean coal facility in each hour with respect to an amount of electricity equal to all clean coal energy made available from the initial clean coal facility during such hour, which the utilities are not required to procure under the terms of subsection (d) of Section 1-75 of the Illinois Power Agency Act, multiplied by a fraction, the numerator of which is the alternative retail electric supplier'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 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 paragraph (5) of subsection (d) of this Section and subsection (d) of Section 1-75 of the Illinois Power Agency Act plus the total sales of electricity (expressed in kilowatthours sold) by utilities outside of their service areas during such prior month, pursuant to subsection (c) of Section 16-116 of this Act;

(v) if, in any year after the first year of commercial operation, the owner of the clean coal facility fails to demonstrate to the Commission 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 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 costs of any such offsets 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 an alternative retail electric supplier 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 that apply to the initial clean coal facility 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;

(vi) The Commission shall, after notice and hearing, revoke the certification of any alternative retail electric supplier that fails to execute a sourcing agreement with the initial clean coal facility as required by item (5) of subsection (d) of this Section. 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 item (4) of subsection (d) of Section 1-75 of the Illinois Power Agency Act, and shall be executed within 90 days after any such approval by the General Assembly. The Commission shall not accept an application for certification from an alternative retail electric supplier that has lost certification under this subsection (d), or any corporate affiliate thereof, for at least one year from the date of revocation;

(6) With respect to an applicant that seeks to serve residential or small commercial retail customers, that the area to be served by the applicant and any limitations it proposes on the number of customers or maximum amount of load to be served meet the provisions of Section 16-115A, provided, that the Commission can extend the time for considering such a certificate request by up to 90 days, and can schedule hearings on such a request;

(7) That the applicant meets the requirements of subsection (a) of Section 16-128;

(8) That the applicant discloses whether the applicant is the subject of any lawsuit filed in a court of law or formal complaint filed with a regulatory agency alleging fraud, deception, or unfair marketing practices or other similar allegations and, if the applicant is the subject of such lawsuit or formal complaint, the applicant shall identify the name, case number, and jurisdiction of each lawsuit or complaint. For the purpose of this item (8), "formal complaint" includes only those complaints that seek a binding determination from a State or federal regulatory body;

(9) That the applicant shall continue to comply with requirements for certification stated in this Section;

(10) That the applicant shall execute and maintain a license or permit bond issued by a qualifying surety or insurance company authorized to transact business in the State of Illinois in favor of the People of the State of Illinois. The amount of the bond shall equal $30,000 if the applicant seeks to serve only nonresidential retail customers with maximum electrical demands of one megawatt or more, $150,000 if the applicant seeks to serve only non-residential retail customers with annual electrical consumption greater than 15,000 kWh, or $500,000 if the applicant seeks to serve all eligible customers. Applicants shall be required to submit an additional $500,000 bond if the applicant intends to market to residential customers using in-person solicitations. The bond shall be conditioned upon the full and faithful performance of all duties and obligations of the applicant as an alternative retail electric supplier and shall be valid for a period of not less than one year. The cost of the bond shall be paid by the applicant. The applicant shall file a copy of this bond, with a notarized verification page from the issuer, as part of its application for certification under 83 Ill. Adm. Code 451; and

(11) That the applicant will comply with all other applicable laws and regulations.

(d-3) The Commission may deny with prejudice an application in which the applicant fails to provide the Commission with information sufficient for the Commission to grant the application.

(d-5) (Blank).

(e) A retail customer that owns a cogeneration or self-generation facility and that seeks certification only to provide electric power and energy from such facility to retail customers at separate locations which customers are both (i) owned by, or a subsidiary or other corporate affiliate of, such applicant and (ii) eligible for delivery services, shall be granted a certificate of service authority upon filing an application and notifying the Commission that it has entered into an agreement with the relevant electric utilities pursuant to Section 16-118. Provided, however, that if the retail customer owning such cogeneration or self-generation facility would not be charged a transition charge due to the exemption provided under subsection (f) of Section 16-108 prior to the certification, and the retail customers at separate locations are taking delivery services in conjunction with purchasing power and energy from the facility, the retail customer on whose premises the facility is located shall not thereafter be required to pay transition charges on the power and energy that such retail customer takes from the facility.

(f) The Commission shall have the authority to promulgate rules and regulations to carry out the provisions of this Section. On or before May 1, 1999, the Commission shall adopt a rule or rules applicable to the certification of those alternative retail electric suppliers that seek to serve only nonresidential retail customers with maximum electrical demands of one megawatt or more which shall provide for (i) expedited and streamlined procedures for certification of such alternative retail electric suppliers and (ii) specific criteria which, if met by any such alternative retail electric supplier, shall constitute the demonstration of technical, financial and managerial resources and abilities to provide service required by subsection (d) (1) of this Section, such as a requirement to post a bond or letter of credit, from a responsible surety or financial institution, of sufficient size for the nature and scope of the services to be provided; demonstration of adequate insurance for the scope and nature of the services to be provided; and experience in providing similar services in other jurisdictions.

(g) An alternative retail electric supplier may seek confidential treatment for the following information by filing an affidavit with the Commission so long as the affidavit meets the requirements in this subsection (g):

(1) the total annual kilowatt-hours delivered and sold by an alternative retail electric supplier to retail customers within each utility service territory and the total annual kilowatt-hours delivered and sold by an alternative retail electric supplier to retail customers in all utility service territories in the preceding calendar year as required by 83 Ill. Adm. Code 451.770;

(2) the total peak demand supplied by an alternative retail electric supplier during the previous year in each utility service territory as required by 83 Ill. Adm. Code 465.40;

(3) a good faith estimate of the amount an alternative retail electric supplier expects to be obliged to pay the utility under single billing tariffs during the next 12 months and the amount of any bond or letter of credit used to demonstrate an alternative retail electric supplier's credit worthiness to provide single billing services pursuant to 83 Ill. Adm. Code 451.510(a) and (b).

The affidavit must be filed contemporaneously with the information for which confidential treatment is sought and must clearly state that the affiant seeks confidential treatment pursuant to this subsection (g) and the information for which confidential treatment is sought must be clearly identified on the confidential version of the document filed with the Commission. The affidavit must be accompanied by a "confidential" and a "public" version of the document or documents containing the information for which confidential treatment is sought.

If the alternative retail electric supplier has met the affidavit requirements of this subsection (g), then the Commission shall afford confidential treatment to the information identified in the affidavit for a period of 2 years after the date the affidavit is received by the Commission.

Nothing in this subsection (g) prevents an alternative retail electric supplier from filing a petition with the Commission seeking confidential treatment for information beyond that identified in this subsection (g) or for information contained in other reports or documents filed with the Commission.

Nothing in this subsection (g) prevents the Commission, on its own motion, or any party from filing a formal petition with the Commission seeking to reconsider the conferring of confidential status on an item of information afforded confidential treatment pursuant to this subsection (g).

The Commission, on its own motion, may at any time initiate a docketed proceeding to investigate the continued applicability of this subsection (g) to the information contained in items (i), (ii), and (iii) of this subsection (g). If, at the end of such investigation, the Commission determines that a particular item of information should no longer be eligible for the affidavit-based process outlined in this subsection (g), the Commission may enter an order to remove that item from the list of items eligible for the process set forth in this subsection (g). Notwithstanding any such order, in the event the Commission makes such a determination, nothing in this subsection (g) prevents an alternative retail electric supplier desiring confidential treatment for such information from filing a formal petition with the Commission seeking confidential treatment for such information.

(Source: P.A. 101-590, eff. 1-1-20.)

(220 ILCS 5/16-115C)

Sec. 16-115C. Licensure of agents, brokers, and consultants engaged in the procurement or sale of retail electricity supply for third parties.

(a) The purpose of this Section is to adopt licensing and code of conduct rules in a competitive retail electricity market to protect Illinois consumers from unfair or deceptive acts or practices and to provide persons acting as agents, brokers, and consultants engaged in the procurement or sale of retail electricity supply for third parties with notice of the illegality of those acts or practices.

(a-5) All third-party sales representatives engaged in the marketing of retail electricity supply must, prior to the customer signing a contract, disclose that they are not employed by the electric utility operating in the applicable service territory.

(b) For purposes of this Section, "agents, brokers, and consultants engaged in the procurement or sale of retail electricity supply for third parties" means any person or entity that attempts to procure on behalf of or sell retail electric service to an electric customer in the State. "Agents, brokers, and consultants engaged in the procurement or sale of retail electricity supply for third parties" does not include the Illinois Power Agency or any of its employees, any entity licensed as an alternative retail electric supplier pursuant to 83 Ill. Adm. Code 451 offering retail electric service on its own behalf, any person acting exclusively on behalf of a single alternative retail electric supplier on condition that exclusivity is disclosed to any third party contracted in such agent capacity, any person acting exclusively on behalf of a retail electric supplier on condition that exclusivity is disclosed to any third party contracted in such agent capacity, any person or entity representing a municipal power agency, as defined in Section 11-119.1-3 of the Illinois Municipal Code, or any person or entity that is attempting to procure on behalf of or sell retail electric service to a third party that has aggregate billing demand of all of its affiliated electric service accounts in Illinois of greater than 1,500 kW.

(c) No person or entity shall act as an agent, broker, or consultant engaged in the procurement or sale of retail electricity supply for third parties unless that person or entity is licensed by the Commission under this Section or is offering services on their own behalf under 83 Ill. Adm. Code 451. A license granted pursuant to this Section is not property and the grant of a license to an entity does not create a property interest in the license.

(d) The Commission shall create requirements for licensure as an agent, broker, or consultant engaged in the procurement or sale of retail electricity supply for third parties, which shall include all of the following criteria:

(1) Technical competence.

(2) Managerial competence.

(3) Financial responsibility, including the posting of an appropriate performance bond.

(4) Annual reporting requirements.

(e) Any person or entity required to be licensed under this Section must:

(1) disclose in plain language in writing to all persons it solicits (i) before July 1, 2011, the total anticipated remuneration to be paid to it by any third party over the period of the proposed underlying customer contract and (ii) on or after July 1, 2011, the total price per kilowatt-hour, and the total anticipated cost, inclusive of all fees or commissions received by the licensee, to be paid by the customer over the period of the proposed underlying customer contract;

(2) disclose, if applicable, to all customers, prior to the customer signing a contract, the fact that they will be receiving compensation from the supplier;

(3) not hold itself out as independent or unaffiliated with any supplier, or both, or use words reasonably calculated to give that impression, unless the person offering service under this Section has no contractual relationship with any retail electricity supplier or its affiliates regarding retail electric service in Illinois;

(4) not utilize false, misleading, materially inaccurate, defamatory, or otherwise deceptive language or materials in the soliciting or providing of its services;

(5) maintain copies of all marketing materials disseminated to third parties for a period of not less than 3 years;

(6) not present electricity pricing information in a manner that favors one supplier over another, unless a valid pricing comparison is made utilizing all relevant costs and terms; and

(7) comply with the requirements of Sections 2EE, 2FF, 2GG, and 2HH of the Consumer Fraud and Deceptive Business Practices Act.

(f) Any person or entity licensed under this Section shall file with the Commission all of the following information no later than March of each year:

(1) A verified report detailing any and all contractual relationships that it has with certified electricity suppliers in the State regarding retail electric service in Illinois.

(2) A verified report detailing the distribution of its customers with the various certified electricity suppliers in Illinois during the prior calendar year. A report under this Section shall not be required to contain customer-identifying information.

A public redacted version of the verified report may be submitted to the Commission along with a proprietary version. The public redacted version may redact from the verified report the name or names of every certified electricity supplier contained in the report to protect against disclosure of competitively sensitive market share information. The information shall be afforded proprietary treatment for 2 years after the date of the filing of the verified report.

(3) A verified statement of any changes to the original licensure qualifications and notice of continuing compliance with all requirements.

(g) The Commission shall have jurisdiction over disciplinary proceedings and complaints, including on the Commission's own motion, for violations of this Section. The findings of a violation of this Section by the Commission shall result in discipline on a progressive disciplinary scale. For a first violation, the Commission may, in its discretion, suspend the license of the person or entity so disciplined for a period of no less than one month. For a second violation within a 5-year period, the Commission shall suspend the license of for the person or entity so disciplined for a period of not less than 6 months. For a third or subsequent violation within a 5-year period, the Commission shall suspend the license of the disciplined person for a period of not less than 2 years. Notwithstanding the minimum progressive suspensions, the Commission shall have authority, in its discretion, to impose whatever disciplinary measures it deems appropriate for any violation, including but not limited to terminating the license of the person or entity.

(h) This Section shall not apply to a retail customer that operates or manages either directly or indirectly any facilities, equipment, or property used or contemplated to be used to distribute electric power or energy if that retail customer is a political subdivision or public institution of higher education of this State, or any corporation, company, limited liability company, association, joint-stock company or association, firm, partnership, or individual, or their lessees, trusts, or receivers appointed by any court whatsoever that are owned or controlled by the political subdivision, public institution of higher education, or operated by any of its lessees or operating agents.

(Source: P.A. 95-679, eff. 10-11-07; 96-1385, eff. 7-29-10.)

(220 ILCS 5/19-110)

Sec. 19-110. Certification of alternative gas suppliers.

(a) The provisions of this Section shall apply only to alternative gas suppliers serving or seeking to serve residential or small commercial customers and only to the extent such alternative gas suppliers provide services to residential or small commercial customers.

(b) An alternative gas supplier must obtain a certificate of service authority from the Commission in accordance with this Section before serving any customer or other user located in this State. An alternative gas supplier may request, and the Commission may grant, a certificate of service authority for the entire State or for a specified geographic area of the State. An alternative gas supplier may request, and the Commission may grant, a certificate of service authority for the entire State or for a specified geographic area of the State. A license granted pursuant to this Section is not property and the grant of a license to an entity does not create a property interest in the license. A person, corporation, or other entity acting as an alternative gas supplier on the effective date of this amendatory Act of the 92nd General Assembly shall have 180 days from the effective date of this amendatory Act of the 92nd General Assembly to comply with the requirements of this Section in order to continue to operate as an alternative gas supplier.

(c) An alternative gas supplier seeking a certificate of service authority shall file with the Commission a verified application containing information showing that the applicant meets the requirements of this Section. The alternative gas supplier shall publish notice of its application in the official State newspaper within 10 days following the date of its filing. No later than 45 days after the application is properly filed with the Commission, and such notice is published, the Commission shall issue its order granting or denying the application.

