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.


LRB102 17909 JWD 25989 b

 

 

A BILL FOR

 

SB2896LRB102 17909 JWD 25989 b

1    AN ACT concerning regulation.
 
2    Be it enacted by the People of the State of Illinois,
3represented in the General Assembly:
 
4
Article 1. Consumers and Climate First

 
5    Section 1-1. Short title. This Article may be cited as the
6Consumers and Climate First Act. As used in this Article,
7"this Act" refers to this Article.
 
8    Section 1-5. Clean Energy Goals.
9    (a) Article XI of the Constitution of the State of
10Illinois provides that every citizen deserves a healthful
11environment, that it is the public policy of the State to
12maintain a healthful environment for this generation and
13future generations and that the General Assembly should enable
14this policy.
15    (b) To fulfill this policy, Illinois has a responsibility
16to protect its citizens and economy against the threats of
17climate change, including threats to our economy, health,
18safety, and national security.
19    (c) Moving Illinois toward a goal of 100% clean energy by
202050 is in furtherance of the State's policy to provide a
21healthful environment for its citizens. To accomplish this
22goal, the State must undertake several policy initiatives,

 

 

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1such as incentivizing renewable energy and other low or zero
2carbon sources of energy, adopting measures to reduce our
3energy usage, and improving the reliability and affordability
4of our energy system.
5    (d) The move toward 100% clean energy will allow Illinois
6to take advantage of the clean energy economy that can provide
7new quality jobs and economic opportunities, and wealth
8building in economically disadvantaged communities that have
9borne a disproportionate burden of pollution and climate
10change. It will further improve health outcomes through
11reduction of co-emissions of pollutants other than greenhouse
12gases for all citizens of the State. These improved health
13outcomes also provide economic benefits for the State.
14    (e) These initiatives must ensure that the development of
15a clean energy economy will provide benefits and opportunities
16for economically disadvantaged communities, communities of
17color and environmental justice communities, and a just
18transition for communities and workers who rely on existing
19power plants for jobs, property tax revenues, and other
20economic benefits.
21    (f) Energy efficiency should be prominent in the State's
22clean energy policy, since it is the most cost-effective
23energy resource. Energy efficiency upgrades help customers
24manage their individual energy bills, while reducing the total
25energy needs of the State and the cost of the energy system.
26    (g) The transportation sector is now the leading source of

 

 

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1carbon pollution in Illinois, responsible for roughly
2one-third of carbon emissions in the State. The State should
3adopt policies that will encourage and expand access to public
4transit, promote walking and biking mobility, and increase
5electric vehicle adoption. If properly implemented,
6transitioning to electric vehicles can greatly decrease
7emissions from the transportation sector, provide reliability
8assistance to the electric power grid, and potentially lower
9electric bills for customers by moving electric demand to
10off-peak hours.
11    (h) The transition to a clean energy economy will also
12provide an impetus for the development of new technologies and
13products and the potential for manufacturing some of these
14products in Illinois.
15    (i) Energy storage can provide many services and benefits
16to the electricity grid, including reducing peak load,
17frequency regulation, voltage support, and the greater
18utilization of renewable energy, which will provide many
19benefits.
20    (j) Greater implementation of these new technologies and
21generation sources will provide for greater customer choice in
22their energy sources and usage. To help further these goals,
23new and innovative regulatory policies are needed to
24transition to a more resilient grid that is equipped to
25implement the clean energy economy, while also achieving
26reliability and affordability goals.
 

 

 

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1
Article 5. Energy Transition

 
2    Section 5-1. Short title. This Article may be cited as the
3Energy Transition Act. As used in this Article, "this Act"
4refers to this Article.
 
5    Section 5-5. Definitions. As used in this Act:
6    "Clean Energy Jobs" means jobs in the solar energy, wind
7energy, energy efficiency, energy storage, solar thermal,
8hydrogen, carbon management, geothermal, electric vehicle
9industries, other renewable energy industries, industries
10achieving emission reductions, and other related sectors
11including related industries that manufacture, develop, build,
12maintain, or provide ancillary services to renewable energy
13resources or energy efficiency products or services, including
14the manufacture and installation of healthier building
15materials that contain fewer hazardous chemicals. "Clean
16Energy Jobs" include administrative, sales, other support
17functions within these industries and other related sector
18industries.
19    "Closure" means the permanent shutdown of an
20investor-owned electric generating unit or coal mine.
21    "Community-based organization" means an organization that:
22(1) provides employment, skill development or related services
23to members of the community; (2) includes community colleges,

 

 

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1nonprofits, and local governments; (3) has at least one main
2operating office in the community or region it serves; and (4)
3demonstrates relationships with local residents and other
4organizations serving the community.
5    "Community-based provider" means a not-for-profit
6organization that has a history of serving low-wage,
7low-skilled workers, or individuals from economically
8disadvantaged communities.
9    "Department" means the Department of Commerce and Economic
10Opportunity, unless the text solely specifies a particular
11Department.
12    "Director" means the Director of Commerce and Economic
13Opportunity.
14    "Displaced energy worker" means an energy worker who has
15lost employment, or is anticipated by the Department to lose
16employment within the next 2 years, due to the reduced
17operation or closure of a fossil fuel power plant, nuclear
18power plant, or coal mine.
19    "Economically disadvantaged community" means areas of one
20or more census tracts where average household income does not
21exceed 80% of area median income.
22    "Equity focused populations" means (1) low-income persons;
23(2) persons residing in equity investment eligible
24communities; (3) persons who identify as Black, Indigenous,
25and People of Color (BIPOC); (4) justice-involved persons; (5)
26persons who are or were in the child welfare system; (6) energy

 

 

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1workers; (7) dependents of displaced energy workers; (8)
2women; (9) LGBTQ+, transgender, or gender nonconforming
3persons; (10) persons with disabilities, and (11) members of
4any of these groups who are also youth.
5    "Equity investment eligible community" or "eligible
6community" mean people living in geographic areas throughout
7Illinois who will most benefit from equitable investments by
8the State that are designed to combat historic inequities and
9the effects of discrimination. "Eligible community" includes
10census tracts that meet the following characteristics:
11        (1) At least 15% of households or at least 20% of the
12    population 18 or under fall below the federal poverty
13    level; and
14        (2) falls in the top 25th percentile in the State on
15    measured levels for one or more of the following
16    environmental indicators from the United States
17    Environmental Protection Agency's EJSCREEN screening tool:
18            (A) Diesel particulate matter level in air.
19            (B) Air toxics cancer risk.
20            (C) Air toxics respiratory hazard index.
21            (D) Indicator for major direct dischargers to
22        water.
23            (E) Proximity to National Priorities List (NPL)
24        sites.
25            (F) Proximity to Risk Management Plan (RMP)
26        facilities.

 

 

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1            (G) Proximity to Treatment and Storage and
2        Disposal (TSDF) facilities.
3            (H) Ozone level in air.
4            (I) PM2.5 (particulate matter with diameters that
5        are 2.5 micrometers and smaller) level in the air.
6    "Equity investment eligible persons" or "eligible persons"
7means persons who would most benefit from equitable
8investments by the State designed to combat discrimination,
9specifically:
10        (1) persons whose primary residence is in an equity
11    investment eligible community;
12        (2) persons whose primary residence is in a
13    municipality or a county with a population under 100,000
14    where the closure of an electric generating unit or coal
15    mine has been publicly announced, or the electric
16    generating unit or coal mine is in the process of closing
17    or has closed within the last 5 years;
18        (3) persons who are graduates of or currently enrolled
19    in the foster care system; or
20        (4) persons who were formerly incarcerated.
21    "Plant owner" means the owners of an investor-owned
22electric generating unit with a nameplate capacity of greater
23than 300 megawatts.
 
24    Section 5-10. Findings. The General Assembly finds that
25the clean energy sector is a growing area of the economy in the

 

 

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1State of Illinois. The General Assembly further finds that
2State investment in the clean energy economy in Illinois can
3be a vehicle for expanding equitable access to public health,
4safety, a cleaner environment, quality jobs, and economic
5opportunity.
6    It is in the public policy interest of the State to ensure
7that Illinois residents from communities disproportionately
8impacted by climate change, facing coal plant or coal mine
9closures, economically disadvantaged communities, and
10individuals experiencing barriers to employment have access to
11State programs and good jobs and career opportunities in
12growing sectors of the State economy. To promote those
13interests in the growing clean energy sector, the General
14Assembly hereby creates the Energy Transition Act to increase
15access to and opportunities for education, training, and
16support services Illinois residents from communities
17disproportionately impacted by climate change, facing coal
18plant or coal mine closures, economically disadvantage
19communities, and individuals experiencing barriers to
20employment need to succeed in the labor market generally and
21the clean energy sector specifically. The General Assembly
22further finds that the programs included in the Energy
23Transition Act are essential to equitable, statewide access to
24quality training, jobs, and economic opportunities across the
25clean energy sector.
 

 

 

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1    Section 5-15. Regional administrators.
2    (a) Subject to appropriations, the Department shall select
33 unique regional administrators: one regional administrator
4for coordination of the work in the Northern Illinois Program
5Delivery Area, one regional administrator selected for
6coordination of the work in the Central Illinois Program
7Delivery Area, and one regional administrator selected for
8coordination of the work in the Southern Illinois Program
9Delivery Area.
10(b) The Clean Jobs Workforce Network Hubs Program shall be
11administered by 3 regional administrators selected under this
12Section 5-15.
13    (c) The regional administrators shall have: strong
14capabilities, experience, and knowledge related to program
15development and fiscal management; cultural and language
16competency needed to be effective in their respective
17communities to be served; expertise in working in and with
18BIPOC and environmental justice communities; knowledge and
19experience in working with employer or sectoral partnerships,
20if applicable, in clean energy or related sectors; and
21awareness of industry trends and activities, workforce
22development best practices, regional workforce development
23needs, regional and industry employers, and community
24development. The regional administrators shall demonstrate a
25track record of strong partnerships with community-based
26organizations.

 

 

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1    (d) The regional administrators shall work together to
2coordinate the implementation of the Clean Jobs Workforce
3Program.
 
4    Section 5-20. Clean Jobs Workforce Network Program.
5    (a) Subject to appropriations, the Department shall
6develop, and through regional administrators administer, the
7Clean Jobs Workforce Network Program ("Program") to create a
8network of 16 Program delivery Hub Sites with program elements
9delivered by community-based organizations and their
10subcontractors geographically distributed across the State.
11        (1) The Clean Jobs Workforce Hubs Network shall be
12    made up of 16 Program delivery Hub Sites geographically
13    distributed across the State, including at least one Hub
14    Site located in or near each of the following areas:
15    Chicago (South Side), Chicago (Southwest and West Sides),
16    Waukegan, Rockford, Aurora, Joliet, Peoria, Champaign,
17    Danville, Decatur, Carbondale, East St. Louis, and Alton.
18        (2) Three additional Hub Sites shall be determined by
19    the Department. One of the additional sites shall be
20    located in the Northern Illinois Program Delivery Area
21    covering Northern Illinois, one of the additional sites
22    shall be located in the Central Illinois Program Delivery
23    Area covering Central Illinois, and one of the additional
24    sites shall be located in the Southern Illinois Program
25    Delivery Area covering Southern Illinois.

 

 

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1    (b) The Program shall be available to members of one or
2more of the population groups listed as equity focused
3populations across the State to enter and complete the career
4pipeline for clean energy jobs, with the goal of serving all of
5the equity focused populations distributed across the network.
6    (c) The Program shall be available to members of one or
7more of the population groups listed as equity focused
8populations from communities in the following order of
9priority: (i) communities that host coal-fired power plants or
10coal mines, or both; and (ii) communities across the State.
11    (d) Program elements for each Hub Site shall be provided
12by a community-based organization. The Department shall
13initially select a community-based organization in each Hub
14Site and shall subsequently select a community-based
15organization in each Hub Site every 3 years. Community-based
16organizations delivering program elements outlined in
17subsection (e) may provide all elements required or may
18subcontract to other entities for provision of portions of
19program elements, including, but not limited to,
20administrative soft and hard skills for program participants,
21delivery of specific training in the core curriculum, or
22provision of other support functions for program delivery
23compliance.
24    (e) The Clean Jobs Workforce Hubs Network shall:
25        (1) coordinate with Energy Transition Navigators:
26            (A) to increase participation in the Clean Energy

 

 

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1        Workforce Network and clean energy and related sector
2        workforce and training opportunities;
3            (B) coordinate recruitment, communications, and
4        ongoing engagement with potential employers,
5        including, but not limited to, activities such as job
6        matchmaking initiatives, hosting events such as job
7        fairs, and collaborating with other Hub Sites to
8        identify and implement best practices for employer
9        engagement;
10            (C) leverage community-based organizations,
11        educational institutions, and community-based and
12        labor-based training providers to ensure members of
13        equity focused populations across the State have
14        dedicated and sustained support to enter and complete
15        the career pipeline for clean energy and related
16        sector jobs; and
17            (D) develop formal partnerships, including formal
18        sector partnerships between community-based
19        organizations and (a) trades groups, (b) labor unions,
20        and (c) entities that provide clean energy jobs,
21        including businesses, nonprofit organizations, and
22        worker-owned cooperatives to ensure that Program
23        participants have priority access to high-quality
24        preapprenticeship, apprenticeship, and other
25        employment training and hiring opportunities.
26        (2) implement the Clean Jobs Curriculum to provide,

 

 

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1    which may include, but is not limited to, training,
2    preapprenticeship, certification preparation, job
3    readiness, and skill development, including soft skills,
4    math skills, technical skills, certification test
5    preparation, and other development needed, to Program
6    participant members of disadvantaged communities specified
7    in subsection (b) of this Section.
8    (f) Funding for the Program shall be made available from
9the Energy Transition Assistance Fund.
10    (g) The Department shall require submission of quarterly
11reports including program performance metrics by each Hub Site
12to the regional administrator of their Program Delivery Area.
13Program performance measures include, but are not limited to:
14        (1) demographic data, including racial, gender, and
15    geographic distribution data, on Program trainees entering
16    and graduating the Program;
17        (2) demographic data, including racial, gender, and
18    geographic distribution data, on Program trainees who are
19    placed in employment, including the percentages of
20    trainees by race, gender, and geographic categories in
21    each individual job type or category and whether
22    employment is union, nonunion, or nonunion via temp
23    agency;
24        (3) trainee job acquisition and retention statistics,
25    including the duration of employment (start and end dates
26    of hires) by race, gender, and geography;

 

 

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1        (4) hourly wages, including hourly overtime pay rate,
2    and benefits of trainees placed into employment by race,
3    gender, and geography;
4        (5) percentage of jobs by race, gender, and geography
5    held by Program trainees or graduates that are full-time
6    equivalent positions, meaning that the position held is
7    full-time, direct, and permanent based on 2,080 hours
8    worked per year (paid directly by the employer, whose
9    activities, schedule, and manner of work the employer
10    controls, and receives pay and benefits in the same manner
11    as permanent employees); and
12        (6) qualitative data consisting of open-ended
13    reporting on pertinent issues, including, but not limited
14    to, qualitative descriptions accompanying metrics or
15    identifying key successes and challenges.
16    (h) Within 3 years of the effective date, the Department
17shall select an independent evaluator to review and prepare a
18report on the performance of the Program and regional
19administrators.
 
20    Section 5-25. Clean Jobs Curriculum.
21    (a) The Department shall convene a comprehensive
22stakeholder process that includes representatives from the
23Illinois State Board of Education, the Illinois Community
24College Board, the Department of Labor, community-based
25organizations, workforce development providers, labor unions,

 

 

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1building trades, educational institutions, residents of BIPOC
2and low-income communities, residents of environmental justice
3communities, clean energy businesses, nonprofit organizations,
4worker-owned cooperatives, other groups that provide clean
5energy jobs opportunities, and other participants to identify
6the career pathways and training curriculum needed to prepare
7workers to enter clean energy jobs and build careers. The
8curriculum shall:
9        (1) identify the core training curricular competency
10    areas needed to prepare workers to enter clean energy and
11    related sector jobs, such as those included in, but not
12    limited to, the Multi-Craft Core Curriculum, U.S.
13    Department of Labor Employment and Training
14    Administration-sponsored CareerOneStop Renewable Energy
15    Competency Model, the Electric Vehicle Infrastructure
16    Training Program;
17        (2) identify a set of certifications for clean energy
18    and related sector job types to be included in respective
19    training programs and used to inform core training
20    Curricular competency areas, such as, but not limited to,
21    North American Board of Certified Energy Practitioners
22    (NABCEP) Board Certifications, Interstate Renewable Energy
23    Council (IREC) Accredited Certificate Programs, American
24    Society of Heating, Refrigerating and Air-Conditioning
25    Engineers (ASHRAE) ANSI/ISO accreditation standard
26    certifications, Electric Vehicle Infrastructure Training

 

 

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1    Program Certifications, and UL Certification for EV
2    infrastructure;
3        (3) identify a set of required core cross-training
4    competencies provided in each training area for clean
5    energy jobs with the goal of enabling any trainee to
6    receive a standard set of skills common to multiple
7    training areas that would provide a foundation for
8    pursuing a career composed of multiple clean energy job
9    types;
10        (4) include approaches to integrate broad occupational
11    training to provide career entry into the general
12    construction and building trades sector and any remedial
13    education and work readiness support necessary to achieve
14    educational and professional eligibility thresholds;
15        (5) identify, directly or through references to
16    external resources, career pathways for clean energy jobs
17    types, such as, but not limited to, pathways identified
18    in: IREC Careers in Climate Control Technology Map, IREC
19    Solar Career Map for Workforce Training, NABCEP
20    Certification Career Map, and U.S. Department of Labor's
21    Bureau of Labor Statistics Green Jobs Initiative; and
22        (6) identify on-the-job training formats, where
23    relevant; and identify suggested trainer certification
24    standards, where relevant.
25    (b) The Department shall publish a report that includes
26the findings, recommendations, and core curriculum identified

 

 

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1by the stakeholder group and shall post a copy of the report on
2its public website. The Department shall convene the process
3described to update and modify the recommended curriculum
4every 3 years to ensure the curriculum contents are current to
5the evolving clean energy industries, practices, and
6technologies.
7    (c) Organizations that receive funding to provide training
8under the Clean Jobs Workforce Hubs Program, including, but
9not limited to, community-based and labor-based training
10providers, and educational institutions must use the core
11curriculum that is developed under this Section.
 
12    Section 5-30. Energy Transition Barrier Reduction Program.
13    (a) Subject to appropriations, the Department shall create
14and administer an Energy Transition Barrier Reduction Program.
15The Energy Transition Barrier Reduction Program shall be used
16to provide supportive services for individuals impacted by the
17energy transition. Services allowed are intended to help
18equity focused populations overcome financial and other
19barriers to participation in the Clean Jobs Workforce Program.
20    (b) The Program shall be available to members of one or
21more of the equity focused populations from communities in the
22following order of priority: (i) communities that host
23coal-fired power plants, or coal mines, or both; and (ii)
24communities across the State.
25    (c) The Department shall determine appropriate allowable

 

 

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1program costs, elements and financial supports to reduce
2barriers to successful participation in the Clean Jobs
3Workforce Program for equity focused populations.
4    (d) Community-based organizations and other nonprofits
5selected by the Department will be selected to provide
6supportive services described in this Section to equity
7focused populations participating in the Clean Jobs Workforce
8Program.
9    (e) The community-based organizations that provide support
10services under this Section shall coordinate with the Energy
11Transition Navigators to ensure equity focused populations
12have access to these services.
13    (f) Funding for the Program shall be made available from
14the Energy Transition Assistance Fund.
 
15    Section 5-35. Energy Transition Navigators.
16    (a) In order to engage equity focused populations to
17participate in the Clean Jobs Workforce Program and utilize
18the services offered under the Energy Transition Barrier
19Reduction Program, the Department shall, subject to
20appropriation, contract with community-based providers to
21conduct education, outreach, and recruitment services to
22equity focused populations to make sure they are aware of and
23engaged in the statewide and local workforce development
24systems. Additional strategies will include recruitment
25activities and events, among others.

 

 

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1    (b) For members of equity focused populations who may be
2interested in entrepreneurial pursuits, Energy Transition
3Navigators will connect these individuals with their area
4Small Business Development Center, Procurement Technical
5Assistance Centers, and/or economic development organization
6to engage in services such as business consulting, business
7planning, regulatory compliance, marketing, training,
8accessing capital, government bid, certification assistance,
9and others.
10    (c) Energy Transition Navigators will build strong
11relationships with equity focused populations, organizations
12working with these populations, local workforce innovation
13boards, and other stakeholders to coordinate outreach
14initiatives promoting information about the programs and
15services offered under the Clean Jobs Workforce Program and
16Energy Transition Barrier Reduction Program, and support
17clients applying for these services and programs.
18    (d) Community education, outreach, and recruitment about
19the Clean Jobs Workforce Program and Energy Transition Barrier
20Reduction Program will be targeted to the equity focused
21populations.
22    (e) Community-based providers will partner with
23educational institutions or organizations working with equity
24focused populations, local employers, labor unions, and others
25to identify members of equity focused populations in eligible
26communities who are unable to advance in their careers due to

 

 

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1inadequate skills. Community-based providers will provide
2information and consultation to equity focused populations on
3various educational opportunities and supportive services
4available to them.
5    (f) Community-based providers will establish partnerships
6with employers, educational institutions, local economic
7development organizations, environmental justice
8organizations, trades groups, labor unions, and entities that
9provide jobs, including businesses and other nonprofit
10organizations to target the skill needs of local industry. The
11community-based provider will work with local workforce
12innovation boards and other relevant partners to develop skill
13curriculum and career pathway support for disadvantaged
14individuals in equity focused populations that meets local
15employer's needs and establishes job placement opportunities
16after training.
17    (g) Funding for the Program shall be made available from
18the Energy Transition Assistance Fund.
19    (h) Priority in awarding grants under this Section will be
20given to organizations that also have experience serving
21equity investment eligible communities.
22    (i) Each community-based organization that receives
23funding from the Department as an Energy Transition Navigator
24shall provide an annual report to the Department by April 1 of
25each calendar year. The annual report shall include the
26following information:

 

 

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1        (1) a description of the community-based
2    organization's recruitment, screening, and training
3    efforts;
4        (2) the number of individuals who apply to,
5    participate in, and complete programs offered through the
6    Energy Transition Workforce Program, broken down by race,
7    gender, age, and location; and
8        (3) any other information deemed necessary by the
9    Department.
 
10    Section 5-40. Displaced Energy Workers Bill of Rights.
11    (a) The Department, in collaboration with the Illinois
12Department of Employment Security, shall have the authority to
13implement the Displaced Energy Workers Bill of Rights, and
14shall be responsible for the implementation of the Displaced
15Energy Workers Bill of Rights programs and rights created
16under this Section. Subject to appropriation, the Department
17shall provide the following benefits to displaced energy
18workers:
19        (1) The Department shall engage the employer and
20    energy workers no later than within 30 days of a closure or
21    deactivation notice being filed by the plant owner to the
22    Regional Transmission Organization of jurisdiction, within
23    30 days of the announced closure of a coal mine, or within
24    30 days of a WARN notice being filed with the Department,
25    whichever is first. The Department shall take reasonable

 

 

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1    steps to ensure that all displaced energy workers are
2    educated on the various programs available through the
3    Department to assist with the energy transition,
4    including, but not limited to, the Illinois Dislocated
5    Worker and Rapid Response programs. The Department will
6    develop an outreach strategy, workforce toolkit and quick
7    action plan to deploy when closures are announced. This
8    strategy will include identifying any additional resources
9    that may be needed to aid worker transitions that would
10    require contracting services.
11        (2) The Department shall provide information and
12    consultation to displaced energy workers on various
13    employment and educational opportunities available to
14    them, supportive services, and advise workers on which
15    opportunities meet their skills, needs, and preferences.
16            (A) Available services will include reemployment
17        services, training services, work-based learning
18        services, and financial and retirement planning
19        support.
20            (B) The Department will provide skills matching as
21        part of career counseling services to enable
22        assessment of the displaced energy worker's skills and
23        map those skills to emerging occupations in the region
24        or nationally, or both, depending on the displaced
25        worker's preferences.
26            (C) For energy workers who may be interested in

 

 

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1        entrepreneurial pursuits, the Department will connect
2        these individuals with their area Small Business
3        Development Center, Procurement Technical Assistance
4        Centers, and economic development organization to
5        engage in services including, but not limited to,
6        business consulting, business planning, regulatory
7        compliance, marketing, training, accessing capital,
8        and government bid certification assistance.
9    (b) Plant owners and the owners of coal mines located in
10Illinois shall be required to comply with the requirements set
11out in this subsection (b). The owners shall be required to
12take the following actions:
13        (1) provide written notice of deactivation or closure
14    filing with the Regional Transmission Organization of
15    jurisdiction to the Department within 48 hours, if
16    applicable;
17        (2) provide employment information for energy workers;
18    90 days prior to the closure of an electric generating
19    unit or mine, the owners of the power plant or mine shall
20    provide energy workers information on whether there are
21    employment opportunities provided by their employer; and
22        (3) annually report to the Department on announced
23    closures of qualifying facilities. The report must include
24    information on expected closure date, number of employees,
25    planning processes, services offered for employees (such
26    as training opportunities) leading up to the closure,

 

 

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1    efforts made to retain employees through other employment
2    opportunities within the company, and any other
3    information that the Department requires in order to
4    implement this Section.
5        (4) Ninety days prior to closure date, the owners of
6    the power plant or mine shall provide a final closure
7    report to the Department that includes expected closure
8    date, number of employees and salaries, transition support
9    the company is providing to employee and timelines,
10    including assistance for training opportunities,
11    transportation support or child care resources to attend
12    training, career counseling, resume support, and others.
13    The closure report will be made available to the chief
14    elected official of each municipal and county government
15    within which the employment loss, relocation, or mass
16    layoff occurs. It shall not be made publicly available.
17        (5) The owners of the power plant or mine will provide
18    job descriptions for each employee at the plant or mine to
19    the Department and the entity providing career and
20    training counseling.
21        (6) The owners of the power plant or mine will make
22    available to the Department and the entity providing
23    career and training counseling any industry related
24    certifications and on-the-job training the employee earned
25    to allow union training programs, Community Colleges, or
26    other certification programs to award credit for life

 

 

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1    experiences in order to reduce the amount of time to
2    complete training, certificates or degrees for the
3    dislocated employee.
 
4    Section 5-45. Displaced Energy Worker Dependent Transition
5Scholarship.
6    (a) Subject to appropriation, the benefits of this Section
7shall be administered by and paid for out of funds made
8available to the Illinois Student Assistance Commission.
9    (b) Any natural child, legally adopted child, or
10step-child of an eligible dislocated energy worker who
11possesses all necessary entrance requirements shall, upon
12application and proper proof, be awarded a transition
13scholarship consisting of the equivalent of one calendar year
14of full-time enrollment including summer terms, to the
15state-supported Illinois institution of higher learning of his
16or her choice.
17    (c) As used in this Section, "eligible dislocated energy
18worker" means an energy worker who has lost employment due to
19the reduced operation or closure of a fossil fuel power plant
20or coal mine.
21    (d) Full-time enrollment means 12 or more semester hours
22of courses per semester, or 12 or more quarter hours of courses
23per quarter, or the equivalent thereof per term. Scholarships
24utilized by dependents enrolled in less than full-time study
25shall be computed in the proportion which the number of hours

 

 

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1so carried bears to full-time enrollment.
2    (e) Scholarships awarded under this Section may be used by
3a child without regard to his or her age. The holder of a
4Scholarship awarded under this Section shall be subject to all
5examinations and academic standards, including the maintenance
6of minimum grade levels, that are applicable generally to
7other enrolled students at the Illinois institution of higher
8learning where the Scholarship is being used.
9    (f) An applicant is eligible for a scholarship under this
10Section when the Commission finds the applicant:
11        (1) is the natural child, legally adopted child, or
12    step-child of an eligible dislocated energy worker; and
13        (2) in the absence of transition scholarship
14    assistance, will be deterred by financial considerations
15    from completing an educational program at the
16    state-supported Illinois institution of higher learning of
17    his or her choice.
18    (g) Funds shall be made available from the Energy
19Transition Assistance Fund to the Commission to provide these
20grants.
21    (h) The scholarship shall only cover tuition and fees at
22the In-District/In-State rates but shall not exceed the cost
23equivalent of one calendar year of full-time enrollment,
24including summer terms, at the University of Illinois. The
25Commission shall determine the grant amount for each student.
 

 

 

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1    Section 5-50. Energy Transition Community Grants.
2    (a) Subject to appropriation, the Department shall
3establish an Energy Transition Community Grant Program to
4award grants to promote economic development in eligible
5communities.
6    (b) Funds shall be made available from the Energy
7Transition Assistance Fund to the Department to provide these
8grants.
9    (c) Communities eligible to receive these grants must meet
10one or more of the following:
11        (1) the area contains a fossil fuel or nuclear power
12    plant that was retired from service or has significantly
13    reduced service within 10 years before the application for
14    designation or will be retired or have service
15    significantly reduced within 5 years following the
16    application for designation;
17        (2) the area contains a coal mine that was closed or
18    had operations significantly reduced within 10 years
19    before the application for designation or is anticipated
20    to be closed or have operations; or
21        (3) the area contains a nuclear power plant that was
22    decommissioned, but continued storing nuclear waste before
23    the effective date of this Act.
24    (d) Local units of governments in eligible areas may join
25with any other local unit of government, economic development
26organization, local educational institutions, community-based

 

 

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1groups, or with any number or combination thereof to apply for
2the Energy Transition Community Grant.
3    (e) To receive grant funds, an eligible community must
4submit an application to the Department, using a form
5developed by the Department.
6    (f) For grants awarded to counties or other entities that
7are not the city that hosts or has hosted the investor-owned
8electric generating plant, a resolution of support for the
9project from the city or cities that hosts or has hosted the
10investor-owned electric generating plant is required to be
11submitted with the application.
12    (g) Grants must be used to plan for or address the economic
13and social impact on the community or region of plant
14retirement or transition.
15    (h) Project applications should include community input
16and consultation with a diverse set of stakeholders including,
17but not limited to: Regional Planning Councils, where
18applicable; economic development organizations; low-income or
19environmental justice communities; educational institutions;
20elected and appointed officials; organizations representing
21workers; and other relevant organizations.
22    (i) Grant costs are authorized to procure third-party
23vendors for grant writing and implementation costs, including
24for guidance and opportunities to apply for additional
25federal, State, local and private funding resources. If the
26application is approved for pre-award, one-time reimbursable

 

 

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1costs to apply for the Energy Transition Community Grant are
2authorized up to 3% of the award.
 
3    Section 5-55. Energy Transition Assistance Fund.
4    (a) The Energy Transition Assistance Fund is created as a
5special fund in the State treasury to be used by the Department
6for purposes provided under this Act. The Department shall be
7responsible for the administration of the Fund.
8    (b) The Department is authorized to utilize up to 10% of
9the Energy Transition Assistance Fund for administrative and
10operational expenses to implement the requirements of this
11Act.
12    (c) The Fund shall be used to fund the following programs:
13Energy Transition Community Grants, Energy Transition
14Workforce Program, Energy Transition Barrier Reduction
15Program, Displaced Energy Worker Dependent Scholarship, and
16Displaced Energy Worker Bill of Rights.
17    (d) The Department shall strive to direct at least 40% of
18the expenditures in the Fund toward programs that benefit
19equity investment eligible communities.
 
20    Section 5-60. State Energy Transition Council.
21    (a) The State Energy Transition Council is hereby created
22within the Department.
23    (b) The Council shall consist of the following members, or
24their respective designees, and a staff member from each

 

 

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1listed State agency to provide technical support to the
2Council:
3        the Director of Commerce and Economic Opportunity, who
4    shall serve as the chair of the Council;
5        the Director of Employment Security;
6        the Secretary of Human Services;
7        the Director of Labor;
8        the Director of the Illinois Environmental Protection
9    Agency;
10        the Executive Director of the Illinois Community
11    College Board;
12        the State Superintendent of Education; and
13        the directors of such other State agencies as a
14    majority of the Council may select.
15    The President of the Senate, the Minority Leader of the
16Senate, the Speaker of the House of Representatives, and the
17Minority Leader of the House of Representatives shall each
18appoint one member of the Council.
19    Members shall serve without compensation.
20    (c) The Council shall:
21        (1) further determine policy goals and plans of State
22    agency activity as it relates to workforce and economic
23    energy transition opportunities and support;
24        (2) align local, State and federal resources and
25    programming, and leverage additional resources and
26    programming, to invest in and support coal transition

 

 

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1    workers and coal transition communities;
2        (3) perform an assessment of existing tools and
3    support offered through federal and State programs to meet
4    the goals established by the Council;
5        (4) explore ways to support communities and energy
6    workers as the State of Illinois transitions to a clean
7    energy economy; and
8        (5) guide, inform and provide recommendations of
9    policy proposals offered by the Energy Transition Advisory
10    Council.
11    (d) The Council shall conduct its first meeting within 30
12days after all members have been appointed. The Council shall
13meet quarterly after its first meeting. Additional hearings
14and public meetings are permitted at the discretion of the
15members. The Council may meet in person or through video or
16audio conference.
 
17    Section 5-65. Energy Transition Advisory Council.
18    (a) The Energy Transition Advisory Council is hereby
19created within the Department.
20    (b) The Council shall consist of the following voting
21members:
22        (1) two members representing trade associations;
23        (2) two members representing a labor union;
24        (3) two members representing local communities
25    impacted by electric generating plant closures;

 

 

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1        (4) two members representing electric generating plant
2    operators;
3        (5) two members representing economic development
4    organizations;
5        (6) two low-income persons residing in coal
6    communities;
7        (7) two members representing higher education;
8        (8) two residents of environmental justice
9    communities;
10        (9) two members from community-based organizations in
11    environmental justice communities and community-based
12    organizations serving low-income persons and families;
13        (10) two members who are policy or implementation
14    experts on small business development, contractor
15    incubation, or small business lending and financing needs;
16        (11) two members who are policy or implementation
17    experts on workforce development for populations and
18    individuals such as low-income persons and families,
19    environmental justice communities, BIPOC communities,
20    justice-involved persons, persons who are or were in the
21    child welfare system, energy workers, gender nonconforming
22    and transgender individuals, and youth; and
23        (12) two representatives of clean energy businesses,
24    nonprofit organizations, or other groups that provide
25    clean energy.
26    The President of the Senate, the Minority Leader of the

 

 

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1Senate, the Speaker of the House of Representatives, and the
2Minority Leader of the House of Representatives shall each
3appoint one non-voting member of the Council.
4    (c) The Council shall:
5        (1) Coordinate and inform on worker and community
6    support priorities beyond current federal, State, local,
7    and private programs and resources.
8        (2) Advise and produce recommendations for further
9    federal, State, and local programs and activities.
10        (3) Other duties determined by the Council to further
11    the economic prosperity of the individuals and communities
12    impacted by the energy transition.
13    (d) The Council shall conduct its first meeting within 30
14days after all members have been appointed. The Council shall
15meet quarterly after its first meeting. Additional hearings
16and public meetings are permitted at the discretion of the
17members. The Council may meet in person or through video or
18audio conference.
19    (e) Members shall serve without compensation and may be
20reimbursed for reasonable expenses incurred in the performance
21of their duties from funds appropriated for that purpose.
 
22    Section 5-70. The Illinois Worker Adjustment and
23Retraining Notification Act is amended by changing Section 10
24as follows:
 

 

 

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1    (820 ILCS 65/10)
2    Sec. 10. Notice.
3    (a) An employer may not order a mass layoff, relocation,
4or employment loss unless, 60 days before the order takes
5effect, the employer gives written notice of the order to the
6following:
7        (1) affected employees and representatives of affected
8    employees; and
9        (2) the Department of Commerce and Economic
10    Opportunity and the chief elected official of each
11    municipal and county government within which the
12    employment loss, relocation, or mass layoff occurs.
13    (a-5) An employer of an investor-owned electric generating
14plant or coal mining operation may not order a mass layoff,
15relocation, or employment loss unless, 2 years before the
16order takes effect, the employer gives written notice of the
17order to the following:
18        (1) affected employees and representatives of affected
19    employees; and
20        (2) the Department of Commerce and Economic
21    Opportunity and the chief elected official of each
22    municipal and county government within which the
23    employment loss, relocation, or mass layoff occurs.
24    (b) An employer required to give notice of any mass
25layoff, relocation, or employment loss under this Act shall
26include in its notice the elements required by the federal

 

 

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1Worker Adjustment and Retraining Notification Act (29 U.S.C.
22101 et seq.).
3    (c) Notwithstanding the requirements of subsection (a), an
4employer is not required to provide notice if a mass layoff,
5relocation, or employment loss is necessitated by a physical
6calamity or an act of terrorism or war.
7    (d) The mailing of notice to an employee's last known
8address or inclusion of notice in the employee's paycheck
9shall be considered acceptable methods for fulfillment of the
10employer's obligation to give notice to each affected employee
11under this Act.
12    (e) In the case of a sale of part or all of an employer's
13business, the seller shall be responsible for providing notice
14for any plant closing or mass layoff in accordance with this
15Section, up to and including the effective date of the sale.
16After the effective date of the sale of part or all of an
17employer's business, the purchaser shall be responsible for
18providing notice for any plant closing or mass layoff in
19accordance with this Section. Notwithstanding any other
20provision of this Act, any person who is an employee of the
21seller (other than a part-time employee) as of the effective
22date of the sale shall be considered an employee of the
23purchaser immediately after the effective date of the sale.
24    (f) An employer which is receiving State or local economic
25development incentives for doing or continuing to do business
26in this State may be required to provide additional notice

 

 

SB2896- 36 -LRB102 17909 JWD 25989 b

1pursuant to Section 15 of the Business Economic Support Act.
2    (g) The rights and remedies provided to employees by this
3Act are in addition to, and not in lieu of, any other
4contractual or statutory rights and remedies of the employees,
5and are not intended to alter or affect such rights and
6remedies, except that the period of notification required by
7this Act shall run concurrently with any period of
8notification required by contract or by any other law.
9    (h) It is the sense of the General Assembly that an
10employer who is not required to comply with the notice
11requirements of this Section should, to the extent possible,
12provide notice to its employees about a proposal to close a
13plant or permanently reduce its workforce.
14(Source: P.A. 93-915, eff. 1-1-05.)
 