(d) An application for a certificate of service authority shall identify the area or areas in which the applicant intends to offer service and the types of services it intends to offer. Applicants that seek to serve residential or small commercial customers within a geographic area that is smaller than a gas utility's service area shall submit evidence demonstrating that the designation of this smaller area does not violate Section 19-115. An applicant may state in its application for certification any limitations that will be imposed on the number of customers or maximum load to be served. The applicant shall submit as part of its application a statement indicating:

(1) Whether the applicant has been denied a natural gas supplier license in any state in the United States.

(2) Whether the applicant has had a natural gas supplier license suspended or revoked by any state in the United States.

(3) Where, if any, other natural gas supplier license applications are pending in the United States.

(4) Whether the applicant is the subject of any lawsuits filed in a court of law or formal complaints filed with a regulatory agency alleging fraud, deception or unfair marketing practices, or other similar allegations, identifying the name, case number, and jurisdiction of each such lawsuit or complaint.

For the purposes of this subsection (d), formal complaints include only those complaints that seek a binding determination from a state or federal regulatory body.

(e) The Commission shall grant the application for a certificate of service authority if it makes the findings set forth in this subsection based on the verified application and such other information as the applicant may submit.

(1) That the applicant possesses sufficient technical, financial, and managerial resources and abilities to provide the service for which it seeks a certificate of service authority. In determining the level of technical, financial, and managerial resources and abilities which the applicant must demonstrate, the Commission shall consider:

(A) the characteristics, including the size and financial sophistication of the customers that the applicant seeks to serve;

(B) whether the applicant seeks to provide gas using property, plant, and equipment that it owns, controls, or operates; and

(C) the applicant's commitment of resources to the management of sales and marketing staff, through affirmative managerial policies, independent audits, technology, hands-on field monitoring and training, and, in the case of applicants who will have sales personnel or sales agents within the State of Illinois, the applicant's managerial presence within the State.

(2) That the applicant will comply with all applicable federal, State, regional, and industry rules, policies, practices, and procedures for the use, operation, and maintenance of the safety, integrity, and reliability of the gas transmission system.

(3) That the applicant will comply with such informational or reporting requirements as the Commission may by rule establish.

(4) That the area to be served by the applicant and any limitations it proposes on the number of customers or maximum amount of load to be served meet the provisions of Section 19-115, provided, that if the applicant seeks to serve an area smaller than the service area of a gas utility or proposes other limitations on the number of customers or maximum amount of load to be served, the Commission can extend the time for considering such a certificate request by up to 90 days, and can schedule hearings on such a request.

(5) That the applicant shall continue to comply with requirements for certification stated in this Section.

(6) That the applicant shall execute and maintain a license or permit bond issued by a qualifying surety or insurance company authorized to transact business in the State of Illinois in favor of the People of the State of Illinois. The amount of the bond shall equal $150,000 if the applicant seeks to serve only nonresidential retail customers or $500,000 if the applicant seeks to serve all eligible customers. Applicants shall be required to submit an additional $500,000 bond if the applicant intends to market to residential customers using in-person solicitations. The bond shall be conditioned upon the full and faithful performance of all duties and obligations of the applicant as an alternative retail gas supplier and shall be valid for a period of not less than one year. The cost of the bond shall be paid by the applicant. The applicant shall file a copy of this bond, with a notarized verification page from the issuer, as part of its application for certification under 83 Ill. Adm. Code 551.

(7) That the applicant will comply with all other applicable laws and rules.

(e-5) The Commission may deny with prejudice an application in which the applicant fails to provide the Commission with information sufficient for the Commission to grant the application.

(f) The Commission can extend the time for considering such a certificate request by up to 90 days, and can schedule hearings on such a request if:

(1) a party to the application proceeding has formally requested that the Commission hold hearings in a pleading that alleges that one or more of the allegations or certifications in the application is false or misleading; or

(2) other facts or circumstances exist that will necessitate additional time or evidence in order to determine whether a certificate should be issued.

(g) The Commission shall have the authority to promulgate rules to carry out the provisions of this Section. Within 30 days after the effective date of this amendatory Act of the 92nd General Assembly, the Commission shall adopt an emergency rule or rules applicable to the certification of those gas suppliers that seek to serve residential customers. Within 180 days of the effective date of this amendatory Act of the 92nd General Assembly, the Commission shall adopt rules that specify criteria which, if met by any such alternative gas supplier, shall constitute the demonstration of technical, financial, and managerial resources and abilities to provide service required by item (1) of subsection (e) of this Section, such as a requirement to post a bond or letter of credit, from a responsible surety or financial institution, of sufficient size for the nature and scope of the services to be provided, demonstration of adequate insurance for the scope and nature of the services to be provided, and experience in providing similar services in other jurisdictions.

(h) The Commission may deny with prejudice any application that repeatedly fails to include the attachments, documentation, and affidavits required by the application form or that repeatedly fails to provide any other information required by this Section.

(i) An alternative gas supplier may seek confidential treatment for the reporting to the Commission of its total annual dekatherms delivered and sold by it to residential and small commercial customers by utility service territory during the preceding year via the filing of an affidavit with the Commission so long as the affidavit meets the requirements of this subsection (i). The affidavit must be filed contemporaneously with the information for which confidential treatment is sought and must clearly state that the affiant seeks confidential treatment pursuant to this subsection (i) and the information for which confidential treatment is sought must be clearly identified on the confidential version of the document filed with the Commission. The affidavit must be accompanied by both a "confidential" and a "public" version of the document or documents containing the information for which confidential treatment is sought.

If the alternative gas supplier has met the affidavit requirements of this subsection (i), then the Commission shall afford confidential treatment to the information identified in the affidavit for a period of 2 years after the date the affidavit is received by the Commission.

Nothing in this subsection (i) prevents an alternative gas supplier from filing a petition with the Commission seeking confidential treatment for information beyond that identified in this subsection (i) or for information contained in other reports or documents filed with the Commission.

Nothing in this subsection (i) prevents the Commission, on its own motion, or any party from filing a formal petition with the Commission seeking to reconsider the conferring of confidential status pursuant to this subsection (i).

The Commission, on its own motion, may at any time initiate a docketed proceeding to investigate the continued applicability of this affidavit-based process for seeking confidential treatment. If, at the end of such investigation, the Commission determines that this affidavit-based process for seeking confidential treatment for the information is no longer necessary, the Commission may enter an order to that effect. Notwithstanding any such order, in the event the Commission makes such a determination, nothing in this subsection (i) prevents an alternative gas supplier desiring confidential treatment for such information from filing a formal petition with the Commission seeking confidential treatment for such information.

(Source: P.A. 101-590, eff. 1-1-20.)

(220 ILCS 5/19-145)

Sec. 19-145. Automatic adjustment clause tariff; uncollectibles.

(a) A gas utility shall be permitted, at its election, to recover through an automatic adjustment clause tariff the incremental difference between its actual uncollectible amount as set forth in Account 904 in the utility's most recent annual Form 21 ILCC and the uncollectible amount included in the utility's rates for the period reported in such annual Form 21 ILCC. The Commission may, in a proceeding to review a general rate case filed subsequent to the effective date of the tariff established under this Section, prospectively switch, from using the actual uncollectible amount set forth in Account 904 to using net write-offs in such tariff, but only if net write-offs are also used to determine the utility's uncollectible amount in rates. In the event the Commission requires such a change, it shall be made effective at the beginning of the first full calendar year after the new rates approved in such proceeding are first placed in effect and an adjustment shall be made, if necessary, to ensure the change does not result in double-recovery or unrecovered uncollectible amounts for any year. For purposes of this Section, "uncollectible amount" means the expense set forth in Account 904 of the utility's Form 21 ILCC or cost of net write-offs as appropriate. In the event the utility's rates change during the period of time reported in its most recent annual Form 21 ILCC, the uncollectible amount included in the utility's rates during such period of time for purposes of this Section will be a weighted average, based on revenues earned during such period by the utility under each set of rates, of the uncollectible amount included in the utility's rates at the beginning of such period and at the end of such period. This difference may either be a charge or a credit to customers depending on whether the uncollectible amount is more or less than the uncollectible amount then included in the utility's rates.

(b) The tariff may be established outside the context of a general rate case filing, and shall specify the terms of any applicable audit. The Commission shall review and by order approve, or approve as modified, the proposed tariff within 180 days after the date on which it is filed. Charges and credits under the tariff shall be allocated to the appropriate customer class or classes. In addition, customers who do not purchase their gas supply from a gas utility shall not be charged by the utility for uncollectible amounts associated with gas supply provided by the utility to the utility's customers. Upon approval of the tariff, the utility shall, based on the 2008 Form 21 ILCC, apply the appropriate credit or charge based on the full year 2008 amounts for the remainder of the 2010 calendar year. Starting with the 2009 Form 21 ILCC reporting period and each subsequent period, the utility shall apply the appropriate credit or charge over a 12-month period beginning with the June billing period and ending with the May billing period, with the first such billing period beginning June 2010.

(c) The approved tariff shall provide that the utility shall file a petition with the Commission annually, no later than August 31st, seeking initiation of an annual review to reconcile all amounts collected with the actual uncollectible amount in the prior period. As part of its review, the Commission shall verify that the utility collects no more and no less than its actual uncollectible amount in each applicable Form 21 ILCC reporting period, and that the utility has demonstrated actions to make its rates more affordable, minimize disconnections, and therefore preserve the availability of utility services to all customers, consistent with item (viii) of subsection (d) of Section 1-102. The Commission shall review the prudence and reasonableness of the utility's actions to pursue minimization and collection of uncollectibles and preserve the availability of utility services to all customers, which shall include, at a minimum, the 6 enumerated criteria set forth in this Section. The Commission shall determine any required adjustments and may include suggestions for prospective changes in current practices. Nothing in this Section or the implementing tariffs shall affect or alter the gas utility's existing obligation to pursue collection of uncollectibles or the gas utility's right to disconnect service. A utility that has in effect a tariff authorized by this Section shall pursue minimization of and collection of uncollectibles through the following activities, including but not limited to:

(1) contacting the customers in an effort to obtain payment;

(2) providing delinquent customers with information about possible options, including payment plans and assistance programs, and how to reach agencies and community-based organizations that provide assistance;

(3) specific action to limit disconnections in zip code areas that would otherwise be disproportionately impacted by the utility's credit and collection policies;

(4) community outreach in areas demonstrating higher than average arrearages to help inform customers about available assistance programs;

(5) providing bill payment assistance funds in an amount that equals 50% of its total uncollectibles for calendar year 2019, the funding of which shall be recovered through the automatic adjustment clause that is the subject of this subsection;

(6) demonstrating that the bill payment assistance funds reduced the number of disconnections in the reconciliation year;

(7) the offering of a Commission-approved discount rate tariff pursuant to Section 9-241, tiered by income level, for customers whose income falls at or below 80% of area median income; and

(8) an arrearage reduction program for low income discount rate customers that eliminates customer arrearages in ratable proportion for each month that plan participants timely pay their utility bill.

(1) identifying customers with late payments;

(2) contacting the customers in an effort to obtain payment;

(3) providing delinquent customers with information about possible options, including payment plans and assistance programs;

(4) serving disconnection notices;

(5) implementing disconnections based on the level of uncollectibles; and

(6) pursuing collection activities based on the level of uncollectibles.

(d) Nothing in this Section shall be construed to require a utility to immediately disconnect service for nonpayment.

(Source: P.A. 96-33, eff. 7-10-09.)

Section 30-41. The Citizens Utility Board Act is amended by changing Sections 3, 5, and 13 as follows:

(220 ILCS 10/3) (from Ch. 111 2/3, par. 903)

Sec. 3. Definitions. As used in this Act:

"Affiliated organization" means any Illinois nonprofit organization that has a formal association with the corporation, as demonstrated by such factors such as use of the corporation name or receipt of a gift, grant or donation from the corporation.

(1)"Board" means the board of directors of the corporation.

(2)"Campaign contribution" means a gift, subscription, loan, advance or deposit of money or anything of value, made for the purpose of electing a candidate to the board; or a contract, a promise or agreement, express or implied, whether or not legally enforceable, to make any campaign contribution; but does not include the value of services provided without compensation by individuals who volunteer a portion or all of their time on behalf of a candidate or political committee, or the use of real or personal property and the cost of invitations, food and beverages, voluntarily provided by an individual to a candidate in rendering voluntary personal services on the individual's residential premises for candidate-related activities if the cumulative value of the activities to the individual on behalf of any candidate does not exceed $100 for any election.

(3)"Campaign expenditures" means a purchase, payment distribution, loan, advance, deposit or gift of money or anything of value, made for the purpose of electing a candidate to the board; or a contract, promise, or agreement, express or implied, whether or not legally enforceable, to make any campaign expenditure; but does not include the use of real or personal property and the cost of invitations, food and beverages, voluntarily provided by an individual to a candidate in rendering voluntary personal services on the individual's residential premises for candidate-related activities if the cumulative value of the activities by the individual on behalf of any candidate does not exceed $100 for any election.

(4)"Class A utility" means any gas, electric or water public utility with annual total gross operating revenues of $2.5 million or more or any telephone public utility with annual total gross operating revenues of $1,600,000 or more on the effective date of this Act.

(5)"Corporation" means the citizens utility board.

(6)"Director" means any member of the board.

(7)"District" means a corporation district, the boundaries of which are congruent with the boundaries of the Congressional districts in the State.

(8)"Immediate family" of a person means the person's spouse and legal dependents.

(9)"Member" means any person who satisfies the requirements for membership under Section 4.

(10)"Periodic customer billing" means a demand for payment for utility services by a public utility to a residential utility consumer on a monthly or other regular basis.

(11)"Political committee" means any committee, club, association or other group of persons which make campaign expenditures or receive campaign contributions during the year before an election of the board.

(12)"Public utility" means any person who owns, operates, manages or controls any plant or equipment or any part of a plant or equipment, within the State, for the conveyance of telephone messages or for the production, transmission, delivery or furnishing of heat, light, water or power either directly or indirectly to or for the public. "Public utility" includes any person engaged in the transmission or delivery of natural gas for compensation within this State by means of pipes or mains. "Public utility" does not include a cooperative association organized for the purpose of furnishing telephone service to its members only. "Public utility" does not include electric cooperatives as defined in Section 3-119 of the Public Utilities Act. However, "public utility" does not include either public utilities that are owned and operated by a political subdivision, public institution of higher education or municipal corporation of this State or public utilities that are owned by such political subdivision, public institution of higher education, or municipal corporation and operated by any of its lessees or operating agents.

(13)"Utility consumer" means any individual or entity, which is not governmental or a public utility, which is located in this State and which is furnished with a utility service by a public utility.

(14)"Utility service" means electricity, natural gas, water and telephone service supplied by a public utility.

(Source: P.A. 91-357, eff. 7-29-99.)

(220 ILCS 10/5) (from Ch. 111 2/3, par. 905)

Sec. 5. Powers and duties.

(1) The corporation shall:

(a) Represent and protect the interests of the residential utility consumers of this State. All actions by the corporation under this Act shall be directed toward such duty; provided that the corporation may also give due consideration to the interests of business in the State.

(b) Inform, in so far as possible, all utility consumers about the corporation, including the procedure for obtaining membership in the corporation.

(2) The corporation shall have all the powers necessary or convenient for the effective representation and protection of the interest of utility consumers and to implement this Act, including the following powers in addition to all other powers granted by this Act.

(a) To make, amend and repeal bylaws and rules for the regulation of its affairs and the conduct of its business; to adopt an official seal and alter it at pleasure; to maintain an office; to sue and be sued in its own name, plead and be impleaded; and to make and execute contracts and other instruments necessary or convenient to the exercise of the powers of the corporation.

(b) To employ such agents, employees and special advisors as it finds necessary and to fix their compensation.

(c) To solicit and accept gifts, loans, including loans made by the Illinois Commerce Commission from funds appropriated for that purpose by law, or other aid in order to support activities concerning the interests of utility consumers. Except as provided in Section 5.1, the corporation may not accept gifts, loans or other aid from any public utility or from any director, employee or agent or member of the immediate family of a director, employee or agent of any public utility, or from any foundation or nonprofit organization established by or affiliated with a public utility and, after the first election the corporation, may not accept from any individual, private corporation, association or partnership in any single year a total of more than $1,000 in gifts. Under this paragraph, "aid" does not mean payment of membership dues.

(d) To intervene as a party or otherwise participate on behalf of utility consumers in any proceeding which affects the interest of utility consumers.

(e) To represent the interests of utility consumers before the Illinois Commerce Commission, the Federal Energy Regulatory Commission, the Federal Communications Commission, the courts, and other public bodies, except that no director, employee or agent of the corporation may engage in lobbying without first complying with any applicable statute, administrative rule or other regulation relating to lobbying.

(f) To establish annual dues which shall be set at a level that provides sufficient funding for the corporation to effectively perform its powers and duties, and is affordable for as many utility consumers as is possible.

(g) To implement solicitation for corporation funding and membership.

(h) To seek tax exempt status under State and federal law, including 501(c)(3) status under the United States Internal Revenue Code.

(i) To provide information and advice to utility consumers on any matter with respect to utility service, including but not limited to information and advice on benefits and methods of energy conservation.

(3) The powers, duties, rights and privileges conferred or imposed upon the corporation by this Act may not be transferred.

(4) The corporation shall refrain from interfering with collective bargaining rights of any employees of a public utility.

(Source: P.A. 91-50, eff. 6-30-99.)

(220 ILCS 10/13) (from Ch. 111 2/3, par. 913)

Sec. 13. Public records. Statements filed with the corporation shall be available for public inspection at the office of the corporation during reasonable hours of the day. With regard to the records described in this Section, a corporation and any affiliated organizations are considered public bodies subject to the provisions of the Freedom of Information Act. Such records may be copied. The corporation may charge a reasonable fee for the cost of such copies.

(Source: P.A. 83-945.)

Section 30-45. The Energy Assistance Act is amended by changing Sections 6, 13, and 18 and by adding Section 20 as follows:

(305 ILCS 20/6) (from Ch. 111 2/3, par. 1406)

Sec. 6. Eligibility, Conditions of Participation, and Energy Assistance.

(a) Any person who is a resident of the State of Illinois and whose household income is not greater than an amount determined annually by the Department, in consultation with the Policy Advisory Council, may apply for assistance pursuant to this Act in accordance with regulations promulgated by the Department. In setting the annual eligibility level, the Department shall consider the amount of available funding and may not set a limit higher than 150% of the federal nonfarm poverty level as established by the federal Office of Management and Budget or 60% of the State median income for the current State fiscal year as established by the U.S. Department of Health and Human Services; except that for the period from the effective date of this amendatory Act of the 101st General Assembly through June 30, 2021, the Department may establish limits not higher than 200% of that poverty level. The Department, in consultation with the Policy Advisory Council, may adjust the percentage of poverty level annually in accordance with federal guidelines and based on funding availability.

(b) Applicants who qualify for assistance pursuant to subsection (a) of this Section shall, subject to appropriation from the General Assembly and subject to availability of funds to the Department, receive energy assistance as provided by this Act. The Department, upon receipt of monies authorized pursuant to this Act for energy assistance, shall commit funds for each qualified applicant in an amount determined by the Department. In determining the amounts of assistance to be provided to or on behalf of a qualified applicant, the Department shall ensure that the highest amounts of assistance go to households with the greatest energy costs in relation to household income. The Department shall include factors such as energy costs, household size, household income, and region of the State when determining individual household benefits. In setting assistance levels, the Department shall attempt to provide assistance to approximately the same number of households who participated in the 1991 Residential Energy Assistance Partnership Program. Such assistance levels shall be adjusted annually on the basis of funding availability and energy costs. In promulgating rules for the administration of this Section the Department shall assure that a minimum of 1/3 of funds available for benefits to eligible households with the lowest incomes and that elderly households, households with children under the age of 6 years old, and households with persons with disabilities are offered a priority application period.

(c) If the applicant is not a customer of record of an energy provider for energy services or an applicant for such service, such applicant shall receive a direct energy assistance payment in an amount established by the Department for all such applicants under this Act; provided, however, that such an applicant must have rental expenses for housing greater than 30% of household income.

(c-1) This subsection shall apply only in cases where: (1) the applicant is not a customer of record of an energy provider because energy services are provided by the owner of the unit as a portion of the rent; (2) the applicant resides in housing subsidized or developed with funds provided under the Rental Housing Support Program Act or under a similar locally funded rent subsidy program, or is the voucher holder who resides in a rental unit within the State of Illinois and whose monthly rent is subsidized by the tenant-based Housing Choice Voucher Program under Section 8 of the U.S. Housing Act of 1937; and (3) the rental expenses for housing are no more than 30% of household income. In such cases, the household may apply for an energy assistance payment under this Act and the owner of the housing unit shall cooperate with the applicant by providing documentation of the energy costs for that unit. Any compensation paid to the energy provider who supplied energy services to the household shall be paid on behalf of the owner of the housing unit providing energy services to the household. The Department shall report annually to the General Assembly on the number of households receiving energy assistance under this subsection and the cost of such assistance. The provisions of this subsection (c-1), other than this sentence, are inoperative after August 31, 2012.

(d) If the applicant is a customer of an energy provider, such applicant shall receive energy assistance in an amount established by the Department for all such applicants under this Act, such amount to be paid by the Department to the energy provider supplying winter energy service to such applicant. Such applicant shall:

(i) make all reasonable efforts to apply to any other appropriate source of public energy assistance; and

(ii) sign a waiver permitting the Department to receive income information from any public or private agency providing income or energy assistance and from any employer, whether public or private.

(e) Any qualified applicant pursuant to this Section may receive or have paid on such applicant's behalf an emergency assistance payment to enable such applicant to obtain access to winter energy services. Any such payments shall be made in accordance with regulations of the Department.

(f) The Department may, if sufficient funds are available, provide additional benefits to certain qualified applicants:

(i) for the reduction of past due amounts owed to energy providers; and

(ii) to assist the household in responding to excessively high summer temperatures or energy costs. Households containing elderly members, children, a person with a disability, or a person with a medical need for conditioned air shall receive priority for receipt of such benefits.

(Source: P.A. 101-636, eff. 6-10-20.)

(305 ILCS 20/13)

(Section scheduled to be repealed on January 1, 2025)

Sec. 13. Supplemental Low-Income Energy Assistance Fund.

(a) The Supplemental Low-Income Energy Assistance Fund is hereby created as a special fund in the State Treasury. The Supplemental Low-Income Energy Assistance Fund is authorized to receive moneys from voluntary donations from individuals, foundations, corporations, and other sources, moneys received pursuant to Section 17, and, by statutory deposit, the moneys collected pursuant to this Section. The Fund is also authorized to receive voluntary donations from individuals, foundations, corporations, and other sources. Subject to appropriation, the Department shall use moneys from the Supplemental Low-Income Energy Assistance Fund for payments to electric or gas public utilities, municipal electric or gas utilities, and electric cooperatives on behalf of their customers who are participants in the program authorized by Sections 4 and 18 of this Act, for the provision of weatherization services and for administration of the Supplemental Low-Income Energy Assistance Fund. All other deposits, except for the Energy Assistance Charge in subsection (b), are not subject to the percentage restrictions related to administrative and weatherization expenses provided in this subsection. The yearly expenditures for weatherization may not exceed 10% of the amount collected during the year pursuant to this Section, except when unspent funds from the Supplemental Low-Income Energy Assistance Fund are reallocated from a previous year; any unspent balance of the 10% weatherization allowance may be utilized for weatherization expenses in the year they are reallocated. The yearly administrative expenses of the Supplemental Low-Income Energy Assistance Fund may not exceed 13% 10% of the amount collected during that year pursuant to this Section, except when unspent funds from the Supplemental Low-Income Energy Assistance Fund are reallocated from a previous year; any unspent balance of the 13% 10% administrative allowance may be utilized for administrative expenses in the year they are reallocated. Of the 13% administrative allowance, no less than 8% shall be provided to Local Administrative Agencies for administrative expenses.

(b) Notwithstanding the provisions of Section 16-111 of the Public Utilities Act but subject to subsection (k) of this Section, each public utility, electric cooperative, as defined in Section 3.4 of the Electric Supplier Act, and municipal utility, as referenced in Section 3-105 of the Public Utilities Act, that is engaged in the delivery of electricity or the distribution of natural gas within the State of Illinois shall, effective January 1, 2022 effective January 1, 1998, assess each of its customer accounts a monthly Energy Assistance Charge for the Supplemental Low-Income Energy Assistance Fund. The delivering public utility, municipal electric or gas utility, or electric or gas cooperative for a self-assessing purchaser remains subject to the collection of the fee imposed by this Section. The monthly charge shall be as follows:

(1) Base Energy Assistance Charge per month on each account for residential electrical service;

(2) Base Energy Assistance Charge per month on each account for residential gas service;

(3) Ten times the Base Energy Assistance Charge per month on each account for nonresidential electric service which had less than 10 megawatts of peak demand during the previous calendar year;

(4) Ten times the Base Energy Assistance Charge per month on each account for nonresidential gas service which had distributed to it less than 4,000,000 therms of gas during the previous calendar year;

(5) Three hundred and seventy-five times the Base Energy Assistance Charge per month on each account for nonresidential electric service which had 10 megawatts or greater of peak demand during the previous calendar year; and

(6) Three hundred and seventy-five times the Base Energy Assistance Charge per month on each account for nonresidential gas service which had 4,000,000 or more therms of gas distributed to it during the previous calendar year.

The Base Energy Assistance Charge shall be $0.48 per month for the calendar year beginning January 1, 2022 and shall increase by $0.16 per month for any calendar year, provided no less than 80% of the previous State fiscal year's available Supplemental Low-Income Energy Assistance Fund funding was exhausted. The maximum Base Energy Assistance Charge shall not exceed $0.96 per month for any calendar year.

(1) $0.48 per month on each account for residential electric service;

(2) $0.48 per month on each account for residential gas service;

(3) $4.80 per month on each account for non-residential electric service which had less than 10 megawatts of peak demand during the previous calendar year;

(4) $4.80 per month on each account for non-residential gas service which had distributed to it less than 4,000,000 therms of gas during the previous calendar year;

(5) $360 per month on each account for non-residential electric service which had 10 megawatts or greater of peak demand during the previous calendar year; and

(6) $360 per month on each account for non-residential gas service which had 4,000,000 or more therms of gas distributed to it during the previous calendar year.

The incremental change to such charges imposed by Public Act 99-933 and this amendatory Act of the 102nd General Assembly this amendatory Act of the 96th General Assembly shall not (i) be used for any purpose other than to directly assist customers and (ii) be applicable to utilities serving less than 25,000 100,000 customers in Illinois on January 1, 2021 2009. The incremental change to such charges imposed by this amendatory Act of the 102nd General Assembly are intended to increase utilization of the Percentage of Income Payment Plan (PIPP or PIP Plan) and shall be applied such that PIP Plan enrollment is at least doubled, as compared to 2020 enrollment, by 2024.

In addition, electric and gas utilities have committed, and shall contribute, a one-time payment of $22 million to the Fund, within 10 days after the effective date of the tariffs established pursuant to Sections 16-111.8 and 19-145 of the Public Utilities Act to be used for the Department's cost of implementing the programs described in Section 18 of this amendatory Act of the 96th General Assembly, the Arrearage Reduction Program described in Section 18, and the programs described in Section 8-105 of the Public Utilities Act. If a utility elects not to file a rider within 90 days after the effective date of this amendatory Act of the 96th General Assembly, then the contribution from such utility shall be made no later than February 1, 2010.

(c) For purposes of this Section:

(1) "residential electric service" means electric utility service for household purposes delivered to a dwelling of 2 or fewer units which is billed under a residential rate, or electric utility service for household purposes delivered to a dwelling unit or units which is billed under a residential rate and is registered by a separate meter for each dwelling unit;

(2) "residential gas service" means gas utility service for household purposes distributed to a dwelling of 2 or fewer units which is billed under a residential rate, or gas utility service for household purposes distributed to a dwelling unit or units which is billed under a residential rate and is registered by a separate meter for each dwelling unit;

(3) "non-residential electric service" means electric utility service which is not residential electric service; and

(4) "non-residential gas service" means gas utility service which is not residential gas service.