15
Article 10. Community Energy and Climate Planning

 
16    Section 10-1. Short title. This Article may be cited as
17the Community Energy and Climate Planning Act. References in
18this Article to "this Act" mean this Article.
 
19    Section 10-5. Findings and purpose. The General Assembly
20makes the following findings:
21    (1) The health, welfare, and prosperity of Illinois
22citizens require that Illinois take all steps possible to
23combat climate change, address harmful environmental impacts

 

 

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1deriving from the generation of electricity, ensure affordable
2utility service, equitable and affordable access to
3transportation, and clean, safe, affordable housing.
4    (2) The achievement of these goals will depend on strong
5community engagement to ensure that programs and policy
6solutions meet the needs of disparate communities.
7    (3) Ensuring that these goals are met without adverse
8impacts on utility bill affordability, housing affordability,
9and other essential services will depend on the coordination
10of policies and programs within local communities.
 
11    Section 10-10. Definitions. As used in this Act:
12    "Alternative energy improvement" means the installation or
13upgrade of electrical wiring, outlets, or charging stations to
14charge a motor vehicle that is fully or partially powered by:
15electricity; photovoltaic, energy storage, or thermal
16resource; or any combination thereof.
17    "Energy efficiency improvement" means equipment, devices,
18or materials intended to decrease energy consumption or
19promote a more efficient use of electricity, natural gas,
20propane, or other forms of energy on property, including, but
21not limited to, all of the following: (1) insulation in walls,
22roofs, floors, foundations, or heating and cooling
23distribution systems; (2) storm windows and doors,
24multi-glazed windows and doors, heat-absorbing or
25heat-reflective glazed and coated window and door systems, and

 

 

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1additional glazing, reductions in glass area, and other window
2and door system modifications that reduce energy consumption;
3(3) automated energy control systems; (4) high efficiency
4heating, ventilating, or air-conditioning and distribution
5system modifications or replacements; (5) caulking,
6weather-stripping, and air sealing; (6) replacement or
7modification of lighting fixtures to reduce the energy use of
8the lighting system; (7) energy controls or recovery systems;
9(8) day lighting systems; (9) any energy efficiency project,
10as defined in Section 825-65 of the Illinois Finance Authority
11Act; and (10) any other installation or modification of
12equipment, devices, or materials approved as a utility
13cost-savings measure by the governing body.
14    "Energy project" means the installation or modification of
15an alternative energy improvement, energy efficiency
16improvement, or water use improvement, or the acquisition,
17installation, or improvement of a renewable energy system that
18is affixed to a stabilized existing property (including new
19construction).
20    "Environmental justice communities" means the proposed
21definition of that term based on existing methodologies and
22findings used by the Illinois Power Agency and its
23Administrator in its Illinois Solar for All Program.
24    "Governing body" means the county board or board of county
25commissioners of a county, the city council of a city, or the
26board of trustees of a village. "Local unit of government"

 

 

SB2896- 39 -LRB102 17909 JWD 25989 b

1means a county, city, or village.
2    "Renewable energy resource" includes energy and its
3associated renewable energy credit or renewable energy credits
4from wind energy, solar thermal energy, geothermal energy,
5photovoltaic cells and panels, biodiesel, anaerobic digestion,
6and hydropower that does not involve new construction or
7significant expansion of hydropower dams. For purposes of this
8Act, landfill gas produced in the State is considered a
9renewable energy resource. "Renewable energy resource" does
10not include the incineration or burning of any solid material.
11    "Renewable energy system" means a fixture, product,
12device, or interacting group of fixtures, products, or devices
13on the customer's side of the meter that use one or more
14renewable energy resources to generate electricity, and
15specifically includes any renewable energy project, as defined
16in Section 825-65 of the Illinois Finance Authority Act.
17    "Water use improvement" means any fixture, product,
18system, device, or interacting group thereof for or serving
19any property that has the effect of conserving water resources
20through improved water management, efficiency, or thermal
21resource.
 
22    Section 10-15. Community Energy and Climate Plans;
23creation.
24    (a) Pursuant to the procedures in Section 10-20, a local
25unit of government may establish Community Energy and Climate

 

 

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1Plans and identify boundaries and areas covered by the Plans.
2    (b) Community Energy and Climate Plans are intended to aid
3local governments develop a comprehensive approach to
4combining different energy and climate programs and funding
5resources to achieve complementary impact. An effective
6planning process may:
7        (1) help communities discover ways that their local
8    government, businesses, and residents can control their
9    energy use and bills;
10        (2) ensure a cost-effective transition away from
11    fossil fuels in the transportation sector;
12        (3) expand access to workforce development and job
13    training opportunities in the emerging clean energy
14    economy;
15        (4) promote economic development through improvements
16    in community infrastructure, transit, and support for
17    local business;
18        (5) improve the health of Illinois communities by
19    reducing emissions, addressing existing brownfield areas,
20    and promoting the integration of distributed energy
21    resources;
22        (6) enable greater customer engagement, empowerment,
23    and options for energy services, and ultimately reduce
24    utility bills for Illinoisans;
25        (7) bring the benefits of grid modernization and the
26    deployment of distributed energy resources to economically

 

 

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1    disadvantaged communities throughout Illinois;
2        (8) support existing Illinois policy goals promoting
3    energy efficiency, demand response and investments in
4    renewable energy resources; and
5        (9) ensure minorities, women, people with
6    disabilities, and veterans meaningfully participate in the
7    transition to a clean energy economy.
8    (c) A Community Energy and Climate Plan may include
9discussion of:
10        (1) the demographics of the community, including
11    information on the mix of residential and commercial areas
12    and populations, ages, languages, education and workforce
13    training. This includes an examination of the average
14    utility bills paid within the community by class and
15    census area, the percentage and locations of individuals
16    requiring energy assistance, and the participation of
17    community members in other assistance programs. This also
18    includes an examination of the community's energy use, for
19    electricity, natural gas, transportation, and other fuels;
20        (2) the geography of the community, including the
21    amount of green space, brownfield sites, open space for
22    potential development, location of critical infrastructure
23    such as emergency response facilities, health care and
24    education facilities, and public transportation routes;
25    and
26        (3) information on economic development opportunities,

 

 

SB2896- 42 -LRB102 17909 JWD 25989 b

1    commercial usage, and employment opportunities.
2    (d) A Community Energy and Climate Plan may address the
3following areas:
4        (1) distributed energy resources, including energy
5    efficiency, demand response, dynamic pricing, energy
6    storage, solar (thermal, rooftop, and community);
7        (2) building codes (both commercial and residential);
8        (3) vehicle miles traveled; and
9        (4) transit options, including individual car
10    ownership, ride sharing, buses, trains, bicycles, and
11    pedestrian walkways.
12    (e) A Community Energy and Climate Plan may conclude with
13proposals to:
14        (1) increase the use of electricity as a
15    transportation fuel at multi-unit dwellings;
16        (2) maximize the system-wide benefits of
17    transportation electrification;
18        (3) test innovative load management programs or rate
19    structures associated with the use of electric vehicles by
20    residential customers to achieve customer fuel cost
21    savings relative to gasoline or diesel fuels and to
22    optimize grid efficiency;
23        (4) increase the integration of distributed energy
24    resources in the community;
25        (5) significantly expand the percentage of net-zero
26    housing and net-zero buildings in the community;

 

 

SB2896- 43 -LRB102 17909 JWD 25989 b

1        (6) improve utility bill affordability;
2        (7) increase mass transit ridership;
3        (8) decrease vehicle miles traveled;
4        (9) reduce local emissions of greenhouse gases, NOx,
5    SOx, particulate matter, and other air pollutants; and
6        (10) expand opportunities for minorities, women,
7    people with disabilities, and veterans to meaningfully
8    participate in the transition to a clean energy economy.
 
9    Section 10-20. Community Energy and Climate Planning
10Process.
11    (a) An effective planning process shall engage with a
12diverse set of stakeholders in local communities, including:
13environmental justice organizations; economic development
14organizations; faith-based nonprofit organizations;
15educational institutions; interested residents; health care
16institutions; tenant organizations; housing institutions,
17developers, and owners; elected and appointed officials; and
18representatives reflective of each local community.
19    (b) An effective planning process shall engage with
20individual members of the community as much as possible to
21ensure that the Plans receive input from as diverse a set of
22perspectives as possible.
23    (c) Plan materials and meetings related to the Plan shall
24be translated into languages that reflect the makeup of the
25local community.

 

 

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1    (d) The planning process shall be conducted in an ethical,
2transparent fashion, and will continually review its policies
3and practices to determine how best to meet its objectives.
4    (e) The Community Energy and Climate Plans shall take into
5account other applicable or relevant economic development
6plans, such as a Comprehensive Economic Development Strategy,
7developed by a local unit of government, economic development
8organization, or Regional Planning Council.
 
9    Section 10-25. Joint Community Energy and Climate Plans. A
10local unit of government may join with any other local unit of
11government, or with any public or private person, or with any
12number or combination thereof, under the Intergovernmental
13Cooperation Act, by contract or otherwise as may be permitted
14by law, for the implementation of a Community Energy and
15Climate Plan, in whole or in part.
 
16
Article 15. Minimum Energy and Water Efficiency Standards

 
17    Section 15-1. Short title. This Article may be cited as
18the Minimum Energy and Water Efficiency Standards Act.
19References in this Article to "this Act" mean this Article.
 
20    Section 15-5. Findings. The General Assembly finds that:
21        (1) Efficiency standards for certain products sold or
22    installed in the State assure consumers and businesses

 

 

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1    that such products meet minimum efficiency performance
2    levels, thus reducing energy and water waste and saving
3    consumers and businesses money on utility bills.
4        (2) Efficiency standards contribute to the economy of
5    this State by helping to better balance supply and demand
6    for both energy and water, thus reducing pressure that
7    creates higher natural gas, electricity, and water prices.
8    By saving consumers and businesses money on utility bills,
9    efficiency standards help the State and local economy,
10    since utility bill savings can be spent on local goods and
11    services.
12        (3) Such efficiency standards save energy and thus
13    reduce pollution and other environmental impacts
14    associated with the production, distribution, and use of
15    electricity, natural gas, and other fuels.
16        (4) Such water efficiency standards save water and
17    thus reduce the strain on the water supply. Furthermore,
18    improved water efficiency can reduce or delay the need for
19    water and sewer infrastructure improvements.
20        (5) Such efficiency standards can make electricity and
21    natural gas systems more reliable by reducing the strain
22    on systems during peak demand periods. Furthermore,
23    improved efficiency can reduce or delay the need for new
24    power plants, power transmission lines, and power
25    distribution system upgrades as well as new and expanded
26    gas pipelines.
 

 

 

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1    Section 15-10. Definitions. In this Act:
2    "Agency" means the Illinois Environmental Protection
3Agency.
4    "Air purifier", also known as "room air cleaner", means an
5electric, cord-connected, portable appliance with the primary
6function of removing particulate matter from the air and which
7can be moved from room to room.
8    "Cold-only unit" means a water cooler that dispenses cold
9water only.
10    "Cold temperature fluorescent lamp" means a fluorescent
11lamp that is not a compact fluorescent lamp that is: (1)
12specifically designed to start at -20° F when used with a
13ballast conforming to the requirements of ANSI C78.81 and ANSI
14C78.901; and (2) expressly designated as a cold temperature
15lamp both in markings on the lamp and in marketing materials,
16including catalogs, sales literature, and promotional
17materials.
18    "Commercial dishwasher" means a machine designed to clean
19and sanitize plates, pots, pans, glasses, cups, bowls,
20utensils, and trays by applying sprays of detergent solution
21(with or without blasting media granules) and a sanitizing
22rinse.
23    "Commercial fryer" means an appliance, including a cooking
24vessel, in which oil is placed to such a depth that the cooking
25food is essentially supported by displacement of the cooking

 

 

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1fluid rather than by the bottom of the vessel. Heat is
2delivered to the cooking fluid by means of an immersed
3electric element of band-wrapped vessel (electric fryers) or
4by heat transfer from gas burners through either the walls of
5the fryer or through tubes passing through the cooking fluid
6(gas fryers).
7    "Commercial hot-food holding cabinet" means a heated,
8fully enclosed compartment with one or more solid or
9transparent doors designed to maintain the temperature of hot
10food that has been cooked using a separate appliance.
11"Commercial hot-food holding cabinet" does not include heated
12glass merchandizing cabinets, drawer warmers, or cook-and-hold
13appliances.
14    "Commercial oven" means a chamber designed for heating,
15roasting, or baking food by conduction, convection, radiation,
16or electromagnetic energy.
17    "Commercial steam cooker" or "compartment steamer" means a
18device with one or more food-steaming compartments in which
19the energy in the steam is transferred to the food by direct
20contact and includes countertop models, wall-mounted models,
21and floor models mounted on a stand, pedestal, or
22cabinet-style base.
23    "Compensation" means money or any other valuable thing,
24regardless of form, received or to be received by a person for
25services rendered.
26    "Cook and cold unit" means a water cooler that dispenses

 

 

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1both cold and room temperature water.
2    "Decorative gas fireplace" means a vented fireplace,
3including appliances that are freestanding, recessed, zero
4clearance, or gas fireplace inserts, that is fueled by natural
5gas or propane, marked for decorative use only, and not
6equipped with a thermostat or intended for use as a heater.
7    "Dual-flush effective flush volume" means the average
8flush volume of 2 reduced flushes and one full flush.
9    "Dual-flush water closet" means a water closet
10incorporating a feature that allows the user to flush the
11water closet with either a reduced or a full volume of water.
12    "Electric vehicle supply equipment" means conductors,
13including, but not limited to, ungrounded, grounded, and
14equipment grounding conductors, electric vehicle connectors,
15attachment plugs, and all other fittings, devices, power
16outlets, or apparatuses installed specifically for the purpose
17of delivering energy from the premises wiring to an electric
18vehicle. "Electric vehicle supply equipment" includes charging
19cords with NEMA 5-15P and NEMA 5-20P attachment plugs.
20"Electric vehicle supply equipment" does not include
21conductors, connectors, and fittings that are part of an
22electric vehicle.
23    "Faucet" means a private lavatory faucet, residential
24kitchen faucet, metering faucet, public lavatory faucet, or
25replacement aerator for a private lavatory, public lavatory,
26or residential kitchen faucet.

 

 

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1    "Gas fireplace" means a decorative gas fireplace or a
2heating gas fireplace.
3    "Handheld shower head" means a shower head that can be
4held or fixed in place for the purpose of spraying water onto a
5bather and that is connected to a flexible hose.
6    "Heating gas fireplace" means a vented fireplace,
7including appliances that are freestanding, recessed, zero
8clearance, or gas fireplace inserts, that is fueled by natural
9gas or propane and is not a decorative fireplace.
10    "High color rendering index fluorescent lamp" or "high CRI
11fluorescent lamp" means a fluorescent lamp with a color
12rendering index of 87 or greater that is not a compact
13fluorescent lamp.
14    "Hot and cold unit" means a water cooler that dispenses
15hot, cold, or room temperature water.
16    "Impact-resistant fluorescent lamp" means a fluorescent
17lamp that is not a compact fluorescent lamp that:
18        (1) has a coating or equivalent technology that is
19    compliant with NSF/ANSI 51 and is designed to contain
20    glass if the glass envelope of the lamp is broken; and
21        (2) is designated and marketed for the intended
22    application, with:
23            (A) the designation on the lamp packaging; and
24            (B) marketing materials that identify the lamp as
25        being impact-resistant, shatter-resistant,
26        shatterproof, or shatter-protected.

 

 

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1    "Metering faucet" means a faucet with a fitting that, when
2turned on, will gradually shut itself off over a period of
3several seconds.
4    "On demand water cooler" means a water cooler that heats
5water as it is requested, typically taking a few minutes to
6deliver.
7    "Plumbing fixture" means an exchangeable device that
8connects to a plumbing system to deliver and drain away water
9and waste.
10    "Portable electric spa" means a factory-built electric spa
11or hot tub which may or may not include any combination of
12integral controls, water heating, or water circulating
13equipment.
14    "Pressure regulator" means a device that maintains
15constant operating pressure immediately downstream from the
16device, given higher pressure upstream.
17    "Public lavatory faucet" means a faucet with a fitting
18designed to be installed in nonresidential bathrooms that are
19exposed to walk-in traffic.
20    "Replacement aerator" means an aerator sold as a
21replacement, separate from the faucet to which it is intended
22to be attached.
23    "Residential ventilating fan" means a ceiling-mounted fan,
24wall-mounted fan, or remotely mounted in-line fan designed to
25be used in a bathroom or utility room for the purpose of moving
26air from inside the building to the outdoors.

 

 

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1    "Shower head" means a device through which water is
2discharged for a shower bath. "Shower head" includes a
3handheld shower head. "Shower head" does not include a shower
4head for a safety shower.
5    "Spray sprinkler body" means the exterior case or shell of
6a sprinkler incorporating a means of connection to the piping
7system designed to convey water to a nozzle or orifice.
8    "State-regulated general service lamp" means any of the
9following medium-base incandescent light bulbs:
10        (1) Reflector lamps that are:
11            (A) ER30, BR30, BR40, or ER40 lamps rated at 50
12        watts or less;
13            (B) BR30, BR40, or ER40 lamps rated at 65 watts; or
14            (C) R20 lamps rated at 45 watts or less.
15        (2) B, BA, CA, F, and G shape lamps, as defined in ANSI
16    C79.1:2002 with a lumen output of greater than or equal to
17    200 and rated at 40 watts or less.
18        (3) A and C shape lamps, as defined in ANSI C79.1:2002
19    with lumen output greater than or equal to 200 and less
20    than 310.
21        (4) Shatter-resistant lamps.
22        (5) 3-way lamps.
23    "Storage-type water cooler" means a water cooler in which
24thermally conditioned water is stored in a tank in the water
25cooler and is available instantaneously. "Storage-type water
26cooler" includes point-of-use, dry storage compartment, and

 

 

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1bottled water coolers.
2    "Trough-type urinal" means a urinal designed for
3simultaneous use by 2 or more persons.
4    "Urinal" means a plumbing fixture that receives only
5liquid body waste and conveys the waste through a trap into a
6drainage system.
7    "Water closet" means a plumbing fixture having a
8water-containing receptor that receives liquid and solid body
9waste through an exposed integral trap into a drainage system.
10    "Water cooler" means a freestanding device that consumes
11energy to cool or heat potable water.
 
12    Section 15-15. Scope.
13    (a) The provisions of this Act apply to:
14        (1) air purifiers;
15        (2) commercial dishwashers;
16        (3) commercial fryers;
17        (4) commercial hot-food holding cabinets;
18        (5) commercial ovens;
19        (6) commercial steam cookers;
20        (7) computers and computer monitors;
21        (8) electric vehicle supply equipment;
22        (9) faucets;
23        (10) gas fireplaces;
24        (11) high CRI, cold temperature, and impact-resistant
25    fluorescent lamps;

 

 

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1        (12) portable electric spas;
2        (13) residential ventilating fans;
3        (14) shower heads;
4        (15) spray sprinkler bodies;
5        (16) State-regulated general service lamps;
6        (17) urinals;
7        (18) water closets;
8        (19) water coolers; and
9        (20) any other products as may be designated by the
10    Agency in accordance with Section 15-30 or under Section
11    15-40.
12    (b) The provisions of this Act do not apply to:
13        (1) new products manufactured in the State and sold
14    outside the State;
15        (2) new products manufactured outside the State and
16    sold at wholesale inside the State for final retail sale
17    and installation outside the State;
18        (3) products installed in mobile manufactured homes at
19    the time of construction; or
20        (4) products designed expressly for installation and
21    use in recreational vehicles.
 
22    Section 15-20. Standards.
23    (a) Not later than one year after the effective date of
24this Act, the Agency shall adopt rules establishing minimum
25efficiency standards for the types of new products set forth

 

 

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1in Section 15-15.
2    (b) The rules shall provide for the following minimum
3efficiency standards:
4        (1) Air purifiers, except industrial air purifiers,
5    shall meet the following requirements as measured in
6    accordance with the ENERGY STAR Program Requirements
7    Product Specification for Room Air Cleaners, Version 2.0:
8            (A) clean air delivery rate for smoke shall be 30
9        or greater;
10            (B) for models with a clean air delivery rate for
11        smoke less than 100, clean air delivery rate per watt
12        for smoke shall be greater than or equal to 1.7;
13            (C) for models with a clean air delivery rate for
14        smoke greater than or equal to 100 and less than 150,
15        clean air delivery rate per watt for smoke shall be
16        greater than or equal to 1.9;
17            (D) for models with a clean air delivery rate for
18        smoke greater than or equal to 150, clean air delivery
19        rate per watt for smoke shall be greater than or equal
20        to 2.0;
21            (E) for ozone-emitting models, measured ozone
22        shall be less than or equal to 50 parts per billion
23        (ppb);
24            (F) for models with a Wi-Fi network connection
25        enabled by default when shipped, partial on mode power
26        shall not exceed 2 watts; and

 

 

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1            (G) For models without a Wi-Fi network connection
2        enabled by default when shipped, partial on mode power
3        shall not exceed 1 watt.
4        (2) Commercial dishwashers included in the scope of
5    the ENERGY STAR Program Requirements Product Specification
6    for Commercial Dishwashers, Version 2.0, shall meet the
7    qualification criteria of that specification.
8        (3) Commercial fryers included in the scope of the
9    ENERGY STAR Program Requirements Product Specification for
10    Commercial Fryers, Version 2.0, shall meet the
11    qualification criteria of that specification.
12        (4) Commercial hot-food holding cabinets shall meet
13    the qualification criteria of the ENERGY STAR Program
14    Requirements Product Specification for Commercial Hot Food
15    Holding Cabinets, Version 2.0.
16        (5) Commercial steam cookers shall meet the
17    requirements of the ENERGY STAR Program Requirements
18    Product Specification for Commercial Steam Cookers,
19    Version 1.2. Commercial ovens included in the scope of the
20    ENERGY STAR Program Requirements Product Specification for
21    Commercial Ovens, Version 2.2, shall meet the
22    qualification criteria of that specification.
23        (6) Computers and computer monitors shall be
24    consistent with similar energy and water efficiency
25    standards adopted federally and in other states.
26        (7) Electric vehicle supply equipment included in the

 

 

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1    scope of the ENERGY STAR Program Requirements Product
2    Specification for Electric Vehicle Supply Equipment,
3    Version 1.0 (Rev. April 2017), shall meet the
4    qualification criteria of that specification.
5        (8) Faucets, except for metering faucets, shall meet
6    the standards shown in this paragraph when tested in
7    accordance with Appendix S to Subpart B of Part 430 of
8    Title 10 of the Code of Federal Regulations and compliance
9    with those requirements shall be, "Uniform Test Method for
10    Measuring the Water Consumption of Faucets and
11    Showerheads", as in effect on January 1, 2020.
12            (A) Lavatory faucets and replacement aerators
13        shall not exceed a maximum flow rate of 1.5 gallons per
14        minute at 60 pounds per square inch.
15            (B) Residential kitchen faucets and replacement
16        aerators shall not exceed a maximum flow rate of 1.8
17        gallons per minute at 60 pounds per square inch, with
18        optional temporary flow of 2.2 gallons per minute,
19        provided they default to a maximum flow rate of 1.8
20        gallons per minute at 60 pounds per square inch after
21        each use.
22            (C) Public lavatory faucets and replacement
23        aerators shall not exceed a maximum flow rate of 0.5
24        gallons per minute at 60 pounds per square inch.
25        (9) Gas fireplaces shall comply with the following
26    requirements:

 

 

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1            (A) Gas fireplaces shall be capable of
2        automatically extinguishing any pilot flame when the
3        main gas burner flame is established and when it is
4        extinguished.
5            (B) Gas fireplaces must prevent any ignition
6        source for the main gas burner flame from operating
7        continuously for more than 7 days.
8            (C) Decorative gas fireplaces must have a direct
9        vent configuration, unless marked for replacement use
10        only.
11            (D) Heating gas fireplaces shall have a fireplace
12        efficiency greater than or equal to 50% when tested in
13        accordance with CSA P.4.1-15, "Testing Method for
14        Measuring Annual Fireplace Efficiency".
15        (10) High CRI, cold temperature, and impact-resistant
16    fluorescent lamps shall meet the minimum efficacy
17    requirements contained in Section 430.32(n)(4) of Title 10
18    of the Code of Federal Regulations as in effect on January
19    1, 2020, as measured in accordance with Appendix R to
20    Subpart B of Part 430 of Title 10 of the Code of Federal
21    Regulations, "Uniform Test Method for Measuring Average
22    Lamp Efficacy, Color Rendering Index, and Correlated Color
23    Temperature of Electric Lamps", as in effect on January 1,
24    2020.
25        (11) Portable electric spas shall meet the
26    requirements of the "American National Standard for

 

 

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1    Portable Electric Spa Energy Efficiency".
2        (12) In-line residential ventilating fans shall have a
3    fan motor efficacy of no less than 2.8 cubic feet per
4    minute per watt. All other residential ventilating fans
5    shall have a fan motor efficacy of no less than 1.4 cubic
6    feet per minute per watt for airflows less than 90 cubic
7    feet per minute and no less than 2.8 cubic feet per minute
8    per watt for other airflows when tested in accordance with
9    Home Ventilation Institute Publication 916 "HVI Airflow
10    Test Procedure".
11        (13) Shower heads shall not exceed a maximum flow rate
12    of 2.0 gallons per minute at 80 pounds per square feet when
13    tested in accordance with Appendix S to Subpart B of Part
14    430 of Title 10 of the Code of Federal Regulations and
15    compliance with those requirements shall be "Uniform Test
16    Method for Measuring the Water Consumption of Faucets and
17    Showerheads", as in effect on January 1, 2020.
18        (14) Spray sprinkler bodies that are not specifically
19    excluded from the scope of the WaterSense Specification
20    for Spray Sprinkler Bodies, Version 1.0, shall include an
21    integral pressure regulator and shall meet the water
22    efficiency and performance criteria and other requirements
23    of that specification.
24        (15) State-regulated general service lamps shall meet
25    or exceed a lamp efficacy of 45 lumens per watt when tested
26    in accordance with the federal test procedures for general

 

 

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1    service lamps, prescribed in Section 430.23(gg) of Title
2    10 of the Code of Federal Regulations as in effect on
3    January 1, 2020.
4        (16) Urinals and water closets, other than those
5    designed and marketed exclusively for use at prisons or
6    mental health facilities, shall meet the standards shown
7    in paragraphs (1) through (3) when tested in accordance
8    with Appendix T to Subpart B of Part 430 of Title 10 of the
9    Code of Federal Regulations, "Uniform Test Method for
10    Measuring the Water Consumption of Water Closets and
11    Urinals", as in effect on January 1, 2020, and water
12    closets shall pass the waste extraction test for water
13    closets of the American Society of Mechanical Engineers
14    A112.19.2/CSA B45.1-2018.
15            (A) Wall-mounted urinals, except for trough-type
16        urinals, shall have a maximum flush volume of 0.5
17        gallons per flush.
18            (B) Floor-mounted urinals, except for trough-type
19        urinals, shall have a maximum flush volume of 0.5
20        gallons per flush.
21            (C) Water closets, except for dual-flush tank-type
22        water closets, shall have a maximum flush volume of
23        1.28 gallons per flush.
24            (D) Dual-flush tank-type water closets shall have
25        a maximum dual-flush effective flush volume of 1.28
26        gallons per flush.

 

 

SB2896- 60 -LRB102 17909 JWD 25989 b

1        (18) Water coolers included in the scope of the ENERGY
2    STAR Program Requirements Product Specification for Water
3    Coolers, Version 2.0, shall have on mode with no water
4    draw energy consumption less than or equal the following
5    values as measured in accordance with the test
6    requirements of that program:
7            (A) 0.16 kilowatt-hours per day for cold-only
8        units and cook and cold units;
9            (B) 0.87 kilowatt-hours per day for storage-type
10        hot and cold units; and
11            (C) 0.18 kilowatt-hours per day for on demand hot
12        and cold units.
 
13    Section 15-25. Implementation.
14    (a) On or after January 1, 2023, no new air purifier, cold
15temperature fluorescent lamp, commercial dishwasher,
16commercial fryer, commercial hot-food holding cabinet,
17commercial oven, commercial steam cooker, computer or computer
18monitor, electrical vehicle supply equipment, faucet, gas
19fireplace, high CRI fluorescent lamp, impact-resistant
20fluorescent lamp, portable electric spa, residential
21ventilating fan, shower head, spray sprinkler body,
22State-regulated general service lamp, urinal, water closet, or
23water cooler may be sold or offered for sale, lease, or rent in
24the State unless the new product meets the requirements of the
25standards provided in Section 15-20.

 

 

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1    (b) No later than 6 months from the effective date of this
2Act, and as necessary thereafter, the Agency shall determine
3which general service lamps are subject to federal preemption.
4On or after January 1, 2022, no general service lamp that is
5not subject to federal preemption may be sold or offered for
6sale in the State unless the efficiency of the new product
7meets or exceeds the efficiency standards provided in Section
815-20.
9    (c) One year after the date upon which the sale or offering
10for sale of certain products becomes subject to the
11requirements of subsection (a) or (b) of this Section, no such
12products may be installed for compensation in the State unless
13the efficiency of the new product meets or exceeds the
14efficiency standards provided in Section 15-20.
 
15    Section 15-30. New and revised standards. The Agency may
16adopt rules, in accordance with the provisions of Illinois
17Administrative Procedure Act, to establish increased
18efficiency standards for the products listed or incorporated
19in Section 15-15. The Agency may also establish standards for
20products not specifically listed in Section 15-15.
 
21    Section 15-35. Protection against repeal of federal
22standards.
23    (a) If any of the energy or water conservation standards
24issued or approved for publication by the Office of the United

 

 

SB2896- 62 -LRB102 17909 JWD 25989 b

1States Secretary of Energy as of January 1, 2018, under the
2federal Energy Policy and Conservation Act, are withdrawn,
3repealed, or otherwise voided, the minimum energy or water
4efficiency level permitted for products previously subject to
5federal energy or water conservation standards shall be the
6previously applicable federal standards, and no such new
7product may be sold or offered for sale, lease or rent in the
8State unless it meets or exceeds such standards.
9    (b) This Section shall not apply to any federal energy or
10water conservation standard set aside by a court upon the
11petition of a person who will be adversely affected, as
12provided in Section 6306(b) of Title 42 of the United States
13Code.
 
14    Section 15-40. Testing, certification, labeling, and
15enforcement.
16    (a) The manufacturers of products covered by this Act
17shall test samples of their products in accordance with the
18test procedures adopted under this Act. The Agency may adopt
19updated test methods when new versions of test procedures
20become available.
21    (b) Manufacturers of new products covered by Section 15-15
22of this Act shall certify to the Agency that such products are
23in compliance with the provisions of this Act. Such
24certifications shall be based on test results. The Agency
25shall adopt rules governing the certification of such products

 

 

SB2896- 63 -LRB102 17909 JWD 25989 b

1and shall coordinate with the certification programs of other
2states and federal agencies with similar standards.
3    (c) Manufacturers of new products covered by Section 15-15
4of this Act shall identify each product offered for sale or
5installation in the State as in compliance with the provisions
6of this Act by means of a mark, label, or tag on the product
7and packaging at the time of sale or installation. The Agency
8shall adopt rules governing the identification of such
9products and packaging, which shall be coordinated to the
10greatest practical extent with the labeling programs of other
11states and federal agencies with equivalent efficiency
12standards. The Agency shall allow the use of existing marks,
13labels, or tags, which connote compliance with the efficiency
14requirements of this Act.
15    (d) The Agency may test products covered by Section 15-15.
16If products so tested are found not to be in compliance with
17the minimum efficiency standards established under Section
1815-20, the Agency shall:
19        (1) charge the manufacturer of such product for the
20    cost of product purchase and testing; and
21        (2) make information available to the public on
22    products found not to be in compliance with the standards.
23    (e) With prior notice and at reasonable and convenient
24hours, the Agency may cause periodic inspections to be made of
25distributors or retailers of new products covered by Section
2615-15 in order to determine compliance with the provisions of

 

 

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1this Act.
2    (f) The Agency shall investigate complaints received
3concerning violations of this Act and shall report the results
4of such investigations to the Attorney General. The Attorney
5General may institute proceedings to enforce the provisions of
6this Act. Any manufacturer, distributor, or retailer, or any
7person who installs a product covered by this Act for
8compensation, who violates any provision of this Act, shall be
9issued a warning by the Agency for any first violation and
10subject to a civil penalty of up to one hundred dollars for
11each offense. Repeat violations shall be subject to a civil
12penalty of not more than $500 for each offense. Each violation
13shall constitute a separate offense, and each day that such
14violation continues shall constitute a separate offense.
15    (g) The Agency may adopt such further rules as necessary
16to ensure the proper implementation and enforcement of the
17provisions of this Act.
 
18
Article 20. Electric Vehicle Charging Act

 
19    Section 20-1. Short title. This Article may be cited as
20the Electric Vehicle Charging Act. References in this Article
21to "this Act" mean this Article.
 
22    Section 20-5. Legislative intent. Electric vehicles are an
23important tool to fight the climate crisis, tackle air

 

 

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1pollution, and provide safe, clean, and affordable personal
2transportation. The State should encourage urgent and
3widespread adoption of electric vehicles. Since most current
4electric vehicle owners are single-family homeowners who
5charge at home, providing access to home charging for those in
6multi-unit dwellings is crucial to wider electric vehicle
7adoption. This includes condominium unit owners and renters,
8regardless of parking space ownership and regardless of
9income. Therefore, a significant portion of parking spaces in
10new and renovated residential and commercial developments must
11be capable of electric vehicle charging. Additionally, renters
12and condominium unit owners must be able to install charging
13equipment for their cars under reasonable conditions.
 
14    Section 20-10. Applicability. This Act applies to new or
15renovated residential or nonresidential buildings that have
16parking spaces and are constructed or renovated after the
17effective date of this Act.
 
18    Section 20-15. Definitions. As used in this Act:
19    "Association" has the meaning set forth in subsection (o)
20of Section 2 of the Condominium Property Act or Section 1-5 of
21the Common Interest Community Association Act, as applicable.
22    "Electric vehicle" means (i) a vehicle that is exclusively
23powered by and refueled by electricity, (2) must be plugged in
24to charge, and (3) is licensed to drive on public roadways.

 

 

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1"Electric vehicle" does not include (i) electric motorcycles,
2or (ii) hybrid electric vehicles and extended-range electric
3vehicles that are also equipped with conventional fueled
4propulsion or auxiliary engines.
5    "Electric vehicle capable" means having an installed
6electrical panel capacity with a dedicated branch circuit and
7a continuous raceway from the panel to the future electric
8vehicle parking space.
9    "Electric vehicle station" means a station that is
10designed in compliance with the relevant building code and
11delivers electricity from a source outside an electric vehicle
12into one or more electric vehicles.
13    "Electric vehicle system" includes several charging points
14simultaneously connecting several electric vehicles to the
15electric vehicle charging station and any related equipment
16needed to facilitate charging an electric vehicle. "Electric
17vehicle charging system" means a device that is:
18        (1) used to provide electricity to an electric
19    vehicle;
20        (2) designed to ensure that a safe connection has been
21    made between the electric grid and the electric vehicle;
22    and
23        (3) able to communicate with the vehicle's control
24    system so that electricity flows at an appropriate voltage
25    and current level. An electric vehicle charging system may
26    be wall mounted or pedestal style, may provide multiple

 

 

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1    cords to connect with electric vehicles, and shall:
2            (i) be certified by underwriters laboratories or
3        have been granted an equivalent certification; and
4            (ii) comply with the current version of Article
5        625 of the National Electrical Code.
6    "Electric vehicle supply equipment" means a conductor,
7including an ungrounded, grounded, and equipment grounding
8conductor, and electric vehicle connectors, attachment plugs,
9and all other fittings, devices, power outlets, and
10apparatuses installed specifically for the purpose of
11transferring energy between the premises wiring and the
12electric vehicle.
13    "Electric vehicle ready" means a parking space that is
14designed and constructed to include a fully wired circuit with
15a 208-volt to 250-volt, rated no more than 50-ampere electric
16vehicle charging receptacle outlet or termination point,
17including the conduit, wiring, and electrical service capacity
18necessary to serve that receptacle, to allow for future
19electric vehicle supply equipment.
20    "Level 1" means a charging system that provides charging
21through a 120-volt AC plug with a cord connector that meets the
22SAE International J2954 standard or successor standard.
23    "Level 2" means a charging system that provides charging
24through a 208-volt to 240-volt AC plug with a cord connector
25that meets the SAE International J2954 standard or a successor
26standard.

 

 

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1    "New" means any newly constructed building and associated
2newly constructed parking facility.
3    "Reasonable restriction" means a restriction that does not
4significantly increase the cost of the electric vehicle
5charging station or electric vehicle charging system or
6significantly decrease its efficiency or specified
7performance.
8    "Renovated" means altered or added where electrical
9service capacity is increased.
 
10    Section 20-20. Residential requirements. A new or
11renovated residential building shall have:
12        (1) 100% of its total parking spaces electric vehicle
13    ready, if there are one to 6 parking spaces;
14        (2) 100% of its total parking spaces electric vehicle
15    capable, of which at least 20% shall be electric vehicle
16    ready, if there are 6 to 23 parking spaces; or
17        (3) 100% of its total parking spaces electric vehicle
18    capable, if there are 24 or more parking spaces, of which
19    at least 5 spots shall be EV Ready. Additionally, if there
20    are 24 or more parking spaces, a new or renovated
21    residential building shall provide at least one parking
22    space with electric vehicle supply equipment installed,
23    and for each additional parking space with electric
24    vehicle supply equipment installed, the electric vehicle
25    ready requirement is decreased by 2%.

 

 

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1    Where additional parking exists or is feasible, each
2parking space shall be marked and signed for common use by
3residents. A resident shall use an electric vehicle parking
4space only when he or she is charging his or her electric
5vehicle.
 
6    Section 20-25. Nonresidential requirements. A new or
7renovated nonresidential building shall have 20% of its total
8parking spaces electric vehicle ready.
 
9    Section 20-30. Electric vehicle charging station policy
10for unit owners.
11    (a) Any covenant, restriction, or condition contained in
12any deed, contract, security interest, or other instrument
13affecting the transfer or sale of any interest in a
14condominium or common interest community, and any provision of
15a governing document that effectively prohibits or
16unreasonably restricts the installation or use of an electric
17vehicle charging station within a unit owner's unit or a
18designated parking space, including, but not limited to, a
19deeded parking space, a parking space in a unit owner's
20exclusive use common area, or a parking space that is
21specifically designated for use by a particular unit owner, or
22is in conflict with this Section, is void and unenforceable.
23    (b) This Section does not apply to provisions that impose
24a reasonable restriction on an electric vehicle charging

 

 

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1station. However, it is the policy of this State to promote,
2encourage, and remove obstacles to the use of an electric
3vehicle charging station.
4    (c) An electric vehicle charging station shall meet
5applicable health and safety standards and requirements
6imposed by State and local authorities, and all other
7applicable zoning, land use, or other ordinances or land use
8permits.
9    (d) If approval is required for the installation or use of
10an electric vehicle charging station, the association shall
11process and approve the application in the same manner as an
12application for approval of an architectural modification to
13the property, and the association shall not willfully avoid or
14delay the adjudication of the application. The approval or
15denial of an application shall be in writing.
16    (e) If the electric vehicle charging station is to be
17placed in a common area or exclusive use common area, as
18designated by the condominium or common interest community
19association, the following applies:
20        (1) The unit owner shall first obtain approval from
21    the association to install the electric vehicle charging
22    station and the association shall approve the installation
23    if the unit owner agrees, in writing, to:
24            (i) comply with the association's architectural
25        standards for the installation of the electric vehicle
26        charging station;

 

 

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1            (ii) engage a licensed electrical contractor to
2        install the electric vehicle charging station;
3            (iii) within 14 days after approval, provide a
4        certificate of insurance that names the association as
5        an additional insured party under the unit owner's
6        insurance policy as required under paragraph (3); and
7            (iv) pay for both the costs associated with the
8        installation of and the electricity usage associated
9        with the electric vehicle charging station.
10        (2) The unit owner, and each successive unit owner of
11    the electric vehicle charging station, is responsible for:
12            (i) costs for damage to the electric vehicle
13        charging station, common area, exclusive use common
14        area, or separate interests resulting from the
15        installation, maintenance, repair, removal, or
16        replacement of the electric vehicle charging station;
17            (ii) costs for the maintenance, repair, and
18        replacement of the electric vehicle charging station
19        until it has been removed, and for the restoration of
20        the common area after removal;
21            (iii) costs of electricity associated with the
22        charging station, which shall be based on:
23                (A) an inexpensive submetering device; or
24                (B) a reasonable calculation of cost, based on
25            the average miles driven, efficiency of the
26            electric vehicle calculated by the United States

 

 

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1            Environmental Protection Agency, and the cost of
2            electricity for the common area; and
3            (iv) disclosing to a prospective buyer the
4        existence of any electric vehicle charging station of
5        the unit owner and the related responsibilities of the
6        unit owner under this Section.
7        (3) The purpose of the costs under paragraph (2) is
8    for the reasonable reimbursement of electricity usage, and
9    shall not be set to deliberately exceed the reasonable
10    reimbursement.
11        (4) The unit owner of the electric vehicle charging
12    station, whether the electric vehicle charging station is
13    located within the common area or exclusive use common
14    area, shall, at all times, maintain a liability coverage
15    policy. The unit owner that submitted the application to
16    install the electric vehicle charging station shall
17    provide the association with the corresponding certificate
18    of insurance within 14 days after approval of the
19    application. The unit owner, and each successive unit
20    owner, shall provide the association with the certificate
21    of insurance annually thereafter.
22        (5) A unit owner is not required to maintain a
23    homeowner liability coverage policy for an existing
24    National Electrical Manufacturers Association standard
25    alternating current power plug.
26    (f) Except as provided in subsection (g), the installation

 

 

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1of an electric vehicle charging station for the exclusive use
2of a unit owner in a common area that is not an exclusive use
3common area shall be authorized by the association only if
4installation in the unit owner's designated parking space is
5impossible or unreasonably expensive. In such an event, the
6association shall enter into a license agreement with the unit
7owner for the use of the space in a common area, and the unit
8owner shall comply with all of the requirements in subsection
9(e).
10    (g) An association may install an electric vehicle
11charging station in the common area for the use of all unit
12owners and members of the association. The association shall
13develop appropriate terms of use for the electric vehicle
14charging station.
15    (h) An association may create a new parking space where
16one did not previously exist to facilitate the installation of
17an electric vehicle charging station.
18    (i) An association that willfully violates this Section
19shall be liable to the unit owner for actual damages and shall
20pay a civil penalty to the unit owner not to exceed $1,000.
21    (j) In any action by a unit owner requesting to have an
22electric vehicle charging station installed and seeking to
23enforce compliance with this Section, the court shall award
24reasonable attorney's fees to a prevailing plaintiff.
 
25    Section 20-35. Electric vehicle charging system policy for

 

 

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1renters.
2    (a) Notwithstanding any provision in the lease to the
3contrary, and subject to subsection (b):
4        (1) A tenant may install, at the tenant's expense for
5    the tenant's own use, a level 1 or level 2 electric vehicle
6    charging system on or in the leased premises.
7        (2) A landlord shall not assess or charge a tenant any
8    fee for the placement or use of an electric vehicle
9    charging system, except that:
10            (i) The landlord may:
11                (A) require reimbursement for the actual cost
12            of electricity provided by the landlord that was
13            used by the electric vehicle charging system; or
14                (B) charge a reasonable fee for access. If the
15            electric vehicle charging system is part of a
16            network for which a network fee is charged, the
17            landlord's reimbursement may include the amount of
18            the network fee. Nothing in this subparagraph
19            requires a landlord to impose upon a tenant a fee
20            or charge other than the rental payments specified
21            in the lease.
22            (ii) The landlord may require reimbursement for
23        the cost of the installation of the electric vehicle
24        charging system, including any additions or upgrades
25        to existing wiring directly attributable to the
26        requirements of the electric vehicle charging system,

 

 

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1        if the landlord places or causes the electric vehicle
2        charging system to be placed at the request of the
3        tenant.
4            (iii) If the tenant desires to place an electric
5        vehicle charging system in an area accessible to other
6        tenants, the landlord may assess or charge the tenant
7        a reasonable fee to reserve a specific parking space
8        in which to install the electric vehicle charging
9        system.
10    (b) A landlord may require a tenant to comply with:
11        (1) bona fide safety requirements consistent with an
12    applicable building code or recognized safety standard for
13    the protection of persons and property;
14        (2) a requirement that the electric vehicle charging
15    system be registered with the landlord within 30 days
16    after installation; or
17        (3) reasonable aesthetic provisions that govern the
18    dimensions, placement, or external appearance of an
19    electric vehicle charging system.
20    (c) A tenant may place an electric vehicle charging system
21in an area accessible to other tenants if:
22        (1) the electric vehicle charging system is in
23    compliance with all applicable requirements adopted by a
24    landlord under subsection (b); and
25        (2) the tenant agrees, in writing, to:
26            (i) comply with the landlord's design

 

 

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1        specifications for the installation of an electric
2        vehicle charging system;
3            (ii) engage the services of a duly licensed and
4        registered electrical contractor familiar with the
5        installation and code requirements of an electric
6        vehicle charging system; and
7            (iii) provide, within 14 days after receiving the
8        landlord's consent for the installation, a certificate
9        of insurance naming the landlord as an additional
10        insured party on the tenant's renter's insurance
11        policy for any claim related to the installation,
12        maintenance, or use of the electric vehicle charging
13        system or, at the landlord's option, reimbursement to
14        the landlord for the actual cost of any increased
15        insurance premium amount attributable to the electric
16        vehicle charging system, notwithstanding any provision
17        to the contrary in the lease. The tenant shall provide
18        reimbursement for an increased insurance premium
19        amount within 14 days after the tenant receives the
20        landlord's invoice for the amount attributable to the
21        electric vehicle charging system.
22    (d) If the landlord consents to a tenant's installation of
23an electric vehicle charging system on property accessible to
24other tenants, including a parking space, carport, or garage
25stall, then, unless otherwise specified in a written agreement
26with the landlord:

 

 

SB2896- 77 -LRB102 17909 JWD 25989 b

1        (1) The tenant, and each successive tenant with
2    exclusive rights to the area where the electric vehicle
3    charging system is installed, is responsible for costs for
4    damages to the electric vehicle charging system and to any
5    other property of the landlord or another tenant resulting
6    from the installation, maintenance, repair, removal, or
7    replacement of the electric vehicle charging system.
8            (i) Costs under this paragraph shall be based on:
9                (A) an inexpensive submetering device; or
10                (B) a reasonable calculation of cost, based on
11            the average miles driven, efficiency of the
12            electric vehicle calculated by the United States
13            Environmental Protection Agency, and the cost of
14            electricity for the common area.
15            (ii) The purpose of the costs under this paragraph
16        is for reasonable reimbursement of electricity usage
17        and shall not be set to deliberately exceed that
18        reasonable reimbursement.
19        (2) Each successive tenant with exclusive rights to
20    the area where the electric vehicle charging system is
21    installed shall assume responsibility for the repair,
22    maintenance, removal, and replacement of the electric
23    vehicle charging system until the electric vehicle
24    charging system is removed.
25        (3) The tenant, and each successive tenant with
26    exclusive rights to the area where the electric vehicle

 

 

SB2896- 78 -LRB102 17909 JWD 25989 b

1    charging system is installed, shall, at all times, have
2    and maintain an insurance policy covering the obligations
3    of the tenant under this subsection and shall name the
4    landlord as an additional insured party under the policy.
5        (4) The tenant, and each successive tenant with
6    exclusive rights to the area where the electric vehicle
7    charging system is installed, is responsible for removing
8    the system if reasonably necessary or convenient for the
9    repair, maintenance, or replacement of any property of the
10    landlord, whether or not leased to another tenant.
11    (e) An electric vehicle charging system installed at the
12tenant's cost is the property of the tenant. Upon termination
13of the lease, if the electric vehicle charging system is
14removable, the tenant may either remove it or sell it to the
15landlord or another tenant for an agreed price. Nothing in
16this subsection requires the landlord or another tenant to
17purchase the electric vehicle charging system.
18    (f) A landlord that willfully violates this Section shall
19be liable to the tenant for actual damages, and shall pay a
20civil penalty to the tenant in an amount not to exceed $1,000.
21    (g) In any action by a tenant requesting to have an
22electric vehicle charging system installed and seeking to
23enforce compliance with this Section, the court shall award
24reasonable attorney's fees to a prevailing plaintiff.
 
25
Article 30. Amendatory Provisions

 

 

 

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1    Section 30-10. The Illinois Governmental Ethics Act is
2amended by changing Sections 4A-102 and 4A-103 and by adding
3Section 1-121.5 as follows:
 
4    (5 ILCS 420/1-121.5 new)
5    Sec. 1-121.5. "Public utility" has the meaning provided in
6Section 3-105 of the Public Utilities Act.
 
7    (5 ILCS 420/4A-102)  (from Ch. 127, par. 604A-102)
8    Sec. 4A-102. The statement of economic interests required
9by this Article shall include the economic interests of the
10person making the statement as provided in this Section. The
11interest (if constructively controlled by the person making
12the statement) of a spouse or any other party, shall be
13considered to be the same as the interest of the person making
14the statement. Campaign receipts shall not be included in this
15statement.
16        (a) The following interests shall be listed by all
17    persons required to file:
18            (1) The name, address and type of practice of any
19        professional organization or individual professional
20        practice in which the person making the statement was
21        an officer, director, associate, partner or
22        proprietor, or served in any advisory capacity, from
23        which income in excess of $1200 was derived during the

 

 

SB2896- 80 -LRB102 17909 JWD 25989 b

1        preceding calendar year;
2            (2) The nature of professional services (other
3        than services rendered to the unit or units of
4        government in relation to which the person is required
5        to file) and the nature of the entity to which they
6        were rendered if fees exceeding $5,000 were received
7        during the preceding calendar year from the entity for
8        professional services rendered by the person making
9        the statement.
10            (3) The identity (including the address or legal
11        description of real estate) of any capital asset from
12        which a capital gain of $5,000 or more was realized in
13        the preceding calendar year.
14            (4) The name of any unit of government which has
15        employed the person making the statement during the
16        preceding calendar year other than the unit or units
17        of government in relation to which the person is
18        required to file.
19            (5) The name of any entity from which a gift or
20        gifts, or honorarium or honoraria, valued singly or in
21        the aggregate in excess of $500, was received during
22        the preceding calendar year.
23        (b) The following interests shall also be listed by
24    persons listed in items (a) through (f), item (l), item
25    (n), and item (p) of Section 4A-101:
26            (1) The name and instrument of ownership in any

 

 

SB2896- 81 -LRB102 17909 JWD 25989 b

1        entity doing business in the State of Illinois, in
2        which an ownership interest held by the person at the
3        date of filing is in excess of $5,000 fair market value
4        or from which dividends of in excess of $1,200 were
5        derived during the preceding calendar year. (In the
6        case of real estate, location thereof shall be listed
7        by street address, or if none, then by legal
8        description). No time or demand deposit in a financial
9        institution, nor any debt instrument need be listed;
10            (2) Except for professional service entities, the
11        name of any entity and any position held therein from
12        which income of in excess of $1,200 was derived during
13        the preceding calendar year, if the entity does
14        business in the State of Illinois. No time or demand
15        deposit in a financial institution, nor any debt
16        instrument need be listed.
17            (3) The identity of any compensated lobbyist with
18        whom the person making the statement maintains a close
19        economic association, including the name of the
20        lobbyist and specifying the legislative matter or
21        matters which are the object of the lobbying activity,
22        and describing the general type of economic activity
23        of the client or principal on whose behalf that person
24        is lobbying.
25        (c) The following interests shall also be listed by
26    persons listed in items (a) through (c) and item (e) of

 

 

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1    Section 4A-101.5:
2            (1) The name and instrument of ownership in any
3        entity doing business with a unit of local government
4        in relation to which the person is required to file if
5        the ownership interest of the person filing is greater
6        than $5,000 fair market value as of the date of filing
7        or if dividends in excess of $1,200 were received from
8        the entity during the preceding calendar year. (In the
9        case of real estate, location thereof shall be listed
10        by street address, or if none, then by legal
11        description). No time or demand deposit in a financial
12        institution, nor any debt instrument need be listed.
13            (2) Except for professional service entities, the
14        name of any entity and any position held therein from
15        which income in excess of $1,200 was derived during
16        the preceding calendar year if the entity does
17        business with a unit of local government in relation
18        to which the person is required to file. No time or
19        demand deposit in a financial institution, nor any
20        debt instrument need be listed.
21            (3) The name of any entity and the nature of the
22        governmental action requested by any entity which has
23        applied to a unit of local government in relation to
24        which the person must file for any license, franchise
25        or permit for annexation, zoning or rezoning of real
26        estate during the preceding calendar year if the

 

 

SB2896- 83 -LRB102 17909 JWD 25989 b

1        ownership interest of the person filing is in excess
2        of $5,000 fair market value at the time of filing or if
3        income or dividends in excess of $1,200 were received
4        by the person filing from the entity during the
5        preceding calendar year.
6        (d) The following interest shall also be listed by
7    persons listed in items (a) through (f) of Section 4A-101:
8    the name of any spouse or immediate family member living
9    with such person employed by a public utility in this
10    State and the name of the public utility that employs such
11    person.
12    For the purposes of this Section, the unit of local
13government in relation to which a person is required to file
14under item (e) of Section 4A-101.5 shall be the unit of local
15government that contributes to the pension fund of which such
16person is a member of the board.
17(Source: P.A. 101-221, eff. 8-9-19.)
 
18    (5 ILCS 420/4A-103)  (from Ch. 127, par. 604A-103)
19    Sec. 4A-103. The statement of economic interests required
20by this Article to be filed with the Secretary of State shall
21be filled in by typewriting or hand printing, shall be
22verified, dated, and signed by the person making the statement
23and shall contain substantially the following:
24
STATEMENT OF ECONOMIC INTEREST
25
(TYPE OR HAND PRINT)

 

 

SB2896- 84 -LRB102 17909 JWD 25989 b

1.............................................................
2(name)
3.............................................................
4(each office or position of employment for which this
5statement is filed)
6.............................................................
7(full mailing address)
8GENERAL DIRECTIONS:
9    The interest (if constructively controlled by the person
10making the statement) of a spouse or any other party, shall be
11considered to be the same as the interest of the person making
12the statement.
13    Campaign receipts shall not be included in this statement.
14    If additional space is needed, please attach supplemental
15listing.
16    1. List the name and instrument of ownership in any entity
17doing business in the State of Illinois, in which the
18ownership interest held by the person at the date of filing is
19in excess of $5,000 fair market value or from which dividends
20in excess of $1,200 were derived during the preceding calendar
21year. (In the case of real estate, location thereof shall be
22listed by street address, or if none, then by legal
23description.) No time or demand deposit in a financial
24institution, nor any debt instrument need be listed.
25Business EntityInstrument of Ownership
26..............................................................

 

 

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1..............................................................
2..............................................................
3..............................................................
4    2. List the name, address and type of practice of any
5professional organization in which the person making the
6statement was an officer, director, associate, partner or
7proprietor or served in any advisory capacity, from which
8income in excess of $1,200 was derived during the preceding
9calendar year.
10NameAddressType of Practice
11.............................................................
12.............................................................
13.............................................................
14    3. List the nature of professional services rendered
15(other than to the State of Illinois) to each entity from which
16income exceeding $5,000 was received for professional services
17rendered during the preceding calendar year by the person
18making the statement.
19.............................................................
20.............................................................
21    4. List the identity (including the address or legal
22description of real estate) of any capital asset from which a
23capital gain of $5,000 or more was realized during the
24preceding calendar year.
25.............................................................
26.............................................................

 

 

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1    5. List the identity of any compensated lobbyist with whom
2the person making the statement maintains a close economic
3association, including the name of the lobbyist and specifying
4the legislative matter or matters which are the object of the
5lobbying activity, and describing the general type of economic
6activity of the client or principal on whose behalf that
7person is lobbying.
8LobbyistLegislative MatterClient or Principal
9.............................................................
10.............................................................
11    6. List the name of any entity doing business in the State
12of Illinois from which income in excess of $1,200 was derived
13during the preceding calendar year other than for professional
14services and the title or description of any position held in
15that entity. (In the case of real estate, location thereof
16shall be listed by street address, or if none, then by legal
17description). No time or demand deposit in a financial
18institution nor any debt instrument need be listed.
19EntityPosition Held
20..............................................................
21..............................................................
22..............................................................
23    7. List the name of any unit of government which employed
24the person making the statement during the preceding calendar
25year other than the unit or units of government in relation to
26which the person is required to file.

 

 

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1.............................................................
2.............................................................
3    8. List the name of any entity from which a gift or gifts,
4or honorarium or honoraria, valued singly or in the aggregate
5in excess of $500, was received during the preceding calendar
6year.
7.............................................................
8    9. List the name of any spouse or immediate family member
9living with the person making this statement employed by a
10public utility in this State and the name of the public utility
11that employs the relative.
12Name and relation Public Utility
13............................... ...............................
14..............................................................
15..............................................................
16VERIFICATION:
17    "I declare that this statement of economic interests
18(including any accompanying schedules and statements) has been
19examined by me and to the best of my knowledge and belief is a
20true, correct and complete statement of my economic interests
21as required by the Illinois Governmental Ethics Act. I
22understand that the penalty for willfully filing a false or
23incomplete statement shall be a fine not to exceed $1,000 or
24imprisonment in a penal institution other than the
25penitentiary not to exceed one year, or both fine and
26imprisonment."

 

 

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1................  ..........................................
2(date of filing)   (signature of person making the statement)
3(Source: P.A. 95-173, eff. 1-1-08.)
 
4    Section 30-15. The Illinois Enterprise Zone Act is amended
5by changing Section 5.5 as follows:
 
6    (20 ILCS 655/5.5)   (from Ch. 67 1/2, par. 609.1)
7    Sec. 5.5. High Impact Business.
8    (a) In order to respond to unique opportunities to assist
9in the encouragement, development, growth, and expansion of
10the private sector through large scale investment and
11development projects, the Department is authorized to receive
12and approve applications for the designation of "High Impact
13Businesses" in Illinois subject to the following conditions:
14        (1) such applications may be submitted at any time
15    during the year;
16        (2) such business is not located, at the time of
17    designation, in an enterprise zone designated pursuant to
18    this Act;
19        (3) the business intends to do one or more of the
20    following:
21            (A) the business intends to make a minimum
22        investment of $12,000,000 which will be placed in
23        service in qualified property and intends to create
24        500 full-time equivalent jobs at a designated location

 

 

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1        in Illinois or intends to make a minimum investment of
2        $30,000,000 which will be placed in service in
3        qualified property and intends to retain 1,500
4        full-time retained jobs at a designated location in
5        Illinois. The business must certify in writing that
6        the investments would not be placed in service in
7        qualified property and the job creation or job
8        retention would not occur without the tax credits and
9        exemptions set forth in subsection (b) of this
10        Section. The terms "placed in service" and "qualified
11        property" have the same meanings as described in
12        subsection (h) of Section 201 of the Illinois Income
13        Tax Act; or
14            (B) the business intends to establish a new
15        electric generating facility at a designated location
16        in Illinois. "New electric generating facility", for
17        purposes of this Section, means a newly-constructed
18        electric generation plant or a newly-constructed
19        generation capacity expansion at an existing electric
20        generation plant, including the transmission lines and
21        associated equipment that transfers electricity from
22        points of supply to points of delivery, and for which
23        such new foundation construction commenced not sooner
24        than July 1, 2001. Such facility shall be designed to
25        provide baseload electric generation and shall operate
26        on a continuous basis throughout the year; and (i)

 

 

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1        shall have an aggregate rated generating capacity of
2        at least 1,000 megawatts for all new units at one site
3        if it uses natural gas as its primary fuel and
4        foundation construction of the facility is commenced
5        on or before December 31, 2004, or shall have an
6        aggregate rated generating capacity of at least 400
7        megawatts for all new units at one site if it uses coal
8        or gases derived from coal as its primary fuel and
9        shall support the creation of at least 150 new
10        Illinois coal mining jobs, or (ii) shall be funded
11        through a federal Department of Energy grant before
12        December 31, 2010 and shall support the creation of
13        Illinois coal-mining jobs, or (iii) shall use coal
14        gasification or integrated gasification-combined cycle
15        units that generate electricity or chemicals, or both,
16        and shall support the creation of Illinois coal-mining
17        jobs. The business must certify in writing that the
18        investments necessary to establish a new electric
19        generating facility would not be placed in service and
20        the job creation in the case of a coal-fueled plant
21        would not occur without the tax credits and exemptions
22        set forth in subsection (b-5) of this Section. The
23        term "placed in service" has the same meaning as
24        described in subsection (h) of Section 201 of the
25        Illinois Income Tax Act; or
26            (B-5) the business intends to establish a new

 

 

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1        gasification facility at a designated location in
2        Illinois. As used in this Section, "new gasification
3        facility" means a newly constructed coal gasification
4        facility that generates chemical feedstocks or
5        transportation fuels derived from coal (which may
6        include, but are not limited to, methane, methanol,
7        and nitrogen fertilizer), that supports the creation
8        or retention of Illinois coal-mining jobs, and that
9        qualifies for financial assistance from the Department
10        before December 31, 2010. A new gasification facility
11        does not include a pilot project located within
12        Jefferson County or within a county adjacent to
13        Jefferson County for synthetic natural gas from coal;
14        or
15            (C) the business intends to establish production
16        operations at a new coal mine, re-establish production
17        operations at a closed coal mine, or expand production
18        at an existing coal mine at a designated location in
19        Illinois not sooner than July 1, 2001; provided that
20        the production operations result in the creation of
21        150 new Illinois coal mining jobs as described in
22        subdivision (a)(3)(B) of this Section, and further
23        provided that the coal extracted from such mine is
24        utilized as the predominant source for a new electric
25        generating facility. The business must certify in
26        writing that the investments necessary to establish a

 

 

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1        new, expanded, or reopened coal mine would not be
2        placed in service and the job creation would not occur
3        without the tax credits and exemptions set forth in
4        subsection (b-5) of this Section. The term "placed in
5        service" has the same meaning as described in
6        subsection (h) of Section 201 of the Illinois Income
7        Tax Act; or
8            (D) the business intends to construct new
9        transmission facilities or upgrade existing
10        transmission facilities at designated locations in
11        Illinois, for which construction commenced not sooner
12        than July 1, 2001. For the purposes of this Section,
13        "transmission facilities" means transmission lines
14        with a voltage rating of 115 kilovolts or above,
15        including associated equipment, that transfer
16        electricity from points of supply to points of
17        delivery and that transmit a majority of the
18        electricity generated by a new electric generating
19        facility designated as a High Impact Business in
20        accordance with this Section. The business must
21        certify in writing that the investments necessary to
22        construct new transmission facilities or upgrade
23        existing transmission facilities would not be placed
24        in service without the tax credits and exemptions set
25        forth in subsection (b-5) of this Section. The term
26        "placed in service" has the same meaning as described

 

 

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1        in subsection (h) of Section 201 of the Illinois
2        Income Tax Act; or
3            (E) the business intends to establish a new wind
4        power facility at a designated location in Illinois.
5        For purposes of this Section, "new wind power
6        facility" means a newly constructed electric
7        generation facility, or a newly constructed expansion
8        of an existing electric generation facility, placed in
9        service on or after July 1, 2009, that generates
10        electricity using wind energy devices, and such
11        facility shall be deemed to include all associated
12        transmission lines, substations, and other equipment
13        related to the generation of electricity from wind
14        energy devices. For purposes of this Section, "wind
15        energy device" means any device, with a nameplate
16        capacity of at least 0.5 megawatts, that is used in the
17        process of converting kinetic energy from the wind to
18        generate electricity; or
19            (E-5) the business intends to establish a new
20        utility scale solar or photovoltaic community
21        renewable energy generation facility at a designated
22        location in Illinois. For purposes of this Section,
23        "new utility scale solar power facility" has the same
24        meaning as "utility-scale solar" in the Illinois Power
25        Agency Act and was put into service on or after July 1,
26        2021, and such facility shall be deemed to include all

 

 

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1        associated transmission lines, substations, and other
2        equipment related to the generation of electricity
3        from photovoltaic cells. For the purposes of this
4        Section "community renewable energy generation
5        facility" has the same meaning as "community renewable
6        generation facility" in the Illinois Power Agency Act
7        and was placed in service on or after July 1, 2021,
8        that generates electricity using photovoltaic cells;
9        or
10            (F) the business commits to (i) make a minimum
11        investment of $500,000,000, which will be placed in
12        service in a qualified property, (ii) create 125
13        full-time equivalent jobs at a designated location in
14        Illinois, (iii) establish a fertilizer plant at a
15        designated location in Illinois that complies with the
16        set-back standards as described in Table 1: Initial
17        Isolation and Protective Action Distances in the 2012
18        Emergency Response Guidebook published by the United
19        States Department of Transportation, (iv) pay a
20        prevailing wage for employees at that location who are
21        engaged in construction activities, and (v) secure an
22        appropriate level of general liability insurance to
23        protect against catastrophic failure of the fertilizer
24        plant or any of its constituent systems; in addition,
25        the business must agree to enter into a construction
26        project labor agreement including provisions

 

 

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1        establishing wages, benefits, and other compensation
2        for employees performing work under the project labor
3        agreement at that location; for the purposes of this
4        Section, "fertilizer plant" means a newly constructed
5        or upgraded plant utilizing gas used in the production
6        of anhydrous ammonia and downstream nitrogen
7        fertilizer products for resale; for the purposes of
8        this Section, "prevailing wage" means the hourly cash
9        wages plus fringe benefits for training and
10        apprenticeship programs approved by the U.S.
11        Department of Labor, Bureau of Apprenticeship and
12        Training, health and welfare, insurance, vacations and
13        pensions paid generally, in the locality in which the
14        work is being performed, to employees engaged in work
15        of a similar character on public works; this paragraph
16        (F) applies only to businesses that submit an
17        application to the Department within 60 days after
18        July 25, 2013 (the effective date of Public Act
19        98-109) this amendatory Act of the 98th General
20        Assembly; and
21        (4) no later than 90 days after an application is
22    submitted, the Department shall notify the applicant of
23    the Department's determination of the qualification of the
24    proposed High Impact Business under this Section.
25    (b) Businesses designated as High Impact Businesses
26pursuant to subdivision (a)(3)(A) of this Section shall

 

 

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1qualify for the credits and exemptions described in the
2following Acts: Section 9-222 and Section 9-222.1A of the
3Public Utilities Act, subsection (h) of Section 201 of the
4Illinois Income Tax Act, and Section 1d of the Retailers'
5Occupation Tax Act; provided that these credits and exemptions
6described in these Acts shall not be authorized until the
7minimum investments set forth in subdivision (a)(3)(A) of this
8Section have been placed in service in qualified properties
9and, in the case of the exemptions described in the Public
10Utilities Act and Section 1d of the Retailers' Occupation Tax
11Act, the minimum full-time equivalent jobs or full-time
12retained jobs set forth in subdivision (a)(3)(A) of this
13Section have been created or retained. Businesses designated
14as High Impact Businesses under this Section shall also
15qualify for the exemption described in Section 5l of the
16Retailers' Occupation Tax Act. The credit provided in
17subsection (h) of Section 201 of the Illinois Income Tax Act
18shall be applicable to investments in qualified property as
19set forth in subdivision (a)(3)(A) of this Section.
20    (b-5) Businesses designated as High Impact Businesses
21pursuant to subdivisions (a)(3)(B), (a)(3)(B-5), (a)(3)(C),
22and (a)(3)(D) of this Section shall qualify for the credits
23and exemptions described in the following Acts: Section 51 of
24the Retailers' Occupation Tax Act, Section 9-222 and Section
259-222.1A of the Public Utilities Act, and subsection (h) of
26Section 201 of the Illinois Income Tax Act; however, the

 

 

SB2896- 97 -LRB102 17909 JWD 25989 b

1credits and exemptions authorized under Section 9-222 and
2Section 9-222.1A of the Public Utilities Act, and subsection
3(h) of Section 201 of the Illinois Income Tax Act shall not be
4authorized until the new electric generating facility, the new
5gasification facility, the new transmission facility, or the
6new, expanded, or reopened coal mine is operational, except
7that a new electric generating facility whose primary fuel
8source is natural gas is eligible only for the exemption under
9Section 5l of the Retailers' Occupation Tax Act.
10    (b-6) Businesses designated as High Impact Businesses
11pursuant to subdivision (a)(3)(E) of this Section shall
12qualify for the exemptions described in Section 5l of the
13Retailers' Occupation Tax Act; any business so designated as a
14High Impact Business being, for purposes of this Section, a
15"Wind Energy Business".
16    (b-7) Beginning on January 1, 2021, businesses designated
17as High Impact Businesses by the Department shall qualify for
18the High Impact Business construction jobs credit under
19subsection (h-5) of Section 201 of the Illinois Income Tax Act
20if the business meets the criteria set forth in subsection (i)
21of this Section. The total aggregate amount of credits awarded
22under the Blue Collar Jobs Act (Article 20 of Public Act 101-9
23this amendatory Act of the 101st General Assembly) shall not
24exceed $20,000,000 in any State fiscal year.
25    (c) High Impact Businesses located in federally designated
26foreign trade zones or sub-zones are also eligible for

 

 

SB2896- 98 -LRB102 17909 JWD 25989 b

1additional credits, exemptions and deductions as described in
2the following Acts: Section 9-221 and Section 9-222.1 of the
3Public Utilities Act; and subsection (g) of Section 201, and
4Section 203 of the Illinois Income Tax Act.
5    (d) Except for businesses contemplated under subdivision
6(a)(3)(E) of this Section, existing Illinois businesses which
7apply for designation as a High Impact Business must provide
8the Department with the prospective plan for which 1,500
9full-time retained jobs would be eliminated in the event that
10the business is not designated.
11    (e) Except for new wind power facilities contemplated
12under subdivision (a)(3)(E) of this Section, new proposed
13facilities which apply for designation as High Impact Business
14must provide the Department with proof of alternative
15non-Illinois sites which would receive the proposed investment
16and job creation in the event that the business is not
17designated as a High Impact Business.
18    (f) Except for businesses contemplated under subdivision
19(a)(3)(E) of this Section, in the event that a business is
20designated a High Impact Business and it is later determined
21after reasonable notice and an opportunity for a hearing as
22provided under the Illinois Administrative Procedure Act, that
23the business would have placed in service in qualified
24property the investments and created or retained the requisite
25number of jobs without the benefits of the High Impact
26Business designation, the Department shall be required to

 

 

SB2896- 99 -LRB102 17909 JWD 25989 b

1immediately revoke the designation and notify the Director of
2the Department of Revenue who shall begin proceedings to
3recover all wrongfully exempted State taxes with interest. The
4business shall also be ineligible for all State funded
5Department programs for a period of 10 years.
6    (g) The Department shall revoke a High Impact Business
7designation if the participating business fails to comply with
8the terms and conditions of the designation. However, the
9penalties for new wind power facilities or Wind Energy
10Businesses, new utility scale solar power facilities, or new
11photovoltaic community renewable generation facilities for
12failure to comply with any of the terms or conditions of the
13Illinois Prevailing Wage Act shall be only those penalties
14identified in the Illinois Prevailing Wage Act, and the
15Department shall not revoke a High Impact Business designation
16as a result of the failure to comply with any of the terms or
17conditions of the Illinois Prevailing Wage Act in relation to
18a new wind power facility or a Wind Energy Business, new
19utility scale solar power facility, or new photovoltaic
20community renewable generation facility.
21    (h) Prior to designating a business, the Department shall
22provide the members of the General Assembly and Commission on
23Government Forecasting and Accountability with a report
24setting forth the terms and conditions of the designation and
25guarantees that have been received by the Department in
26relation to the proposed business being designated.

 

 

SB2896- 100 -LRB102 17909 JWD 25989 b

1    (i) High Impact Business construction jobs credit.
2Beginning on January 1, 2021, a High Impact Business may
3receive a tax credit against the tax imposed under subsections
4(a) and (b) of Section 201 of the Illinois Income Tax Act in an
5amount equal to 50% of the amount of the incremental income tax
6attributable to High Impact Business construction jobs credit
7employees employed in the course of completing a High Impact
8Business construction jobs project. However, the High Impact
9Business construction jobs credit may equal 75% of the amount
10of the incremental income tax attributable to High Impact
11Business construction jobs credit employees if the High Impact
12Business construction jobs credit project is located in an
13underserved area.
14    The Department shall certify to the Department of Revenue:
15(1) the identity of taxpayers that are eligible for the High
16Impact Business construction jobs credit; and (2) the amount
17of High Impact Business construction jobs credits that are
18claimed pursuant to subsection (h-5) of Section 201 of the
19Illinois Income Tax Act in each taxable year. Any business
20entity that receives a High Impact Business construction jobs
21credit shall maintain a certified payroll pursuant to
22subsection (j) of this Section.
23    As used in this subsection (i):
24    "High Impact Business construction jobs credit" means an
25amount equal to 50% (or 75% if the High Impact Business
26construction project is located in an underserved area) of the

 

 

SB2896- 101 -LRB102 17909 JWD 25989 b

1incremental income tax attributable to High Impact Business
2construction job employees. The total aggregate amount of
3credits awarded under the Blue Collar Jobs Act (Article 20 of
4Public Act 101-9 this amendatory Act of the 101st General
5Assembly) shall not exceed $20,000,000 in any State fiscal
6year
7    "High Impact Business construction job employee" means a
8laborer or worker who is employed by an Illinois contractor or
9subcontractor in the actual construction work on the site of a
10High Impact Business construction job project.
11    "High Impact Business construction jobs project" means
12building a structure or building or making improvements of any
13kind to real property, undertaken and commissioned by a
14business that was designated as a High Impact Business by the
15Department. The term "High Impact Business construction jobs
16project" does not include the routine operation, routine
17repair, or routine maintenance of existing structures,
18buildings, or real property.
19    "Incremental income tax" means the total amount withheld
20during the taxable year from the compensation of High Impact
21Business construction job employees.
22    "Underserved area" means a geographic area that meets one
23or more of the following conditions:
24        (1) the area has a poverty rate of at least 20%
25    according to the latest federal decennial census;
26        (2) 75% or more of the children in the area

 

 

SB2896- 102 -LRB102 17909 JWD 25989 b

1    participate in the federal free lunch program according to
2    reported statistics from the State Board of Education;
3        (3) at least 20% of the households in the area receive
4    assistance under the Supplemental Nutrition Assistance
5    Program (SNAP); or
6        (4) the area has an average unemployment rate, as
7    determined by the Illinois Department of Employment
8    Security, that is more than 120% of the national
9    unemployment average, as determined by the U.S. Department
10    of Labor, for a period of at least 2 consecutive calendar
11    years preceding the date of the application.
12    (j) Each contractor and subcontractor who is engaged in
13and executing a High Impact Business Construction jobs
14project, as defined under subsection (i) of this Section, for
15a business that is entitled to a credit pursuant to subsection
16(i) of this Section shall:
17        (1) make and keep, for a period of 5 years from the
18    date of the last payment made on or after June 5, 2019 (the
19    effective date of Public Act 101-9) this amendatory Act of
20    the 101st General Assembly on a contract or subcontract
21    for a High Impact Business Construction Jobs Project,
22    records for all laborers and other workers employed by the
23    contractor or subcontractor on the project; the records
24    shall include:
25            (A) the worker's name;
26            (B) the worker's address;

 

 

SB2896- 103 -LRB102 17909 JWD 25989 b

1            (C) the worker's telephone number, if available;
2            (D) the worker's social security number;
3            (E) the worker's classification or
4        classifications;
5            (F) the worker's gross and net wages paid in each
6        pay period;
7            (G) the worker's number of hours worked each day;
8            (H) the worker's starting and ending times of work
9        each day;
10            (I) the worker's hourly wage rate; and
11            (J) the worker's hourly overtime wage rate;
12        (2) no later than the 15th day of each calendar month,
13    provide a certified payroll for the immediately preceding
14    month to the taxpayer in charge of the High Impact
15    Business construction jobs project; within 5 business days
16    after receiving the certified payroll, the taxpayer shall
17    file the certified payroll with the Department of Labor
18    and the Department of Commerce and Economic Opportunity; a
19    certified payroll must be filed for only those calendar
20    months during which construction on a High Impact Business
21    construction jobs project has occurred; the certified
22    payroll shall consist of a complete copy of the records
23    identified in paragraph (1) of this subsection (j), but
24    may exclude the starting and ending times of work each
25    day; the certified payroll shall be accompanied by a
26    statement signed by the contractor or subcontractor or an

 

 

SB2896- 104 -LRB102 17909 JWD 25989 b

1    officer, employee, or agent of the contractor or
2    subcontractor which avers that:
3            (A) he or she has examined the certified payroll
4        records required to be submitted by the Act and such
5        records are true and accurate; and
6            (B) the contractor or subcontractor is aware that
7        filing a certified payroll that he or she knows to be
8        false is a Class A misdemeanor.
9    A general contractor is not prohibited from relying on a
10certified payroll of a lower-tier subcontractor, provided the
11general contractor does not knowingly rely upon a
12subcontractor's false certification.
13    Any contractor or subcontractor subject to this
14subsection, and any officer, employee, or agent of such
15contractor or subcontractor whose duty as an officer,
16employee, or agent it is to file a certified payroll under this
17subsection, who willfully fails to file such a certified
18payroll on or before the date such certified payroll is
19required by this paragraph to be filed and any person who
20willfully files a false certified payroll that is false as to
21any material fact is in violation of this Act and guilty of a
22Class A misdemeanor.
23    The taxpayer in charge of the project shall keep the
24records submitted in accordance with this subsection on or
25after June 5, 2019 (the effective date of Public Act 101-9)
26this amendatory Act of the 101st General Assembly for a period

 

 

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1of 5 years from the date of the last payment for work on a
2contract or subcontract for the High Impact Business
3construction jobs project.
4    The records submitted in accordance with this subsection
5shall be considered public records, except an employee's
6address, telephone number, and social security number, and
7made available in accordance with the Freedom of Information
8Act. The Department of Labor shall accept any reasonable
9submissions by the contractor that meet the requirements of
10this subsection (j) and shall share the information with the
11Department in order to comply with the awarding of a High
12Impact Business construction jobs credit. A contractor,
13subcontractor, or public body may retain records required
14under this Section in paper or electronic format.
15    (k) Upon 7 business days' notice, each contractor and
16subcontractor shall make available for inspection and copying
17at a location within this State during reasonable hours, the
18records identified in this subsection (j) to the taxpayer in
19charge of the High Impact Business construction jobs project,
20its officers and agents, the Director of the Department of
21Labor and his or her deputies and agents, and to federal,
22State, or local law enforcement agencies and prosecutors.
23(Source: P.A. 101-9, eff. 6-5-19; revised 7-12-19.)
 