(d) Within 30 days after the effective date of this amendatory Act of the 96th General Assembly, each public utility engaged in the delivery of electricity or the distribution of natural gas shall file with the Illinois Commerce Commission tariffs incorporating the Energy Assistance Charge in other charges stated in such tariffs, which shall become effective no later than the beginning of the first billing cycle following such filing.

(e) The Energy Assistance Charge assessed by electric and gas public utilities shall be considered a charge for public utility service.

(f) By the 20th day of the month following the month in which the charges imposed by the Section were collected, each public utility, municipal utility, and electric cooperative shall remit to the Department of Revenue all moneys received as payment of the Energy Assistance Charge on a return prescribed and furnished by the Department of Revenue showing such information as the Department of Revenue may reasonably require; provided, however, that a utility offering an Arrearage Reduction Program or Supplemental Arrearage Reduction Program pursuant to Section 18 of this Act shall be entitled to net those amounts necessary to fund and recover the costs of such Programs as authorized by that Section that is no more than the incremental change in such Energy Assistance Charge authorized by Public Act 96-33. If a customer makes a partial payment, a public utility, municipal utility, or electric cooperative may elect either: (i) to apply such partial payments first to amounts owed to the utility or cooperative for its services and then to payment for the Energy Assistance Charge or (ii) to apply such partial payments on a pro-rata basis between amounts owed to the utility or cooperative for its services and to payment for the Energy Assistance Charge.

If any payment provided for in this Section exceeds the distributor's liabilities under this Act, as shown on an original return, the Department may authorize the distributor to credit such excess payment against liability subsequently to be remitted to the Department under this Act, in accordance with reasonable rules adopted by the Department. If the Department subsequently determines that all or any part of the credit taken was not actually due to the distributor, the distributor's discount shall be reduced by an amount equal to the difference between the discount as applied to the credit taken and that actually due, and that distributor shall be liable for penalties and interest on such difference.

(g) The Department of Revenue shall deposit into the Supplemental Low-Income Energy Assistance Fund all moneys remitted to it in accordance with subsection (f) of this Section. ; provided, however, that the amounts remitted by each utility shall be used to provide assistance to that utility's customers. The utilities shall coordinate with the Department to establish an equitable and practical methodology for implementing this subsection (g) beginning with the 2010 program year.

(h) On or before December 31, 2002, the Department shall prepare a report for the General Assembly on the expenditure of funds appropriated from the Low-Income Energy Assistance Block Grant Fund for the program authorized under Section 4 of this Act.

(i) The Department of Revenue may establish such rules as it deems necessary to implement this Section.

(j) The Department of Commerce and Economic Opportunity may establish such rules as it deems necessary to implement this Section.

(k) The charges imposed by this Section shall only apply to customers of municipal electric or gas utilities and electric or gas cooperatives if the municipal electric or gas utility or electric or gas cooperative makes an affirmative decision to impose the charge. If a municipal electric or gas utility or an electric cooperative makes an affirmative decision to impose the charge provided by this Section, the municipal electric or gas utility or electric cooperative shall inform the Department of Revenue in writing of such decision when it begins to impose the charge. If a municipal electric or gas utility or electric or gas cooperative does not assess this charge, the Department may not use funds from the Supplemental Low-Income Energy Assistance Fund to provide benefits to its customers under the program authorized by Section 4 of this Act.

In its use of federal funds under this Act, the Department may not cause a disproportionate share of those federal funds to benefit customers of systems which do not assess the charge provided by this Section.

This Section is repealed on January 1, 2025 unless renewed by action of the General Assembly.

(Source: P.A. 99-457, eff. 1-1-16; 99-906, eff. 6-1-17; 99-933, eff. 1-27-17; 100-863, eff. 8-14-18; 100-1171, eff. 1-4-19.)

(305 ILCS 20/18)

Sec. 18. Financial assistance; payment plans.

(a) The Percentage of Income Payment Plan (PIPP or PIP Plan) is hereby created as a mandatory bill payment assistance program for low-income residential customers of utilities serving more than 100,000 100,000 retail customers as of January 1, 2021 2009. The PIP Plan will:

(1) bring participants' gas and electric bills into the range of affordability;

(2) provide incentives for participants to make timely payments;

(3) encourage participants to reduce usage and participate in conservation and energy efficiency measures that reduce the customer's bill and payment requirements; and

(4) identify participants whose homes are most in need of weatherization; and .

(5) endeavor to maximize participation and spend at least 80% of the funding available for the year.

(b) For purposes of this Section:

(1) "LIHEAP" means the energy assistance program established under the Illinois Energy Assistance Act and the Low-Income Home Energy Assistance Act of 1981.

(2) "Plan participant" is an eligible participant who is also eligible for the PIPP and who will receive either a percentage of income payment credit under the PIPP criteria set forth in this Act or a benefit pursuant to Section 4 of this Act. Plan participants are a subset of eligible participants.

(3) "Pre-program arrears" means the amount a plan participant owes for gas or electric service at the time the participant is determined to be eligible for the PIPP or the program set forth in Section 4 of this Act.

(4) "Eligible participant" means any person who has applied for, been accepted and is receiving residential service from a gas or electric utility and who is also eligible for LIHEAP or otherwise satisfies the eligibility criteria set forth in paragraph (1) of subsection (c).

(c) The PIP Plan shall be administered as follows:

(1) The Department shall coordinate with Local Administrative Agencies (LAAs), to determine eligibility for the Illinois Low Income Home Energy Assistance Program (LIHEAP) pursuant to the Energy Assistance Act, provided that eligible income shall be no more than 150% of the poverty level or 60% of the State median income, except that for the period from the effective date of this amendatory Act of the 101st General Assembly through June 30, 2021, eligible income shall be no more than 200% of the poverty level. Applicants will be screened to determine whether the applicant's projected payments for electric service or natural gas service over a 12-month period exceed the criteria established in this Section. The Department, in consultation with the Policy Advisory Council, may adjust the percentage of poverty level annually to determine income eligibility. To maintain the financial integrity of the program, the Department may limit eligibility to households with income below 125% of the poverty level.

(2) The Department shall establish the percentage of income formula to determine the amount of a monthly credit for participants with eligible income based on poverty level. , not to exceed $150 per month per household, not to exceed $1,800 annually; however, for the period from the effective date of this amendatory Act of the 101st General Assembly through June 30, 2021, the monthly credit for participants with eligible income over 100% of the poverty level may be as much as $200 per month per household, not to exceed $2,400 annually, and, the monthly credit for participants with eligible income 100% or less of the poverty level may be as much as $250 per month per household, not to exceed $3,000 annually. Credits will be applied to PIP Plan participants' utility bills based on the portion of the bill that is the responsibility of the participant provided that the percentage shall be no more than a total of 6% of the relevant income for gas and electric utility bills combined, but in any event no less than $10 per month, unless the household does not pay directly for heat, in which case its payment shall be 2.4% of income but in any event no less than $5 per month. The Department, in consultation with the Policy Advisory Council, may adjust such monthly credit amounts annually and may establish a minimum credit amount based on the cost of administering the program and may deny credits to otherwise eligible participants if the cost of administering the credit exceeds the actual amount of any monthly credit to a participant. If the participant takes both gas and electric service, 50% 66.67% of the credit shall be allocated to the entity that provides the participant's primary energy supply for heating. Each participant shall enter into a levelized payment plan for, as applicable, gas and electric service and such plans shall be implemented by the utility so that a participant's usage and required payments are reviewed and adjusted regularly, but no more frequently than quarterly. Nothing in this Section is intended to prohibit a customer, who is otherwise eligible for LIHEAP, from participating in the program described in Section 4 of this Act. Eligible participants who receive such a benefit shall be considered plan participants and shall be eligible to participate in the Arrearage Reduction Program described in item (5) of this subsection (c).

(3) The Department shall remit, through the LAAs, to the utility or participating alternative supplier that portion of the plan participant's bill that is not the responsibility of the participant. In the event that the Department fails to timely remit payment to the utility, the utility shall be entitled to recover all costs related to such nonpayment through the automatic adjustment clause tariffs established pursuant to Section 16-111.8 and Section 19-145 of the Public Utilities Act. For purposes of this item (3) of this subsection (c), payment is due on the date specified on the participant's bill. The Department, the Department of Revenue and LAAs shall adopt processes that provide for the timely payment required by this item (3) of this subsection (c).

(4) A plan participant is responsible for all actual charges for utility service in excess of the PIPP credit. Pre-program arrears that are included in the Arrearage Reduction Program described in item (5) of this subsection (c) shall not be included in the calculation of the levelized payment plan. Emergency or crisis assistance payments shall not affect the amount of any PIPP credit to which a participant is entitled.

(5) Electric and gas utilities subject to this Section shall implement an Arrearage Reduction Program (ARP) for plan participants as follows: for each month that a plan participant timely pays his or her utility bill, the utility shall apply a credit to a portion of the participant's pre-program arrears, if any, equal to one-twelfth of such arrearage provided that the total amount of arrearage credits shall equal no more than $1,000 annually for each participant for gas and no more than $1,000 annually for each participant for electricity. In the third year of the PIPP, the Department, in consultation with the Policy Advisory Council established pursuant to Section 5 of this Act, shall determine by rule an appropriate per participant total cap on such amounts, if any. Those plan participants participating in the ARP shall not be subject to the imposition of any additional late payment fees on pre-program arrears covered by the ARP. In all other respects, the utility shall bill and collect the monthly bill of a plan participant pursuant to the same rules, regulations, programs and policies as applicable to residential customers generally. Participation in the Arrearage Reduction Program shall be limited to the maximum amount of funds available as set forth in subsection (f) of Section 13 of this Act. In the event any donated funds under Section 13 of this Act are specifically designated for the purpose of funding the ARP, the Department shall remit such amounts to the utilities upon verification that such funds are needed to fund the ARP. Nothing in this Section shall preclude a utility from continuing to implement, and apply credits under, an ARP in the event that the PIPP or LIHEAP is suspended due to lack of funding such that the plan participant does not receive a benefit under either the PIPP or LIHEAP.

(5.5) In addition to the ARP described in paragraph (5) of this subsection (c), utilities may also implement a Supplemental Arrearage Reduction Program (SARP) for eligible participants who are not able to become plan participants due to PIPP timing or funding constraints. If a utility elects to implement a SARP, it shall be administered as follows: for each month that a SARP participant timely pays his or her utility bill, the utility shall apply a credit to a portion of the participant's pre-program arrears, if any, equal to one-twelfth of such arrearage, provided that the utility may limit the total amount of arrearage credits to no more than $1,000 annually for each participant for gas and no more than $1,000 annually for each participant for electricity. SARP participants shall not be subject to the imposition of any additional late payment fees on pre-program arrears covered by the SARP. In all other respects, the utility shall bill and collect the monthly bill of a SARP participant under the same rules, regulations, programs, and policies as applicable to residential customers generally. Participation in the SARP shall be limited to the maximum amount of funds available as set forth in subsection (f) of Section 13 of this Act. In the event any donated funds under Section 13 of this Act are specifically designated for the purpose of funding the SARP, the Department shall remit such amounts to the utilities upon verification that such funds are needed to fund the SARP.

(6) The Department may terminate a plan participant's eligibility for the PIP Plan upon notification by the utility that the participant's monthly utility payment is more than 75 45 days past due. One-twelfth of a customer's arrearage shall be deducted from the total arrearage owed for each on-time payment made by the customer.

(7) The Department, in consultation with the Policy Advisory Council, may adjust the number of PIP Plan participants annually, if necessary, to match the availability of funds. Any plan participant who qualifies for a PIPP credit under a utility's PIPP shall be entitled to participate in and receive a credit under such utility's ARP for so long as such utility has ARP funds available, regardless of whether the customer's participation under another utility's PIPP or ARP has been curtailed or limited because of a lack of funds.

(8) The Department shall fully implement the PIPP at the earliest possible date it is able to effectively administer the PIPP. Within 90 days of the effective date of this amendatory Act of the 96th General Assembly, the Department shall, in consultation with utility companies, participating alternative suppliers, LAAs and the Illinois Commerce Commission (Commission), issue a detailed implementation plan which shall include detailed testing protocols and analysis of the capacity for implementation by the LAAs and utilities. Such consultation process also shall address how to implement the PIPP in the most cost-effective and timely manner, and shall identify opportunities for relying on the expertise of utilities, LAAs and the Commission. Following the implementation of the testing protocols, the Department shall issue a written report on the feasibility of full or gradual implementation. The PIPP shall be fully implemented by September 1, 2011, but may be phased in prior to that date.

(9) As part of the screening process established under item (1) of this subsection (c), the Department and LAAs shall assess whether any energy efficiency or demand response measures are available to the plan participant at no cost, and if so, the participant shall enroll in any such program for which he or she is eligible. The LAAs shall assist the participant in the applicable enrollment or application process.

(10) Each alternative retail electric and gas supplier serving residential customers shall elect whether to participate in the PIPP or ARP described in this Section. Any such supplier electing to participate in the PIPP shall provide to the Department such information as the Department may require, including, without limitation, information sufficient for the Department to determine the proportionate allocation of credits between the alternative supplier and the utility. If a utility in whose service territory an alternative supplier serves customers contributes money to the ARP fund which is not recovered from ratepayers, then an alternative supplier which participates in ARP in that utility's service territory shall also contribute to the ARP fund in an amount that is commensurate with the number of alternative supplier customers who elect to participate in the program.

(11) The PIPP shall be designed and implemented each year to maximize participation and spend at least 80% of the funding available for the year.

(d) The Department, in consultation with the Policy Advisory Council, shall develop and implement a program to educate customers about the PIP Plan and about their rights and responsibilities under the percentage of income component. The Department, in consultation with the Policy Advisory Council, shall establish a process that LAAs shall use to contact customers in jeopardy of losing eligibility due to late payments. The Department shall ensure that LAAs are adequately funded to perform all necessary educational tasks.

(e) The PIPP shall be administered in a manner which ensures that credits to plan participants will not be counted as income or as a resource in other means-tested assistance programs for low-income households or otherwise result in the loss of federal or State assistance dollars for low-income households.

(f) In order to ensure that implementation costs are minimized, the Department and utilities shall work together to identify cost-effective ways to transfer information electronically and to employ available protocols that will minimize their respective administrative costs as follows:

(1) The Commission may require utilities to provide such information on customer usage and billing and payment information as required by the Department to implement the PIP Plan and to provide written notices and communications to plan participants.