24    Section 30-18. The Electric Vehicle Act is amended by
25changing Sections 5, 10, 15, and 20 and by adding Sections 30,

 

 

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135, 40, 45, and 50 as follows:
 
2    (20 ILCS 627/5)
3    Sec. 5. Findings. The General Assembly finds:
4    (1) Illinois should increase the adoption of electric
5vehicles in the State to 1,000,000 by 2030.
6    (2) Illinois should strive to be the best state in the
7nation in which to drive and manufacture an electric vehicle.
8    (3) Widespread adoption of electric vehicles is necessary
9to electrify the transportation sector, diversify the
10transportation fuel mix, drive economic development, and
11protect air quality.
12    (4) Accelerating the adoption of electric vehicles will
13drive the decarbonization of Illinois' transportation sector.
14    (5) Expanded infrastructure investment will help Illinois
15more rapidly decarbonize the transportation sector.
16    (6) Statewide adoption of electric vehicles requires
17increasing access to electrification for all consumers.
18    (7) Private investments in charging equipment and electric
19utility investments can assist the growth of electric vehicles
20and help increase access to electricity for electric vehicle
21charging.
22    (8) Widespread adoption of electric vehicles requires
23increasing public access to charging equipment throughout
24Illinois, especially in low-income, moderate-income,
25environmental justice, and equity investment eligible

 

 

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1communities, where levels of air pollution burden tend to be
2higher.
3    (9) Widespread adoption of electric vehicles and charging
4equipment has the potential to provide customers with fuel
5cost savings and electric utility customers with cost-saving
6benefits.
7    (10) Widespread adoption of electric vehicles can help
8Illinois stimulate innovation, create jobs, increase
9competition, and expand private investments in charging
10equipment and networks.
11    (11) Widespread adoption of electric vehicles can improve
12an electric utility's electric system efficiency and
13operational flexibility, including the ability of the electric
14utility to integrate renewable energy resources and make use
15of off-peak generation resources that support the operation of
16charging equipment. that the adoption and use of electric
17vehicles would benefit the State of Illinois by (i) improving
18the health and environmental quality of the residents of
19Illinois through reduced pollution, (ii) reducing the
20operating costs of vehicle transportation, and (iii) shifting
21the demand for imported petroleum to locally produced
22electricity.
23(Source: P.A. 97-89, eff. 7-11-11.)
 
24    (20 ILCS 627/10)
25    Sec. 10. Definitions.

 

 

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1    "Agency" means the Illinois Environmental Protection
2Agency.
3    "Commission" means the Illinois Commerce Commission.
4    "Coordinator" means the Electric Vehicle Coordinator
5created in Section 15.
6    "Council" means the Electric Vehicle Advisory Council
7created in Section 20.
8    "Electric vehicle" means (i) a vehicle that is exclusively
9powered by and refueled by electricity (ii) is licensed to
10drive on public roadways. "Electric vehicle" does not include
11(A) electric motorcycles, or (B) hybrid electric vehicles and
12extended-range electric vehicles that are also equipped with
13conventional fueled propulsion or auxiliary engines.
14battery-powered electric vehicle operated solely by
15electricity or (ii) a plug-in hybrid electric vehicle that
16operates on electricity and gasoline and has a battery that
17can be recharged from an external source.
18    "Electric vehicle charging station" means a station that
19delivers electricity from a source outside an electric vehicle
20into one or more electric vehicles.
21    "Equity investment eligible community" or "eligible
22community" mean people living in geographic areas throughout
23Illinois who will most benefit from equitable investments by
24the State that are designed to combat historic inequities and
25the effects of discrimination. "Eligible community" includes
26census tracts that meet the following characteristics:

 

 

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1        (1) At least 15% of the population or at least 20% of
2    the population 18 or under fall below the federal poverty
3    level; and
4        (2) falls in the top 25th percentile in the State on
5    measured levels for one or more of the following
6    environmental indicators from the United States
7    Environmental Protection Agency's EJSCREEN screening tool:
8            (A) Diesel particulate matter level in air.
9            (B) Air toxics cancer risk.
10            (C) Air toxics respiratory hazard index.
11            (D) Indicator for major direct dischargers to
12        water.
13            (E) Proximity to National Priorities List (NPL)
14        sites.
15            (F) Proximity to Risk Management Plan (RMP)
16        facilities.
17            (G) Proximity to Treatment and Storage and
18        Disposal (TSDF) facilities.
19            (H) Ozone level in air.
20            (I) PM2.5 (particulate matter with diameters that
21        are 2.5 micrometers and smaller) level in the air.
22    "Equity investment eligible persons" or "eligible persons"
23means persons who would most benefit from equitable
24investments by the State designed to combat discrimination,
25specifically:
26        (1) persons whose primary residence is in an equity

 

 

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1    investment eligible community;
2        (2) persons whose primary residence is in a
3    municipality or a county with a population under 100,000
4    where the closure of an electric generating unit or coal
5    mine has been publicly announced, or the electric
6    generating unit or coal mine is in the process of closing
7    or has closed within the last 5 years;
8        (3) persons who are graduates of or currently enrolled
9    in the foster care system; or
10        (4) persons who were formerly incarcerated.
11    "Make-ready infrastructure" means the electrical and
12construction work necessary between the distribution circuit
13to the connection point of charging equipment to facilitate
14private investment in charging equipment.
15(Source: P.A. 97-89, eff. 7-11-11.)
 
16    (20 ILCS 627/15)
17    Sec. 15. Electric Vehicle Coordinator. The Governor shall
18appoint a person within the Illinois Environmental Protection
19Agency Department of Commerce and Economic Opportunity to
20serve as the Electric Vehicle Coordinator for the State of
21Illinois. This person may be an existing employee with other
22duties. The Coordinator shall act as a point person for
23electric vehicle-related and electric vehicle charging-related
24electric vehicle related policies and activities in Illinois,
25including but not limited to the issuance of electric vehicle

 

 

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1rebates for consumers and electric vehicle charging rebates
2for organizations and companies.
3(Source: P.A. 97-89, eff. 7-11-11.)
 
4    (20 ILCS 627/20)
5    Sec. 20. Electric vehicle advisory council.
6    (a) There is created the Illinois Electric Vehicle
7Advisory Council. The Council shall investigate and recommend
8strategies that the Governor and the General Assembly may
9implement to promote the use of electric vehicles. Strategies
10shall include, but are not limited to, methods of achieving
11greater adoption of electric vehicles, rapidly expanding
12statewide charging infrastructure, electrifying the State
13fleet, and changing electric utility rates and tariffs related
14to electric vehicle charging. , including, but not limited to,
15potential infrastructure improvements, State and local
16regulatory streamlining, and changes to electric utility rates
17and tariffs.
18    (b) The Council shall include all of the following
19members:
20        (1) The Electric Vehicle Coordinator to serve as
21    chairperson.
22        (2) Four members of the General Assembly, one
23    appointed by the Speaker of the House of Representatives,
24    one appointed by the Minority Leader of the House of
25    Representatives, one appointed by the President of the

 

 

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1    Senate, and one appointed by the Minority Leader of the
2    Senate.
3        (3) The Director of Commerce and Economic Opportunity
4    or his or her designee.
5        (4) The Director of the Illinois Environmental
6    Protection Agency or his or her designee.
7        (5) The Executive Director of the Illinois Commerce
8    Commission or his or her designee.
9        (6) The Secretary of the Illinois Department of
10    Transportation or his or her designee.
11        (7) The Director of Central Management Services or his
12    or her designee.
13        (8) The following (7) Ten at-large members appointed
14    by the Governor as follows:
15            (A) two representatives of statewide environmental
16        organizations;
17            (B) two representatives of national or regional
18        environmental organizations;
19            (C) two representatives of charging companies; one
20        representative of a nonprofit car-sharing
21        organization;
22            (D) two representatives of automobile
23        manufacturers;
24            (E) one representative of the City of Chicago; and
25            (F) two representatives of electric utilities.
26    (c) The Council shall report its findings to the Governor

 

 

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1and General Assembly by December 31, 2022 2011.
2    (d) The Illinois Environmental Protection Agency
3Department of Commerce and Economic Opportunity shall provide
4administrative and other support to the Council.
5(Source: P.A. 97-89, eff. 7-11-11.)
 
6    (20 ILCS 627/30 new)
7    Sec. 30. Commercial tariff; electric vehicle charging.
8Within 90 days after the effective date of this amendatory Act
9of the 102nd General Assembly, electric utilities serving
10greater than 500,000 customers in the State shall file a
11proposal with the Illinois Commerce Commission to establish a
12commercial tariff utilizing alternatives to traditional
13demand-based rate structures to facilitate charging for
14light-duty, heavy-duty, and fleet electric vehicles and
15charging that supports integration of renewable energy
16resources.
 
17    (20 ILCS 627/35 new)
18    Sec. 35. Transportation Electrification Plans.
19    (a) An electric utility serving more than 500,000
20customers as of January 1, 2009 shall prepare a Transportation
21Electrification Plan that meets the requirements of this
22section and shall file said plan with the Commission no later
23than July 1, 2022. Within 45 days after the filing of the
24Transportation Electrification Plan, the Commission shall,

 

 

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1with reasonable notice, open an investigation to consider
2whether the plan meets the objectives and contains the
3information required by this Section. The Commission shall
4approve, approve with modifications, or reject the plan within
5270 days from the date of filing. The Commission may approve
6the plan if it finds that the plan will achieve the goals
7described in this Section and contains the information
8described in this Section. Proceedings under this Section
9shall proceed according to the rules provided by Article IX of
10the Public Utilities Act. Information contained in the
11approved plan shall be considered part of the record in any
12Commission proceeding under Section 16-107.6 of the Public
13Utilities Act, provided that a final order has not been
14entered prior to the initial filing date.
15    The Transportation Electrification Plan shall specifically
16address, at minimum, the following information:
17        (1) Investments and incentives to facilitate the rapid
18    deployment of charging equipment throughout the State
19    through programs that support make-ready infrastructure
20    and align infrastructure investments with Agency-issued
21    rebates for charging equipment, in accordance with Section
22    50.
23        (2) Investments and incentives to facilitate the rapid
24    deployment of charging equipment in eligible communities
25    in order to provide those communities with greater
26    economic investment, transportation opportunities, and a

 

 

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1    cleaner environment so they can directly benefit from
2    transportation electrification efforts.
3        (3) Investments and incentives to facilitate the
4    electrification of public transit and other vehicle fleets
5    in the light-duty, medium-duty, and heavy-duty sectors.
6        (4) Whether to establish standards for charging plugs,
7    and if so, what standards.
8        (5) Additional rate designs to support public and
9    private electric vehicle charging.
10        (6) Financial and other challenges to electric vehicle
11    usage in low-income communities and strategies for
12    overcoming those challenges, particularly for people for
13    whom car ownership or electric car ownership is not an
14    option.
15        (7) Customer education, outreach, and incentive
16    programs that increase awareness of the programs and the
17    benefits of transportation electrification, including
18    direct outreach to eligible communities.
19        (8) Plans to increase access to Level 3 charging
20    infrastructure located along transportation corridors to
21    serve vehicles that need quicker charging times and
22    vehicles of persons who have no other access to charging
23    infrastructure, regardless of whether those projects
24    participate in optimized charging programs.
25        (9) Methods of minimizing ratepayer impacts and
26    exempting or minimizing, to the extent possible,

 

 

SB2896- 116 -LRB102 17909 JWD 25989 b

1    low-income ratepayers from the costs associated with
2    facilitating the expansion of electric vehicle charging.
3        (10) Financial and other challenges to electric
4    vehicle usage in low-income communities and strategies for
5    overcoming those challenges.
6        (11) The development of optimized charging programs to
7    achieve savings identified, and new contracts and
8    compensation for services in those programs, through
9    signals that allow electric vehicle charging to respond to
10    local system conditions, manage critical peak periods,
11    serve as a demand response or peak resource, and maximize
12    renewable energy use and integration into the grid.
13        (12) Opportunities for coordination and alignment with
14    electric vehicle and electric vehicle charging equipment
15    incentives established by any agency, department, board,
16    or commission of the State of Illinois, any other unit of
17    government in the State, any national programs, or any
18    unit of the federal government.
19    (b) The Commission's investigation shall determine if each
20proposed plan is in the public interest. When considering if
21the plan is in the public interest and determining appropriate
22levels of cost recovery for investments and expenditures
23related to programs proposed by an electric utility, the
24Commission shall consider whether the investments and other
25expenditures are designed and reasonably expected to:
26        (1) increase access to charging equipment and

 

 

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1    electricity as a transportation fuel throughout the State,
2    including in low-income, moderate-income, and eligible
3    communities;
4        (2) stimulate innovation, competition, private
5    investment, and increased consumer choices in electric
6    vehicle charging equipment and networks;
7        (3) contribute to meeting air quality standards,
8    including improving air quality in equity investment
9    eligible communities who disproportionately suffer from
10    emissions from the transportation sector, the
11    consideration of which shall include consultation with the
12    Agency;
13        (4) support the efficient and cost-effective use of
14    the electric grid in a manner that supports electric
15    vehicle charging operations; and
16        (5) provide resources to support private investment in
17    charging equipment for uses in public and private charging
18    applications, including residential, multi-family, fleet,
19    transit, community, and corridor applications.
 
20    (20 ILCS 627/40 new)
21    Sec. 40. Plan updates. The utility shall file an update to
22the plan on July 1, 2024 and every three years thereafter. This
23update shall describe transportation investments made during
24the prior plan period, investments planned for the following
2524 months, and updates to the information required by this

 

 

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1Section. Within 35 days after the utility files its report,
2the Commission shall, upon its own initiative, open an
3investigation regarding the utility's plan update to
4investigate whether the objectives described in this Section
5are being achieved. If the Commission finds, after notice and
6hearing, that the utility's plan is materially deficient, the
7Commission shall issue an order requiring the utility to
8devise a corrective action plan, subject to Commission
9approval, to bring the plan into compliance with the goals of
10this Section. The Commission's order shall be entered within
11270 days after the utility files its annual report.
12    The contents of a plan filed under this Section shall be
13available for evidence in Commission proceedings. However,
14omission from an approved plan shall not render any future
15utility expenditure to be considered unreasonable or
16imprudent. The Commission may, upon sufficient evidence, allow
17expenditures that were not part of any particular distribution
18plan.
 
19    (20 ILCS 627/45 new)
20    Sec. 45. Rulemaking; resources. The Agency shall adopt
21rules as necessary and dedicate sufficient resources to
22implement Sections 35 and 50.
 
23    (20 ILCS 627/50 new)
24    Sec. 50. Charging rebate program.

 

 

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1    (a) In order to substantially offset the installation
2costs of electric vehicle charging infrastructure, beginning
3July 1, 2023, and continuing as long as funds are available,
4the Agency shall issue rebates, consistent with the provisions
5of this Act and Commission-approved Transportation
6Electrification Plans in accordance with Section 35, to public
7and private organizations and companies to install and
8maintain Level 2 or Level 3 charging stations at any of the
9following locations:
10        (1) Public parking facilities.
11        (2) Workplaces.
12        (3) Multifamily apartment buildings.
13        (4) Public roads and highways.
14        (5) Ridesharing and taxi charging depots.
15    (b) The Agency shall award rebates that fund up to 90% of
16the cost of the charging station, up to $4,000 for Level 2
17chargers and up to $5,000 for Level 3 chargers. The Agency
18shall award an additional $500 per port for every charging
19station installed in an eligible community and every charging
20station located to support eligible persons. In order to be
21eligible to receive a rebate, the organization or company must
22submit an application to the Agency. The Agency shall by rule
23provide application requirements. The Agency shall accept
24applications on a rolling basis and shall award rebates within
2560 days of each application.
 

 

 

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1    Section 30-20. The Energy Policy and Planning Act is
2amended by changing Section 2 as follows:
 
3    (20 ILCS 1120/2)  (from Ch. 96 1/2, par. 7802)
4    Sec. 2. (a) The General Assembly finds:
5    (1) that the reliable provision of adequate amounts of
6energy in the forms required is of vital importance to the
7public welfare and to the continued operation of business and
8industry; and (2) that many problems relating to energy are
9beyond the ability of the national government to solve, or are
10such that action by the national government would represent a
11displacement of prerogatives that are properly those of the
12State government; and (3) that among these problems is that of
13climate change; and (4) that there is a need for an organized
14and comprehensive approach for dealing with energy matters in
15the State, which can be best served through the adoption of a
16State energy policy.
17    (b) It is declared to be the policy of the State of
18Illinois:
19    (1) To become energy self-reliant to the greatest extent
20possible, primarily by the utilization of the energy resources
21available within the borders of this State, and by the
22increased conservation of energy; and
23    (2) To emphasize an approach to energy problems and
24solutions on a local or regional basis, and to emphasize the
25use of renewable energy sources wherever possible and

 

 

SB2896- 121 -LRB102 17909 JWD 25989 b

1practical to do so; and
2    (2.1) To recognize the detrimental impacts of climate
3change to the citizens of this State, and to act to reverse
4these impacts through a transition to 100% clean energy; and
5    (3) To seek and promote and aid the efforts of private
6citizens, businesses, and industries in developing individual
7contributions to energy problems and difficulties that are
8being encountered, making use of renewable energy sources that
9are matched in quality to end-use needs; and
10    (4) The development of a comprehensive master plan for
11energy that considers available supplies, production and
12conversion capabilities, levels of demand by each energy type
13and level of total demand, and the changes in each that are
14likely to occur over time is a priority that should be
15developed and implemented immediately.
16    (c) The General Assembly further declares that the
17progress towards a comprehensive energy plan should be in
18accordance with the following guidelines:
19    (1) The energy problems being faced in the State can be
20effectively addressed only by a government that accepts
21responsibility for dealing with them comprehensively, and by
22an informed public that understands the seriousness and is
23ready to make the necessary commitment.
24    (2) Economic growth, employment, and production must be
25maintained.
26    (3) Policies for the protection of the environment must be

 

 

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1maintained.
2    (4) The solutions sought as part of the master planning
3process must be equitable and fair to all regions, sectors and
4income groups.
5    (5) The growth of energy demand must be prudently
6restrained through conservation and improved efficiency of
7energy usage.
8    (6) Energy prices should generally reflect the true
9replacement cost of energy.
10    (7) Both energy producers and consumers are entitled to
11reasonable certainty as to governmental energy policy.
12    (8) Resources in plentiful supply must be used more
13widely, and the State or locality must begin the process of
14moderating the use of those in short supply.
15    (9) Use of nonconventional sources of energy must be
16vigorously expanded.
17    (10) The plans developed:
18    (i) should be realistic and consistent with the basic
19physical limitations of energy production and utilization
20processes, and recognize the costs and lead times necessary
21for implementation of large-scale projects.
22    (ii) must reflect both the need for early action in
23implementing near-term programs and the need for early
24planning of programs having long lead times.
25    (iii) must allow flexible response and choice of
26alternatives to accommodate changing requirements as well as

 

 

SB2896- 123 -LRB102 17909 JWD 25989 b

1presenting uncertainties in future requirements.
2    (iv) should reflect features that are unique to the State.
3    (v) should recognize the interdisciplinary aspects of
4State objectives and provide positive guidance for
5coordination of various organizations and programs.
6    (vi) must consider both direct energy flows and indirect
7energy embodied in the goods and services entering and leaving
8a region.
9    (vii) should recognize and include not only long-range
10aspects, but must also prepare actions to manage the
11transition from present circumstances to a more manageable
12energy situation.
13(Source: P.A. 81-385.)
 
14    Section 30-22. The Illinois Finance Authority Act is
15amended by changing Sections 801-1, 801-5, 801-10, and 801-40
16and by adding the heading of Article 850 and Sections 850-5,
17850-10, and 850-15 as follows:
 
18    (20 ILCS 3501/801-1)
19    Sec. 801-1. Short Title. Articles 801 through 850 845 of
20this Act may be cited as the Illinois Finance Authority Act.
21References to "this Act" in Articles 801 through 850 845 are
22references to the Illinois Finance Authority Act.
23(Source: P.A. 95-331, eff. 8-21-07.)
 

 

 

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1    (20 ILCS 3501/801-5)
2    Sec. 801-5. Findings and declaration of policy. The
3General Assembly hereby finds, determines and declares:
4    (a) that there are a number of existing State authorities
5authorized to issue bonds to alleviate the conditions and
6promote the objectives set forth below; and to provide a
7stronger, better coordinated development effort, it is
8determined to be in the interest of promoting the health,
9safety, morals and general welfare of all the people of the
10State to consolidate certain of such existing authorities into
11one finance authority;
12    (b) that involuntary unemployment affects the health,
13safety, morals and general welfare of the people of the State
14of Illinois;
15    (c) that the economic burdens resulting from involuntary
16unemployment fall in part upon the State in the form of public
17assistance and reduced tax revenues, and in the event the
18unemployed worker and his family migrate elsewhere to find
19work, may also fall upon the municipalities and other taxing
20districts within the areas of unemployment in the form of
21reduced tax revenues, thereby endangering their financial
22ability to support necessary governmental services for their
23remaining inhabitants;
24    (d) that a vigorous growing economy is the basic source of
25job opportunities;
26    (e) that protection against involuntary unemployment, its

 

 

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1economic burdens and the spread of economic stagnation can
2best be provided by promoting, attracting, stimulating and
3revitalizing industry, manufacturing and commerce in the
4State;
5    (f) that the State has a responsibility to help create a
6favorable climate for new and improved job opportunities for
7its citizens by encouraging the development of commercial
8businesses and industrial and manufacturing plants within the
9State;
10    (g) that increased availability of funds for construction
11of new facilities and the expansion and improvement of
12existing facilities for industrial, commercial and
13manufacturing facilities will provide for new and continued
14employment in the construction industry and alleviate the
15burden of unemployment;
16    (h) that in the absence of direct governmental subsidies
17the unaided operations of private enterprise do not provide
18sufficient resources for residential construction,
19rehabilitation, rental or purchase, and that support from
20housing related commercial facilities is one means of
21stimulating residential construction, rehabilitation, rental
22and purchase;
23    (i) that it is in the public interest and the policy of
24this State to foster and promote by all reasonable means the
25provision of adequate capital markets and facilities for
26borrowing money by units of local government, and for the

 

 

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1financing of their respective public improvements and other
2governmental purposes within the State from proceeds of bonds
3or notes issued by those governmental units; and to assist
4local governmental units in fulfilling their needs for those
5purposes by use of creation of indebtedness;
6    (j) that it is in the public interest and the policy of
7this State to the extent possible, to reduce the costs of
8indebtedness to taxpayers and residents of this State and to
9encourage continued investor interest in the purchase of bonds
10or notes of governmental units as sound and preferred
11securities for investment; and to encourage governmental units
12to continue their independent undertakings of public
13improvements and other governmental purposes and the financing
14thereof, and to assist them in those activities by making
15funds available at reduced interest costs for orderly
16financing of those purposes, especially during periods of
17restricted credit or money supply, and particularly for those
18governmental units not otherwise able to borrow for those
19purposes;
20    (k) that in this State the following conditions exist: (i)
21an inadequate supply of funds at interest rates sufficiently
22low to enable persons engaged in agriculture in this State to
23pursue agricultural operations at present levels; (ii) that
24such inability to pursue agricultural operations lessens the
25supply of agricultural commodities available to fulfill the
26needs of the citizens of this State; (iii) that such inability

 

 

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1to continue operations decreases available employment in the
2agricultural sector of the State and results in unemployment
3and its attendant problems; (iv) that such conditions prevent
4the acquisition of an adequate capital stock of farm equipment
5and machinery, much of which is manufactured in this State,
6therefore impairing the productivity of agricultural land and,
7further, causing unemployment or lack of appropriate increase
8in employment in such manufacturing; (v) that such conditions
9are conducive to consolidation of acreage of agricultural land
10with fewer individuals living and farming on the traditional
11family farm; (vi) that these conditions result in a loss in
12population, unemployment and movement of persons from rural to
13urban areas accompanied by added costs to communities for
14creation of new public facilities and services; (vii) that
15there have been recurrent shortages of funds for agricultural
16purposes from private market sources at reasonable rates of
17interest; (viii) that these shortages have made the sale and
18purchase of agricultural land to family farmers a virtual
19impossibility in many parts of the State; (ix) that the
20ordinary operations of private enterprise have not in the past
21corrected these conditions; and (x) that a stable supply of
22adequate funds for agricultural financing is required to
23encourage family farmers in an orderly and sustained manner
24and to reduce the problems described above;
25    (l) that for the benefit of the people of the State of
26Illinois, the conduct and increase of their commerce, the

 

 

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1protection and enhancement of their welfare, the development
2of continued prosperity and the improvement of their health
3and living conditions it is essential that all the people of
4the State be given the fullest opportunity to learn and to
5develop their intellectual and mental capacities and skills;
6that to achieve these ends it is of the utmost importance that
7private institutions of higher education within the State be
8provided with appropriate additional means to assist the
9people of the State in achieving the required levels of
10learning and development of their intellectual and mental
11capacities and skills and that cultural institutions within
12the State be provided with appropriate additional means to
13expand the services and resources which they offer for the
14cultural, intellectual, scientific, educational and artistic
15enrichment of the people of the State;
16    (m) that in order to foster civic and neighborhood pride,
17citizens require access to facilities such as educational
18institutions, recreation, parks and open spaces, entertainment
19and sports, a reliable transportation network, cultural
20facilities and theaters and other facilities as authorized by
21this Act, and that it is in the best interests of the State to
22lower the costs of all such facilities by providing financing
23through the State;
24    (n) that to preserve and protect the health of the
25citizens of the State, and lower the costs of health care, that
26financing for health facilities should be provided through the

 

 

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1State; and it is hereby declared to be the policy of the State,
2in the interest of promoting the health, safety, morals and
3general welfare of all the people of the State, to address the
4conditions noted above, to increase job opportunities and to
5retain existing jobs in the State, by making available through
6the Illinois Finance Authority, hereinafter created, funds for
7the development, improvement and creation of industrial,
8housing, local government, educational, health, public purpose
9and other projects; to issue its bonds and notes to make funds
10at reduced rates and on more favorable terms for borrowing by
11local governmental units through the purchase of the bonds or
12notes of the governmental units; and to make or acquire loans
13for the acquisition and development of agricultural
14facilities; to provide financing for private institutions of
15higher education, cultural institutions, health facilities and
16other facilities and projects as authorized by this Act; and
17to grant broad powers to the Illinois Finance Authority to
18accomplish and to carry out these policies of the State which
19are in the public interest of the State and of its taxpayers
20and residents;
21    (o) that providing financing alternatives for projects
22that are located outside the State that are owned, operated,
23leased, managed by, or otherwise affiliated with, institutions
24located within the State would promote the economy of the
25State for the benefit of the health, welfare, safety, trade,
26commerce, industry, and economy of the people of the State by

 

 

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1creating employment opportunities in the State and lowering
2the cost of accessing healthcare, private education, or
3cultural institutions in the State by reducing the cost of
4financing or operating those projects; and
5    (p) that the realization of the objectives of the
6Authority identified in this Act including, without
7limitation, those designed (1) to assist and enable veterans,
8minorities, women and disabled individuals to own and operate
9small businesses; (2) to assist in the delivery of
10agricultural assistance; and (3) to aid, assist, and encourage
11economic growth and development within this State, will be
12enhanced by empowering the Authority to purchase loan
13participations from participating lenders;
14    (q) that climate change threatens the health, welfare and
15prosperity of all of the residents of the State;
16    (r) combating climate change is necessary to preserve and
17enhance the health, welfare and prosperity of all of the
18residents of the State;
19    (s) that the promotion of the development and
20implementation of clean energy is necessary to combat climate
21change and is hereby declared to be the policy of the State;
22and
23    (t) that designating the Authority as the "Climate Bank"
24to aid in all respects with providing financial products and
25programs to finance and otherwise develop and implement clean
26energy in the State to mitigate or adapt to the negative

 

 

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1consequences of climate change, will further the clean energy
2policy of the State.
3(Source: P.A. 100-919, eff. 8-17-18.)
 
4    (20 ILCS 3501/801-10)
5    Sec. 801-10. Definitions. The following terms, whenever
6used or referred to in this Act, shall have the following
7meanings, except in such instances where the context may
8clearly indicate otherwise:
9    (a) The term "Authority" means the Illinois Finance
10Authority created by this Act.
11    (b) The term "project" means an industrial project, clean
12energy project, conservation project, housing project, public
13purpose project, higher education project, health facility
14project, cultural institution project, municipal bond program
15project, PACE Project, agricultural facility or agribusiness,
16and "project" may include any combination of one or more of the
17foregoing undertaken jointly by any person with one or more
18other persons.
19    (c) The term "public purpose project" means (i) any
20project or facility, including without limitation land,
21buildings, structures, machinery, equipment and all other real
22and personal property, which is authorized or required by law
23to be acquired, constructed, improved, rehabilitated,
24reconstructed, replaced or maintained by any unit of
25government or, in the case of a clean energy project, any

 

 

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1person, or any other lawful public purpose, including
2provision of working capital, which is authorized or required
3by law to be undertaken by any unit of government or, in the
4case of a clean energy project, any person, or (ii) costs
5incurred and other expenditures, including expenditures for
6management, investment, or working capital costs, incurred in
7connection with the reform, consolidation, or implementation
8of the transition process as described in Articles 22B and 22C
9of the Illinois Pension Code.
10    (d) The term "industrial project" means the acquisition,
11construction, refurbishment, creation, development or
12redevelopment of any facility, equipment, machinery, real
13property or personal property for use by any instrumentality
14of the State or its political subdivisions, for use by any
15person or institution, public or private, for profit or not
16for profit, or for use in any trade or business, including, but
17not limited to, any industrial, manufacturing, clean energy,
18or commercial enterprise that is located within or outside the
19State, provided that, with respect to a project involving
20property located outside the State, the property must be
21owned, operated, leased or managed by an entity located within
22the State or an entity affiliated with an entity located
23within the State, and which is (1) a capital project or a clean
24energy project, including, but not limited to: (i) land and
25any rights therein, one or more buildings, structures or other
26improvements, machinery and equipment, whether now existing or

 

 

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1hereafter acquired, and whether or not located on the same
2site or sites; (ii) all appurtenances and facilities
3incidental to the foregoing, including, but not limited to,
4utilities, access roads, railroad sidings, track, docking and
5similar facilities, parking facilities, dockage, wharfage,
6railroad roadbed, track, trestle, depot, terminal, switching
7and signaling or related equipment, site preparation and
8landscaping; and (iii) all non-capital costs and expenses
9relating thereto or (2) any addition to, renovation,
10rehabilitation or improvement of a capital project or a clean
11energy project, or (3) any activity or undertaking within or
12outside the State, provided that, with respect to a project
13involving property located outside the State, the property
14must be owned, operated, leased or managed by an entity
15located within the State or an entity affiliated with an
16entity located within the State, which the Authority
17determines will aid, assist or encourage economic growth,
18development or redevelopment within the State or any area
19thereof, will promote the expansion, retention or
20diversification of employment opportunities within the State
21or any area thereof or will aid in stabilizing or developing
22any industry or economic sector of the State economy. The term
23"industrial project" also means the production of motion
24pictures.
25    (e) The term "bond" or "bonds" shall include bonds, notes
26(including bond, grant or revenue anticipation notes),

 

 

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1certificates and/or other evidences of indebtedness
2representing an obligation to pay money, including refunding
3bonds.
4    (f) The terms "lease agreement" and "loan agreement" shall
5mean: (i) an agreement whereby a project acquired by the
6Authority by purchase, gift or lease is leased to any person,
7corporation or unit of local government which will use or
8cause the project to be used as a project as heretofore defined
9upon terms providing for lease rental payments at least
10sufficient to pay when due all principal of, interest and
11premium, if any, on any bonds of the Authority issued with
12respect to such project, providing for the maintenance,
13insuring and operation of the project on terms satisfactory to
14the Authority, providing for disposition of the project upon
15termination of the lease term, including purchase options or
16abandonment of the premises, and such other terms as may be
17deemed desirable by the Authority, or (ii) any agreement
18pursuant to which the Authority agrees to loan the proceeds of
19its bonds issued with respect to a project or other funds of
20the Authority to any person which will use or cause the project
21to be used as a project as heretofore defined upon terms
22providing for loan repayment installments at least sufficient
23to pay when due all principal of, interest and premium, if any,
24on any bonds of the Authority, if any, issued with respect to
25the project, and providing for maintenance, insurance and
26other matters as may be deemed desirable by the Authority.

 

 

SB2896- 135 -LRB102 17909 JWD 25989 b

1    (g) The term "financial aid" means the expenditure of
2Authority funds or funds provided by the Authority through the
3issuance of its bonds, notes or other evidences of
4indebtedness or from other sources for the development,
5construction, acquisition or improvement of a project.
6    (h) The term "person" means an individual, corporation,
7unit of government, business trust, estate, trust, partnership
8or association, 2 or more persons having a joint or common
9interest, or any other legal entity.
10    (i) The term "unit of government" means the federal
11government, the State or unit of local government, a school
12district, or any agency or instrumentality, office, officer,
13department, division, bureau, commission, college or
14university thereof.
15    (j) The term "health facility" means: (a) any public or
16private institution, place, building, or agency required to be
17licensed under the Hospital Licensing Act; (b) any public or
18private institution, place, building, or agency required to be
19licensed under the Nursing Home Care Act, the Specialized
20Mental Health Rehabilitation Act of 2013, the ID/DD Community
21Care Act, or the MC/DD Act; (c) any public or licensed private
22hospital as defined in the Mental Health and Developmental
23Disabilities Code; (d) any such facility exempted from such
24licensure when the Director of Public Health attests that such
25exempted facility meets the statutory definition of a facility
26subject to licensure; (e) any other public or private health

 

 

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1service institution, place, building, or agency which the
2Director of Public Health attests is subject to certification
3by the Secretary, U.S. Department of Health and Human Services
4under the Social Security Act, as now or hereafter amended, or
5which the Director of Public Health attests is subject to
6standard-setting by a recognized public or voluntary
7accrediting or standard-setting agency; (f) any public or
8private institution, place, building or agency engaged in
9providing one or more supporting services to a health
10facility; (g) any public or private institution, place,
11building or agency engaged in providing training in the
12healing arts, including, but not limited to, schools of
13medicine, dentistry, osteopathy, optometry, podiatry, pharmacy
14or nursing, schools for the training of x-ray, laboratory or
15other health care technicians and schools for the training of
16para-professionals in the health care field; (h) any public or
17private congregate, life or extended care or elderly housing
18facility or any public or private home for the aged or infirm,
19including, without limitation, any Facility as defined in the
20Life Care Facilities Act; (i) any public or private mental,
21emotional or physical rehabilitation facility or any public or
22private educational, counseling, or rehabilitation facility or
23home, for those persons with a developmental disability, those
24who are physically ill or disabled, the emotionally disturbed,
25those persons with a mental illness or persons with learning
26or similar disabilities or problems; (j) any public or private

 

 

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1alcohol, drug or substance abuse diagnosis, counseling
2treatment or rehabilitation facility, (k) any public or
3private institution, place, building or agency licensed by the
4Department of Children and Family Services or which is not so
5licensed but which the Director of Children and Family
6Services attests provides child care, child welfare or other
7services of the type provided by facilities subject to such
8licensure; (l) any public or private adoption agency or
9facility; and (m) any public or private blood bank or blood
10center. "Health facility" also means a public or private
11structure or structures suitable primarily for use as a
12laboratory, laundry, nurses or interns residence or other
13housing or hotel facility used in whole or in part for staff,
14employees or students and their families, patients or
15relatives of patients admitted for treatment or care in a
16health facility, or persons conducting business with a health
17facility, physician's facility, surgicenter, administration
18building, research facility, maintenance, storage or utility
19facility and all structures or facilities related to any of
20the foregoing or required or useful for the operation of a
21health facility, including parking or other facilities or
22other supporting service structures required or useful for the
23orderly conduct of such health facility. "Health facility"
24also means, with respect to a project located outside the
25State, any public or private institution, place, building, or
26agency which provides services similar to those described

 

 

SB2896- 138 -LRB102 17909 JWD 25989 b

1above, provided that such project is owned, operated, leased
2or managed by a participating health institution located
3within the State, or a participating health institution
4affiliated with an entity located within the State.
5    (k) The term "participating health institution" means (i)
6a private corporation or association or (ii) a public entity
7of this State, in either case authorized by the laws of this
8State or the applicable state to provide or operate a health
9facility as defined in this Act and which, pursuant to the
10provisions of this Act, undertakes the financing, construction
11or acquisition of a project or undertakes the refunding or
12refinancing of obligations, loans, indebtedness or advances as
13provided in this Act.
14    (l) The term "health facility project", means a specific
15health facility work or improvement to be financed or
16refinanced (including without limitation through reimbursement
17of prior expenditures), acquired, constructed, enlarged,
18remodeled, renovated, improved, furnished, or equipped, with
19funds provided in whole or in part hereunder, any accounts
20receivable, working capital, liability or insurance cost or
21operating expense financing or refinancing program of a health
22facility with or involving funds provided in whole or in part
23hereunder, or any combination thereof.
24    (m) The term "bond resolution" means the resolution or
25resolutions authorizing the issuance of, or providing terms
26and conditions related to, bonds issued under this Act and

 

 

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1includes, where appropriate, any trust agreement, trust
2indenture, indenture of mortgage or deed of trust providing
3terms and conditions for such bonds.
4    (n) The term "property" means any real, personal or mixed
5property, whether tangible or intangible, or any interest
6therein, including, without limitation, any real estate,
7leasehold interests, appurtenances, buildings, easements,
8equipment, furnishings, furniture, improvements, machinery,
9rights of way, structures, accounts, contract rights or any
10interest therein.
11    (o) The term "revenues" means, with respect to any
12project, the rents, fees, charges, interest, principal
13repayments, collections and other income or profit derived
14therefrom.
15    (p) The term "higher education project" means, in the case
16of a private institution of higher education, an educational
17facility to be acquired, constructed, enlarged, remodeled,
18renovated, improved, furnished, or equipped, or any
19combination thereof.
20    (q) The term "cultural institution project" means, in the
21case of a cultural institution, a cultural facility to be
22acquired, constructed, enlarged, remodeled, renovated,
23improved, furnished, or equipped, or any combination thereof.
24    (r) The term "educational facility" means any property
25located within the State, or any property located outside the
26State, provided that, if the property is located outside the

 

 

SB2896- 140 -LRB102 17909 JWD 25989 b

1State, it must be owned, operated, leased or managed by an
2entity located within the State or an entity affiliated with
3an entity located within the State, in each case constructed
4or acquired before or after the effective date of this Act,
5which is or will be, in whole or in part, suitable for the
6instruction, feeding, recreation or housing of students, the
7conducting of research or other work of a private institution
8of higher education, the use by a private institution of
9higher education in connection with any educational, research
10or related or incidental activities then being or to be
11conducted by it, or any combination of the foregoing,
12including, without limitation, any such property suitable for
13use as or in connection with any one or more of the following:
14an academic facility, administrative facility, agricultural
15facility, assembly hall, athletic facility, auditorium,
16boating facility, campus, communication facility, computer
17facility, continuing education facility, classroom, dining
18hall, dormitory, exhibition hall, fire fighting facility, fire
19prevention facility, food service and preparation facility,
20gymnasium, greenhouse, health care facility, hospital,
21housing, instructional facility, laboratory, library,
22maintenance facility, medical facility, museum, offices,
23parking area, physical education facility, recreational
24facility, research facility, stadium, storage facility,
25student union, study facility, theatre or utility.
26    (s) The term "cultural facility" means any property

 

 

SB2896- 141 -LRB102 17909 JWD 25989 b

1located within the State, or any property located outside the
2State, provided that, if the property is located outside the
3State, it must be owned, operated, leased or managed by an
4entity located within the State or an entity affiliated with
5an entity located within the State, in each case constructed
6or acquired before or after the effective date of this Act,
7which is or will be, in whole or in part, suitable for the
8particular purposes or needs of a cultural institution,
9including, without limitation, any such property suitable for
10use as or in connection with any one or more of the following:
11an administrative facility, aquarium, assembly hall,
12auditorium, botanical garden, exhibition hall, gallery,
13greenhouse, library, museum, scientific laboratory, theater or
14zoological facility, and shall also include, without
15limitation, books, works of art or music, animal, plant or
16aquatic life or other items for display, exhibition or
17performance. The term "cultural facility" includes buildings
18on the National Register of Historic Places which are owned or
19operated by nonprofit entities.
20    (t) "Private institution of higher education" means a
21not-for-profit educational institution which is not owned by
22the State or any political subdivision, agency,
23instrumentality, district or municipality thereof, which is
24authorized by law to provide a program of education beyond the
25high school level and which:
26        (1) Admits as regular students only individuals having

 

 

SB2896- 142 -LRB102 17909 JWD 25989 b

1    a certificate of graduation from a high school, or the
2    recognized equivalent of such a certificate;
3        (2) Provides an educational program for which it
4    awards a bachelor's degree, or provides an educational
5    program, admission into which is conditioned upon the
6    prior attainment of a bachelor's degree or its equivalent,
7    for which it awards a postgraduate degree, or provides not
8    less than a 2-year program which is acceptable for full
9    credit toward such a degree, or offers a 2-year program in
10    engineering, mathematics, or the physical or biological
11    sciences which is designed to prepare the student to work
12    as a technician and at a semiprofessional level in
13    engineering, scientific, or other technological fields
14    which require the understanding and application of basic
15    engineering, scientific, or mathematical principles or
16    knowledge;
17        (3) Is accredited by a nationally recognized
18    accrediting agency or association or, if not so
19    accredited, is an institution whose credits are accepted,
20    on transfer, by not less than 3 institutions which are so
21    accredited, for credit on the same basis as if transferred
22    from an institution so accredited, and holds an unrevoked
23    certificate of approval under the Private College Act from
24    the Board of Higher Education, or is qualified as a
25    "degree granting institution" under the Academic Degree
26    Act; and

 

 

SB2896- 143 -LRB102 17909 JWD 25989 b

1        (4) Does not discriminate in the admission of students
2    on the basis of race or color. "Private institution of
3    higher education" also includes any "academic
4    institution".
5    (u) The term "academic institution" means any
6not-for-profit institution which is not owned by the State or
7any political subdivision, agency, instrumentality, district
8or municipality thereof, which institution engages in, or
9facilitates academic, scientific, educational or professional
10research or learning in a field or fields of study taught at a
11private institution of higher education. Academic institutions
12include, without limitation, libraries, archives, academic,
13scientific, educational or professional societies,
14institutions, associations or foundations having such
15purposes.
16    (v) The term "cultural institution" means any
17not-for-profit institution which is not owned by the State or
18any political subdivision, agency, instrumentality, district
19or municipality thereof, which institution engages in the
20cultural, intellectual, scientific, educational or artistic
21enrichment of the people of the State. Cultural institutions
22include, without limitation, aquaria, botanical societies,
23historical societies, libraries, museums, performing arts
24associations or societies, scientific societies and zoological
25societies.
26    (w) The term "affiliate" means, with respect to financing

 

 

SB2896- 144 -LRB102 17909 JWD 25989 b

1of an agricultural facility or an agribusiness, any lender,
2any person, firm or corporation controlled by, or under common
3control with, such lender, and any person, firm or corporation
4controlling such lender.
5    (x) The term "agricultural facility" means land, any
6building or other improvement thereon or thereto, and any
7personal properties deemed necessary or suitable for use,
8whether or not now in existence, in farming, ranching, the
9production of agricultural commodities (including, without
10limitation, the products of aquaculture, hydroponics and
11silviculture) or the treating, processing or storing of such
12agricultural commodities when such activities are customarily
13engaged in by farmers as a part of farming and which land,
14building, improvement or personal property is located within
15the State, or is located outside the State, provided that, if
16such property is located outside the State, it must be owned,
17operated, leased, or managed by an entity located within the
18State or an entity affiliated with an entity located within
19the State.
20    (y) The term "lender" with respect to financing of an
21agricultural facility or an agribusiness, means any federal or
22State chartered bank, Federal Land Bank, Production Credit
23Association, Bank for Cooperatives, federal or State chartered
24savings and loan association or building and loan association,
25Small Business Investment Company or any other institution
26qualified within this State to originate and service loans,

 

 

SB2896- 145 -LRB102 17909 JWD 25989 b

1including, but without limitation to, insurance companies,
2credit unions and mortgage loan companies. "Lender" also means
3a wholly owned subsidiary of a manufacturer, seller or
4distributor of goods or services that makes loans to
5businesses or individuals, commonly known as a "captive
6finance company".
7    (z) The term "agribusiness" means any sole proprietorship,
8limited partnership, co-partnership, joint venture,
9corporation or cooperative which operates or will operate a
10facility located within the State or outside the State,
11provided that, if any facility is located outside the State,
12it must be owned, operated, leased, or managed by an entity
13located within the State or an entity affiliated with an
14entity located within the State, that is related to the
15processing of agricultural commodities (including, without
16limitation, the products of aquaculture, hydroponics and
17silviculture) or the manufacturing, production or construction
18of agricultural buildings, structures, equipment, implements,
19and supplies, or any other facilities or processes used in
20agricultural production. Agribusiness includes but is not
21limited to the following:
22        (1) grain handling and processing, including grain
23    storage, drying, treatment, conditioning, mailing and
24    packaging;
25        (2) seed and feed grain development and processing;
26        (3) fruit and vegetable processing, including

 

 

SB2896- 146 -LRB102 17909 JWD 25989 b

1    preparation, canning and packaging;
2        (4) processing of livestock and livestock products,
3    dairy products, poultry and poultry products, fish or
4    apiarian products, including slaughter, shearing,
5    collecting, preparation, canning and packaging;
6        (5) fertilizer and agricultural chemical
7    manufacturing, processing, application and supplying;
8        (6) farm machinery, equipment and implement
9    manufacturing and supplying;
10        (7) manufacturing and supplying of agricultural
11    commodity processing machinery and equipment, including
12    machinery and equipment used in slaughter, treatment,
13    handling, collecting, preparation, canning or packaging of
14    agricultural commodities;
15        (8) farm building and farm structure manufacturing,
16    construction and supplying;
17        (9) construction, manufacturing, implementation,
18    supplying or servicing of irrigation, drainage and soil
19    and water conservation devices or equipment;
20        (10) fuel processing and development facilities that
21    produce fuel from agricultural commodities or byproducts;
22        (11) facilities and equipment for processing and
23    packaging agricultural commodities specifically for
24    export;
25        (12) facilities and equipment for forestry product
26    processing and supplying, including sawmilling operations,

 

 

SB2896- 147 -LRB102 17909 JWD 25989 b

1    wood chip operations, timber harvesting operations, and
2    manufacturing of prefabricated buildings, paper, furniture
3    or other goods from forestry products;
4        (13) facilities and equipment for research and
5    development of products, processes and equipment for the
6    production, processing, preparation or packaging of
7    agricultural commodities and byproducts.
8    (aa) The term "asset" with respect to financing of any
9agricultural facility or any agribusiness, means, but is not
10limited to the following: cash crops or feed on hand;
11livestock held for sale; breeding stock; marketable bonds and
12securities; securities not readily marketable; accounts
13receivable; notes receivable; cash invested in growing crops;
14net cash value of life insurance; machinery and equipment;
15cars and trucks; farm and other real estate including life
16estates and personal residence; value of beneficial interests
17in trusts; government payments or grants; and any other
18assets.
19    (bb) The term "liability" with respect to financing of any
20agricultural facility or any agribusiness shall include, but
21not be limited to the following: accounts payable; notes or
22other indebtedness owed to any source; taxes; rent; amounts
23owed on real estate contracts or real estate mortgages;
24judgments; accrued interest payable; and any other liability.
25    (cc) The term "Predecessor Authorities" means those
26authorities as described in Section 845-75.

 

 

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1    (dd) The term "housing project" means a specific work or
2improvement located within the State or outside the State and
3undertaken to provide residential dwelling accommodations,
4including the acquisition, construction or rehabilitation of
5lands, buildings and community facilities and in connection
6therewith to provide nonhousing facilities which are part of
7the housing project, including land, buildings, improvements,
8equipment and all ancillary facilities for use for offices,
9stores, retirement homes, hotels, financial institutions,
10service, health care, education, recreation or research
11establishments, or any other commercial purpose which are or
12are to be related to a housing development, provided that any
13work or improvement located outside the State is owned,
14operated, leased or managed by an entity located within the
15State, or any entity affiliated with an entity located within
16the State.
17    (ee) The term "conservation project" means any project
18including the acquisition, construction, rehabilitation,
19maintenance, operation, or upgrade that is intended to create
20or expand open space or to reduce energy usage through
21efficiency measures. For the purpose of this definition, "open
22space" has the definition set forth under Section 10 of the
23Illinois Open Land Trust Act.
24    (ff) The term "significant presence" means the existence
25within the State of the national or regional headquarters of
26an entity or group or such other facility of an entity or group

 

 

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1of entities where a significant amount of the business
2functions are performed for such entity or group of entities.
3    (gg) The term "municipal bond issuer" means the State or
4any other state or commonwealth of the United States, or any
5unit of local government, school district, agency or
6instrumentality, office, department, division, bureau,
7commission, college or university thereof located in the State
8or any other state or commonwealth of the United States.
9    (hh) The term "municipal bond program project" means a
10program for the funding of the purchase of bonds, notes or
11other obligations issued by or on behalf of a municipal bond
12issuer.
13    (ii) The term "participating lender" means any trust
14company, bank, savings bank, credit union, merchant bank,
15investment bank, broker, investment trust, pension fund,
16building and loan association, savings and loan association,
17insurance company, venture capital company, or other
18institution approved by the Authority which provides a portion
19of the financing for a project.
20    (jj) The term "loan participation" means any loan in which
21the Authority co-operates with a participating lender to
22provide all or a portion of the financing for a project.
23    (kk) The term "PACE Project" means an energy project as
24defined in Section 5 of the Property Assessed Clean Energy
25Act.
26    (ll) The term "clean energy" means energy generation that

 

 

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1is substantially free (90% or more) of carbon dioxide
2emissions by design or operations, or which otherwise
3contributes to the reduction in emissions of
4environmentally-hazardous materials or reduces the volume of
5environmentally-dangerous materials.
6    (mm) The term "clean energy project" means the
7acquisition, construction, refurbishment, creation,
8development or redevelopment of any facility, equipment,
9machinery, real property or personal property for use by the
10State or any unit of local government, school district, agency
11or instrumentality, office, department, division, bureau,
12commission, college or university of the State, for use by any
13person or institution, public or private, for profit or not
14for profit, or for use in any trade or business, which the
15Authority determines will aid, assist or encourage the
16development or implementation of clean energy in the State, or
17as otherwise contemplated by Article 850.
18    (nn) The term "Climate Bank" means the Authority in the
19exercise of those powers conferred on it by this Act related to
20clean energy or clean water, drinking water, or wastewater
21treatment.
22(Source: P.A. 100-919, eff. 8-17-18; 101-610, eff. 1-1-20.)
 
23    (20 ILCS 3501/801-40)
24    Sec. 801-40. In addition to the powers otherwise
25authorized by law and in addition to the foregoing general

 

 

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1corporate powers, the Authority shall also have the following
2additional specific powers to be exercised in furtherance of
3the purposes of this Act.
4    (a) The Authority shall have power (i) to accept grants,
5loans or appropriations from the federal government or the
6State, or any agency or instrumentality thereof, or, in the
7case of clean energy projects, any not for profit,
8philanthropic or other charitable organization, public or
9private, to be used for the operating expenses of the
10Authority, or for any purposes of the Authority, including the
11making of direct loans of such funds with respect to projects,
12and (ii) to enter into any agreement with the federal
13government or the State, or any agency or instrumentality
14thereof, in relationship to such grants, loans or
15appropriations.
16    (b) The Authority shall have power to procure and enter
17into contracts for any type of insurance and indemnity
18agreements covering loss or damage to property from any cause,
19including loss of use and occupancy, or covering any other
20insurable risk.
21    (c) The Authority shall have the continuing power to issue
22bonds for its corporate purposes. Bonds may be issued by the
23Authority in one or more series and may provide for the payment
24of any interest deemed necessary on such bonds, of the costs of
25issuance of such bonds, of any premium on any insurance, or of
26the cost of any guarantees, letters of credit or other similar

 

 

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1documents, may provide for the funding of the reserves deemed
2necessary in connection with such bonds, and may provide for
3the refunding or advance refunding of any bonds or for
4accounts deemed necessary in connection with any purpose of
5the Authority. The bonds may bear interest payable at any time
6or times and at any rate or rates, notwithstanding any other
7provision of law to the contrary, and such rate or rates may be
8established by an index or formula which may be implemented or
9established by persons appointed or retained therefor by the
10Authority, or may bear no interest or may bear interest
11payable at maturity or upon redemption prior to maturity, may
12bear such date or dates, may be payable at such time or times
13and at such place or places, may mature at any time or times
14not later than 40 years from the date of issuance, may be sold
15at public or private sale at such time or times and at such
16price or prices, may be secured by such pledges, reserves,
17guarantees, letters of credit, insurance contracts or other
18similar credit support or liquidity instruments, may be
19executed in such manner, may be subject to redemption prior to
20maturity, may provide for the registration of the bonds, and
21may be subject to such other terms and conditions all as may be
22provided by the resolution or indenture authorizing the
23issuance of such bonds. The holder or holders of any bonds
24issued by the Authority may bring suits at law or proceedings
25in equity to compel the performance and observance by any
26person or by the Authority or any of its agents or employees of

 

 

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1any contract or covenant made with the holders of such bonds
2and to compel such person or the Authority and any of its
3agents or employees to perform any duties required to be
4performed for the benefit of the holders of any such bonds by
5the provision of the resolution authorizing their issuance,
6and to enjoin such person or the Authority and any of its
7agents or employees from taking any action in conflict with
8any such contract or covenant. Notwithstanding the form and
9tenor of any such bonds and in the absence of any express
10recital on the face thereof that it is non-negotiable, all
11such bonds shall be negotiable instruments. Pending the
12preparation and execution of any such bonds, temporary bonds
13may be issued as provided by the resolution. The bonds shall be
14sold by the Authority in such manner as it shall determine. The
15bonds may be secured as provided in the authorizing resolution
16by the receipts, revenues, income and other available funds of
17the Authority and by any amounts derived by the Authority from
18the loan agreement or lease agreement with respect to the
19project or projects; and bonds may be issued as general
20obligations of the Authority payable from such revenues, funds
21and obligations of the Authority as the bond resolution shall
22provide, or may be issued as limited obligations with a claim
23for payment solely from such revenues, funds and obligations
24as the bond resolution shall provide. The Authority may grant
25a specific pledge or assignment of and lien on or security
26interest in such rights, revenues, income, or amounts and may

 

 

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1grant a specific pledge or assignment of and lien on or
2security interest in any reserves, funds or accounts
3established in the resolution authorizing the issuance of
4bonds. Any such pledge, assignment, lien or security interest
5for the benefit of the holders of the Authority's bonds shall
6be valid and binding from the time the bonds are issued without
7any physical delivery or further act, and shall be valid and
8binding as against and prior to the claims of all other parties
9having claims against the Authority or any other person
10irrespective of whether the other parties have notice of the
11pledge, assignment, lien or security interest. As evidence of
12such pledge, assignment, lien and security interest, the
13Authority may execute and deliver a mortgage, trust agreement,
14indenture or security agreement or an assignment thereof. A
15remedy for any breach or default of the terms of any such
16agreement by the Authority may be by mandamus proceedings in
17any court of competent jurisdiction to compel the performance
18and compliance therewith, but the agreement may prescribe by
19whom or on whose behalf such action may be instituted. It is
20expressly understood that the Authority may, but need not,
21acquire title to any project with respect to which it
22exercises its authority.
23    (d) With respect to the powers granted by this Act, the
24Authority may adopt rules and regulations prescribing the
25procedures by which persons may apply for assistance under
26this Act. Nothing herein shall be deemed to preclude the

 

 

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1Authority, prior to the filing of any formal application, from
2conducting preliminary discussions and investigations with
3respect to the subject matter of any prospective application.
4    (e) The Authority shall have power to acquire by purchase,
5lease, gift or otherwise any property or rights therein from
6any person useful for its purposes, whether improved for the
7purposes of any prospective project, or unimproved. The
8Authority may also accept any donation of funds for its
9purposes from any such source. The Authority shall have no
10independent power of condemnation but may acquire any property
11or rights therein obtained upon condemnation by any other
12authority, governmental entity or unit of local government
13with such power.
14    (f) The Authority shall have power to develop, construct
15and improve either under its own direction, or through
16collaboration with any approved applicant, or to acquire
17through purchase or otherwise, any project, using for such
18purpose the proceeds derived from the sale of its bonds or from
19governmental loans or grants, and to hold title in the name of
20the Authority to such projects.
21    (g) The Authority shall have power to lease pursuant to a
22lease agreement any project so developed and constructed or
23acquired to the approved tenant on such terms and conditions
24as may be appropriate to further the purposes of this Act and
25to maintain the credit of the Authority. Any such lease may
26provide for either the Authority or the approved tenant to

 

 

SB2896- 156 -LRB102 17909 JWD 25989 b

1assume initially, in whole or in part, the costs of
2maintenance, repair and improvements during the leasehold
3period. In no case, however, shall the total rentals from any
4project during any initial leasehold period or the total loan
5repayments to be made pursuant to any loan agreement, be less
6than an amount necessary to return over such lease or loan
7period (1) all costs incurred in connection with the
8development, construction, acquisition or improvement of the
9project and for repair, maintenance and improvements thereto
10during the period of the lease or loan; provided, however,
11that the rentals or loan repayments need not include costs met
12through the use of funds other than those obtained by the
13Authority through the issuance of its bonds or governmental
14loans; (2) a reasonable percentage additive to be agreed upon
15by the Authority and the borrower or tenant to cover a properly
16allocable portion of the Authority's general expenses,
17including, but not limited to, administrative expenses,
18salaries and general insurance, and (3) an amount sufficient
19to pay when due all principal of, interest and premium, if any
20on, any bonds issued by the Authority with respect to the
21project. The portion of total rentals payable under clause (3)
22of this subsection (g) shall be deposited in such special
23accounts, including all sinking funds, acquisition or
24construction funds, debt service and other funds as provided
25by any resolution, mortgage or trust agreement of the
26Authority pursuant to which any bond is issued.

 

 

SB2896- 157 -LRB102 17909 JWD 25989 b

1    (h) The Authority has the power, upon the termination of
2any leasehold period of any project, to sell or lease for a
3further term or terms such project on such terms and
4conditions as the Authority shall deem reasonable and
5consistent with the purposes of the Act. The net proceeds from
6all such sales and the revenues or income from such leases
7shall be used to satisfy any indebtedness of the Authority
8with respect to such project and any balance may be used to pay
9any expenses of the Authority or be used for the further
10development, construction, acquisition or improvement of
11projects. In the event any project is vacated by a tenant prior
12to the termination of the initial leasehold period, the
13Authority shall sell or lease the facilities of the project on
14the most advantageous terms available. The net proceeds of any
15such disposition shall be treated in the same manner as the
16proceeds from sales or the revenues or income from leases
17subsequent to the termination of any initial leasehold period.
18    (i) The Authority shall have the power to make loans, or to
19purchase loan participations in loans made, to persons to
20finance a project, to enter into loan agreements or agreements
21with participating lenders with respect thereto, and to accept
22guarantees from persons of its loans or the resultant
23evidences of obligations of the Authority.
24    (j) The Authority may fix, determine, charge and collect
25any premiums, fees, charges, costs and expenses, including,
26without limitation, any application fees, commitment fees,

 

 

SB2896- 158 -LRB102 17909 JWD 25989 b

1program fees, financing charges or publication fees from any
2person in connection with its activities under this Act.
3    (k) In addition to the funds established as provided
4herein, the Authority shall have the power to create and
5establish such reserve funds and accounts as may be necessary
6or desirable to accomplish its purposes under this Act and to
7deposit its available monies into the funds and accounts.
8    (l) At the request of the governing body of any unit of
9local government, the Authority is authorized to market such
10local government's revenue bond offerings by preparing bond
11issues for sale, advertising for sealed bids, receiving bids
12at its offices, making the award to the bidder that offers the
13most favorable terms or arranging for negotiated placements or
14underwritings of such securities. The Authority may, at its
15discretion, offer for concurrent sale the revenue bonds of
16several local governments. Sales by the Authority of revenue
17bonds under this Section shall in no way imply State guarantee
18of such debt issue. The Authority may require such financial
19information from participating local governments as it deems
20necessary in order to carry out the purposes of this
21subsection (1).
22    (m) The Authority may make grants to any county to which
23Division 5-37 of the Counties Code is applicable to assist in
24the financing of capital development, construction and
25renovation of new or existing facilities for hospitals and
26health care facilities under that Act. Such grants may only be

 

 

SB2896- 159 -LRB102 17909 JWD 25989 b

1made from funds appropriated for such purposes from the Build
2Illinois Bond Fund.
3    (n) The Authority may establish an urban development
4action grant program for the purpose of assisting
5municipalities in Illinois which are experiencing severe
6economic distress to help stimulate economic development
7activities needed to aid in economic recovery. The Authority
8shall determine the types of activities and projects for which
9the urban development action grants may be used, provided that
10such projects and activities are broadly defined to include
11all reasonable projects and activities the primary objectives
12of which are the development of viable urban communities,
13including decent housing and a suitable living environment,
14and expansion of economic opportunity, principally for persons
15of low and moderate incomes. The Authority shall enter into
16grant agreements from monies appropriated for such purposes
17from the Build Illinois Bond Fund. The Authority shall monitor
18the use of the grants, and shall provide for audits of the
19funds as well as recovery by the Authority of any funds
20determined to have been spent in violation of this subsection
21(n) or any rule or regulation promulgated hereunder. The
22Authority shall provide technical assistance with regard to
23the effective use of the urban development action grants. The
24Authority shall file an annual report to the General Assembly
25concerning the progress of the grant program.
26    (o) The Authority may establish a Housing Partnership

 

 

SB2896- 160 -LRB102 17909 JWD 25989 b

1Program whereby the Authority provides zero-interest loans to
2municipalities for the purpose of assisting in the financing
3of projects for the rehabilitation of affordable multi-family
4housing for low and moderate income residents. The Authority
5may provide such loans only upon a municipality's providing
6evidence that it has obtained private funding for the
7rehabilitation project. The Authority shall provide 3 State
8dollars for every 7 dollars obtained by the municipality from
9sources other than the State of Illinois. The loans shall be
10made from monies appropriated for such purpose from the Build
11Illinois Bond Fund. The total amount of loans available under
12the Housing Partnership Program shall not exceed $30,000,000.
13State loan monies under this subsection shall be used only for
14the acquisition and rehabilitation of existing buildings
15containing 4 or more dwelling units. The terms of any loan made
16by the municipality under this subsection shall require
17repayment of the loan to the municipality upon any sale or
18other transfer of the project. In addition, the Authority may
19use any moneys appropriated for such purpose from the Build
20Illinois Bond Fund, including funds loaned under this
21subsection and repaid as principal or interest, and investment
22income on such funds, to make the loans authorized by
23subsection (z), without regard to any restrictions or
24limitations provided in this subsection.
25    (p) The Authority may award grants to universities and
26research institutions, research consortiums and other

 

 

SB2896- 161 -LRB102 17909 JWD 25989 b

1not-for-profit entities for the purposes of: remodeling or
2otherwise physically altering existing laboratory or research
3facilities, expansion or physical additions to existing
4laboratory or research facilities, construction of new
5laboratory or research facilities or acquisition of modern
6equipment to support laboratory or research operations
7provided that such grants (i) be used solely in support of
8project and equipment acquisitions which enhance technology
9transfer, and (ii) not constitute more than 60 percent of the
10total project or acquisition cost.
11    (q) Grants may be awarded by the Authority to units of
12local government for the purpose of developing the appropriate
13infrastructure or defraying other costs to the local
14government in support of laboratory or research facilities
15provided that such grants may not exceed 40% of the cost to the
16unit of local government.
17    (r) In addition to the powers granted to the Authority
18under subsection (i), and in all cases supplemental to it, the
19Authority may establish a direct loan program to make loans
20to, or may purchase participations in loans made by
21participating lenders to, individuals, partnerships,
22corporations, or other business entities for the purpose of
23financing an industrial project, as defined in Section 801-10
24of this Act. For the purposes of such program and not by way of
25limitation on any other program of the Authority, including,
26without limitation, programs established under subsection (i),

 

 

SB2896- 162 -LRB102 17909 JWD 25989 b

1the Authority shall have the power to issue bonds, notes, or
2other evidences of indebtedness including commercial paper for
3purposes of providing a fund of capital from which it may make
4such loans. The Authority shall have the power to use any
5appropriations from the State made especially for the
6Authority's direct loan program, or moneys at any time held by
7the Authority under this Act outside the State treasury in the
8custody of either the Treasurer of the Authority or a trustee
9or depository appointed by the Authority, for additional
10capital to make such loans or purchase such loan
11participations, or for the purposes of reserve funds or
12pledged funds which secure the Authority's obligations of
13repayment of any bond, note or other form of indebtedness
14established for the purpose of providing capital for which it
15intends to make such loans or purchase such loan
16participations. For the purpose of obtaining such capital, the
17Authority may also enter into agreements with financial
18institutions, participating lenders, and other persons for the
19purpose of administering a loan participation program, selling
20loans or developing a secondary market for such loans or loan
21participations. Loans made under the direct loan program
22specifically established under this subsection (r), including
23loans under such program made by participating lenders in
24which the Authority purchases a participation, may be in an
25amount not to exceed $600,000 and shall be made for a portion
26of an industrial project which does not exceed 50% of the total

 

 

SB2896- 163 -LRB102 17909 JWD 25989 b

1project. No loan may be made by the Authority unless approved
2by the affirmative vote of at least 8 members of the board. The
3Authority shall establish procedures and publish rules which
4shall provide for the submission, review, and analysis of each
5direct loan and loan participation application and which shall
6preserve the ability of each board member and the Executive
7Director, as applicable, to reach an individual business
8judgment regarding the propriety of each direct loan or loan
9participation. The collective discretion of the board to
10approve or disapprove each loan shall be unencumbered. The
11Authority may establish and collect such fees and charges,
12determine and enforce such terms and conditions, and charge
13such interest rates as it determines to be necessary and
14appropriate to the successful administration of the direct
15loan program, including purchasing loan participations. The
16Authority may require such interests in collateral and such
17guarantees as it determines are necessary to protect the
18Authority's interest in the repayment of the principal and
19interest of each loan and loan participation made under the
20direct loan program. The restrictions established under this
21subsection (r) shall not be applicable to any loan or loan
22participation made under subsection (i) or to any loan or loan
23participation made under any other Section of this Act.
24    (s) The Authority may guarantee private loans to third
25parties up to a specified dollar amount in order to promote
26economic development in this State.

 

 

SB2896- 164 -LRB102 17909 JWD 25989 b

1    (t) The Authority may adopt rules and regulations as may
2be necessary or advisable to implement the powers conferred by
3this Act.
4    (u) The Authority shall have the power to issue bonds,
5notes or other evidences of indebtedness, which may be used to
6make loans to units of local government which are authorized
7to enter into loan agreements and other documents and to issue
8bonds, notes and other evidences of indebtedness for the
9purpose of financing the protection of storm sewer outfalls,
10the construction of adequate storm sewer outfalls, and the
11provision for flood protection of sanitary sewage treatment
12plans, in counties that have established a stormwater
13management planning committee in accordance with Section
145-1062 of the Counties Code. Any such loan shall be made by the
15Authority pursuant to the provisions of Section 820-5 to
16820-60 of this Act. The unit of local government shall pay back
17to the Authority the principal amount of the loan, plus annual
18interest as determined by the Authority. The Authority shall
19have the power, subject to appropriations by the General
20Assembly, to subsidize or buy down a portion of the interest on
21such loans, up to 4% per annum.
22    (v) The Authority may accept security interests as
23provided in Sections 11-3 and 11-3.3 of the Illinois Public
24Aid Code.
25    (w) Moral Obligation. In the event that the Authority
26determines that monies of the Authority will not be sufficient

 

 

SB2896- 165 -LRB102 17909 JWD 25989 b

1for the payment of the principal of and interest on its bonds
2during the next State fiscal year, the Chairperson, as soon as
3practicable, shall certify to the Governor the amount required
4by the Authority to enable it to pay such principal of and
5interest on the bonds. The Governor shall submit the amount so
6certified to the General Assembly as soon as practicable, but
7no later than the end of the current State fiscal year. This
8subsection shall apply only to any bonds or notes as to which
9the Authority shall have determined, in the resolution
10authorizing the issuance of the bonds or notes, that this
11subsection shall apply. Whenever the Authority makes such a
12determination, that fact shall be plainly stated on the face
13of the bonds or notes and that fact shall also be reported to
14the Governor. In the event of a withdrawal of moneys from a
15reserve fund established with respect to any issue or issues
16of bonds of the Authority to pay principal or interest on those
17bonds, the Chairperson of the Authority, as soon as
18practicable, shall certify to the Governor the amount required
19to restore the reserve fund to the level required in the
20resolution or indenture securing those bonds. The Governor
21shall submit the amount so certified to the General Assembly
22as soon as practicable, but no later than the end of the
23current State fiscal year. The Authority shall obtain written
24approval from the Governor for any bonds and notes to be issued
25under this Section. In addition to any other bonds authorized
26to be issued under Sections 825-60, 825-65(e), 830-25 and

 

 

SB2896- 166 -LRB102 17909 JWD 25989 b

1845-5, the principal amount of Authority bonds outstanding
2issued under this Section 801-40(w) or under 20 ILCS 3850/1-80
3or 30 ILCS 360/2-6(c), which have been assumed by the
4Authority, shall not exceed $150,000,000. This subsection (w)
5shall in no way be applied to any bonds issued by the Authority
6on behalf of the Illinois Power Agency under Section 825-90 of
7this Act.
8    (x) The Authority may enter into agreements or contracts
9with any person necessary or appropriate to place the payment
10obligations of the Authority under any of its bonds in whole or
11in part on any interest rate basis, cash flow basis, or other
12basis desired by the Authority, including without limitation
13agreements or contracts commonly known as "interest rate swap
14agreements", "forward payment conversion agreements", and
15"futures", or agreements or contracts to exchange cash flows
16or a series of payments, or agreements or contracts, including
17without limitation agreements or contracts commonly known as
18"options", "puts", or "calls", to hedge payment, rate spread,
19or similar exposure; provided that any such agreement or
20contract shall not constitute an obligation for borrowed money
21and shall not be taken into account under Section 845-5 of this
22Act or any other debt limit of the Authority or the State of
23Illinois.
24    (y) The Authority shall publish summaries of projects and
25actions approved by the members of the Authority on its
26website. These summaries shall include, but not be limited to,

 

 

SB2896- 167 -LRB102 17909 JWD 25989 b

1information regarding the:
2        (1) project;
3        (2) Board's action or actions;
4        (3) purpose of the project;
5        (4) Authority's program and contribution;
6        (5) volume cap;
7        (6) jobs retained;
8        (7) projected new jobs;
9        (8) construction jobs created;
10        (9) estimated sources and uses of funds;
11        (10) financing summary;
12        (11) project summary;
13        (12) business summary;
14        (13) ownership or economic disclosure statement;
15        (14) professional and financial information;
16        (15) service area; and
17        (16) legislative district.
18    The disclosure of information pursuant to this subsection
19shall comply with the Freedom of Information Act.
20    (z) Consistent with the findings and declaration of policy
21set forth in item (j) of Section 801-5 of this Act, the
22Authority shall have the power to make loans to the Police
23Officers' Pension Investment Fund authorized by Section
2422B-120 of the Illinois Pension Code and to make loans to the
25Firefighters' Pension Investment Fund authorized by Section
2622C-120 of the Illinois Pension Code. Notwithstanding anything

 

 

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1in this Act to the contrary, loans authorized by Section
222B-120 and Section 22C-120 of the Illinois Pension Code may
3be made from any of the Authority's funds, including, but not
4limited to, funds in its Illinois Housing Partnership Program
5Fund, its Industrial Project Insurance Fund, or its Illinois
6Venture Investment Fund.
7(Source: P.A. 100-919, eff. 8-17-18; 101-610, eff. 1-1-20.)
 
8    (20 ILCS 3501/Art. 850 heading new)
9
ARTICLE 850 GENERAL PROVISIONS

 
10    (20 ILCS 3501/850-5 new)
11    Sec. 850-5. Climate Bank. The General Assembly designates
12the Authority as the Climate Bank to aid in all respects with
13providing financial products and programs to finance and
14otherwise develop and implement clean energy and the provision
15of clean water, drinking water and wastewater treatment in the
16State. Nothing in this Section 850-5 shall be deemed to
17supersede powers and regulatory duties conferred to other
18State agencies or governmental units.
 