(2) Each utility and participating alternative supplier shall file annual reports with the Department and the Commission that cumulatively summarize and update program information as required by the Commission's rules. The reports shall track implementation costs and contain such information as is necessary to evaluate the success of the PIPP.

(2.5) The Department shall annually prepare and submit a report to the General Assembly, the Commission, and the Policy Advisory Council that identifies the following amounts for the most recently completed year: total moneys collected under subsection (b) of Section 13 of this Act for all PIPPs implemented in the State; moneys allocated to each utility for implementation of its PIPP; and moneys allocated to each utility for other purposes, including a description of each of those purposes. The Commission shall publish the report on its website.

(3) The Department and the Commission shall have the authority to promulgate rules and regulations necessary to execute and administer the provisions of this Section.

(g) Each utility shall be entitled to recover reasonable administrative and operational costs incurred to comply with this Section from the Supplemental Low Income Energy Assistance Fund. The utility may net such costs against monies it would otherwise remit to the Funds, and each utility shall include in the annual report required under subsection (f) of this Section an accounting for the funds collected.

(Source: P.A. 101-636, eff. 6-10-20.)

(305 ILCS 20/20 new)

Sec. 20. Expanded eligibility. All programs pursuant to this Act shall be available to eligible low-income Illinois residents who qualify for assistance under Sections 6 and 18, regardless of immigration status, using the Supplemental Low-Income Energy Assistance Fund for customers of utilities and vendors that collect the Energy Assistance Charge and pay into the Supplemental Low-Income Energy Assistance Fund.

Section 30-50. The Environmental Protection Act is amended by changing Sections 2 and 9.15 and by adding Section 3.1325 as follows:

(415 ILCS 5/2) (from Ch. 111 1/2, par. 1002)

Sec. 2. (a) The General Assembly finds:

(i) that environmental damage seriously endangers the public health and welfare, as more specifically described in later sections of this Act;

(ii) that because environmental damage does not respect political boundaries, it is necessary to establish a unified state-wide program for environmental protection and to cooperate fully with other States and with the United States in protecting the environment;

(iii) that air, water, and other resource pollution, public water supply, solid waste disposal, noise, and other environmental problems are closely interrelated and must be dealt with as a unified whole in order to safeguard the environment;

(iv) that it is the obligation of the State Government to manage its own activities so as to minimize environmental damage; to encourage and assist local governments to adopt and implement environmental-protection programs consistent with this Act; to promote the development of technology for environmental protection and conservation of natural resources; to do its part to stop and reverse the effects of climate change by moving toward 100% clean energy generation; and in appropriate cases to afford financial assistance in preventing environmental damage;

(v) that in order to alleviate the burden on enforcement agencies, to assure that all interests are given a full hearing, and to increase public participation in the task of protecting the environment, private as well as governmental remedies must be provided;

(vi) that despite the existing laws and regulations concerning environmental damage there exist continuing destruction and damage to the environment and harm to the public health, safety and welfare of the people of this State, and that among the most significant sources of this destruction, damage, and harm are the improper and unsafe transportation, treatment, storage, disposal, and dumping of hazardous wastes;

(vii) that it is necessary to supplement and strengthen existing criminal sanctions regarding environmental damage, by enacting specific penalties for injury to public health and welfare and the environment.

(b) It is the purpose of this Act, as more specifically described in later sections, to establish a unified, state-wide program supplemented by private remedies, to restore, protect and enhance the quality of the environment, and to assure that adverse effects upon the environment are fully considered and borne by those who cause them.

(c) The terms and provisions of this Act shall be liberally construed so as to effectuate the purposes of this Act as set forth in subsection (b) of this Section, but to the extent that this Act prescribes criminal penalties, it shall be construed in accordance with the Criminal Code of 2012.

(Source: P.A. 97-1150, eff. 1-25-13.)

(415 ILCS 5/3.1325 new)

Sec. 3.1325. Clean Energy. "Clean Energy" means energy generation that is substantially free (90% or greater) of carbon dioxide emissions.

(415 ILCS 5/9.15)

Sec. 9.15. Greenhouse gases.

(a) An air pollution construction permit shall not be required due to emissions of greenhouse gases if the equipment, site, or source is not subject to regulation, as defined by 40 CFR 52.21, as now or hereafter amended, for greenhouse gases or is otherwise not addressed by the Board in regulations for greenhouse gases. These exemptions do . This exemption does not relieve an owner or operator from the obligation to comply with other applicable rules or regulations.

(b) An air pollution operating permit shall not be required due to emissions of greenhouse gases if the equipment, site, or source is not subject to regulation, as defined by Section 39.5 of this Act, for greenhouse gases or is otherwise not addressed by the Board in regulations for greenhouse gases. These exemptions do . This exemption does not relieve an owner or operator from the obligation to comply with other applicable rules or regulations.

(c) (Blank). Notwithstanding any provision to the contrary in this Section, an air pollution construction or operating permit shall not be required due to emissions of greenhouse gases if any of the following events occur:

(1) enactment of federal legislation depriving the Administrator of the USEPA of authority to regulate greenhouse gases under the Clean Air Act;

(2) the issuance of any opinion, ruling, judgment, order, or decree by a federal court depriving the Administrator of the USEPA of authority to regulate greenhouse gases under the Clean Air Act; or

(3) action by the President of the United States or the President's authorized agent, including the Administrator of the USEPA, to repeal or withdraw the Greenhouse Gas Tailoring Rule (75 Fed. Reg. 31514, June 3, 2010).

This subsection (c) does not relieve an owner or operator from the obligation to comply with applicable rules or regulations other than those relating to greenhouse gases.

(d) (Blank). If any event listed in subsection (c) of this Section occurs, permits issued after such event shall not impose permit terms or conditions addressing greenhouse gases during the effectiveness of any event listed in subsection (c).

(e) (Blank). If an event listed in subsection (c) of this Section occurs, any owner or operator with a permit that includes terms or conditions addressing greenhouse gases may elect to submit an application to the Agency to address a revision or repeal of such terms or conditions. The Agency shall expeditiously process such permit application in accordance with applicable laws and regulations.

(f) Definitions. As used in this Section:

"Carbon dioxide equivalent emissions" or "CO₂e" means the sum total of the mass amount of emissions in tons per year, calculated by multiplying the mass amount of each of the 6 greenhouse gases specified in Section 3.207 of the Act (in tons per year) by its associated global warming potential as set forth in 40 CFR 98, subpart A, table A-1, and then adding them all together.

"Electric generating unit" or "EGU" means a fossil fuel-fired stationary boiler, combustion turbine, or combined cycle system that serves a generator that has a nameplate capacity greater than 25 MWe and produces electricity for sale.

"Large greenhouse gas-emitting" or "large GHG-emitting unit" means a unit that is an electric generating unit or other fossil fuel-fired unit that itself has a nameplate capacity or serves a generator that has a nameplate capacity greater than 25 MWe and that produces electricity (including, but not limited to, coal-fired, coal-derived, oil-fired, natural gas-fired, and cogeneration units).

(g) The Agency shall, within 365 days after the effective date of this amendatory Act of the 102nd General Assembly, initiate a rulemaking to amend Title 35 of the Illinois Administrative Code to establish declining greenhouse gas emissions caps beginning in 2024 from all large GHG-emitting units so as to progressively eliminate all greenhouse gas emissions from such units by the year 2030 for EGUs that use coal as a fuel, and by the year 2045 for remaining large GHG-emitting units, except under conditions described in subsection (j), and to establish aggregate statewide emissions caps. No later than 365 days after receipt of the Agency's proposal under this Section, the Board shall adopt rules that establish declining emissions caps for greenhouse gases for each individual large GHG-emitting unit in Illinois, as well as an aggregate statewide greenhouse gas emissions cap. The Board may set different declining caps for each unit, but caps must decline to zero emissions for all EGUs that use coal as a fuel by 2030 and all other large GHG-emitting units by 2045, except under conditions described in subsection (j).

(h) As part of its rulemaking proposal, the Agency:

(1) Shall conduct a stakeholder process prior to initiating a rulemaking proceeding before the Illinois Pollution Control Board that encourages the meaningful participation of Illinois residents. This process should include a public comment period, during which the Agency shall:

(A) encourage and accept written public comments from across the State;

(B) hold three public outreach events; and

(C) ensure access for residents by providing opportunity for oral public comment outside the workday.

(2) May set declining rates of greenhouse gas emissions from individual large GHG-emitting units based on factors such as the amount of greenhouse gas emissions at a unit, electric grid supply and reliability, and unit operational schedule.

(3) May set greenhouse gas emissions caps that result in zero emissions from certain EGUs that use coal as a fuel earlier than 2030 and from other large GHG-emitting units earlier than 2045, as supported by the Agency's assessment of units.

(i) The Agency's rulemaking proposal and the Board's adopted rule shall address the following:

(1) Aggregate statewide emissions caps. The Agency shall establish a schedule by which the aggregate cap shall decline consistently. A baseline shall be calculated by averaging the total actual greenhouse gas emissions, calculated in terms of CO₂e, from the years 2018, 2019, and 2020 from all large GHG-emitting units for which the Agency has issued a permit to operate or a permit to construct as of the date the Agency proposes the rule to the Board. For any units that were not yet operating in 2018 but were operating by January 1, 2020, the baseline amount included within the aggregate statewide emissions cap shall be the total actual greenhouse gas emissions, calculated in terms of CO₂e, from the unit in 2020. For any units that were not yet operating by January 1, 2020, the baseline amount included within the aggregate statewide emissions cap shall be an amount that is proposed by the Agency and adopted by the Board, consistent with expected operations and taking into account any other operational factors that have occurred prior to the proposal and adoption of the rule. To ensure consistent progress toward the goal of eliminating all greenhouse gas emissions from large GHG-emitting units, the aggregate emissions cap shall decrease by no less than 20% of the baseline amount in every five-year period.

(2) Unit-specific emissions caps. Greenhouse gas emissions caps, calculated in terms of CO₂e, shall be established for individual large GHG-emitting units by evaluating individual units and setting appropriate declining caps for emission reductions. Greenhouse gas emissions caps shall apply to each large GHG-emitting unit in the State and the sum of all unit-specific emissions caps shall total to no more than the aggregate statewide greenhouse gas emissions cap. The Agency shall include in its rulemaking proposal a declining greenhouse gas emission cap, calculated in terms of CO₂e, that delineates each unit's allowable greenhouse gas emissions in every year until the unit reaches zero greenhouse gas emissions.

(j) The Agency's proposal and the Board's adopted rule shall include language that allows EGUs that use coal as a fuel to continue emitting greenhouse gases after 2030 and other large GHG-emitting units to continue emitting greenhouse gases after 2045, or after any earlier deadline specified in the rulemaking, only in such circumstance that it has been determined that ongoing operation of the unit is necessary to maintain power grid supply and reliability for EGUs or is necessary to serve as an emergency backup to operations for other large GHG-emitting units. The rule must include language mandating that:

(1) each large GHG-emitting unit that is a participant in a regional transmission organization submit documentation to the appropriate regional transmission organization by deadlines specified in the rulemaking that meets all applicable regulatory requirements necessary to obtain approval to permanently cease operating the large GHG-emitting unit;

(2) if any large GHG-emitting unit that is a participant in a regional transmission organization cannot obtain such permission because the regional transmission organization determines that operation of the unit is required to maintain transmission supply and reliability, the unit may continue operating but the owner or operator of the unit must use its best efforts to resolve the supply and reliability requirement with the regional transmission organization and cease operation as soon as practicable; and

(3) any large GHG-emitting unit that is not a participant in a regional transmission organization be allowed to continue emitting greenhouse gases after 2045 in the capacity of an emergency backup unit if the owner or operator can justify the need for such extension to the Agency, in consultation with the Illinois Commerce Commission.

(k) Annual report. Each year by June 30, beginning in 2025, the Agency shall prepare and publish on its website a report setting forth the actual greenhouse gas emissions from individual units and the aggregate statewide emissions from all units for the prior year.

(l) Greenhouse gas emissions fee. On and after January 1, 2022, the owner or operator of each large GHG-emitting unit shall, on an annual basis, pay a fee to the Agency for such unit as described below.

(1) In 2022, the fee amount for each unit shall be $8.00 per ton of CO₂e emitted from July 1, 2021, through December 31, 2021. In each subsequent year, the fee amount for each unit shall be based on the tons of CO₂e emitted from January 1 through December 31, plus 3%.

(2) No later than February 1, 2022, the owner or operator shall submit a report to the Agency's Bureau of Air Compliance Section, specifying the tons of CO₂e emitted from July 1, 2021, through December 31, 2021, with supporting calculations for each of the 6 greenhouse gases and any subcategories thereof. No later than February 1 of each subsequent year, the owner or operator shall submit a report to the Agency's Bureau of Air Compliance Section, specifying the tons of CO₂e emitted in the prior year with supporting calculations for each of the 6 greenhouse gases and any subcategories thereof.

(3) No later than March 1, 2022, the Agency shall send a billing statement to the owner or operator indicating the amount of greenhouse gas emissions fees owed for July 1, 2021, through December 31, 2021. No later than March 1 of each subsequent year, the Agency shall send a billing statement to the owner or operator indicating the amount of greenhouse gas emissions fees owed for the previous year.

(4) The owner or operator shall pay all greenhouse gas emissions fees by April 1 each year. Payment shall be made through the Illinois E-Pay system or by a check or money order payable to either the "Treasurer, State of Illinois" or the "Illinois Environmental Protection Agency". The check or money order shall be accompanied by the billing statement that includes the site name and identification number assigned by the Agency's Bureau of Air. If paying by check or money order, payment shall be directed to the Agency's Fiscal Services Section. Payment shall not include any fees due to the Agency for any purpose other than greenhouse gas emissions fees. Failure to timely pay the fees will subject the owner or operator to possible enforcement under Section 31 of the Act and collection actions.

(5) Greenhouse gas emissions fees shall not be refunded unless the amount paid is in excess of the amount billed or the amount billed is determined by the Agency to be incorrect. The owner or operator shall request reconsideration of the amount of the greenhouse gas emissions fees as determined by the Agency within 30 days after issuance of a billing statement. Failure to request reconsideration within this period shall constitute waiver of all rights to seek reconsideration of the amount from the Agency, waiver of all rights to a refund, and waiver of all rights to appeal. All requests for reconsideration shall be in writing, directed to the Agency's Bureau of Air Compliance Section, and shall include all pertinent facts and arguments in support of the request.