19    (20 ILCS 3501/850-10 new)
20    Sec. 850-10. Powers and Duties.
21    (a) The Authority shall have the powers enumerated in this
22Act to assist in the development and implementation of clean
23energy in the State. The powers enumerated in this Article 850

 

 

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1shall in addition to all other powers with respect to clean
2energy and the provision of clean water, drinking water and
3wastewater treatment conferred elsewhere in the Act.
4    (b) In its role as the Climate Bank of the State, the
5Authority shall have the power to (i) finance and otherwise
6support clean energy projects and investment in the State,
7including for residential, municipal, small business and
8larger commercial projects as it may determine, (ii) support
9and otherwise promote investment in clean energy projects to
10foster the growth, development and commercialization of clean
11energy projects and related enterprises, and (iii) stimulate
12demand for clean energy and the development of clean energy
13projects within the State.
14    (c) In addition to, and not in limitation of, any other
15power of the Authority set forth in this Section or any other
16provisions of the general statutes, the Authority shall have
17and may exercise the following powers in furtherance of or in
18carrying out its clean energy powers and purposes:
19        (1) To enter into joint ventures and invest in, and
20    participate with any person, including, without
21    limitation, government entities and private corporations,
22    in the formation, ownership, management and operation of
23    business entities, including stock and nonstock
24    corporations, limited liability companies and general or
25    limited partnerships, formed to advance the purposes of
26    clean energy, provided that members of the Authority or

 

 

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1    officers may serve as directors, members or officers of
2    any such business entity, and such service shall be deemed
3    to be in the discharge of the duties or within the scope of
4    the employment of any such member or officer, or Authority
5    or officers, as the case may be, so long as such member or
6    officer does not receive any compensation or direct or
7    indirect financial benefit as a result of serving in such
8    role.
9        (2) To do all other acts and things necessary or
10    convenient to carry out the clean energy purposes and
11    powers of the Authority.
12        (3) To utilize funding sources including but not
13    limited to:
14            (A) funds repurposed from existing programs
15        providing financing support for clean energy projects,
16        provided any transfer of funds from such existing
17        programs shall be subject to approval by the General
18        Assembly and shall be used for expenses of financing,
19        grants and loans;
20            (B) any federal funds that can be used for clean
21        energy purposes;
22            (C) charitable gifts, grants, contributions as
23        well as loans from individuals, corporations,
24        university endowments and philanthropic foundations
25        for clean energy projects or for the provision of
26        clean water, drinking water and wastewater treatment;

 

 

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1            (D) earnings and interest derived from financing
2        support activities for clean energy projects financed
3        by the Authority; and
4            (E) if and to the extent that the Authority
5        qualifies as a Community Development Financial
6        Institution under Section 4702 of the United States
7        Code, funding from the Community Development Financial
8        Institution Fund administered by the United States
9        Department of Treasury, as well as loans from and
10        investments by depository institutions seeking to
11        comply with their obligations under the United States
12        Community Reinvestment Act of 1977.
13        (4) The Authority may enter into contracts with
14    private sources to raise capital.
15    (f) The Authority may finance working capital, refinance
16outstanding indebtedness of any person, and otherwise assist
17in the investment of equity from any source, public or
18private, in connection with a clean energy project.
19    (g) The Authority may assess reasonable fees on its
20financing activities to cover its reasonable costs and
21expenses, as determined by it.
22    (h) The Authority shall make information regarding the
23rates, terms and conditions for all of its financing support
24transactions available to the public for inspection, including
25formal annual reviews by both a private auditor and the
26Comptroller, and providing details to the public on the

 

 

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1internet, provided public disclosure shall be restricted for
2patentable ideas, trade secrets, proprietary or confidential
3commercial or financial information, disclosure of which may
4cause commercial harm to a nongovernmental recipient of such
5financing support and for other information exempt from public
6records disclosure pursuant to Section 1-210.
 
7    (20 ILCS 3501/850-15 new)
8    Sec. 850-15. Purposes. In its role as the Climate Bank for
9the State, the Authority shall consider the following
10purposes:
11    (a) the equitable distribution of the benefits of clean
12energy;
13    (b) making clean energy accessible to all through
14financing opportunities and grants for Minority Business
15Enterprises, as defined in the Business Enterprise Act, and
16for low-income communities, environmental justice communities,
17and the businesses that serve these communities; and
18    (c) accelerating the investment of private capital into
19clean energy projects in an equitable fashion in order to
20reflect the geographic, racial, ethnic, gender, and
21income-level diversity of the State.
 
22    Section 30-23. The Energy Efficient Building Act is
23amended by changing Sections 10, 15, 20, 30, and 45 and by
24adding Section 55 as follows:
 

 

 

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1    (20 ILCS 3125/10)
2    Sec. 10. Definitions.
3    "Board" means the Capital Development Board.
4    "Building" includes both residential buildings and
5commercial buildings.
6    "Code" means the latest published edition of the
7International Code Council's International Energy Conservation
8Code as adopted by the Board, including any published
9supplements adopted by the Board and any amendments and
10adaptations to the Code that are made by the Board.
11    "Commercial building" means any building except a building
12that is a residential building, as defined in this Section.
13    "Department" means the Department of Commerce and Economic
14Opportunity.
15    "Municipality" means any city, village, or incorporated
16town.
17    "Residential building" means (i) a detached one-family or
182-family dwelling or (ii) any building that is 3 stories or
19less in height above grade that contains multiple dwelling
20units, in which the occupants reside on a primarily permanent
21basis, such as a townhouse, a row house, an apartment house, a
22convent, a monastery, a rectory, a fraternity or sorority
23house, a dormitory, and a rooming house; provided, however,
24that when applied to a building located within the boundaries
25of a municipality having a population of 1,000,000 or more,

 

 

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1the term "residential building" means a building containing
2one or more dwelling units, not exceeding 4 stories above
3grade, where occupants are primarily permanent.
4    "Site energy index" means a scalar published by the
5Pacific Northwest National Laboratories representing the ratio
6of the site energy performance of an evaluated code compared
7to the site energy performance of the 2006 International
8Energy Conservation Code. A "site energy index" includes only
9conservation measures and excludes net energy credit for any
10on-site or off-site energy production.
11(Source: P.A. 101-144, eff. 7-26-19.)
 
12    (20 ILCS 3125/15)
13    Sec. 15. Energy Efficient Building Code. The Board, in
14consultation with the Department, shall adopt the Code as
15minimum requirements for commercial buildings, applying to the
16construction of, renovations to, and additions to all
17commercial buildings in the State. The Board, in consultation
18with the Department, shall also adopt the Code as the minimum
19and maximum requirements for residential buildings, applying
20to the construction of, renovations to, and additions to all
21residential buildings in the State, except as provided for in
22Section 45 of this Act. The Board may appropriately adapt the
23International Energy Conservation Code to apply to the
24particular economy, population distribution, geography, and
25climate of the State and construction therein, consistent with

 

 

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1the public policy objectives of this Act.
2(Source: P.A. 96-778, eff. 8-28-09.)
 
3    (20 ILCS 3125/20)
4    Sec. 20. Applicability.
5    (a) The Board shall review and adopt the Code within one
6year after its publication. The Code shall take effect within
76 months after it is adopted by the Board, except that,
8beginning January 1, 2012, the Code adopted in 2012 shall take
9effect on January 1, 2013. Except as otherwise provided in
10this Act, the Code shall apply to (i) any new building or
11structure in this State for which a building permit
12application is received by a municipality or county and (ii)
13beginning on the effective date of this amendatory Act of the
14100th General Assembly, each State facility specified in
15Section 4.01 of the Capital Development Board Act. In the case
16of any addition, alteration, renovation, or repair to an
17existing residential or commercial structure, the Code adopted
18under this Act applies only to the portions of that structure
19that are being added, altered, renovated, or repaired. The
20changes made to this Section by this amendatory Act of the 97th
21General Assembly shall in no way invalidate or otherwise
22affect contracts entered into on or before the effective date
23of this amendatory Act of the 97th General Assembly.
24    (b) The following buildings shall be exempt from the Code:
25        (1) Buildings otherwise exempt from the provisions of

 

 

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1    a locally adopted building code and buildings that do not
2    contain a conditioned space.
3        (2) Buildings that do not use either electricity or
4    fossil fuel for comfort conditioning. For purposes of
5    determining whether this exemption applies, a building
6    will be presumed to be heated by electricity, even in the
7    absence of equipment used for electric comfort heating,
8    whenever the building is provided with electrical service
9    in excess of 100 amps, unless the code enforcement
10    official determines that this electrical service is
11    necessary for purposes other than providing electric
12    comfort heating.
13        (3) Historic buildings. This exemption shall apply to
14    those buildings that are listed on the National Register
15    of Historic Places or the Illinois Register of Historic
16    Places, and to those buildings that have been designated
17    as historically significant by a local governing body that
18    is authorized to make such designations.
19        (4) (Blank).
20        (5) Other buildings specified as exempt by the
21    International Energy Conservation Code.
22    (c) Additions, alterations, renovations, or repairs to an
23existing building, building system, or portion thereof shall
24conform to the provisions of the Code as they relate to new
25construction without requiring the unaltered portion of the
26existing building or building system to comply with the Code.

 

 

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1The following need not comply with the Code, provided that the
2energy use of the building is not increased: (i) storm windows
3installed over existing fenestration, (ii) glass-only
4replacements in an existing sash and frame, (iii) existing
5ceiling, wall, or floor cavities exposed during construction,
6provided that these cavities are filled with insulation, and
7(iv) construction where the existing roof, wall, or floor is
8not exposed.
9    (d) A unit of local government that does not regulate
10energy efficient building standards is not required to adopt,
11enforce, or administer the Code; however, any energy efficient
12building standards adopted by a unit of local government must
13comply with this Act. If a unit of local government does not
14regulate energy efficient building standards, any
15construction, renovation, or addition to buildings or
16structures is subject to the provisions contained in this Act.
17(Source: P.A. 100-729, eff. 8-3-18.)
 
18    (20 ILCS 3125/30)
19    Sec. 30. Enforcement. The Board, in consultation with the
20Department, shall determine procedures for compliance with the
21Code. These procedures may include but need not be limited to
22certification by a national, State, or local accredited energy
23conservation program or inspections from private
24Code-certified inspectors using the Code. For purposes of the
25Illinois Stretch Energy Code under Section 55, the Board shall

 

 

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1allow and encourage, as an alternative compliance mechanism,
2project certification by a nationally recognized nonprofit
3certification organization specializing in high-performance
4passive buildings and offering climate-specific building
5energy standards that require equal or better energy
6performance than the Illinois Stretch Energy Code.
7(Source: P.A. 93-936, eff. 8-13-04.)
 
8    (20 ILCS 3125/45)
9    Sec. 45. Home rule.
10    (a) (Blank). No unit of local government, including any
11home rule unit, may regulate energy efficient building
12standards for commercial buildings in a manner that is less
13stringent than the provisions contained in this Act.
14    (b) No unit of local government, including any home rule
15unit, may regulate energy efficient building standards for
16residential buildings in a manner that is either less or more
17stringent than the standards established pursuant to this Act;
18provided, however, that the following entities may regulate
19energy efficient building standards for residential or
20commercial buildings in a manner that is more stringent than
21the provisions contained in this Act: (i) a unit of local
22government, including a home rule unit, that has, on or before
23May 15, 2009, adopted or incorporated by reference energy
24efficient building standards for residential or commercial
25buildings that are equivalent to or more stringent than the

 

 

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12006 International Energy Conservation Code, (ii) a unit of
2local government, including a home rule unit, that has, on or
3before May 15, 2009, provided to the Capital Development
4Board, as required by Section 10.18 of the Capital Development
5Board Act, an identification of an energy efficient building
6code or amendment that is equivalent to or more stringent than
7the 2006 International Energy Conservation Code, (ii-5) a
8municipality that has adopted the Illinois Stretch Energy
9Code, and (iii) a municipality with a population of 1,000,000
10or more.
11    (c) No unit of local government, including any home rule
12unit or unit of local government that is subject to State
13regulation under the Code as provided in Section 15 of this
14Act, may hereafter enact any annexation ordinance or
15resolution, or require or enter into any annexation agreement,
16that imposes energy efficient building standards for
17residential or commercial buildings that are either less or
18more stringent than the energy efficiency standards in effect,
19at the time of construction, throughout the unit of local
20government, except for the Illinois Stretch Energy Code.
21    (d) This Section is a denial and limitation of home rule
22powers and functions under subsection (i) of Section 6 of
23Article VII of the Illinois Constitution on the concurrent
24exercise by home rule units of powers and functions exercised
25by the State. Nothing in this Section, however, prevents a
26unit of local government from adopting an energy efficiency

 

 

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1code or standards for commercial buildings that are more
2stringent than the Code under this Act.
3(Source: P.A. 99-639, eff. 7-28-16.)
 
4    (20 ILCS 3125/55 new)
5    Sec. 55. Illinois Stretch Energy Code.
6    (a) The Board, in consultation with the Department, shall
7create and adopt the Illinois Stretch Energy Code, to allow
8municipalities and projects authorized or funded by the Board
9to achieve more energy efficiency in buildings than the
10Illinois Energy Conservation Code through a consistent pathway
11across the State. The Illinois Stretch Energy Code shall be
12available for adoption by any municipality and shall set The
13Illinois Stretch Energy Code shall be available for adoption
14by any municipality and shall set minimum energy efficiency
15requirements, taking the place of the Illinois Energy
16Conservation Code within any municipality that adopts the
17Illinois Stretch Energy Code.
18    (b) The Illinois Stretch Energy Code shall have separate
19components for commercial and residential buildings, which may
20be adopted by the municipality jointly or separately.
21    (c) The Illinois Stretch Energy Code shall apply to all
22projects to which an energy conservation code is applicable
23that are authorized or funded in any part by the Board after
24January 1, 2023.
25    (d) Development of the Illinois Stretch Energy Code shall

 

 

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1be completed and available for adoption by municipalities by
2December 31, 2022.
3    (e) Consistent with the requirements under paragraph (2.5)
4of subsection (g) of Section 8-103B of the Public Utilities
5Act and under paragraph (2) of subsection (j) of Section
68-104.1 of the Public Utilities Act, municipalities that adopt
7the Illinois Stretch Energy Code may use utility programs to
8support compliance with the Illinois Stretch Energy Code. The
9amount of savings from such utility efforts that may be
10counted toward achievement of their cumulative persisting
11annual savings goals shall be based on reasonable estimates of
12the increase in savings resulting from the utility efforts,
13relative to reasonable approximations of what would have
14occurred absent the utility involvement.
15    (f) The Illinois Stretch Energy Code's residential
16components shall:
17        (1) apply to residential buildings as defined under
18    Section 10;
19        (2) set performance targets using a site energy index
20    with reductions relative to the 2006 International Energy
21    Conservation Code; and
22        (3) include stretch energy codes with site energy
23    index standards and adoption dates as follows: by no later
24    than December 31, 2022, the Board shall create and adopt a
25    stretch energy code with a site energy index no greater
26    than 0.50 of the 2006 International Energy Conservation

 

 

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1    Code; by no later than December 31, 2025, the Board shall
2    create and adopt a stretch energy code with a site energy
3    index no greater than 0.40 of the 2006 International
4    Energy Conservation Code, unless the Board identifies
5    unanticipated burdens associated with the stretch energy
6    code adopted in 2022, in which case the Board may adopt a
7    stretch energy code with a site energy index no greater
8    than 0.42 of the 2006 International Energy Conservation
9    Code, provided that the more relaxed standard has a site
10    energy index that is at least 0.05 more restrictive than
11    the 2024 International Energy Conservation Code; by no
12    later than December 31, 2028, the Board shall create and
13    adopt a stretch energy code with a site energy index no
14    greater than 0.33 of the 2006 International Energy
15    Conservation Code, unless the Board identifies
16    unanticipated burdens associated with the stretch energy
17    code adopted in 2025, in which case the Board may adopt a
18    stretch energy code with a site energy index no greater
19    than 0.35 of the 2006 International Energy Conservation
20    Code, but only if that more relaxed standard has a site
21    energy index that is at least 0.05 more restrictive than
22    the 2027 International Energy Conservation Code; and by no
23    later than December 31, 2031, the Board shall create and
24    adopt a stretch energy code with a site energy index no
25    greater than 0.25 of the 2006 International Energy
26    Conservation Code.

 

 

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1    (g) The Illinois Stretch Energy Code's commercial
2components shall:
3        (1) apply to commercial buildings as defined under
4    Section 10;
5        (2) set performance targets using a site energy index
6    with reductions relative to the 2006 International Energy
7    Conservation Code; and
8        (3) include stretch energy codes with site energy
9    index standards and adoption dates as follows: by no later
10    than December 31, 2022, the Board shall create and adopt a
11    stretch energy code with a site energy index no greater
12    than 0.60 of the 2006 International Energy Conservation
13    Code; by no later than December 31, 2025, the Board shall
14    create and adopt a stretch energy code with a site energy
15    index no greater than 0.50 of the 2006 International
16    Energy Conservation Code; by no later than December 31,
17    2028, the Board shall create and adopt a stretch energy
18    code with a site energy index no greater than 0.44 of the
19    2006 International Energy Conservation Code; and by no
20    later than December 31, 2031, the Board shall create and
21    adopt a stretch energy code with a site energy index no
22    greater than 0.39 of the 2006 International Energy
23    Conservation Code.
24    (h) The process for the creation of the Illinois Stretch
25Energy Code includes:
26        (1) within 60 days after the effective date of this

 

 

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1    amendatory Act of the 102nd General Assembly, the Capital
2    Development Board shall establish an Illinois Stretch
3    Energy Code Task Force to advise and provide technical
4    assistance and recommendations to the Capital Development
5    Board for the Illinois Stretch Energy Code, which shall:
6            (A) advise the Capital Development Board on
7        creation of interim performance targets, code
8        requirements, and an implementation plan for the
9        Illinois Stretch Energy Code;
10            (B) recommend amendments to proposed rules issued
11        by the Capital Development Board;
12            (C) recommend complementary programs or policies;
13            (D) complete recommendations and development for
14        the Illinois Stretch Energy Code elements and
15        requirements by July 31, 2022;
16            (E) be composed of, but not limited to,
17        representatives, or their designees, from the
18        following entities:
19                (i) a representative from a group that
20            represents environmental justice;
21                (ii) a representative of a nonprofit or
22            professional association advocating for the
23            environment;
24                (iii) a representative of an organization
25            representing local governments in the metropolitan
26            Chicago region;

 

 

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1                (iv) a representative of the City of Chicago;
2                (v) a representative of an organization
3            representing local governments outside the
4            metropolitan Chicago region;
5                (vi) a representative for the investor-owned
6            utilities of Illinois;\
7                (vii) an energy-efficiency advocate with
8            technical expertise in single-family residential
9            buildings;
10                (viii) an energy-efficiency advocate with
11            technical expertise in commercial buildings;
12                (ix) an energy-efficiency advocate with
13            technical expertise in multifamily buildings, such
14            as an affordable housing developer;
15                (x) a representative from the architecture or
16            engineering industry;
17                (xi) a representative from a home builders
18            association;
19                (xii) a representative from the commercial
20            building industry;
21                (xiii) a representative of the enforcement
22            industry, such as a code official or energy rater;
23                (xiv) a representative of organized labor; and
24                (xv) other experts or organizations deemed
25            necessary by the Capital Development Board; and
26            (F) be co-chaired by:

 

 

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1                (i) a representative of the environmental
2            community;
3                (ii) a representative of the environmental
4            justice community; and
5                (iii) a municipal representative.
6        (2) As part of its deliberations, the Illinois Stretch
7    Energy Code Task Force shall actively solicit input from
8    other energy code stakeholders and interested parties.
 
9    Section 30-25. The Illinois Power Agency Act is amended by
10changing Sections 1-5, 1-10, 1-35, 1-56, 1-70, 1-75, 1-92, and
111-125 and by adding Sections 1-135 and 1-140 as follows:
 
12    (20 ILCS 3855/1-5)
13    Sec. 1-5. Legislative declarations and findings. The
14General Assembly finds and declares:
15        (1) The health, welfare, and prosperity of all
16    Illinois citizens require the provision of adequate,
17    reliable, affordable, efficient, and environmentally
18    sustainable electric service at the lowest total cost over
19    time, taking into account any benefits of price stability.
20        (1.5) In order to provide for the highest quality of
21    life for the citizens of Illinois, and to provide for a
22    healthy environment and prosperity for Illinois citizens
23    through a clean energy economy, it is the policy of the
24    State of Illinois to transition to 100% clean energy by

 

 

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1    2050. For purposes of this Section, "clean energy" means
2    energy generation that is substantially free (90% or
3    greater) of carbon dioxide emissions.
4        (2) (Blank).
5        (3) (Blank).
6        (4) It is necessary to improve the process of
7    procuring electricity to serve Illinois residents, to
8    promote investment in energy efficiency and
9    demand-response measures, and to maintain and support
10    development of clean coal technologies, generation
11    resources that operate at all hours of the day and under
12    all weather conditions, zero emission facilities, and
13    renewable resources.
14        (5) Procuring a diverse electricity supply portfolio
15    will ensure the lowest total cost over time for adequate,
16    reliable, efficient, and environmentally sustainable
17    electric service.
18        (6) Including renewable resources and zero emission
19    credits from zero emission facilities in that portfolio
20    will reduce long-term direct and indirect costs to
21    consumers by decreasing environmental impacts and by
22    avoiding or delaying the need for new generation,
23    transmission, and distribution infrastructure. Developing
24    new renewable energy resources in Illinois, including
25    brownfield solar projects and community solar projects,
26    will help to diversify Illinois electricity supply, avoid

 

 

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1    and reduce pollution, reduce peak demand, and enhance
2    public health and well-being of Illinois residents.
3        (7) Developing community solar projects in Illinois
4    will help to expand access to renewable energy resources
5    to more Illinois residents.
6        (8) Developing brownfield solar projects in Illinois
7    will help return blighted or contaminated land to
8    productive use while enhancing public health and the
9    well-being of Illinois residents.
10        (9) Energy efficiency, demand-response measures, zero
11    emission energy, and renewable energy are resources
12    currently underused in Illinois. These resources should be
13    used, when cost effective, to reduce costs to consumers,
14    improve reliability, and improve environmental quality and
15    public health.
16        (10) The State should encourage the use of advanced
17    clean coal technologies that capture and sequester carbon
18    dioxide emissions to advance environmental protection
19    goals and to demonstrate the viability of coal and
20    coal-derived fuels in a carbon-constrained economy.
21        (11) The General Assembly enacted Public Act 96-0795
22    to reform the State's purchasing processes, recognizing
23    that government procurement is susceptible to abuse if
24    structural and procedural safeguards are not in place to
25    ensure independence, insulation, oversight, and
26    transparency.

 

 

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1        (12) The principles that underlie the procurement
2    reform legislation apply also in the context of power
3    purchasing.
4    The General Assembly therefore finds that it is necessary
5to create the Illinois Power Agency and that the goals and
6objectives of that Agency are to accomplish each of the
7following:
8        (A) Develop electricity procurement plans to ensure
9    adequate, reliable, affordable, efficient, and
10    environmentally sustainable electric service at the lowest
11    total cost over time, taking into account any benefits of
12    price stability, for electric utilities that on December
13    31, 2005 provided electric service to at least 100,000
14    customers in Illinois and for small multi-jurisdictional
15    electric utilities that (i) on December 31, 2005 served
16    less than 100,000 customers in Illinois and (ii) request a
17    procurement plan for their Illinois jurisdictional load.
18    The procurement plan shall be updated on an annual basis
19    and shall include renewable energy resources and,
20    beginning with the delivery year commencing June 1, 2017,
21    zero emission credits from zero emission facilities
22    sufficient to achieve the standards specified in this Act.
23        (B) Conduct the competitive procurement processes
24    identified in this Act.
25        (C) Develop electric generation and co-generation
26    facilities that use indigenous coal or renewable

 

 

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1    resources, or both, financed with bonds issued by the
2    Illinois Finance Authority.
3        (D) Supply electricity from the Agency's facilities at
4    cost to one or more of the following: municipal electric
5    systems, governmental aggregators, or rural electric
6    cooperatives in Illinois.
7        (E) Ensure that the process of power procurement is
8    conducted in an ethical and transparent fashion, immune
9    from improper influence.
10        (F) Continue to review its policies and practices to
11    determine how best to meet its mission of providing the
12    lowest cost power to the greatest number of people, at any
13    given point in time, in accordance with applicable law.
14        (G) Operate in a structurally insulated, independent,
15    and transparent fashion so that nothing impedes the
16    Agency's mission to secure power at the best prices the
17    market will bear, provided that the Agency meets all
18    applicable legal requirements.
19        (H) Implement renewable energy procurement and
20    training programs throughout the State to diversify
21    Illinois electricity supply, improve reliability, avoid
22    and reduce pollution, reduce peak demand, and enhance
23    public health and well-being of Illinois residents,
24    including low-income residents.
25(Source: P.A. 99-906, eff. 6-1-17.)
 

 

 

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1    (20 ILCS 3855/1-10)
2    Sec. 1-10. Definitions.
3    "Agency" means the Illinois Power Agency.
4    "Agency loan agreement" means any agreement pursuant to
5which the Illinois Finance Authority agrees to loan the
6proceeds of revenue bonds issued with respect to a project to
7the Agency upon terms providing for loan repayment
8installments at least sufficient to pay when due all principal
9of, interest and premium, if any, on those revenue bonds, and
10providing for maintenance, insurance, and other matters in
11respect of the project.
12    "Authority" means the Illinois Finance Authority.
13    "Brownfield site photovoltaic project" means photovoltaics
14that are:
15        (1) interconnected to an electric utility as defined
16    in this Section, a municipal utility as defined in this
17    Section, a public utility as defined in Section 3-105 of
18    the Public Utilities Act, or an electric cooperative, as
19    defined in Section 3-119 of the Public Utilities Act; and
20        (2) located at a site that is regulated by any of the
21    following entities under the following programs:
22            (A) the United States Environmental Protection
23        Agency under the federal Comprehensive Environmental
24        Response, Compensation, and Liability Act of 1980, as
25        amended;
26            (B) the United States Environmental Protection

 

 

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1        Agency under the Corrective Action Program of the
2        federal Resource Conservation and Recovery Act, as
3        amended;
4            (C) the Illinois Environmental Protection Agency
5        under the Illinois Site Remediation Program; or
6            (D) the Illinois Environmental Protection Agency
7        under the Illinois Solid Waste Program.
8    "Clean coal facility" means an electric generating
9facility that uses primarily coal as a feedstock and that
10captures and sequesters carbon dioxide emissions at the
11following levels: at least 50% of the total carbon dioxide
12emissions that the facility would otherwise emit if, at the
13time construction commences, the facility is scheduled to
14commence operation before 2016, at least 70% of the total
15carbon dioxide emissions that the facility would otherwise
16emit if, at the time construction commences, the facility is
17scheduled to commence operation during 2016 or 2017, and at
18least 90% of the total carbon dioxide emissions that the
19facility would otherwise emit if, at the time construction
20commences, the facility is scheduled to commence operation
21after 2017. The power block of the clean coal facility shall
22not exceed allowable emission rates for sulfur dioxide,
23nitrogen oxides, carbon monoxide, particulates and mercury for
24a natural gas-fired combined-cycle facility the same size as
25and in the same location as the clean coal facility at the time
26the clean coal facility obtains an approved air permit. All

 

 

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1coal used by a clean coal facility shall have high volatile
2bituminous rank and greater than 1.7 pounds of sulfur per
3million btu content, unless the clean coal facility does not
4use gasification technology and was operating as a
5conventional coal-fired electric generating facility on June
61, 2009 (the effective date of Public Act 95-1027).
7    "Clean coal SNG brownfield facility" means a facility that
8(1) has commenced construction by July 1, 2015 on an urban
9brownfield site in a municipality with at least 1,000,000
10residents; (2) uses a gasification process to produce
11substitute natural gas; (3) uses coal as at least 50% of the
12total feedstock over the term of any sourcing agreement with a
13utility and the remainder of the feedstock may be either
14petroleum coke or coal, with all such coal having a high
15bituminous rank and greater than 1.7 pounds of sulfur per
16million Btu content unless the facility reasonably determines
17that it is necessary to use additional petroleum coke to
18deliver additional consumer savings, in which case the
19facility shall use coal for at least 35% of the total feedstock
20over the term of any sourcing agreement; and (4) captures and
21sequesters at least 85% of the total carbon dioxide emissions
22that the facility would otherwise emit.
23    "Clean coal SNG facility" means a facility that uses a
24gasification process to produce substitute natural gas, that
25sequesters at least 90% of the total carbon dioxide emissions
26that the facility would otherwise emit, that uses at least 90%

 

 

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1coal as a feedstock, with all such coal having a high
2bituminous rank and greater than 1.7 pounds of sulfur per
3million btu content, and that has a valid and effective permit
4to construct emission sources and air pollution control
5equipment and approval with respect to the federal regulations
6for Prevention of Significant Deterioration of Air Quality
7(PSD) for the plant pursuant to the federal Clean Air Act;
8provided, however, a clean coal SNG brownfield facility shall
9not be a clean coal SNG facility.
10    "Commission" means the Illinois Commerce Commission.
11    "Community renewable generation project" means an electric
12generating facility that:
13        (1) is powered by wind, solar thermal energy,
14    photovoltaic cells or panels, biodiesel, crops and
15    untreated and unadulterated organic waste biomass, tree
16    waste, and hydropower that does not involve new
17    construction or significant expansion of hydropower dams;
18        (2) is interconnected at the distribution system level
19    of an electric utility as defined in this Section, a
20    municipal utility as defined in this Section that owns or
21    operates electric distribution facilities, a public
22    utility as defined in Section 3-105 of the Public
23    Utilities Act, or an electric cooperative, as defined in
24    Section 3-119 of the Public Utilities Act;
25        (3) credits the value of electricity generated by the
26    facility to the subscribers of the facility; and

 

 

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1        (4) is limited in nameplate capacity to less than or
2    equal to 10,000 2,000 kilowatts.
3    "Costs incurred in connection with the development and
4construction of a facility" means:
5        (1) the cost of acquisition of all real property,
6    fixtures, and improvements in connection therewith and
7    equipment, personal property, and other property, rights,
8    and easements acquired that are deemed necessary for the
9    operation and maintenance of the facility;
10        (2) financing costs with respect to bonds, notes, and
11    other evidences of indebtedness of the Agency;
12        (3) all origination, commitment, utilization,
13    facility, placement, underwriting, syndication, credit
14    enhancement, and rating agency fees;
15        (4) engineering, design, procurement, consulting,
16    legal, accounting, title insurance, survey, appraisal,
17    escrow, trustee, collateral agency, interest rate hedging,
18    interest rate swap, capitalized interest, contingency, as
19    required by lenders, and other financing costs, and other
20    expenses for professional services; and
21        (5) the costs of plans, specifications, site study and
22    investigation, installation, surveys, other Agency costs
23    and estimates of costs, and other expenses necessary or
24    incidental to determining the feasibility of any project,
25    together with such other expenses as may be necessary or
26    incidental to the financing, insuring, acquisition, and

 

 

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1    construction of a specific project and starting up,
2    commissioning, and placing that project in operation.
3    "Delivery services" has the same definition as found in
4Section 16-102 of the Public Utilities Act.
5    "Delivery year" means the consecutive 12-month period
6beginning June 1 of a given year and ending May 31 of the
7following year.
8    "Department" means the Department of Commerce and Economic
9Opportunity.
10    "Director" means the Director of the Illinois Power
11Agency.
12    "Demand-response" means measures that decrease peak
13electricity demand or shift demand from peak to off-peak
14periods.
15    "Distributed renewable energy generation device" means a
16device that is:
17        (1) powered by wind, solar thermal energy,
18    photovoltaic cells or panels, biodiesel, crops and
19    untreated and unadulterated organic waste biomass, tree
20    waste, and hydropower that does not involve new
21    construction or significant expansion of hydropower dams,
22    waste heat to power systems, or qualified combined heat
23    and power systems;
24        (2) interconnected at the distribution system level of
25    either an electric utility as defined in this Section, a
26    municipal utility as defined in this Section that owns or

 

 

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1    operates electric distribution facilities, or a rural
2    electric cooperative as defined in Section 3-119 of the
3    Public Utilities Act; and
4        (3) located on the customer side of the customer's
5    electric meter and is primarily used to offset that
6    customer's electricity load. ; and
7        (4) limited in nameplate capacity to less than or
8    equal to 2,000 kilowatts.
9    "Energy efficiency" means measures that reduce the amount
10of electricity or natural gas consumed in order to achieve a
11given end use. "Energy efficiency" includes voltage
12optimization measures that optimize the voltage at points on
13the electric distribution voltage system and thereby reduce
14electricity consumption by electric customers' end use
15devices. "Energy efficiency" also includes measures that
16reduce the total Btus of electricity, natural gas, and other
17fuels needed to meet the end use or uses.
18    "Electric utility" has the same definition as found in
19Section 16-102 of the Public Utilities Act.
20    "Facility" means an electric generating unit or a
21co-generating unit that produces electricity along with
22related equipment necessary to connect the facility to an
23electric transmission or distribution system.
24    "Governmental aggregator" means one or more units of local
25government that individually or collectively procure
26electricity to serve residential retail electrical loads

 

 

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1located within its or their jurisdiction.
2    "Index Price" means the real-time settlement price at the
3applicable Illinois trading hub, such as PJM-NIHUB or MISO-IL,
4for a given settlement period.
5    "Indexed REC Buyer" means as public utility that serves as
6a Buyer under a REC delivery contract executed pursuant to
7item (v) of subparagraph (G) of paragraph (1) of subsection
8(c) of Section 1-75 of this Act.
9    "Indexed renewable energy credit" or "Indexed REC" means a
10renewable energy credit featuring a purchase price calculated
11by subtracting the strike price originally offered by a new
12utility scale wind project or a new utility scale photovoltaic
13project from the index price in a given settlement period.
14    "Local government" means a unit of local government as
15defined in Section 1 of Article VII of the Illinois
16Constitution.
17    "Municipality" means a city, village, or incorporated
18town.
19    "Municipal utility" means a public utility owned and
20operated by any subdivision or municipal corporation of this
21State.
22    "Nameplate capacity" means the aggregate inverter
23nameplate capacity in kilowatts AC.
24    "Person" means any natural person, firm, partnership,
25corporation, either domestic or foreign, company, association,
26limited liability company, joint stock company, or association

 

 

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1and includes any trustee, receiver, assignee, or personal
2representative thereof.
3    "Project" means the planning, bidding, and construction of
4a facility.
5    "Public utility" has the same definition as found in
6Section 3-105 of the Public Utilities Act.
7    "Qualified combined heat and power systems" means systems
8that, either simultaneously or sequentially, produce
9electricity and useful thermal energy from a single fuel
10source. Such systems are eligible for renewable energy credits
11in an amount equal to their total energy output (electric and
12thermal) where a renewable fuel is consumed or, where a
13non-renewable fuel is consumed, a percent equal to the
14displaced fuel use and CO2 emissions attributable to the
15operation of the combined heat and power system as calculated
16based on the United States Environmental Protection Agency's
17fuel and carbon dioxide emissions savings calculation
18methodology for combined heat and power systems.
19    "Real property" means any interest in land together with
20all structures, fixtures, and improvements thereon, including
21lands under water and riparian rights, any easements,
22covenants, licenses, leases, rights-of-way, uses, and other
23interests, together with any liens, judgments, mortgages, or
24other claims or security interests related to real property.
25    "Renewable energy credit" or "REC" means a tradable credit
26that represents the environmental attributes of one megawatt

 

 

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1hour of energy produced from a renewable energy resource.
2    "Renewable energy resources" includes energy and its
3associated renewable energy credit or renewable energy credits
4from wind, solar thermal energy, photovoltaic cells and
5panels, biodiesel, anaerobic digestion, crops and untreated
6and unadulterated organic waste biomass, tree waste, and
7hydropower that does not involve new construction or
8significant expansion of hydropower dams, waste heat to power
9systems, or qualified combined heat and power systems. For
10purposes of this Act, landfill gas produced in the State is
11considered a renewable energy resource. "Renewable energy
12resources" does not include the incineration or burning of
13tires, garbage, general household, institutional, and
14commercial waste, industrial lunchroom or office waste,
15landscape waste other than tree waste, railroad crossties,
16utility poles, or construction or demolition debris, other
17than untreated and unadulterated waste wood.
18    "Retail customer" has the same definition as found in
19Section 16-102 of the Public Utilities Act.
20    "Revenue bond" means any bond, note, or other evidence of
21indebtedness issued by the Authority, the principal and
22interest of which is payable solely from revenues or income
23derived from any project or activity of the Agency.
24    "Sequester" means permanent storage of carbon dioxide by
25injecting it into a saline aquifer, a depleted gas reservoir,
26or an oil reservoir, directly or through an enhanced oil

 

 

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1recovery process that may involve intermediate storage,
2regardless of whether these activities are conducted by a
3clean coal facility, a clean coal SNG facility, a clean coal
4SNG brownfield facility, or a party with which a clean coal
5facility, clean coal SNG facility, or clean coal SNG
6brownfield facility has contracted for such purposes.
7    "Service area" has the same definition as found in Section
816-102 of the Public Utilities Act.
9    "Settlement period" means the period of time utilized by
10MISO, PJM, and their successor organizations as the basis for
11settlement calculations in the real-time market.
12    "Sourcing agreement" means (i) in the case of an electric
13utility, an agreement between the owner of a clean coal
14facility and such electric utility, which agreement shall have
15terms and conditions meeting the requirements of paragraph (3)
16of subsection (d) of Section 1-75, (ii) in the case of an
17alternative retail electric supplier, an agreement between the
18owner of a clean coal facility and such alternative retail
19electric supplier, which agreement shall have terms and
20conditions meeting the requirements of Section 16-115(d)(5) of
21the Public Utilities Act, and (iii) in case of a gas utility,
22an agreement between the owner of a clean coal SNG brownfield
23facility and the gas utility, which agreement shall have the
24terms and conditions meeting the requirements of subsection
25(h-1) of Section 9-220 of the Public Utilities Act.
26    "Strike price" means a contract price for energy and

 

 

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1renewable energy credits from a new utility-scale wind project
2or a new utility-scale photovoltaic project.
3    "Subscriber" means a person who (i) takes delivery service
4from an electric utility, and (ii) has a subscription of no
5less than 200 watts to a community renewable generation
6project that is located in the electric utility's service
7area. No subscriber's subscriptions may total more than 40% of
8the nameplate capacity of an individual community renewable
9generation project. Entities that are affiliated by virtue of
10a common parent shall not represent multiple subscriptions
11that total more than 40% of the nameplate capacity of an
12individual community renewable generation project.
13    "Subscription" means an interest in a community renewable
14generation project expressed in kilowatts, which is sized
15primarily to offset part or all of the subscriber's
16electricity usage.
17    "Substitute natural gas" or "SNG" means a gas manufactured
18by gasification of hydrocarbon feedstock, which is
19substantially interchangeable in use and distribution with
20conventional natural gas.
21    "Total resource cost test" or "TRC test" means a standard
22that is met if, for an investment in energy efficiency or
23demand-response measures, the benefit-cost ratio is greater
24than one. The benefit-cost ratio is the ratio of the net
25present value of the total benefits of the program to the net
26present value of the total costs as calculated over the

 

 

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1lifetime of the measures. A total resource cost test compares
2the sum of avoided electric utility costs, representing the
3benefits that accrue to the system and the participant in the
4delivery of those efficiency measures and including avoided
5costs associated with reduced use of natural gas or other
6fuels, avoided costs associated with reduced water
7consumption, and avoided costs associated with reduced
8operation and maintenance costs, as well as other quantifiable
9societal benefits, to the sum of all incremental costs of
10end-use measures that are implemented due to the program
11(including both utility and participant contributions), plus
12costs to administer, deliver, and evaluate each demand-side
13program, to quantify the net savings obtained by substituting
14the demand-side program for supply resources. In calculating
15avoided costs of power and energy that an electric utility
16would otherwise have had to acquire, reasonable estimates
17shall be included of financial costs likely to be imposed by
18future regulations and legislation on emissions of greenhouse
19gases. In discounting future societal costs and benefits for
20the purpose of calculating net present values, a societal
21discount rate based on actual, long-term Treasury bond yields
22should be used. Notwithstanding anything to the contrary, the
23TRC test shall not include or take into account a calculation
24of market price suppression effects or demand reduction
25induced price effects.
26    "Utility-scale solar project" means an electric generating

 

 

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1facility that:
2        (1) generates electricity using photovoltaic cells;
3    and
4        (2) has a nameplate capacity that is greater than
5    10,000 2,000 kilowatts.
6    "Utility-scale wind project" means an electric generating
7facility that:
8        (1) generates electricity using wind; and
9        (2) has a nameplate capacity that is greater than
10    10,000 2,000 kilowatts.
11    "Waste heat to power systems" means systems that capture
12and generate electricity from energy that would otherwise be
13lost to the atmosphere without the use of additional fuel.
14    "Zero emission credit" means a tradable credit that
15represents the environmental attributes of one megawatt hour
16of energy produced from a zero emission facility.
17    "Zero emission facility" means a facility that: (1) is
18fueled by nuclear power; and (2) is interconnected with PJM
19Interconnection, LLC or the Midcontinent Independent System
20Operator, Inc., or their successors.
21(Source: P.A. 98-90, eff. 7-15-13; 99-906, eff. 6-1-17.)
 