(6) Subject to the waiver provisions set forth in paragraph (5) of this subsection (l), the owner or operator may appeal the Agency's determination of the greenhouse gas emissions fees pursuant to the Administrative Review Law.

(7) The Agency shall have the authority to establish additional procedures for the collection of greenhouse gas emissions fees if necessary.

(m) Greenhouse Gas Emissions Reinvestment Fund.

(1) There is hereby created the Greenhouse Gas Emissions Reinvestment Fund, a special fund in the State Treasury, subject to appropriations unless otherwise provided in this Section. All moneys collected from the greenhouse gas emissions fee under subsection (l) shall be deposited into the Greenhouse Gas Emissions Reinvestment Fund.

(2) Whenever the Agency determines that a refund should be made from the greenhouse gas emissions fee collected under subsection (l) to a claimant, the Agency shall submit a voucher for payment to the State Comptroller, who shall cause the order to be drawn for the amount specified and to the person named in the notification from the Agency. This paragraph (2) shall constitute an irrevocable and continuing appropriation of all amounts necessary for the payment of refunds out of the Fund as authorized under this paragraph (2).

(3) On July 1, 2022 and on July 1 of each year thereafter, the Agency, in consultation with the Governor's Office of Management and Budget, shall identify the following allocations from amounts available in the Greenhouse Gas Emissions Reinvestment Fund and shall prepare and certify to the State Comptroller the transfer and allocations of stated sums of money from the Greenhouse Gas Emissions Reinvestment Fund to other named funds in the State treasury as applicable.

(A) The Agency shall first determine the allocation which shall remain in the Greenhouse Gas Emissions Reinvestment Fund, subject to appropriations, to pay for the direct and indirect costs associated with the implementation, administration, and enforcement of Section 9.15 of the Environmental Protection Act, including the payment of refunds from the greenhouse gas emissions fee under collected subsection (l) of Section 9.15 of the Environmental Protection Act by the Agency, together with the annual audit to determine whether there is a need for State support for the Illinois nuclear fleet under Section 8-201.12 of the Public Utilities Act.

(B) After the allocations have been made as provided in subparagraph (A) of paragraph (3) of this subsection (m), from the remaining amounts the Agency shall certify to the State Comptroller and the State Treasurer shall transfer into the following named funds according to the following allocations:

(i) 30% shall be transferred to the Energy Transition Assistance Fund for use by the Department of Commerce and Economic Opportunity for job training, workforce assistance, and just transition programs for equity-focused populations, and for use by the Illinois Student Assistance Commission for a displaced energy worker dependent transition scholarship;

(ii) 5% shall be transferred to the Alternate Fuels Fund for the Agency to administer and provide rebates for consumers who purchase electric vehicles pursuant to the Electric Vehicle Rebate Act;

(iii) 5% shall be transferred to the Energy Transition Assistance Fund for distribution by the Department of Commerce and Economic Opportunity for assistance for communities who have experienced the closure of a power generation facility after 2016 pursuant to the Energy Transition Community Grant Program;

(iv) 5% shall be transferred to the Energy Efficiency Trust Fund for the Illinois Environmental Protection Agency for energy efficiency programs, including weatherization;

(v) 5% shall be transferred to the Clean Air Act Permit Fund for use by the Environmental Protection Agency including the implementation, administration, and enforcement of the Clean Air Act by the Agency;

(vi) 5% shall be transferred to the Public Utilities Fund for use by the Illinois Commerce Commission for costs of administering the changes made to the Public Utilities Act by this amendatory Act of the 102nd General Assembly;

(vii) 5% shall be transferred to the State Parks Fund for the Department of Natural Resources for the maintenance, and development of State parks including infrastructure improvements to promote outdoor recreation and sustainable energy;

(viii) 1% shall be transferred to the Plugging and Restoration Fund for the Department of Natural Resources for the purposes of plugging, replugging or repairing any well, and restoring the site of any well, determined by the Department to be abandoned;

(ix) 1% shall be transferred to the Illinois Power Agency Operations Fund for use by the Illinois Power Agency;

(x) 10% shall be transferred to the Budget Stabilization Fund;

(xi) 2% for transfers to the State Garage Revolving Fund for purposes of State fleet electrification pursuant to Executive Order 2021-08; and

(xii) 2% shall be transferred to the Illinois Power Agency.

27%, or any remaining balance in the Fund, shall be retained for use by the Agency for the costs of implementing the changes made to the Environmental Protection Act by this amendatory Act of the 102nd General Assembly or distributed in addition to transfers listed in items (i) through (xii) of this subparagraph (B).

(4) On June 30, 2025 and on June 30 of each year thereafter, the Agency shall prepare and publish on its website a report describing the amount of greenhouse gas emissions fees collected that year from large greenhouse gas-emitting units.

(Source: P.A. 97-95, eff. 7-12-11.)

Section 30-55. The Alternate Fuels Act is amended by changing Sections 1, 5, 10, 15, and 40 and by adding Section 27 as follows:

(415 ILCS 120/1)

Sec. 1. Short title. This Act may be cited as the Electric Vehicle Rebate Alternate Fuels Act.

(Source: P.A. 89-410.)

(415 ILCS 120/5)

Sec. 5. Purpose. The General Assembly declares that it is the public policy of the State to promote and encourage the use of electric alternate fuel in vehicles as a means to improve air quality in the State, reduce greenhouse gas emissions, and to meet the requirements of the federal Clean Air Act Amendments of 1990 and the federal Energy Policy Act of 1992. The General Assembly further declares that the State can play a leadership role by increasing the adoption in the development of vehicles powered by electricity alternate fuels, as well as in the establishment of the necessary infrastructure to support this emerging technology.

(Source: P.A. 89-410.)

(415 ILCS 120/10)

Sec. 10. Definitions. As used in this Act:

"Agency" means the Environmental Protection Agency.

"Alternate fuel" means liquid petroleum gas, natural gas, E85 blend fuel, fuel composed of a minimum 80% ethanol, 80% bio-based methanol, fuels that are at least 80% derived from biomass, hydrogen fuel, or electricity, excluding on-board electric generation.

"Alternate fuel vehicle" means any vehicle that is operated in Illinois and is capable of using an alternate fuel.

"Biodiesel fuel" means a renewable fuel conforming to the industry standard ASTM-D6751 and registered with the U.S. Environmental Protection Agency.

"Car sharing organization" means an organization whose primary business is a membership-based service that allows members to drive cars by the hour in order to extend the public transit system, reduce personal car ownership, save consumers money, increase the use of alternative transportation, and improve environmental sustainability.

"Conventional", when used to modify the word "vehicle", "engine", or "fuel", means gasoline or diesel or any reformulations of those fuels.

"Covered Area" means the counties of Cook, DuPage, Kane, Lake, McHenry, and Will, together with Aux Sable and Goose Lake Townships in Grundy County and Oswego Township in Kendall County and those portions of Grundy County and Kendall County that are included in the following ZIP code areas, as designated by the U.S. Postal Service on the effective date of this amendatory Act of 1998: 60416, 60444, 60447, 60450, 60481, 60538, and 60543.

"Director" means the Director of the Environmental Protection Agency.

"Domestic renewable fuel" means a fuel, produced in the United States, composed of a minimum 80% ethanol, 80% bio-based methanol, or 20% biodiesel fuel.

"E85 blend fuel" means fuel that contains 85% ethanol and 15% gasoline.

"Electric vehicle" means a vehicle that is licensed to drive on public roadways, is exclusively predominantly powered by, and exclusively primarily refueled with, electricity, and does not have restrictions confining it to operate on only certain types of streets or roads. "Electric vehicle" does not include hybrid electric vehicles and extended-range electric vehicles that are also equipped with conventional fueled propulsion or auxiliary engines or electric motorcycles.

"GVWR" means Gross Vehicle Weight Rating.

"Location" means (i) a parcel of real property or (ii) multiple, contiguous parcels of real property that are separated by private roadways, public roadways, or private or public rights-of-way and are owned, operated, leased, or under common control of one party.

"Low-income" means persons and families whose average income does not exceed 80% of area median income, adjusted for family size and revised every 2 years.

"Original equipment manufacturer" or "OEM" means a manufacturer of alternate fuel vehicles or a manufacturer or remanufacturer of alternate fuel engines used in vehicles greater than 8500 pounds GVWR.

"Rental vehicle" means any motor vehicle that is owned or controlled primarily for the purpose of short-term leasing or rental pursuant to a contract.

(Source: P.A. 97-90, eff. 7-11-11.)

(415 ILCS 120/15)

Sec. 15. Rulemaking. The Agency shall promulgate rules as necessary and dedicate sufficient resources to implement the purposes of Section 27 30 of this Act. Such rules shall be consistent with applicable the provisions of the federal Clean Air Act Amendments of 1990 and any regulations promulgated pursuant thereto. The Secretary of State may promulgate rules to implement Section 35 of this Act. The Department of Commerce and Economic Opportunity may promulgate rules to implement Section 25 of this Act.

(Source: P.A. 94-793, eff. 5-19-06.)

(415 ILCS 120/27 new)

Sec. 27. Covered Areas; low-income rebate.

(a) Beginning July 1, 2022, and continuing as long as funds are available, each low-income person residing in a Covered Area shall be eligible to apply for a rebate, in the amounts set forth below, following the purchase of an electric vehicle in Illinois. The Agency shall issue rebates consistent with the provisions of this Act and any implementing regulations adopted by the Agency. In no event shall a rebate amount exceed the purchase price of the vehicle.

(1) On and after July 1, 2022 through June 30, 2026, a $4,000 rebate for the purchase of an electric vehicle.

(2) On and after July 1, 2026 through June 30, 2028, a $2,000 rebate for the purchase of an electric vehicle.

(3) On and after July 1, 2028 through June 30, 2030, a $1,000 rebate for the purchase of an electric vehicle.

(b) To be eligible to receive a low-income rebate, a purchaser must:

(1) Be a low-income person residing in a Covered Area, both at the time the vehicle is purchased and at the time the rebate is issued.

(2) Purchase an electric vehicle in Illinois on or after July 1, 2022 and be the owner of the vehicle at the time the rebate is issued. Rented or leased vehicles, vehicles purchased from an out-of-state dealership, and vehicles delivered to or received by the purchaser out-of-state are not eligible for a rebate under this Act.

(3) Apply for the rebate within 90 days after the vehicle purchase date, and provide to the Agency proof of residence, proof of low-income status, proof of vehicle ownership, and proof that the vehicle was purchased in Illinois, including a copy of a purchase agreement noting an Illinois seller. The purchaser must notify the Agency of any changes in residency, low-income status, or ownership of the vehicle that occur between application for a rebate and issuance of a rebate.

(c) The purchaser must retain ownership of the vehicle for a minimum of 12 consecutive months immediately following the vehicle purchase date. The purchaser must continue to reside in a Covered Area during that time frame and register the vehicle in Illinois during that time frame. Rebate recipients who fail to satisfy any of the above criteria will be required to reimburse the Agency all or part of the original rebate amount and shall notify the Agency within 60 days of failing to satisfy the criteria.

(d) Rebates administered under this Section shall be available for both new and used passenger electric vehicles.

(e) A rebate administered under this Act may only be applied for and awarded one time per Vehicle Identification Number. A rebate may only be applied for and awarded once per purchaser in any 10-year period.

(415 ILCS 120/40)

Sec. 40. Appropriations from the Alternate Fuels Fund.

(a) User Fees Funds. The Agency shall estimate the amount of user fees expected to be collected under Section 35 of this Act for each fiscal year. User fee funds shall be deposited into and distributed from the Alternate Fuels Fund in the following manner:

(1) An In each of fiscal years 1999, 2000, 2001, 2002, and 2003, an amount not to exceed $200,000, and beginning in fiscal year 2004 an annual amount not to exceed $225,000, may be appropriated to the Agency from the Alternate Fuels Fund to pay its costs of administering the programs authorized by Section 27 30 of this Act. Up to $200,000 may be appropriated to the Office of the Secretary of State in each of fiscal years 1999, 2000, 2001, 2002, and 2003 from the Alternate Fuels Fund to pay the Secretary of State's costs of administering the programs authorized under this Act. Beginning in fiscal year 2004 and in each fiscal year thereafter, an amount not to exceed $225,000 may be appropriated to the Secretary of State from the Alternate Fuels Fund to pay the Secretary of State's costs of administering the programs authorized under this Act.

(2) In fiscal years 2023, 2024, 2025, 2026, and 2027, and each fiscal year thereafter 1999, 2000, 2001, and 2002, after appropriation of the amounts authorized by item (1) of subsection (a) of this Section, the remaining moneys estimated to be collected during each fiscal year shall be appropriated as follows: 80% of the remaining moneys shall be appropriated to fund the programs authorized by Section 27 30, and 20% shall be appropriated to fund the programs authorized by Section 25. In fiscal year 2004 and each fiscal year thereafter, after appropriation of the amounts authorized by item (1) of subsection (a) of this Section, the remaining moneys estimated to be collected during each fiscal year shall be appropriated as follows: 70% of the remaining moneys shall be appropriated to fund the programs authorized by Section 30 and 30% shall be appropriated to fund the programs authorized by Section 31.

(3) (Blank).

(4) Moneys appropriated to fund the programs authorized in Section 27 Sections 25 and 30 shall be expended only after they have been collected and deposited into the Alternate Fuels Fund.

(b) General Revenue Fund Appropriations. General Revenue Fund amounts appropriated to and deposited into the Alternate Fuels Fund shall be distributed from the Alternate Fuels Fund to fund the programs authorized in Section 27. in the following manner:

(1) In each of fiscal years 2003 and 2004, an amount not to exceed $50,000 may be appropriated to the Department of Commerce and Community Affairs (now Department of Commerce and Economic Opportunity) from the Alternate Fuels Fund to pay its costs of administering the programs authorized by Sections 31 and 32.

(2) In each of fiscal years 2003 and 2004, an amount not to exceed $50,000 may be appropriated to the Department of Commerce and Community Affairs (now Department of Commerce and Economic Opportunity) to fund the programs authorized by Section 32.

(3) In each of fiscal years 2003 and 2004, after appropriation of the amounts authorized in items (1) and (2) of subsection (b) of this Section, the remaining moneys received from the General Revenue Fund shall be appropriated as follows: 52.632% of the remaining moneys shall be appropriated to fund the programs authorized by Sections 25 and 30 and 47.368% of the remaining moneys shall be appropriated to fund the programs authorized by Section 31. The moneys appropriated to fund the programs authorized by Sections 25 and 30 shall be used as follows: 20% shall be used to fund the programs authorized by Section 25, and 80% shall be used to fund the programs authorized by Section 30.

Moneys appropriated to fund the programs authorized in Section 31 shall be expended only after they have been deposited into the Alternate Fuels Fund.

(Source: P.A. 93-32, eff. 7-1-03; 94-793, eff. 5-19-06.)

(415 ILCS 120/20 rep.)

(415 ILCS 120/22 rep.)

(415 ILCS 120/24 rep.)

(415 ILCS 120/30 rep.)

(415 ILCS 120/31 rep.)

(415 ILCS 120/32 rep.)

Section 30-56. The Alternate Fuels Act is amended by repealing Sections 20, 22, 24, 30, 31, and 32.

Section 30-60. The First Informer Broadcasters Act is amended by adding Section 20 as follows:

(430 ILCS 170/20 new)

Sec. 20. Cybersecurity Measures for Municipal Power and Distribution Cooperatives.

(a) It is the policy of the State of Illinois to ensure that the systems which deliver power to its residents are protected from physical and cyber risks and attacks, including through municipal power agencies and distribution cooperatives.

(b) Legislative Findings. The General Assembly finds:

(1) That a substantial number of Illinois residents and businesses rely on power delivered through municipal power agencies and distribution cooperatives.

(2) That all utilities, including municipal power agencies and distribution cooperatives, are the target of physical and cyber threats and attacks.

(3) That cyber attacks have the ability to destabilize portions of the grid, leaving Illinois residents without power and access to critical services.

(4) That it is in the interest of the State of Illinois to understand the nature of threats and to work with municipal agencies and cooperatives to support their planning for such threats.

(c) Planning Summaries. Starting on December 31, 2021 and on or before December 31 of every year thereafter, each municipal power agency and distribution cooperative shall file with the Illinois Emergency Management Agency (IEMA) and the Illinois Commerce Commission (Commission) a summary of its planning process and preparedness for addressing cyber and physical security risks.

(1) In preparing the summary, the municipal power agency or distribution cooperative shall assess risks and the extent to which they can be exploited by bad actors, security controls, previous attacks and vulnerabilities that led to those attacks, incident and vulnerability management, efforts being taken to mitigate risks, continuity of power planning, training and awareness, and any other information the municipal power agency or distribution cooperative deems relevant to a thorough assessment of its preparedness for cyber and physical security attacks.

(2) The summary shall be high-level and contain little explicit information. As part of its summary, the filing entity need not report any confidential, proprietary, or other information in the plan that could in any way compromise or decrease the filing entity's ability to prevent, mitigate, or recover from potential system disruptions caused by physical events, or cyber attacks.

(3) IEMA and the Commission shall, to the extent possible, coordinate with other State or federal agencies to assist the filing entity in developing its report and mitigating issues raised by the report.

Section 30-63. The Renewable Energy Facilities Agricultural Impact Mitigation Act is amended by changing Section 15 as follows:

(505 ILCS 147/15)

Sec. 15. Agricultural impact mitigation agreement.

(a) A commercial renewable energy facility owner of a commercial wind energy facility or a commercial solar energy facility that is located on landowner property shall enter into an agricultural impact mitigation agreement with the Department outlining construction and deconstruction standards and policies designed to preserve the integrity of any agricultural land that is impacted by commercial renewable energy facility construction and deconstruction. The construction and deconstruction of any commercial wind energy facility or commercial solar energy facility shall be in conformance with the Department's standard agricultural impact mitigation agreement referenced in subsection (f) of this Section. The Department shall have the authority to halt the construction or deconstruction of a commercial wind energy facility or a commercial solar energy facility that does not meet or exceed the terms and conditions included in the Department's standard agricultural impact mitigation agreement referenced in subsection (f) of this Section, but shall allow other portions of the construction that are in compliance to continue. The Except as provided in subsection (a-5) of this Section, the terms and conditions of the Department's standard agricultural impact mitigation agreement are subject to and may be modified by an underlying agreement between the landowner and the commercial solar energy facility owner, subject to approval by the Department.

(a-5) Prior to the commencement of construction, the commercial renewable energy facility owner of a commercial wind energy facility or a commercial solar energy facility a commercial solar energy facility owner shall submit to the county in which the commercial wind energy facility or commercial solar energy facility commercial solar facility is to be located a deconstruction plan. A commercial solar energy facility owner commercial renewable energy facility owner shall provide the county with an appropriate financial assurance mechanism consistent with or exceeding the requirements of the Department's standard agricultural impact mitigation agreement for and to assure deconstruction in the event of an abandonment of a commercial wind energy facility or commercial solar energy facility.

(b) The agricultural impact mitigation agreement for a commercial wind energy facility shall include, but is not limited to, such items as restoration of agricultural land affected by construction, deconstruction (including upon abandonment of a commercial wind energy facility), construction staging, and storage areas; support structures; aboveground facilities; guy wires and anchors; underground cabling depth; topsoil replacement; protection and repair of agricultural drainage tiles; rock removal; repair of compaction and rutting; land leveling; prevention of soil erosion; repair of damaged soil conservation practices; compensation for damages to private property; clearing of trees and brush; interference with irrigation systems; access roads; weed control; pumping of water from open excavations; advance notice of access to private property; indemnification of landowners; and deconstruction plans and financial assurance for deconstruction (including upon abandonment of a commercial wind energy facility).

(b-5) The agricultural impact mitigation agreement for a commercial solar energy facility shall include, but is not limited to, such items as restoration of agricultural land affected by construction, deconstruction (including upon abandonment of a commercial solar energy facility); support structures; aboveground facilities; guy wires and anchors; underground cabling depth; topsoil removal and replacement; rerouting and permanent repair of agricultural drainage tiles; rock removal; repair of compaction and rutting; construction during wet weather; land leveling; prevention of soil erosion; repair of damaged soil conservation practices; compensation for damages to private property; clearing of trees and brush; access roads; weed control; advance notice of access to private property; indemnification of landowners; and deconstruction plans and financial assurance for deconstruction (including upon abandonment of a commercial solar energy facility). The commercial solar energy facility owner shall enter into one agricultural impact mitigation agreement for each commercial solar energy facility.

(c) For commercial wind energy facility owners seeking a permit from a county or municipality for the construction of a commercial wind energy facility, the agricultural impact mitigation agreement shall be entered into prior to the public hearing required prior to a siting decision of a county or municipality regarding the commercial wind energy facility. The agricultural impact mitigation agreement is binding on any subsequent commercial wind energy facility owner that takes ownership of the commercial wind energy facility that is the subject of the agreement.

(c-5) A commercial solar energy facility owner shall, not less than 45 days prior to commencement of actual construction, submit to the Department a standard agricultural impact mitigation agreement as referenced in subsection (f) of this Section signed by the commercial solar energy facility owner and including all information required by the Department. The commercial solar energy facility owner shall provide either a copy of that submitted agreement or a copy of the fully executed project-specific agricultural impact mitigation agreement to the landowner not less than 30 days prior to the commencement of construction. The agricultural impact mitigation agreement is binding on any subsequent commercial solar energy facility owner that takes ownership of the commercial solar energy facility that is the subject of the agreement.

(d) If a commercial renewable energy facility owner seeks an extension of a permit granted by a county or municipality for the construction of a commercial wind energy facility prior to the effective date of this Act, the agricultural impact mitigation agreement shall be entered into prior to a decision by the county or municipality to grant the permit extension.

(e) The Department may adopt rules that are necessary and appropriate for the implementation and administration of agricultural impact mitigation agreements as required under this Act.

(f) The Department shall make available on its website a standard agricultural impact mitigation agreement applicable to all commercial wind energy facilities or commercial solar energy facilities within 60 days after the effective date of this amendatory Act of the 100th General Assembly.

(g) Nothing in this amendatory Act of the 100th General Assembly and nothing in an agricultural impact mitigation agreement shall be construed to apply to or otherwise impair an underlying agreement for a commercial solar energy facility entered into prior to the effective date of this amendatory Act of the 100th General Assembly.

(Source: P.A. 99-132, eff. 7-24-15; 100-598, eff. 6-29-18.)

Section 30-65. The Consumer Fraud and Deceptive Business Practices Act is amended by adding Section 10e as follows:

(815 ILCS 505/10e new)

Sec. 10e. Filed Rate Doctrine. The filed rate doctrine shall not be a defense to an action under this Act against any entity regulated by the Illinois Commerce Commission. The remedies for violations of the Public Utilities Act and its rules do not replace, are in addition to and not in substitution for, the remedies that may be imposed for violations of this Act.

Section 30-70. The Illinois Worker Adjustment and Retraining Notification Act is amended by changing Section 10 as follows:

(820 ILCS 65/10)

Sec. 10. Notice.

(a) An employer may not order a mass layoff, relocation, or employment loss unless, 60 days before the order takes effect, the employer gives written notice of the order to the following:

(1) affected employees and representatives of affected employees; and

(2) the Department of Commerce and Economic Opportunity and the chief elected official of each municipal and county government within which the employment loss, relocation, or mass layoff occurs.

(b) An employer of an investor-owned electric generating plant or coal mining operation may not order a mass layoff, relocation, or employment loss unless, 2 years before the order takes effect, the employer gives written notice of the order to the following:

(1) affected employees and representatives of affected employees; and

(2) the Department of Commerce and Economic Opportunity and the chief elected official of each municipal and county government within which the employment loss, relocation, or mass layoff occurs.

(b) An employer required to give notice of any mass layoff, relocation, or employment loss under this Act shall include in its notice the elements required by the federal Worker Adjustment and Retraining Notification Act (29 U.S.C. 2101 et seq.).

(c) Notwithstanding the requirements of subsection (a), an employer is not required to provide notice if a mass layoff, relocation, or employment loss is necessitated by a physical calamity or an act of terrorism or war.

(d) The mailing of notice to an employee's last known address or inclusion of notice in the employee's paycheck shall be considered acceptable methods for fulfillment of the employer's obligation to give notice to each affected employee under this Act.

(e) In the case of a sale of part or all of an employer's business, the seller shall be responsible for providing notice for any plant closing or mass layoff in accordance with this Section, up to and including the effective date of the sale. After the effective date of the sale of part or all of an employer's business, the purchaser shall be responsible for providing notice for any plant closing or mass layoff in accordance with this Section. Notwithstanding any other provision of this Act, any person who is an employee of the seller (other than a part-time employee) as of the effective date of the sale shall be considered an employee of the purchaser immediately after the effective date of the sale.

(f) An employer which is receiving State or local economic development incentives for doing or continuing to do business in this State may be required to provide additional notice pursuant to Section 15 of the Business Economic Support Act.

(g) The rights and remedies provided to employees by this Act are in addition to, and not in lieu of, any other contractual or statutory rights and remedies of the employees, and are not intended to alter or affect such rights and remedies, except that the period of notification required by this Act shall run concurrently with any period of notification required by contract or by any other law.

(h) It is the sense of the General Assembly that an employer who is not required to comply with the notice requirements of this Section should, to the extent possible, provide notice to its employees about a proposal to close a plant or permanently reduce its workforce.

(Source: P.A. 93-915, eff. 1-1-05.)

Section 30-75. The Prevailing Wage Act is amended by changing Section 2 as follows:

(820 ILCS 130/2) (from Ch. 48, par. 39s-2)

Sec. 2. This Act applies to the wages of laborers, mechanics and other workers employed in any public works, as hereinafter defined, by any public body and to anyone under contracts for public works. This includes any maintenance, repair, assembly, or disassembly work performed on equipment whether owned, leased, or rented.

As used in this Act, unless the context indicates otherwise:

"Public works" means all fixed works constructed or demolished by any public body, or paid for wholly or in part out of public funds. "Public works" as defined herein includes all projects financed in whole or in part with bonds, grants, loans, or other funds made available by or through the State or any of its political subdivisions, including but not limited to: bonds issued under the Industrial Project Revenue Bond Act (Article 11, Division 74 of the Illinois Municipal Code), the Industrial Building Revenue Bond Act, the Illinois Finance Authority Act, the Illinois Sports Facilities Authority Act, or the Build Illinois Bond Act; loans or other funds made available pursuant to the Build Illinois Act; loans or other funds made available pursuant to the Riverfront Development Fund under Section 10-15 of the River Edge Redevelopment Zone Act; or funds from the Fund for Illinois' Future under Section 6z-47 of the State Finance Act, funds for school construction under Section 5 of the General Obligation Bond Act, funds authorized under Section 3 of the School Construction Bond Act, funds for school infrastructure under Section 6z-45 of the State Finance Act, and funds for transportation purposes under Section 4 of the General Obligation Bond Act. "Public works" also includes (i) all projects financed in whole or in part with funds from the Department of Commerce and Economic Opportunity under the Illinois Renewable Fuels Development Program Act for which there is no project labor agreement; (ii) all work performed pursuant to a public private agreement under the Public Private Agreements for the Illiana Expressway Act or the Public-Private Agreements for the South Suburban Airport Act; and (iii) all projects undertaken under a public-private agreement under the Public-Private Partnerships for Transportation Act. "Public works" also includes all projects at leased facility property used for airport purposes under Section 35 of the Local Government Facility Lease Act. "Public works" also includes: the construction of a new wind power facility by a business designated as a High Impact Business under Section 5.5(a)(3)(E) of the Illinois Enterprise Zone Act; and any project greater than 2,000 kilowatts and less than 10,000 kilowatts financed in whole or in part with renewable energy credits procured pursuant to subparagraph (K) of paragraph (2) of subsection (a) of Section 1-75 and paragraph (3) of subsection (a) of Section 1-75 of the Illinois Power Agency Act. "Public works" does not include work done directly by any public utility company, whether or not done under public supervision or direction, or paid for wholly or in part out of public funds. "Public works" also includes any corrective action performed pursuant to Title XVI of the Environmental Protection Act for which payment from the Underground Storage Tank Fund is requested. "Public works" does not include projects undertaken by the owner at an owner-occupied single-family residence or at an owner-occupied unit of a multi-family residence. "Public works" does not include work performed for soil and water conservation purposes on agricultural lands, whether or not done under public supervision or paid for wholly or in part out of public funds, done directly by an owner or person who has legal control of those lands.