22    (20 ILCS 3855/1-35)
23    Sec. 1-35. Agency rules. The Agency shall adopt rules as
24may be necessary and appropriate for the operation of the
25Agency. In addition to other rules relevant to the operation

 

 

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1of the Agency, the Agency shall adopt rules that accomplish
2each of the following:
3        (1) Establish procedures for monitoring the
4    administration of any contract administered directly or
5    indirectly by the Agency; except that the procedures shall
6    not extend to executed contracts between electric
7    utilities and their suppliers.
8        (2) If deemed necessary by the Agency, establish
9    Establish procedures for the recovery of costs incurred in
10    connection with the development and construction of a
11    facility should the Agency cancel a project, provided that
12    no such costs shall be passed on to public utilities or
13    their customers or paid from the Illinois Power Agency
14    Operations Fund.
15        (3) Implement accounting rules and a system of
16    accounts, in accordance with State law, permitting all
17    reporting (i) required by the State, (ii) required under
18    this Act, (iii) required by the Authority, or (iv)
19    required under the Public Utilities Act.
20    The Agency shall not adopt any rules that infringe upon
21the authority granted to the Commission.
22(Source: P.A. 95-481, eff. 8-28-07.)
 
23    (20 ILCS 3855/1-56)
24    Sec. 1-56. Illinois Power Agency Renewable Energy
25Resources Fund; Illinois Solar for All Program.

 

 

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1    (a) The Illinois Power Agency Renewable Energy Resources
2Fund is created as a special fund in the State treasury.
3    (b) The Illinois Power Agency Renewable Energy Resources
4Fund shall be administered by the Agency as described in this
5subsection (b), provided that the changes to this subsection
6(b) made by this amendatory Act of the 99th General Assembly
7shall not interfere with existing contracts under this
8Section.
9        (1) The Illinois Power Agency Renewable Energy
10    Resources Fund shall be used to purchase renewable energy
11    credits according to any approved procurement plan
12    developed by the Agency prior to June 1, 2017.
13        (2) The Illinois Power Agency Renewable Energy
14    Resources Fund shall also be used to create the Illinois
15    Solar for All Program, which provides shall include
16    incentives for low-income distributed generation and
17    community solar projects and other qualifying projects and
18    initiatives, and other associated approved expenditures
19    made in connection with the Illinois Solar for All
20    Program. The objectives of the Illinois Solar for All
21    Program are to bring photovoltaics to low-income
22    communities, nonprofit facilities, and public facilities
23    in this State in an effort a manner that maximizes the
24    development of new photovoltaic generating facilities, to
25    create a long-term, low-income solar marketplace. The
26    Illinois Solar for All Program shall be implemented in a

 

 

SB2896- 207 -LRB102 17909 JWD 25989 b

1    manner that seeks to minimize administrative costs, and
2    maximize efficiencies and synergies available through
3    coordination with similar initiatives, including the
4    Adjustable Block Program described in subparagraphs (K)
5    through (M) of paragraph (1) of subsection (c) of Section
6    1-75, energy efficiency programs, job training programs,
7    and community action agencies throughout this State, to
8    integrate, through interaction with stakeholders, with
9    existing energy efficiency initiatives, and to minimize
10    administrative costs. The Illinois Solar for All Program
11    shall be implemented to ensure that the physical location
12    of all supported projects features geographic and
13    demographic diversity, and that participating projects are
14    not concentrated only in select areas. The Agency shall
15    include a description of its proposed approach to the
16    design, administration, implementation and evaluation of
17    the Illinois Solar for All Program, as part of the
18    long-term renewable resources procurement plan authorized
19    by subsection (c) of Section 1-75 of this Act, and the
20    program shall be designed to grow the low-income solar
21    market. To incentivize the development of applicant
22    projects, the The Agency or electric utility, as
23    applicable, shall purchase renewable energy credits from
24    participating photovoltaic projects under contracts
25    subject to approval of the Illinois Commerce Commission as
26    required by subparagraph (iii) of paragraph (5) of

 

 

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1    subsection (b) of Section 16-111.5 of the Public Utilities
2    Act the (i) photovoltaic distributed renewable energy
3    generation projects and (ii) community solar projects that
4    are procured under procurement processes authorized by the
5    long-term renewable resources procurement plans approved
6    by the Commission.
7        The Illinois Solar for All Program shall include the
8    program offerings described in subparagraphs (A) through
9    (E) (D) of this paragraph (2), which the Agency shall
10    implement through renewable energy credit delivery
11    contracts with program participants third-party providers
12    and, subject to appropriation, pay the approximate amounts
13    identified using monies available in the Illinois Power
14    Agency Renewable Energy Resources Fund. Each contract that
15    provides for the installation of solar facilities shall
16    provide that the solar facilities will produce energy and
17    economic benefits, at a level determined by the Agency to
18    be reasonable, for the participating low income customers.
19    The monies available in the Illinois Power Agency
20    Renewable Energy Resources Fund and not otherwise
21    committed to contracts executed under subsection (i) of
22    this Section, as well as funding authorized pursuant to
23    Section 1-75(c)(1)(O) of this Act, shall initially be
24    allocated among the programs described in this paragraph
25    (2), as follows: 40% 22.5% of these funds shall be
26    allocated to programs described in subparagraph (A) of

 

 

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1    this paragraph (2), 40% 37.5% of these funds shall be
2    allocated to programs described in subparagraph (B) of
3    this paragraph (2), 20% 15% of these funds shall be
4    allocated to programs described in subparagraph (C) of
5    this paragraph (2) and no more than $20 million , and 25% of
6    these funds, but in no event more than $50,000,000, shall
7    be allocated to programs described in subparagraph (D) of
8    this paragraph (2). The allocation of funds among
9    subparagraphs (A), (B), or (C), and (D) of this paragraph
10    (2) may be changed if the Agency, after receiving input
11    through a stakeholder process, or administrator, through
12    delegated authority, determines incentives in
13    subparagraphs (A), (B), or (C), or (D) of this paragraph
14    (2) have not been or unlikely to be adequately subscribed
15    to fully utilize available Illinois Solar for All Program
16    Funds the Illinois Power Agency Renewable Energy Resources
17    Fund. The determination shall include input through a
18    stakeholder process. The program offerings described in
19    subparagraphs (A) through (D) of this paragraph (2) shall
20    also be implemented through contracts funded from such
21    additional amounts as are allocated to one or more of the
22    programs in the long-term renewable resources procurement
23    plans as specified in subsection (c) of Section 1-75 of
24    this Act and subparagraph (O) of paragraph (1) of such
25    subsection (c).
26        Contracts that will be paid with funds in the Illinois

 

 

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1    Power Agency Renewable Energy Resources Fund shall be
2    executed by the Agency. Contracts that will be paid with
3    funds collected by an electric utility shall be executed
4    by the electric utility.
5        Contracts under the Illinois Solar for All Program
6    shall include an approach, to be set as set forth in the
7    long-term renewable resources procurement plans, to ensure
8    the wholesale market value of the energy is credited to
9    participating low-income customers or organizations and to
10    ensure tangible economic benefits flow directly to program
11    participants, except in the case of low-income
12    multi-family housing where the low-income customer does
13    not directly pay for energy. Priority shall be given to
14    projects that demonstrate meaningful involvement of
15    low-income community members in designing the initial
16    proposals. Acceptable proposals to implement projects must
17    demonstrate the applicant's ability to conduct initial
18    community outreach, education, and recruitment of
19    low-income participants in the community. Projects must
20    include job training opportunities if available, with the
21    specific level of trainee usage to be determined through
22    the Agency's long-term renewable resources procurement
23    plan, and the Illinois Solar for All Program Administrator
24    shall endeavor to coordinate with the administrator of job
25    training programs described in paragraph (1) of subsection
26    (a) of Section 16-108.12 of the Public Utilities Act to

 

 

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1    help ensure that program participants can be connected
2    with the graduates of these and other job training
3    programs.
4            (A) Low-income distributed generation incentive.
5        This program will provide incentives to projects
6        benefiting low-income customers, either directly or
7        through solar providers, to increase the participation
8        of low-income households in photovoltaic on-site
9        distributed generation. Companies participating in
10        this program that install solar panels shall commit to
11        hiring job trainees for a portion of their low-income
12        installations, and an administrator shall facilitate
13        partnering the companies that install solar panels
14        with entities that provide solar panel installation
15        job training. It is a goal of this program that a
16        minimum of 25% of the incentives for this program be
17        allocated to projects located within environmental
18        justice communities. 40% of the incentives for this
19        program shall be allocated to projects that are 1-4
20        unit residential facilities, although the Agency may
21        consider a standalone program for residential
22        facilities as provided for in paragraph (2). Contracts
23        entered into under this paragraph may be entered into
24        with an entity that will develop and administer the
25        program and shall also include contracts for renewable
26        energy credits from the photovoltaic distributed

 

 

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1        generation that is the subject of the program, as set
2        forth in the long-term renewable resources procurement
3        plan.
4            (B) Low-Income Community Solar Project Initiative.
5        Incentives shall be offered to low-income customers,
6        either directly or through developers, to increase the
7        participation of low-income subscribers of community
8        solar projects. The developer of each project shall
9        identify its partnership with community stakeholders
10        regarding the location, development, and participation
11        in the project, provided that nothing shall preclude a
12        project from including an anchor tenant that does not
13        qualify as low-income. Incentives should also be
14        offered to community solar projects that are 100%
15        low-income subscriber owned, which includes low-income
16        households, not-for-profit organizations, and
17        affordable housing owners. It is a goal of this
18        program that a minimum of 25% of the incentives for
19        this program be allocated to community photovoltaic
20        projects in environmental justice communities.
21        Contracts entered into under this paragraph may be
22        entered into with developers and shall also include
23        contracts for renewable energy credits related to the
24        program.
25            (C) Incentives for non-profits and public
26        facilities. Under this program funds shall be used to

 

 

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1        support on-site photovoltaic distributed renewable
2        energy generation devices to serve the load associated
3        with not-for-profit customers and to support
4        photovoltaic distributed renewable energy generation
5        that uses photovoltaic technology to serve the load
6        associated with public sector customers taking service
7        at public buildings. To be eligible for these
8        incentives, the applicable facility of that
9        not-for-profit or public sector customer must provide
10        services that primarily serve low-income customers. It
11        is a goal of this program that at least 25% of the
12        incentives for this program be allocated to projects
13        located in environmental justice communities.
14        Contracts entered into under this paragraph may be
15        entered into with an entity that will develop and
16        administer the program or with developers and shall
17        also include contracts for renewable energy credits
18        related to the program. Participants may combine
19        incentive funding available through the Illinois Solar
20        for All Program with funding available through other
21        initiatives, including federal tax credits if such
22        credits are available, but the Agency may adjust
23        renewable energy credit prices applicable to projects
24        benefiting from such funding to reflect offset costs.
25            (D) Low-Income Community Solar Pilot Projects.
26        Under this program, persons, including, but not

 

 

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1        limited to, electric utilities, shall propose pilot
2        community solar projects. Community solar projects
3        proposed under this subparagraph (D) may exceed 2,000
4        kilowatts in nameplate capacity, but the amount paid
5        per project under this program may not exceed
6        $20,000,000. Pilot projects must result in economic
7        benefits for the members of the community in which the
8        project will be located. The proposed pilot project
9        must include a partnership with at least one
10        community-based organization. Approved pilot projects
11        shall be competitively bid by the Agency, subject to
12        fair and equitable guidelines developed by the Agency.
13        Funding available under this subparagraph (D) may not
14        be distributed solely to a utility, and at least some
15        funds under this subparagraph (D) must include a
16        project partnership that includes community ownership
17        by the project subscribers. Contracts entered into
18        under this paragraph may be entered into with an
19        entity that will develop and administer the program or
20        with developers and shall also include contracts for
21        renewable energy credits related to the program. A
22        project proposed by a utility that is implemented
23        under this subparagraph (D) shall not be included in
24        the utility's ratebase.
25        The requirement that a qualified person, as defined in
26    paragraph (1) of subsection (i) of this Section, install

 

 

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1    photovoltaic devices does not apply to the Illinois Solar
2    for All Program described in this subsection (b).
3        In addition to the programs outlined in paragraphs (A)
4    through (D), the Agency and other parties may propose
5    additional programs through the Long-Term Renewable
6    Resources Procurement Plan developed and approved under
7    paragraph (5) of subsection (b) of Section 16-111.5 of the
8    Public Utilities Act. Additional programs may target
9    market segments not specified above and may also include
10    incentives targeted to increase the uptake of
11    non-photovoltaic technologies by low-income customers,
12    including energy storage paired with photovoltaics, if the
13    Commission determines that the Illinois Solar for All
14    Program would provide greater benefits to the public
15    health and well-being of low-income residents through also
16    supporting that additional program versus supporting
17    programs already authorized.
18        (3) Costs associated with the Illinois Solar for All
19    Program and its components described in paragraph (2) of
20    this subsection (b), including, but not limited to, costs
21    associated with procuring experts, consultants, and the
22    program administrator referenced in this subsection (b)
23    and related incremental costs, including costs related to
24    income verification and facilitating customer
25    participation in the program and costs related to the
26    evaluation of the Illinois Solar for All Program, may be

 

 

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1    paid for using monies in the Illinois Power Agency
2    Renewable Energy Resources Fund and funds allocated
3    pursuant to subparagraph (O) of paragraph (1) of
4    subsection (c) of Section 1-75, but the Agency or program
5    administrator shall strive to minimize costs in the
6    implementation of the program. The Agency or contracting
7    electric utility shall purchase renewable energy credits
8    from generation that is the subject of a contract under
9    subparagraphs (A) through (D) of this paragraph (2) of
10    this subsection (b), and may pay for such renewable energy
11    credits through an upfront payment per installed kilowatt
12    of nameplate capacity paid once the device is
13    interconnected at the distribution system level of the
14    interconnecting utility and verified as and is energized
15    by the Program Administrator. Payments for renewable
16    energy credits The payment shall be in exchange for an
17    assignment of all renewable energy credits generated by
18    the participating project system during the first 15 years
19    of its operation and shall be structured to overcome
20    barriers to participation in the solar market by the
21    low-income community. The incentives provided for in this
22    Section may be implemented through the pricing of
23    renewable energy credits where the prices paid for the
24    credits are higher than the prices from programs offered
25    under subsection (c) of Section 1-75 of this Act to
26    account for the additional capital necessary to

 

 

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1    successfully access targeted market segments incentives.
2    The Agency shall ensure collaboration with community
3    agencies, and allocate up to 5% of the funds available
4    under the Illinois Solar for All Program to
5    community-based groups to assist in grassroots education
6    efforts related to the Illinois Solar for All Program. The
7    Agency or contracting electric utility shall retire any
8    renewable energy credits purchased under from this program
9    and the credits shall count towards the obligation under
10    subsection (c) of Section 1-75 of this Act for the
11    electric utility to which the project is interconnected,
12    if applicable.
13        The Agency shall direct 5% of the funds available
14    under the Illinois Solar for All Program to
15    community-based groups and other qualifying organizations
16    to assist in community-driven education efforts related to
17    the Illinois Solar for All Program, including general
18    energy education, job training program outreach efforts,
19    and other activities deemed to be qualified by the Agency.
20    Grassroots education funding shall not be used to support
21    the marketing by solar project development firms and
22    organizations, unless such education provides equal
23    opportunities for all applicable firms and organizations.
24        (4) The Agency shall, consistent with the requirements
25    of this subsection (b), propose the Illinois Solar for All
26    Program terms, conditions, and requirements, including the

 

 

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1    prices to be paid for renewable energy credits and
2    requirements applicable to participating entities and
3    project applications, and which prices may be determined
4    through a formula, through the development, review, and
5    approval of the Agency's long-term renewable resources
6    procurement plan described in subsection (c) of Section
7    1-75 of this Act and Section 16-111.5 of the Public
8    Utilities Act. Renewable energy credit prices may be fixed
9    or determined through a formula. In the course of the
10    Commission proceeding initiated to review and approve the
11    plan, including the Illinois Solar for All Program
12    proposed by the Agency, a party may propose an additional
13    low-income solar or solar incentive program, or
14    modifications to the programs proposed by the Agency, and
15    the Commission may approve an additional program, or
16    modifications to the Agency's proposed program, if the
17    additional or modified program more effectively maximizes
18    the benefits to low-income customers after taking into
19    account all relevant factors, including, but not limited
20    to, the extent to which a competitive market for
21    low-income solar has developed. Following the Commission's
22    approval of the Illinois Solar for All Program, the Agency
23    or a party may propose adjustments to the program terms,
24    conditions, and requirements, including the price offered
25    to new systems, to ensure the long-term viability and
26    success of the program. Those changes may be implemented

 

 

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1    between long-term renewable resources procurement plan
2    approval processes if accompanied by a stakeholder review
3    and comment, and the The Commission shall otherwise review
4    and approve any modifications to the program through the
5    plan revision process described in Section 16-111.5 of the
6    Public Utilities Act.
7        (5) The Agency shall issue a request for
8    qualifications for a third-party program administrator or
9    administrators to administer all or a portion of the
10    Illinois Solar for All Program. The third-party program
11    administrator shall be chosen through a competitive bid
12    process based on selection criteria and requirements
13    developed by the Agency, including, but not limited to,
14    experience in administering low-income energy programs and
15    overseeing statewide clean energy or energy efficiency
16    services. If the Agency retains a program administrator or
17    administrators to implement all or a portion of the
18    Illinois Solar for All Program, each administrator shall
19    periodically submit reports to the Agency and Commission
20    for each program that it administers, at appropriate
21    intervals to be identified by the Agency in its long-term
22    renewable resources procurement plan, provided that the
23    reporting interval is at least quarterly. The third-party
24    program administrator may be, but need not be, the same
25    administrator as for the Adjustable Block Program
26    described in subparagraphs (K) through (M) of paragraph

 

 

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1    (1) of subsection (c) of Section 1-75.
2        The third-party administrator's responsibilities
3    shall also include facilitating placement for graduates of
4    Illinois-based renewable energy-specific job training
5    programs, including the Clean Jobs Workforce Network
6    Program administered by the Department of Commerce and
7    Economic Opportunity and programs administered under
8    Section 16-108.12 of the Public Utilities Act. To increase
9    the uptake of trainees by participating firms, the
10    administrator shall also develop a web-based clearinghouse
11    for information available to both job training program
12    graduates and firms participating, directly or indirectly,
13    in Illinois solar incentive programs. The program
14    administrator shall also coordinate its activities with
15    entities implementing electric and natural gas
16    income-qualified energy efficiency programs, including
17    customer referrals to and from such programs, and connect
18    prospective low-income solar customers with any existing
19    deferred maintenance programs where applicable.
20        (6) The long-term renewable resources procurement plan
21    shall also provide for an independent evaluation of the
22    Illinois Solar for All Program. At least every 2 years, an
23    the Agency shall select an independent evaluator shall to
24    review and report on the Illinois Solar for All Program
25    and the performance of the third-party program
26    administrator of the Illinois Solar for All Program. The

 

 

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1    evaluation shall be based on objective criteria developed
2    through a public stakeholder process. The process shall
3    include feedback and participation from Illinois Solar for
4    All Program stakeholders, including participants and
5    organizations in environmental justice and historically
6    underserved communities. The report shall include a
7    summary of the evaluation of the Illinois Solar for All
8    Program based on the stakeholder developed objective
9    criteria. The report shall include the number of projects
10    installed; the total installed capacity in kilowatts; the
11    average cost per kilowatt of installed capacity to the
12    extent reasonably obtainable by the Agency; the number of
13    jobs or job opportunities created; economic, social, and
14    environmental benefits created; and the total
15    administrative costs expended by the Agency and program
16    administrator to implement and evaluate the program. The
17    report shall be delivered to the Commission and posted on
18    the Agency's website, and shall be used, as needed, to
19    revise the Illinois Solar for All Program. The Commission
20    shall also consider the results of the evaluation as part
21    of its review of the long-term renewable resources
22    procurement plan under subsection (c) of Section 1-75 of
23    this Act.
24        (7) If additional funding for the programs described
25    in this subsection (b) is available under subsection (k)
26    of Section 16-108 of the Public Utilities Act, then the

 

 

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1    Agency shall submit a procurement plan to the Commission
2    no later than September 1, 2018, that proposes how the
3    Agency will procure programs on behalf of the applicable
4    utility. After notice and hearing, the Commission shall
5    approve, or approve with modification, the plan no later
6    than November 1, 2018.
7    As used in this subsection (b), "low-income households"
8means persons and families whose income does not exceed 80% of
9area median income, adjusted for family size and revised every
102 5 years.
11    For the purposes of this subsection (b), the Agency shall
12define "environmental justice community" as part of long-term
13renewable resources procurement plan development, to ensure,
14to the extent practicable, compatibility with other agencies'
15definitions and may, for guidance, look to the definitions
16used by federal, state, or local governments.
17    (b-5) After the receipt of all payments required by
18Section 16-115D of the Public Utilities Act, no additional
19funds shall be deposited into the Illinois Power Agency
20Renewable Energy Resources Fund unless directed by order of
21the Commission.
22    (b-10) After the receipt of all payments required by
23Section 16-115D of the Public Utilities Act and payment in
24full of all contracts executed by the Agency under subsections
25(b) and (i) of this Section, if the balance of the Illinois
26Power Agency Renewable Energy Resources Fund is under $5,000,

 

 

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1then the Fund shall be inoperative and any remaining funds and
2any funds submitted to the Fund after that date, shall be
3transferred to the Supplemental Low-Income Energy Assistance
4Fund for use in the Low-Income Home Energy Assistance Program,
5as authorized by the Energy Assistance Act.
6    (c) (Blank).
7    (d) (Blank).
8    (e) All renewable energy credits procured using monies
9from the Illinois Power Agency Renewable Energy Resources Fund
10shall be permanently retired.
11    (f) The selection of one or more third-party program
12managers or administrators, the selection of the independent
13evaluator, and the procurement processes described in this
14Section are exempt from the requirements of the Illinois
15Procurement Code, under Section 20-10 of that Code.
16    (g) All disbursements from the Illinois Power Agency
17Renewable Energy Resources Fund shall be made only upon
18warrants of the Comptroller drawn upon the Treasurer as
19custodian of the Fund upon vouchers signed by the Director or
20by the person or persons designated by the Director for that
21purpose. The Comptroller is authorized to draw the warrant
22upon vouchers so signed. The Treasurer shall accept all
23warrants so signed and shall be released from liability for
24all payments made on those warrants.
25    (h) The Illinois Power Agency Renewable Energy Resources
26Fund shall not be subject to sweeps, administrative charges,

 

 

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1or chargebacks, including, but not limited to, those
2authorized under Section 8h of the State Finance Act, that
3would in any way result in the transfer of any funds from this
4Fund to any other fund of this State or in having any such
5funds utilized for any purpose other than the express purposes
6set forth in this Section.
7    (h-5) The Agency may assess fees to each bidder to recover
8the costs incurred in connection with a procurement process
9held under this Section. Fees collected from bidders shall be
10deposited into the Renewable Energy Resources Fund.
11    (i) Supplemental procurement process.
12        (1) Within 90 days after the effective date of this
13    amendatory Act of the 98th General Assembly, the Agency
14    shall develop a one-time supplemental procurement plan
15    limited to the procurement of renewable energy credits, if
16    available, from new or existing photovoltaics, including,
17    but not limited to, distributed photovoltaic generation.
18    Nothing in this subsection (i) requires procurement of
19    wind generation through the supplemental procurement.
20        Renewable energy credits procured from new
21    photovoltaics, including, but not limited to, distributed
22    photovoltaic generation, under this subsection (i) must be
23    procured from devices installed by a qualified person. In
24    its supplemental procurement plan, the Agency shall
25    establish contractually enforceable mechanisms for
26    ensuring that the installation of new photovoltaics is

 

 

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

 

 

SB2896- 226 -LRB102 17909 JWD 25989 b

1    technology.
2        For the purposes of this paragraph (1), "directly
3    supervised" means that there is a qualified person who
4    meets the qualifications under clause (A) of this
5    paragraph (1) and who is available for supervision and
6    consultation regarding the work performed by persons under
7    clause (B) of this paragraph (1), including a final
8    inspection of the installation work that has been directly
9    supervised to ensure safety and conformity with applicable
10    codes.
11        For the purposes of this paragraph (1), "install"
12    means the major activities and actions required to
13    connect, in accordance with applicable building and
14    electrical codes, the conductors, connectors, and all
15    associated fittings, devices, power outlets, or
16    apparatuses mounted at the premises that are directly
17    involved in delivering energy to the premises' electrical
18    wiring from the photovoltaics, including, but not limited
19    to, to distributed photovoltaic generation.
20        The renewable energy credits procured pursuant to the
21    supplemental procurement plan shall be procured using up
22    to $30,000,000 from the Illinois Power Agency Renewable
23    Energy Resources Fund. The Agency shall not plan to use
24    funds from the Illinois Power Agency Renewable Energy
25    Resources Fund in excess of the monies on deposit in such
26    fund or projected to be deposited into such fund. The

 

 

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1    supplemental procurement plan shall ensure adequate,
2    reliable, affordable, efficient, and environmentally
3    sustainable renewable energy resources (including credits)
4    at the lowest total cost over time, taking into account
5    any benefits of price stability.
6        To the extent available, 50% of the renewable energy
7    credits procured from distributed renewable energy
8    generation shall come from devices of less than 25
9    kilowatts in nameplate capacity. Procurement of renewable
10    energy credits from distributed renewable energy
11    generation devices shall be done through multi-year
12    contracts of no less than 5 years. The Agency shall create
13    credit requirements for counterparties. In order to
14    minimize the administrative burden on contracting
15    entities, the Agency shall solicit the use of third
16    parties to aggregate distributed renewable energy. These
17    third parties shall enter into and administer contracts
18    with individual distributed renewable energy generation
19    device owners. An individual distributed renewable energy
20    generation device owner shall have the ability to measure
21    the output of his or her distributed renewable energy
22    generation device.
23        In developing the supplemental procurement plan, the
24    Agency shall hold at least one workshop open to the public
25    within 90 days after the effective date of this amendatory
26    Act of the 98th General Assembly and shall consider any

 

 

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1    comments made by stakeholders or the public. Upon
2    development of the supplemental procurement plan within
3    this 90-day period, copies of the supplemental procurement
4    plan shall be posted and made publicly available on the
5    Agency's and Commission's websites. All interested parties
6    shall have 14 days following the date of posting to
7    provide comment to the Agency on the supplemental
8    procurement plan. All comments submitted to the Agency
9    shall be specific, supported by data or other detailed
10    analyses, and, if objecting to all or a portion of the
11    supplemental procurement plan, accompanied by specific
12    alternative wording or proposals. All comments shall be
13    posted on the Agency's and Commission's websites. Within
14    14 days following the end of the 14-day review period, the
15    Agency shall revise the supplemental procurement plan as
16    necessary based on the comments received and file its
17    revised supplemental procurement plan with the Commission
18    for approval.
19        (2) Within 5 days after the filing of the supplemental
20    procurement plan at the Commission, any person objecting
21    to the supplemental procurement plan shall file an
22    objection with the Commission. Within 10 days after the
23    filing, the Commission shall determine whether a hearing
24    is necessary. The Commission shall enter its order
25    confirming or modifying the supplemental procurement plan
26    within 90 days after the filing of the supplemental

 

 

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1    procurement plan by the Agency.
2        (3) The Commission shall approve the supplemental
3    procurement plan of renewable energy credits to be
4    procured from new or existing photovoltaics, including,
5    but not limited to, distributed photovoltaic generation,
6    if the Commission determines that it will ensure adequate,
7    reliable, affordable, efficient, and environmentally
8    sustainable electric service in the form of renewable
9    energy credits at the lowest total cost over time, taking
10    into account any benefits of price stability.
11        (4) The supplemental procurement process under this
12    subsection (i) shall include each of the following
13    components:
14            (A) Procurement administrator. The Agency may
15        retain a procurement administrator in the manner set
16        forth in item (2) of subsection (a) of Section 1-75 of
17        this Act to conduct the supplemental procurement or
18        may elect to use the same procurement administrator
19        administering the Agency's annual procurement under
20        Section 1-75.
21            (B) Procurement monitor. The procurement monitor
22        retained by the Commission pursuant to Section
23        16-111.5 of the Public Utilities Act shall:
24                (i) monitor interactions among the procurement
25            administrator and bidders and suppliers;
26                (ii) monitor and report to the Commission on

 

 

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1            the progress of the supplemental procurement
2            process;
3                (iii) provide an independent confidential
4            report to the Commission regarding the results of
5            the procurement events;
6                (iv) assess compliance with the procurement
7            plan approved by the Commission for the
8            supplemental procurement process;
9                (v) preserve the confidentiality of supplier
10            and bidding information in a manner consistent
11            with all applicable laws, rules, regulations, and
12            tariffs;
13                (vi) provide expert advice to the Commission
14            and consult with the procurement administrator
15            regarding issues related to procurement process
16            design, rules, protocols, and policy-related
17            matters;
18                (vii) consult with the procurement
19            administrator regarding the development and use of
20            benchmark criteria, standard form contracts,
21            credit policies, and bid documents; and
22                (viii) perform, with respect to the
23            supplemental procurement process, any other
24            procurement monitor duties specifically delineated
25            within subsection (i) of this Section.
26            (C) Solicitation, pre-qualification, and

 

 

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1        registration of bidders. The procurement administrator
2        shall disseminate information to potential bidders to
3        promote a procurement event, notify potential bidders
4        that the procurement administrator may enter into a
5        post-bid price negotiation with bidders that meet the
6        applicable benchmarks, provide supply requirements,
7        and otherwise explain the competitive procurement
8        process. In addition to such other publication as the
9        procurement administrator determines is appropriate,
10        this information shall be posted on the Agency's and
11        the Commission's websites. The procurement
12        administrator shall also administer the
13        prequalification process, including evaluation of
14        credit worthiness, compliance with procurement rules,
15        and agreement to the standard form contract developed
16        pursuant to item (D) of this paragraph (4). The
17        procurement administrator shall then identify and
18        register bidders to participate in the procurement
19        event.
20            (D) Standard contract forms and credit terms and
21        instruments. The procurement administrator, in
22        consultation with the Agency, the Commission, and
23        other interested parties and subject to Commission
24        oversight, shall develop and provide standard contract
25        forms for the supplier contracts that meet generally
26        accepted industry practices as well as include any

 

 

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1        applicable State of Illinois terms and conditions that
2        are required for contracts entered into by an agency
3        of the State of Illinois. Standard credit terms and
4        instruments that meet generally accepted industry
5        practices shall be similarly developed. Contracts for
6        new photovoltaics shall include a provision attesting
7        that the supplier will use a qualified person for the
8        installation of the device pursuant to paragraph (1)
9        of subsection (i) of this Section. The procurement
10        administrator shall make available to the Commission
11        all written comments it receives on the contract
12        forms, credit terms, or instruments. If the
13        procurement administrator cannot reach agreement with
14        the parties as to the contract terms and conditions,
15        the procurement administrator must notify the
16        Commission of any disputed terms and the Commission
17        shall resolve the dispute. The terms of the contracts
18        shall not be subject to negotiation by winning
19        bidders, and the bidders must agree to the terms of the
20        contract in advance so that winning bids are selected
21        solely on the basis of price.
22            (E) Requests for proposals; competitive
23        procurement process. The procurement administrator
24        shall design and issue requests for proposals to
25        supply renewable energy credits in accordance with the
26        supplemental procurement plan, as approved by the

 

 

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1        Commission. The requests for proposals shall set forth
2        a procedure for sealed, binding commitment bidding
3        with pay-as-bid settlement, and provision for
4        selection of bids on the basis of price, provided,
5        however, that no bid shall be accepted if it exceeds
6        the benchmark developed pursuant to item (F) of this
7        paragraph (4).
8            (F) Benchmarks. Benchmarks for each product to be
9        procured shall be developed by the procurement
10        administrator in consultation with Commission staff,
11        the Agency, and the procurement monitor for use in
12        this supplemental procurement.
13            (G) A plan for implementing contingencies in the
14        event of supplier default, Commission rejection of
15        results, or any other cause.
16        (5) Within 2 business days after opening the sealed
17    bids, the procurement administrator shall submit a
18    confidential report to the Commission. The report shall
19    contain the results of the bidding for each of the
20    products along with the procurement administrator's
21    recommendation for the acceptance and rejection of bids
22    based on the price benchmark criteria and other factors
23    observed in the process. The procurement monitor also
24    shall submit a confidential report to the Commission
25    within 2 business days after opening the sealed bids. The
26    report shall contain the procurement monitor's assessment

 

 

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1    of bidder behavior in the process as well as an assessment
2    of the procurement administrator's compliance with the
3    procurement process and rules. The Commission shall review
4    the confidential reports submitted by the procurement
5    administrator and procurement monitor and shall accept or
6    reject the recommendations of the procurement
7    administrator within 2 business days after receipt of the
8    reports.
9        (6) Within 3 business days after the Commission
10    decision approving the results of a procurement event, the
11    Agency shall enter into binding contractual arrangements
12    with the winning suppliers using the standard form
13    contracts.
14        (7) The names of the successful bidders and the
15    average of the winning bid prices for each contract type
16    and for each contract term shall be made available to the
17    public within 2 days after the supplemental procurement
18    event. The Commission, the procurement monitor, the
19    procurement administrator, the Agency, and all
20    participants in the procurement process shall maintain the
21    confidentiality of all other supplier and bidding
22    information in a manner consistent with all applicable
23    laws, rules, regulations, and tariffs. Confidential
24    information, including the confidential reports submitted
25    by the procurement administrator and procurement monitor
26    pursuant to this Section, shall not be made publicly

 

 

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1    available and shall not be discoverable by any party in
2    any proceeding, absent a compelling demonstration of need,
3    nor shall those reports be admissible in any proceeding
4    other than one for law enforcement purposes.
5        (8) The supplemental procurement provided in this
6    subsection (i) shall not be subject to the requirements
7    and limitations of subsections (c) and (d) of this
8    Section.
9        (9) Expenses incurred in connection with the
10    procurement process held pursuant to this Section,
11    including, but not limited to, the cost of developing the
12    supplemental procurement plan, the procurement
13    administrator, procurement monitor, and the cost of the
14    retirement of renewable energy credits purchased pursuant
15    to the supplemental procurement shall be paid for from the
16    Illinois Power Agency Renewable Energy Resources Fund. The
17    Agency shall enter into an interagency agreement with the
18    Commission to reimburse the Commission for its costs
19    associated with the procurement monitor for the
20    supplemental procurement process.
21(Source: P.A. 98-672, eff. 6-30-14; 99-906, eff. 6-1-17.)
 