"Construction" means all work on public works involving laborers, workers or mechanics. This includes any maintenance, repair, assembly, or disassembly work performed on equipment whether owned, leased, or rented.

"Locality" means the county where the physical work upon public works is performed, except (1) that if there is not available in the county a sufficient number of competent skilled laborers, workers and mechanics to construct the public works efficiently and properly, "locality" includes any other county nearest the one in which the work or construction is to be performed and from which such persons may be obtained in sufficient numbers to perform the work and (2) that, with respect to contracts for highway work with the Department of Transportation of this State, "locality" may at the discretion of the Secretary of the Department of Transportation be construed to include two or more adjacent counties from which workers may be accessible for work on such construction.

"Public body" means the State or any officer, board or commission of the State or any political subdivision or department thereof, or any institution supported in whole or in part by public funds, and includes every county, city, town, village, township, school district, irrigation, utility, reclamation improvement or other district and every other political subdivision, district or municipality of the state whether such political subdivision, municipality or district operates under a special charter or not.

"Labor organization" means an organization that is the exclusive representative of an employer's employees recognized or certified pursuant to the National Labor Relations Act.

The terms "general prevailing rate of hourly wages", "general prevailing rate of wages" or "prevailing rate of wages" when used in this Act mean the hourly cash wages plus annualized fringe benefits for training and apprenticeship programs approved by the U.S. Department of Labor, Bureau of Apprenticeship and Training, health and welfare, insurance, vacations and pensions paid generally, in the locality in which the work is being performed, to employees engaged in work of a similar character on public works.

(Source: P.A. 100-1177, eff. 6-1-19.)

Section 30-80. The Public Utilities Act is amended by changing Section 8-103B 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. "Black, indigenous, and people of color" and "BIPOC" means people who are members of the groups described in subparagraphs (a) through (e) of paragraph (A) of subsection (1) of Section 2 of the Business Enterprise for Minorities, Women, and Persons with Disabilities 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, 2021, the Illinois Commerce Commission shall establish additional cumulative persisting annual savings goals for the years 2031 through 2035. No later than December 31, 2024, 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 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 and through independent analysis, that 0.5 percentage point increases are not cost-effectively achievable. The Commission shall inform its decision based on an energy efficiency potential study that 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, 2021, the Illinois Commerce Commission shall establish additional cumulative persisting annual savings goals for the years 2031 through 2035. No later than December 31, 2024, 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 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 and through independent analysis, that 0.4 percentage point increases are not cost-effectively achievable. The Commission shall inform its decision based on an energy efficiency potential study that 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), 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 (7.5) (7) of subsection (g) of this Section be met through savings of fuels other than electricity.

(b-27) Beginning in 2022, an electric utility may offer and promote measures that electrify space heating, water heating, cooling, drying, cooking, industrial processes, and other building and industrial end uses that would otherwise be served by combustion of fossil fuel at the premises, provided that the electrification measures reduce total energy consumption at the premises. The electric utility may count the reduction in energy consumption at the premises toward achievement of its annual savings goals. The reduction in energy consumption at the premises shall be calculated as the difference between: (A) the reduction in Btu consumption of fossil fuels as a result of electrification, converted to kilowatt-hour equivalents by dividing by 3,412 Btu's per kilowatt hour; and (B) the increase in kilowatt hours of electricity consumption resulting from the displacement of fossil fuel consumption as a result of electrification. An electric utility may recover the costs of offering and promoting electrification measures under this subsection (b-27).

In no event shall electrification savings counted toward each year's applicable annual total savings requirement, as defined in paragraph (7.5) of subsection (g) of this Section, be greater than:

(1) 5% per year for each year from 2022 through 2025;

(2) 10% per year for each year from 2026 through 2029; and

(3) 15% per year for 2030 and all subsequent years. In addition, a minimum of 25% of all electrification savings counted toward a utility's applicable annual total savings requirement must be from electrification of end uses in low-income housing. The limitations on electrification savings that may be counted toward a utility's annual savings goals are separate from and in addition to the subsection (b-25) limitations governing the counting of the other fuel savings resulting from efficiency measures and programs.

As part of the annual informational filing to the Commission that is required under paragraph (9) of subsection (g) of this Section, each utility shall identify the specific electrification measures offered under this subjection (b-27); the quantity of each electrification measure that was installed by its customers; the average total cost, average utility cost, average reduction in fossil fuel consumption, and average increase in electricity consumption associated with each electrification measure; the portion of installations of each electrification measure that were in low-income single-family housing, low-income multifamily housing, non-low-income single-family housing, non-low-income multifamily housing, commercial buildings, and industrial facilities; and the quantity of savings associated with each measure category in each customer category that are being counted toward the utility's applicable annual total savings requirement. Prior to installing an electrification measure, the utility shall provide a customer with an estimate of the impact of the new measure on the customer's average monthly electric bill and total annual energy expenses.

(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, 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 $40,000,000 $25,000,000 per year for electric utilities that serve more than 3,000,000 retail customers in the State and no less than $13,000,000 $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. The ratio of spending on efficiency programs targeted at low-income multifamily buildings to spending on efficiency programs targeted at low-income single-family buildings shall be designed to achieve levels of savings from each building type that are approximately proportional to the magnitude of cost-effective lifetime savings potential in each building type. Investment in low-income whole-building weatherization programs shall constitute a minimum of 80% of a utility's total budget specifically dedicated to serving low-income customers.

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 multifamily customers (owners and residents).

The utilities shall invest in all health and safety measures appropriate and necessary for comprehensively weatherizing a home or multifamily building, and shall implement a health and safety fund of 0.5 at least 15% of the total income-qualified weatherization budget, for electric utilities that serve more than 3,000,000 retail customers in the State, and a minimum of 15% of the total portfolio budget, 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 multifamily 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. Utilities shall also ensure that thermal insulating materials used for energy efficiency programs targeted at low-income single-family and multifamily households do not contain any substance that is a Category 1 respiratory sensitizer as defined by Appendix A to 29 CFR 1910.1200 (Health Hazard Criteria: A.4 Respiratory or Skin Sensitization) that was intentionally added or is present at greater than 0.1% (1000 ppm) by weight in the product.

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). Each electric utility shall also track the types and quantities or volumes of insulation and air sealing materials, and their associated energy saving benefits, installed in energy efficiency programs targeted at low-income single-family and multifamily households.

The electric utilities shall participate in also convene a low-income energy efficiency accountability advisory committee ("the committee"), which will directly inform to assist in the design, implementation, and evaluation of the low-income and public-housing 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, public-housing organizations, and representatives of community-based organizations, especially those living in or working with environmental justice communities and BIPOC communities. The committee shall be composed of 2 geographically differentiated subcommittees: one for stakeholders in northern Illinois and one for stakeholders in central and southern Illinois. The subcommittees shall meet together at least twice per year.

There shall be one statewide leadership committee led by and composed of community-based organizations that are representative of BIPOC and environmental justice communities and that includes equitable representation from BIPOC communities. The leadership committee shall be composed of an equal number of representatives from the 2 subcommittees. The subcommittees shall address specific programs and issues, with the leadership committee convening targeted workgroups as needed. The leadership committee may elect to work with an independent facilitator to solicit and organize feedback, recommendations and meeting participation from a wide variety of community-based stakeholders. If a facilitator is used, they shall be fair and responsive to the needs of all stakeholders involved in the committee.

All committee meetings must be accessible, with rotating locations if meetings are held in-person, virtual participation options, and materials and agendas circulated in advance.

There shall also be opportunities for direct input by committee members outside of committee meetings, such as via individual meetings, surveys, emails and calls, to ensure robust participation by stakeholders with limited capacity and ability to attend committee meetings. Committee meetings shall emphasize opportunities to bundle and coordinate delivery of low-income energy efficiency with other programs that serve low-income communities, such as Solar for All and bill payment assistance programs. Meetings shall include educational opportunities for stakeholders to learn more about these additional offerings, and the committee shall assist in figuring out the best methods for coordinated delivery and implementation of offerings when serving low-income communities. The committee shall directly and equitably influence and inform utility low-income and public-housing energy efficiency programs and priorities. Participating utilities shall implement recommendations from the committee whenever possible.

Participating utilities shall track and report how input from the committee has led to new approaches and changes in their energy efficiency portfolios. This reporting shall occur at committee meetings and in quarterly energy efficiency reports to the Stakeholder Advisory Group and Illinois Commerce Commission, and other relevant reporting mechanisms. Participating utilities shall also report on relevant equity data and metrics requested by the committee, such as energy burden data, geographic, racial, and other relevant demographic data on where programs are being delivered and what populations programs are serving.

The Illinois Commerce Commission shall oversee and have relevant staff participate in the committee. The committee shall have a budget of 0.25% of each utility's entire efficiency portfolio funding for a given year. The budget shall be overseen by the Commission. The budget shall be used to provide grants for community-based organizations serving on the leadership committee, stipends for community-based organizations participating in the committee, grants for community-based organizations to do energy efficiency outreach and education, and relevant meeting needs as determined by the leadership committee. The education and outreach shall include, but is not limited to, basic energy efficiency education, information about low-income energy efficiency programs, and information on the committee's purpose, structure, and activities.

(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); 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), 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), 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 either (1) clear and convincing evidence demonstrates, through independent analysis, that the expenditure limits in subsection (m) of this Section preclude full achievement of the goals or (2) 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 and through independent analysis 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. If there is not clear and convincing evidence that achieving the savings goals specified in paragraph (b-5) or (b-15) of this Section is possible both cost-effectively and within the expenditure limits in subsection (m), such savings goals shall not be reduced. 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 either (1) clear and convincing evidence demonstrates, through independent analysis, that the expenditure limits in subsection (m) of this Section preclude full achievement of the goals or (2) 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 and through independent analysis 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. If there is not clear and convincing evidence that achieving the savings goals specified in paragraphs (b-5) or (b-15) of this Section is possible both cost-effectively and within the expenditure limits in subsection (m), such savings goals shall not be reduced. 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 either (1) clear and convincing evidence and independent analysis demonstrates that the expenditure limits in subsection (m) of this Section preclude full achievement of the goals or (2) 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 and through independent analysis 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. If there is not clear and convincing evidence that achieving the savings goals specified in paragraphs (b-5) or (b-15) of this Section is possible both cost-effectively and within the expenditure limits in subsection (m), such savings goals shall not be reduced. 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 105 days after June 1, 2017 (the effective date of Public Act 99-906). For those plans commencing after December 31, 2021, the Commission shall seek public comment on the utility's plan and shall issue an order approving or disapproving each plan within 6 months after its submission. If the Commission disapproves a plan, the Commission shall, within 30 days, describe in detail the reasons for the disapproval and describe a path by which the utility may file a revised draft of the plan to address the Commission's concerns satisfactorily. If the utility does not refile with the Commission within 60 days, the utility shall be subject to penalties at a rate of $100,000 per day until the plan is filed. This process shall continue, and penalties shall accrue, until the utility has successfully filed a portfolio of energy efficiency and demand-response measures. Penalties shall be deposited into the Energy Efficiency Trust Fund.

(g) In submitting proposed plans and funding levels 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) (Blank). Present specific proposals to implement new building and appliance standards that have been placed into effect.

(2.5) Demonstrate consideration of program options for (A) advancing new building codes, appliance standards, and municipal regulations governing existing and new building efficiency improvements and (B) supporting efforts to improve compliance with new building codes, appliance standards and municipal regulations, as potentially cost-effective means of acquiring energy savings to count toward savings goals.

(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 Percentage of 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 and for programs that target low-income customers, 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 expired 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. Savings may expire because measures installed in previous years have reached the end of their lives, because measures installed in previous years are producing lower savings in the current year than in the previous year, or for other reasons identified by independent evaluators. 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).

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 is equal to the applicable annual incremental goal plus the total new annual savings that are required to replace savings that expired in or at 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.

(9.5) The utility must demonstrate how it will ensure that program implementation contractors and energy efficiency installation vendors will promote workforce equity and quality jobs.

(9.6) Utilities shall collect data necessary to ensure compliance with paragraph (9.5) no less than quarterly and shall communicate progress toward compliance with paragraph (9.5) to program implementation contractors and energy efficiency installation vendors no less than quarterly. Utilities shall work with relevant vendors, providing education, training, and other resources needed to ensure compliance and, where necessary, adjusting or terminating work with vendors that cannot assist with compliance.

(10) Utilities required to implement efficiency programs under subsections (b-5) and (b-10) 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, including data on the implementation of paragraphs (9.5) and (9.6). If the utility is not meeting the requirements of paragraphs (9.5) and (9.6), the utility shall submit a plan to adjust their activities so that they meet the requirements of paragraphs (9.5) and (9.6) within the following year.

(h) No more than 4% 6% of energy efficiency and demand-response program revenue may be allocated for research, development, or pilot deployment of new equipment or measures. Electric utilities shall work with interested stakeholders to formulate a plan for how these funds should be spent, incorporate statewide approaches for these allocations, and file a four-year plan that demonstrates that collaboration. If a utility files a request for modified annual energy savings goals with the Commission, then a utility shall forgo spending portfolio dollars on research and development proposals.

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

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

(3) 4% for each of the 4 5 years beginning January 1, 2022 2026,

(4) 4.25% for the 4 years beginning January 1, 2026, and

(5) 4.25% plus an increase sufficient to account for the rate of inflation between January 1, 2026 and January 1 of the first year of each subsequent 4-year plan cycle, of the average amount paid per kilowatthour by residential eligible retail customers during calendar year 2015. An electric utility may plan to 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.

(n) A utility shall take advantage of the efficiencies available through existing Illinois Home Weatherization Assistance Program infrastructure and services, such as enrollment, marketing, quality assurance and implementation, which can reduce the need for similar services at a lower cost than utility-only programs, subject to capacity constraints at community action agencies, for both single-family and multifamily weatherization services, to the extent Illinois Home Weatherization Assistance Program CAAs provide multifamily services. A utility's plan shall demonstrate that in formulating annual weatherization budgets, it has sought input and coordination with community action agencies regarding agencies' capacity to expand and maximize Illinois Home Weatherization Assistance Program delivery using the ratepayer dollars collected under this Section.

(Source: P.A. 100-840, eff. 8-13-18; 101-81, eff. 7-12-19.)

Article 99. General Provisions

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