22    (20 ILCS 3855/1-70)
23    Sec. 1-70. Agency officials.
24    (a) The Agency shall have a Director who meets the
25qualifications specified in Section 5-222 of the Civil

 

 

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1Administrative Code of Illinois.
2    (b) Within the Illinois Power Agency, the Agency shall
3establish a Planning and Procurement Bureau and may establish
4a Resource Development Bureau. Each Bureau shall report to the
5Director.
6    (c) The Chief of the Planning and Procurement Bureau shall
7be appointed by the Director, at the Director's sole
8discretion, and (i) shall have at least 5 years of direct
9experience in electricity supply planning and procurement and
10(ii) shall also hold an advanced degree in risk management,
11law, business, or a related field.
12    (d) The Chief of the Resource Development Bureau may be
13appointed by the Director and (i) shall have at least 5 years
14of direct experience in electric generating project
15development and (ii) shall also hold an advanced degree in
16economics, engineering, law, business, or a related field.
17    (e) For terms ending before December 31, 2019, the
18Director shall receive an annual salary of $100,000 or as set
19by the Executive Ethics Commission based on a review of
20comparable State agency director salaries Compensation Review
21Board, whichever is higher. For terms ending before December
2231, 2019, the Bureau Chiefs shall each receive an annual
23salary of $85,000 or as set by the Compensation Review Board,
24whichever is higher. For terms beginning after the effective
25date of this amendatory Act of the 100th General Assembly, the
26annual salaries for the Director and the Bureau Chiefs shall

 

 

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1be an amount equal to 15% more than the respective position's
2annual salary as of December 31, 2018. The calculation of the
32018 salary base for this adjustment shall not include any
4cost of living adjustments, as authorized by Senate Joint
5Resolution 192 of the 86th General Assembly, for the period
6beginning July 1, 2009 to June 30, 2019. Beginning July 1, 2019
7and each July 1 thereafter, the Director and the Bureau Chiefs
8shall receive an increase in salary based on a cost of living
9adjustment as authorized by Senate Joint Resolution 192 of the
1086th General Assembly.
11    (f) The Director and Bureau Chiefs shall not, for 2 years
12prior to appointment or for 2 years after he or she leaves his
13or her position, be employed by an electric utility,
14independent power producer, power marketer, or alternative
15retail electric supplier regulated by the Commission or the
16Federal Energy Regulatory Commission.
17    (g) The Director and Bureau Chiefs are prohibited from:
18(i) owning, directly or indirectly, 5% or more of the voting
19capital stock of an electric utility, independent power
20producer, power marketer, or alternative retail electric
21supplier; (ii) being in any chain of successive ownership of
225% or more of the voting capital stock of any electric utility,
23independent power producer, power marketer, or alternative
24retail electric supplier; (iii) receiving any form of
25compensation, fee, payment, or other consideration from an
26electric utility, independent power producer, power marketer,

 

 

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1or alternative retail electric supplier, including legal fees,
2consulting fees, bonuses, or other sums. These limitations do
3not apply to any compensation received pursuant to a defined
4benefit plan or other form of deferred compensation, provided
5that the individual has otherwise severed all ties to the
6utility, power producer, power marketer, or alternative retail
7electric supplier.
8(Source: P.A. 99-536, eff. 7-8-16; 100-1179, eff. 1-18-19.)
 
9    (20 ILCS 3855/1-75)
10    Sec. 1-75. Planning and Procurement Bureau. The Planning
11and Procurement Bureau has the following duties and
12responsibilities:
13    (a) The Planning and Procurement Bureau shall each year,
14beginning in 2008, develop procurement plans and conduct
15competitive procurement processes in accordance with the
16requirements of Section 16-111.5 of the Public Utilities Act
17for the eligible retail customers of electric utilities that
18on December 31, 2005 provided electric service to at least
19100,000 customers in Illinois. Beginning with the delivery
20year commencing on June 1, 2017, the Planning and Procurement
21Bureau shall develop plans and processes for the procurement
22of zero emission credits from zero emission facilities in
23accordance with the requirements of subsection (d-5) of this
24Section. The Planning and Procurement Bureau shall also
25develop procurement plans and conduct competitive procurement

 

 

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1processes in accordance with the requirements of Section
216-111.5 of the Public Utilities Act for the eligible retail
3customers of small multi-jurisdictional electric utilities
4that (i) on December 31, 2005 served less than 100,000
5customers in Illinois and (ii) request a procurement plan for
6their Illinois jurisdictional load. This Section shall not
7apply to a small multi-jurisdictional utility until such time
8as a small multi-jurisdictional utility requests the Agency to
9prepare a procurement plan for their Illinois jurisdictional
10load. For the purposes of this Section, the term "eligible
11retail customers" has the same definition as found in Section
1216-111.5(a) of the Public Utilities Act.
13    Beginning with the plan or plans to be implemented in the
142017 delivery year, the Agency shall no longer include the
15procurement of renewable energy resources in the annual
16procurement plans required by this subsection (a), except as
17provided in subsection (q) of Section 16-111.5 of the Public
18Utilities Act, and shall instead develop a long-term renewable
19resources procurement plan in accordance with subsection (c)
20of this Section and Section 16-111.5 of the Public Utilities
21Act.
22        (1) The Agency shall each year, beginning in 2008, as
23    needed, issue a request for qualifications for experts or
24    expert consulting firms to develop the procurement plans
25    in accordance with Section 16-111.5 of the Public
26    Utilities Act. In order to qualify an expert or expert

 

 

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1    consulting firm must have:
2            (A) direct previous experience assembling
3        large-scale power supply plans or portfolios for
4        end-use customers;
5            (B) an advanced degree in economics, mathematics,
6        engineering, risk management, or a related area of
7        study;
8            (C) 10 years of experience in the electricity
9        sector, including managing supply risk;
10            (D) expertise in wholesale electricity market
11        rules, including those established by the Federal
12        Energy Regulatory Commission and regional transmission
13        organizations;
14            (E) expertise in credit protocols and familiarity
15        with contract protocols;
16            (F) adequate resources to perform and fulfill the
17        required functions and responsibilities; and
18            (G) the absence of a conflict of interest and
19        inappropriate bias for or against potential bidders or
20        the affected electric utilities.
21        (2) The Agency shall each year, as needed, issue a
22    request for qualifications for a procurement administrator
23    to conduct the competitive procurement processes in
24    accordance with Section 16-111.5 of the Public Utilities
25    Act. In order to qualify an expert or expert consulting
26    firm must have:

 

 

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1            (A) direct previous experience administering a
2        large-scale competitive procurement process;
3            (B) an advanced degree in economics, mathematics,
4        engineering, or a related area of study;
5            (C) 10 years of experience in the electricity
6        sector, including risk management experience;
7            (D) expertise in wholesale electricity market
8        rules, including those established by the Federal
9        Energy Regulatory Commission and regional transmission
10        organizations;
11            (E) expertise in credit and contract protocols;
12            (F) adequate resources to perform and fulfill the
13        required functions and responsibilities; and
14            (G) the absence of a conflict of interest and
15        inappropriate bias for or against potential bidders or
16        the affected electric utilities.
17        (3) The Agency shall provide affected utilities and
18    other interested parties with the lists of qualified
19    experts or expert consulting firms identified through the
20    request for qualifications processes that are under
21    consideration to develop the procurement plans and to
22    serve as the procurement administrator. The Agency shall
23    also provide each qualified expert's or expert consulting
24    firm's response to the request for qualifications. All
25    information provided under this subparagraph shall also be
26    provided to the Commission. The Agency may provide by rule

 

 

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1    for fees associated with supplying the information to
2    utilities and other interested parties. These parties
3    shall, within 5 business days, notify the Agency in
4    writing if they object to any experts or expert consulting
5    firms on the lists. Objections shall be based on:
6            (A) failure to satisfy qualification criteria;
7            (B) identification of a conflict of interest; or
8            (C) evidence of inappropriate bias for or against
9        potential bidders or the affected utilities.
10        The Agency shall remove experts or expert consulting
11    firms from the lists within 10 days if there is a
12    reasonable basis for an objection and provide the updated
13    lists to the affected utilities and other interested
14    parties. If the Agency fails to remove an expert or expert
15    consulting firm from a list, an objecting party may seek
16    review by the Commission within 5 days thereafter by
17    filing a petition, and the Commission shall render a
18    ruling on the petition within 10 days. There is no right of
19    appeal of the Commission's ruling.
20        (4) The Agency shall issue requests for proposals to
21    the qualified experts or expert consulting firms to
22    develop a procurement plan for the affected utilities and
23    to serve as procurement administrator.
24        (5) The Agency shall select an expert or expert
25    consulting firm to develop procurement plans based on the
26    proposals submitted and shall award contracts of up to 5

 

 

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1    years to those selected.
2        (6) The Agency shall select an expert or expert
3    consulting firm, with approval of the Commission, to serve
4    as procurement administrator based on the proposals
5    submitted. If the Commission rejects, within 5 days, the
6    Agency's selection, the Agency shall submit another
7    recommendation within 3 days based on the proposals
8    submitted. The Agency shall award a 5-year contract to the
9    expert or expert consulting firm so selected with
10    Commission approval.
11    (b) The experts or expert consulting firms retained by the
12Agency shall, as appropriate, prepare procurement plans, and
13conduct a competitive procurement process as prescribed in
14Section 16-111.5 of the Public Utilities Act, to ensure
15adequate, reliable, affordable, efficient, and environmentally
16sustainable electric service at the lowest total cost over
17time, taking into account any benefits of price stability, for
18eligible retail customers of electric utilities that on
19December 31, 2005 provided electric service to at least
20100,000 customers in the State of Illinois, and for eligible
21Illinois retail customers of small multi-jurisdictional
22electric utilities that (i) on December 31, 2005 served less
23than 100,000 customers in Illinois and (ii) request a
24procurement plan for their Illinois jurisdictional load.
25    (c) Renewable portfolio standard.
26        (1)(A) The Agency shall develop a long-term renewable

 

 

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1    resources procurement plan that shall include procurement
2    programs and competitive procurement events necessary to
3    meet the goals set forth in this subsection (c). The
4    initial long-term renewable resources procurement plan
5    shall be released for comment no later than 160 days after
6    June 1, 2017 (the effective date of Public Act 99-906),
7    and a second revised long-term renewable resources
8    procurement plan shall be released for comment no later
9    than 120 days after the effective date of this amendatory
10    Act of the 102nd General Assembly. The Agency shall
11    review, and may revise on an expedited basis, the
12    long-term renewable resources procurement plan at least
13    every 2 years, which shall be conducted in conjunction
14    with the procurement plan under Section 16-111.5 of the
15    Public Utilities Act to the extent practicable to minimize
16    administrative expense. The long-term renewable resources
17    procurement plans shall be subject to review and approval
18    by the Commission under Section 16-111.5 of the Public
19    Utilities Act.
20        (B) Subject to subparagraph (F) of this paragraph (1),
21    the long-term renewable resources procurement plan shall
22    attempt to meet include the goals for procurement of
23    renewable energy credits at levels of to meet at least the
24    following overall percentages: 13% by the 2017 delivery
25    year; increasing by at least 1.5% each delivery year
26    thereafter to at least 25% by the 2025 delivery year;

 

 

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1    increasing by at least 2.5% each delivery year thereafter
2    to at least 40% by the 2030 delivery year; and continuing
3    at no less than 40% 25% for each delivery year thereafter.
4    In the event of a conflict between these goals and the new
5    wind and new photovoltaic procurement requirements
6    described in items (i) through (iii) of subparagraph (C)
7    of this paragraph (1), the long-term plan shall prioritize
8    compliance with the new wind and new photovoltaic
9    procurement requirements described in items (i) through
10    (iii) of subparagraph (C) of this paragraph (1) over the
11    annual percentage targets described in this subparagraph
12    (B).
13        For the delivery year beginning June 1, 2017, the
14    procurement plan shall attempt to include, subject to the
15    prioritization outlined above, cost-effective renewable
16    energy resources equal to at least 13% of each utility's
17    load for eligible retail customers and 13% of the
18    applicable portion of each utility's load for retail
19    customers who are not eligible retail customers, which
20    applicable portion shall equal 50% of the utility's load
21    for retail customers who are not eligible retail customers
22    on February 28, 2017.
23        For the delivery year beginning June 1, 2018, the
24    procurement plan shall attempt to include, subject to the
25    prioritization outlined above, cost-effective renewable
26    energy resources equal to at least 14.5% of each utility's

 

 

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1    load for eligible retail customers and 14.5% of the
2    applicable portion of each utility's load for retail
3    customers who are not eligible retail customers, which
4    applicable portion shall equal 75% of the utility's load
5    for retail customers who are not eligible retail customers
6    on February 28, 2017.
7        For the delivery year beginning June 1, 2019, and for
8    each year thereafter, the procurement plans shall attempt
9    to include, subject to the prioritization outlined above,
10    include cost-effective renewable energy resources equal to
11    a minimum percentage of each utility's load for all retail
12    customers as follows: 16% by June 1, 2019; increasing by
13    1.5% each year thereafter to 25% by June 1, 2025;
14    increasing by at least 2.5% each delivery year thereafter
15    to at least 40% by June 1, 2030 and 25% by June 1, 2026 and
16    each year thereafter.
17        For each delivery year, the Agency shall first
18    recognize each utility's obligations for that delivery
19    year under existing contracts. Any renewable energy
20    credits under existing contracts, including renewable
21    energy credits as part of renewable energy resources,
22    shall be used to meet the goals set forth in this
23    subsection (c) for the delivery year.
24        (C) Of the renewable energy credits procured under
25    this subsection (c), at least 75% shall come from wind and
26    photovoltaic projects. The long-term renewable resources

 

 

SB2896- 247 -LRB102 17909 JWD 25989 b

1    procurement plan described in subparagraph (A) of this
2    paragraph (1) shall include the procurement of renewable
3    energy credits from new projects in amounts equal to at
4    least the following:
5            (i) 10,000,000 renewable energy credits under
6        contract to be delivered annually from new wind and
7        solar projects by the end of delivery year 2021, and
8        (i) By the end of the 2020 delivery year:
9                increasing ratably to reach 45,000,000
10            renewable energy credits under contract to be
11            delivered annually from new renewable energy
12            projects by the end of delivery year 2031 such
13            that the goals in subsection (b) of this Section
14            (1) are met entirely by procurements of renewable
15            energy credits from new projects. At least
16            2,000,000 renewable energy credits for each
17            delivery year shall come from new wind projects;
18            and
19                At least 2,000,000 renewable energy credits
20            for each delivery year shall come from new
21            photovoltaic projects; of that amount, To to the
22            extent possible, and subject to revision by the
23            Commission through its approval of the Agency's
24            long-term renewable resources procurement plan,
25            the Agency shall procure 50% from wind projects
26            and 50% from photovoltaic projects. Of the amount

 

 

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1            procured from solar projects, the Agency shall
2            endeavor to procure: 40% at least 50% from solar
3            photovoltaic projects using the program outlined
4            in subparagraph (K) of this paragraph (1) from
5            distributed renewable energy generation devices or
6            community renewable generation projects; at least
7            40% from utility-scale solar projects; and 8% at
8            least 2% from brownfield site photovoltaic
9            projects that are not community renewable
10            generation. Programs or competitive procurements
11            used to incentivize the development of new
12            projects utilizing technologies other than wind or
13            photovoltaics may also be proposed as part of the
14            Agency's long-term renewable resources procurement
15            plan, and if successfully procured, shall count
16            toward these targets. projects; and the remainder
17            shall be determined through the long-term planning
18            process described in subparagraph (A) of this
19            paragraph (1).
20            (ii) In any given delivery year, if forecasted
21        expenses are less than the maximum budget available
22        under subparagraph (E), the Agency shall continue to
23        procure renewable credits until that budget is
24        exhausted in the manner outlined in item (i) of this
25        subparagraph (C). (ii) By the end of the 2025 delivery
26        year:

 

 

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1                At least 3,000,000 renewable energy credits
2            for each delivery year shall come from new wind
3            projects; and
4                At least 3,000,000 renewable energy credits
5            for each delivery year shall come from new
6            photovoltaic projects; of that amount, to the
7            extent possible, the Agency shall procure: at
8            least 50% from solar photovoltaic projects using
9            the program outlined in subparagraph (K) of this
10            paragraph (1) from distributed renewable energy
11            devices or community renewable generation
12            projects; at least 40% from utility-scale solar
13            projects; at least 2% from brownfield site
14            photovoltaic projects that are not community
15            renewable generation projects; and the remainder
16            shall be determined through the long-term planning
17            process described in subparagraph (A) of this
18            paragraph (1).
19            (iii) By the end of the 2030 delivery year:
20                At least 4,000,000 renewable energy credits
21            for each delivery year shall come from new wind
22            projects; and
23                At least 4,000,000 renewable energy credits
24            for each delivery year shall come from new
25            photovoltaic projects; of that amount, to the
26            extent possible, the Agency shall procure: at

 

 

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1            least 50% from solar photovoltaic projects using
2            the program outlined in subparagraph (K) of this
3            paragraph (1) from distributed renewable energy
4            devices or community renewable generation
5            projects; at least 40% from utility-scale solar
6            projects; at least 2% from brownfield site
7            photovoltaic projects that are not community
8            renewable generation projects; and the remainder
9            shall be determined through the long-term planning
10            process described in subparagraph (A) of this
11            paragraph (1).
12            (iii) For purposes of this Section:
13                "New wind projects" means wind renewable
14            energy facilities that are energized after June 1,
15            2017 for the delivery year commencing June 1, 2017
16            or within 3 years after the date the Commission
17            approves contracts for subsequent delivery years.
18                "New photovoltaic projects" means photovoltaic
19            renewable energy facilities that are energized
20            after June 1, 2017. Photovoltaic projects
21            developed under Section 1-56 of this Act shall not
22            apply towards the new photovoltaic project
23            requirements in this subparagraph (C).
24            (iv) For purposes of this subparagraph (C),
25        "Brownfield site photovoltaic project" shall generally
26        refer to photovoltaic projects that are:

 

 

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1                (I) interconnected to an electric utility as
2            defined in this Section, a public utility as
3            defined in Section 3-105 of the Public Utilities
4            Act, or an electric cooperative as defined in
5            Section 3-199 of the Public Utilities Act; and
6                (II) located at a site that meets one of the
7            following criteria:
8                    is or was recently regulated by the United
9                States Environmental Protection Agency under
10                the federal Comprehensive Environmental
11                Response, Compensation, and Liability Act of
12                1980, as amended;
13                    is or was recently regulated by the United
14                States Environmental Protection Agency under
15                the Corrective Action Program of the federal
16                Resource Conservation and Recovery Act, as
17                amended;
18                    is or was recently regulated by the
19                Illinois Environmental Protection Agency under
20                the Illinois Site Remediation Program;
21                    is or was recently regulated by the
22                Illinois Environmental Protection Agency under
23                the Illinois Solid Waste Program; or
24                    is primarily physically located on the
25                same parcel or adjacent parcel to a parcel of
26                land on which an electric generating facility

 

 

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1                that burned coal as its primary fuel source as
2                of January 1, 2019 is located.
3                As necessary to maximize the State's interest
4            in the health, safety, and welfare of its
5            residents, this brownfield site photovoltaic
6            project definition may be further refined,
7            including narrowed, through the development and
8            approval of the Illinois Power Agency's Long-Term
9            Renewable Resources Plan produced by the Illinois
10            Power Agency pursuant to Section 16-111.5(b)(5) of
11            the Public Utilities Act. If no further
12            refinements to this definition have been made
13            prior to the Agency conducting a brownfield site
14            photovoltaic project procurement event, the Agency
15            and its Procurement Administrator may, after
16            stakeholder comment, adopt participation
17            requirements more restrictive than this definition
18            for brownfield site photovoltaic project
19            procurement events.
20                In developing its long-term renewable
21            resources procurement plan, the Agency may
22            consider approaches other than competitive
23            procurements for the procurement of renewable
24            energy credits from brownfield site photovoltaic
25            projects. The Commission may approve an
26            alternative procurement approach for renewable

 

 

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1            energy credits from brownfield site photovoltaic
2            projects if it demonstrates that the alternative
3            procurement approach is likely to more effectively
4            return blighted or contaminated land to productive
5            use while enhancing public health and well-being
6            of Illinois residents, taking into account any
7            benefits of cost-efficiencies.
8            (v) The Agency shall ensure that costs associated
9        with renewable energy credit contracts executed by
10        counterparty electric utilities match with that
11        electric utility's anticipated budget under
12        subparagraph (E). However, in approving the Agency's
13        long-term renewable resources procurement plan, the
14        Agency may propose and the Commission may consider
15        requirements associated with the physical location of
16        new wind projects and new solar projects that reflect
17        needs specific to each electric utility's service
18        territory, including known or anticipated retirements
19        of other electric generating facilities and imports of
20        energy from other states into that utility's service
21        territory.
22        (D) Renewable energy credits shall be cost effective.
23    For purposes of this subsection (c), "cost effective"
24    means that the costs of procuring renewable energy
25    resources do not cause the limit stated in subparagraph
26    (E) of this paragraph (1) to be exceeded and, for

 

 

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1    renewable energy credits procured through a competitive
2    procurement event, do not exceed benchmarks based on
3    market prices for like products in the region. For
4    purposes of this subsection (c), "like products" means
5    contracts for renewable energy credits from the same or
6    substantially similar technology, same or substantially
7    similar vintage (new or existing), the same or
8    substantially similar quantity, and the same or
9    substantially similar contract length and structure.
10    Confidential benchmarks Benchmarks shall be developed by
11    the procurement administrator, in consultation with the
12    Commission staff, Agency staff, and the procurement
13    monitor and shall be subject to Commission review and
14    approval. If price benchmarks for like products in the
15    region are not available, the procurement administrator
16    shall establish price benchmarks based on publicly
17    available data on regional technology costs and expected
18    current and future regional energy prices. The benchmarks
19    in this Section shall not be used to curtail or otherwise
20    reduce contractual obligations entered into by or through
21    the Agency prior to June 1, 2017 (the effective date of
22    Public Act 99-906).
23        (E) For purposes of this subsection (c), the required
24    procurement of cost-effective renewable energy resources
25    for a particular year commencing prior to June 1, 2017
26    shall be measured as a percentage of the actual amount of

 

 

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1    electricity (megawatt-hours) supplied by the electric
2    utility to eligible retail customers in the delivery year
3    ending immediately prior to the procurement, and, for
4    delivery years commencing on and after June 1, 2017, the
5    required procurement of cost-effective renewable energy
6    resources for a particular year shall be measured as a
7    percentage of the actual amount of electricity
8    (megawatt-hours) delivered by the electric utility in the
9    delivery year ending immediately prior to the procurement,
10    to all retail customers in its service territory. For
11    purposes of this subsection (c), the amount paid per
12    kilowatthour means the total amount paid for electric
13    service expressed on a per kilowatthour basis. For
14    purposes of this subsection (c), the total amount paid for
15    electric service includes without limitation amounts paid
16    for supply, capacity, transmission, distribution,
17    surcharges, and add-on taxes.
18        Notwithstanding the requirements of this subsection
19    (c), the total of renewable energy resources procured
20    under the procurement plan for any single year shall be
21    subject to the limitations of this subparagraph (E). Such
22    procurement shall be reduced for all retail customers
23    based on the amount necessary to limit the annual
24    estimated average net increase due to the costs of these
25    resources included in the amounts paid by eligible retail
26    customers in connection with electric service to no more

 

 

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1    than the greater of the percentage limitations as included
2    in paragraphs (1), (2), and (3) of subsection (m) of
3    Section 8-103B of the Public Utilities Act 2.015% of the
4    amount paid per kilowatthour by those customers during the
5    year ending May 31, 2009, however the limitation in
6    paragraph (3) shall continue on without end 2007 or the
7    incremental amount per kilowatthour paid for these
8    resources in 2011. To arrive at a maximum dollar amount of
9    renewable energy resources to be procured for the
10    particular delivery year, the resulting per kilowatthour
11    amount shall be applied to the actual amount of
12    kilowatthours of electricity delivered, or applicable
13    portion of such amount as specified in paragraph (1) of
14    this subsection (c), as applicable, by the electric
15    utility in the delivery year immediately prior to the
16    procurement to all retail customers in its service
17    territory. The calculations required by this subparagraph
18    (E) shall be made only once for each delivery year at the
19    time that the renewable energy resources are procured.
20    Once the determination as to the amount of renewable
21    energy resources to procure is made based on the
22    calculations set forth in this subparagraph (E) and the
23    contracts procuring those amounts are executed, no
24    subsequent rate impact determinations shall be made and no
25    adjustments to those contract amounts shall be allowed.
26    All costs incurred under such contracts shall be fully

 

 

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1    recoverable by the electric utility as provided in this
2    Section.
3        (E-5) If the limitation on the amount of renewable
4    energy resources procured in subparagraph (E) of this
5    paragraph (1) would prevent the Agency from meeting all of
6    the goals in this subsection (c), the Agency shall procure
7    additional renewable energy resources using additional
8    funds collected pursuant to Section 16-108(k) of the
9    Public Utilities Act if so authorized by the Illinois
10    Commerce Commission in approving the Agency's long-term
11    renewable resources procurement plan, but only if required
12    to (I) ensure that any contractual obligations existing at
13    the time of that determination are fully met or (II) to
14    ensure that program and procurement activity would not be
15    subject to prolonged cessation. The utilities shall be
16    entitled to recover the total cost associated with
17    procuring renewable energy credits required by this
18    Section regardless of whether the costs are subject to the
19    limitations described in subparagraph (E) of this
20    paragraph (1) through the automatic adjustment clause
21    tariff under subsection (k) of Section 16-108 of the
22    Public Utilities Act.
23        (F) If the limitation on the amount of renewable
24    energy resources procured in subparagraph (E) of this
25    paragraph (1) prevents the Agency from meeting all of the
26    goals in this subsection (c), the Agency's long-term plan

 

 

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1    shall prioritize compliance with the requirements of this
2    subsection (c) regarding renewable energy credits in the
3    following order:
4            (i) renewable energy credits under existing
5        contractual obligations existing as of June 1, 2021;
6            (i-5) funding for the Illinois Solar for All
7        Program, as described in subparagraph (O) of this
8        paragraph (1);
9            (ii) renewable energy credits necessary to comply
10        with the new wind and new photovoltaic procurement
11        requirements described in items (i) through (iii) of
12        subparagraph (C) of this paragraph (1); and
13            (iii) renewable energy credits necessary to meet
14        the remaining requirements of this subsection (c).
15        (G) The following provisions shall apply to the
16    Agency's procurement of renewable energy credits under
17    this subsection (c):
18            (i) Notwithstanding whether a long-term renewable
19        resources procurement plan has been approved, the
20        Agency shall conduct an initial forward procurement
21        for renewable energy credits from new utility-scale
22        wind projects within 160 days after June 1, 2017 (the
23        effective date of Public Act 99-906). For the purposes
24        of this initial forward procurement, the Agency shall
25        solicit 15-year contracts for delivery of 1,000,000
26        renewable energy credits delivered annually from new

 

 

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1        utility-scale wind projects to begin delivery on June
2        1, 2019, if available, but not later than June 1, 2023
3        2021, unless the project has delays in the
4        establishment of an operating interconnection with the
5        applicable transmission or distribution system as a
6        result of the actions or inactions of the transmission
7        or distribution provider, or other causes for force
8        majeure as outlined in the procurement contract, in
9        which case, not later than June 1, 2022. Payments to
10        suppliers of renewable energy credits shall commence
11        upon delivery. Renewable energy credits procured under
12        this initial procurement shall be included in the
13        Agency's long-term plan and shall apply to all
14        renewable energy goals in this subsection (c).
15            (ii) Notwithstanding whether a long-term renewable
16        resources procurement plan has been approved, the
17        Agency shall conduct an initial forward procurement
18        for renewable energy credits from new utility-scale
19        solar projects and brownfield site photovoltaic
20        projects within one year after June 1, 2017 (the
21        effective date of Public Act 99-906). For the purposes
22        of this initial forward procurement, the Agency shall
23        solicit 15-year contracts for delivery of 1,000,000
24        renewable energy credits delivered annually from new
25        utility-scale solar projects and brownfield site
26        photovoltaic projects to begin delivery on June 1,

 

 

SB2896- 260 -LRB102 17909 JWD 25989 b

1        2019, if available, but not later than June 1, 2023
2        2021, unless the project has delays in the
3        establishment of an operating interconnection with the
4        applicable transmission or distribution system as a
5        result of the actions or inactions of the transmission
6        or distribution provider, or other causes for force
7        majeure as outlined in the procurement contract, in
8        which case, not later than June 1, 2022. The Agency may
9        structure this initial procurement in one or more
10        discrete procurement events. Payments to suppliers of
11        renewable energy credits shall commence upon delivery.
12        Renewable energy credits procured under this initial
13        procurement shall be included in the Agency's
14        long-term plan and shall apply to all renewable energy
15        goals in this subsection (c).
16            (iii) Notwithstanding the current
17        Commission-approved long-term renewable resources
18        procurement plan revision described in Section
19        16-111.5 of the Public Utilities Act, the Agency shall
20        conduct at least one subsequent forward procurement
21        for renewable energy credits from new utility scale
22        wind projects, new utility scale solar projects, and
23        new brownfield site photovoltaic projects within 240
24        days after the effective date of this amendatory Act
25        of the 102nd General Assembly in quantities needed to
26        meet the requirements of subparagraph (C) of this

 

 

SB2896- 261 -LRB102 17909 JWD 25989 b

1        subsection (c).
2            (iv) Notwithstanding the current
3        Commission-approved long-term renewable resources
4        procurement plan revision described in Section
5        16-111.5 of the Public Utilities Act, the Agency shall
6        open capacity for each category in the Adjustable
7        Block Program within 90 days after the effective date
8        of this amendatory Act of the 102nd General Assembly.
9        Blocks shall be sized as necessary to meet the
10        requirements of subparagraph (C) of this subsection
11        (c), and shall be opened in the following manner:
12                (I) The Agency shall open the next block of
13            capacity for the category described in item (i) of
14            subparagraph (K) this subsection (c). The price of
15            renewable energy credits for this new block of
16            capacity shall be 6% less than the price of the
17            last open block in this category. Projects on a
18            waitlist shall be awarded contracts first in the
19            order in which they appear on the waitlist.
20                (II) The Agency shall open the next block of
21            capacity for the category described in item (ii)
22            of subparagraph (K) of this subsection (c). The
23            price of the renewable energy credits for this new
24            block of capacity shall be 12% less than the price
25            of the last open block in this category. Projects
26            on a waitlist shall be awarded contracts first in

 

 

SB2896- 262 -LRB102 17909 JWD 25989 b

1            the order in which they appear on the waitlist.
2                (III) The Agency shall open the next block of
3            capacity for the category described in item
4            (iii)(I) of subparagraph (K) of this subsection
5            (c). The price of the renewable energy credits for
6            this new block of capacity shall be 20% less than
7            the price of the last open block of this category.
8            For this initial block, the capacity shall be
9            allocated to waitlisted projects in a manner
10            consistent with ordinal waitlists established by
11            the Agency.
12                (IV) Blocks of capacity for the category
13            described in item (iii)(II) of subparagraph (K) of
14            this subsection (c) shall not be opened until
15            after the Commission's review and approval of the
16            Agency's next revised long-term renewable
17            resources procurement plan.
18            (iii) Subsequent forward procurements for
19        utility-scale wind projects shall solicit at least
20        1,000,000 renewable energy credits delivered annually
21        per procurement event and shall be planned, scheduled,
22        and designed such that the cumulative amount of
23        renewable energy credits delivered from all new wind
24        projects in each delivery year shall not exceed the
25        Agency's projection of the cumulative amount of
26        renewable energy credits that will be delivered from

 

 

SB2896- 263 -LRB102 17909 JWD 25989 b

1        all new photovoltaic projects, including utility-scale
2        and distributed photovoltaic devices, in the same
3        delivery year at the time scheduled for wind contract
4        delivery.
5            (iv) If, at any time after the time set for
6        delivery of renewable energy credits pursuant to the
7        initial procurements in items (i) and (ii) of this
8        subparagraph (G), the cumulative amount of renewable
9        energy credits projected to be delivered from all new
10        wind projects in a given delivery year exceeds the
11        cumulative amount of renewable energy credits
12        projected to be delivered from all new photovoltaic
13        projects in that delivery year by 200,000 or more
14        renewable energy credits, then the Agency shall within
15        60 days adjust the procurement programs in the
16        long-term renewable resources procurement plan to
17        ensure that the projected cumulative amount of
18        renewable energy credits to be delivered from all new
19        wind projects does not exceed the projected cumulative
20        amount of renewable energy credits to be delivered
21        from all new photovoltaic projects by 200,000 or more
22        renewable energy credits, provided that nothing in
23        this Section shall preclude the projected cumulative
24        amount of renewable energy credits to be delivered
25        from all new photovoltaic projects from exceeding the
26        projected cumulative amount of renewable energy

 

 

SB2896- 264 -LRB102 17909 JWD 25989 b

1        credits to be delivered from all new wind projects in
2        each delivery year and provided further that nothing
3        in this item (iv) shall require the curtailment of an
4        executed contract. The Agency shall update, on a
5        quarterly basis, its projection of the renewable
6        energy credits to be delivered from all projects in
7        each delivery year. Notwithstanding anything to the
8        contrary, the Agency may adjust the timing of
9        procurement events conducted under this subparagraph
10        (G). The long-term renewable resources procurement
11        plan shall set forth the process by which the
12        adjustments may be made.
13            (v) Upon the effective date of this Act, for any
14        procurements of renewable energy credits from new
15        utility-scale wind and new utility-scale photovoltaic
16        projects, the Agency shall procure indexed renewable
17        energy credits and direct respondents to offer a
18        strike price.
19                (I) The value of the indexed renewable energy
20            credit payment shall be calculated for each
21            settlement period. That payment, for any
22            settlement period, shall be equal to the
23            difference resulting from subtracting the strike
24            price from the index price for that settlement
25            period. If this difference results in a negative
26            number, the indexed REC counterparty shall owe the

 

 

SB2896- 265 -LRB102 17909 JWD 25989 b

1            seller the absolute value multiplied by the
2            quantity of energy produced in the relevant
3            settlement period. If this difference results in a
4            positive number, the seller shall owe the indexed
5            REC counterparty this amount multiplied by the
6            quantity of energy produced in the relevant
7            settlement period.
8                (II) Parties shall cash settle every month,
9            summing up all settlements (both positive and
10            negative, if applicable) for the prior month.
11                (III) To ensure funding in the annual budget
12            established under subparagraph (E) of this
13            subsection (c) for indexed renewable energy credit
14            procurements for each year of the term of such
15            contracts, which must have a minimum tenor of 15
16            calendar years, the procurement administrator,
17            Agency, Commission staff, and procurement monitor
18            shall quantify the annual cost of the contract by
19            utilizing an industry-standard, third-party
20            forward price curve for energy at the appropriate
21            hub or load zone, including the estimated
22            magnitude and timing of the price effects related
23            to federal carbon controls. Each forward price
24            curve shall contain a specific value of the
25            forecasted market price of electricity for each
26            annual delivery year of the contract. For

 

 

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1            procurement planning purposes, the impact on the
2            annual budget for the cost of indexed renewable
3            energy credits for each delivery year shall be
4            determined as the difference between the expected
5            annual contract expenditures for that year (the
6            sum of the strike price multiplied by quantity of
7            contracts for all relevant contracts) and the
8            total target quantity of contracts multiplied by
9            the forward price curve for each respective load
10            zone for that year. The contracting utility shall
11            not assume an obligation in excess of the
12            estimated annual cost of the contracts for indexed
13            renewable energy credits. Forward curves shall be
14            revised on an annual basis as updated forward
15            price curves are released and filed with the
16            Commission in the proceeding approving the
17            Agency's most recent long-term renewable resources
18            procurement plan. If the expected contract spend
19            is higher or lower than the total quantity of
20            renewable energy credits multiplied by the forward
21            price curve value for that year, the forward price
22            curve shall be updated by the procurement
23            administrator, in consultation with the Agency,
24            Commission staff, and procurement monitors, using
25            then-currently available price forecast data and
26            additional budget dollars shall be obligated or

 

 

SB2896- 267 -LRB102 17909 JWD 25989 b

1            reobligated as appropriate.
2                (IV) To ensure that indexed renewable energy
3            credit prices remain reasonably predictable and
4            affordable, the Agency may consider the
5            institution of a price collar on REC prices paid
6            under indexed renewable energy credit procurements
7            establishing floor and ceiling REC prices
8            applicable to indexed REC contract prices. Any
9            price collars applicable to indexed REC
10            procurements shall be proposed by the Agency
11            through its long-term renewable resources
12            procurement plan.
13            (vi) (v) All procurements under this subparagraph
14        (G) shall comply with the geographic requirements in
15        subparagraph (I) of this paragraph (1) and shall
16        follow the procurement processes and procedures
17        described in this Section and Section 16-111.5 of the
18        Public Utilities Act to the extent practicable, and
19        these processes and procedures may be expedited to
20        accommodate the schedule established by this
21        subparagraph (G).
22        (H) The procurement of renewable energy resources for
23    a given delivery year shall be reduced as described in
24    this subparagraph (H) if an alternative retail electric
25    supplier meets the requirements described in this
26    subparagraph (H).

 

 

SB2896- 268 -LRB102 17909 JWD 25989 b

1            (i) Within 45 days after June 1, 2017 (the
2        effective date of Public Act 99-906), an alternative
3        retail electric supplier or its successor shall submit
4        an informational filing to the Illinois Commerce
5        Commission certifying that, as of December 31, 2015,
6        the alternative retail electric supplier owned one or
7        more electric generating facilities that generates
8        renewable energy resources as defined in Section 1-10
9        of this Act, provided that such facilities are not
10        powered by wind or photovoltaics, and the facilities
11        generate one renewable energy credit for each
12        megawatthour of energy produced from the facility.
13            The informational filing shall identify each
14        facility that was eligible to satisfy the alternative
15        retail electric supplier's obligations under Section
16        16-115D of the Public Utilities Act as described in
17        this item (i).
18            (ii) For a given delivery year, the alternative
19        retail electric supplier may elect to supply its
20        retail customers with renewable energy credits from
21        the facility or facilities described in item (i) of
22        this subparagraph (H) that continue to be owned by the
23        alternative retail electric supplier.
24            (iii) The alternative retail electric supplier
25        shall notify the Agency and the applicable utility, no
26        later than February 28 of the year preceding the

 

 

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1        applicable delivery year or 15 days after June 1, 2017
2        (the effective date of Public Act 99-906), whichever
3        is later, of its election under item (ii) of this
4        subparagraph (H) to supply renewable energy credits to
5        retail customers of the utility. Such election shall
6        identify the amount of renewable energy credits to be
7        supplied by the alternative retail electric supplier
8        to the utility's retail customers and the source of
9        the renewable energy credits identified in the
10        informational filing as described in item (i) of this
11        subparagraph (H), subject to the following
12        limitations:
13                For the delivery year beginning June 1, 2018,
14            the maximum amount of renewable energy credits to
15            be supplied by an alternative retail electric
16            supplier under this subparagraph (H) shall be 68%
17            multiplied by 25% multiplied by 14.5% multiplied
18            by the amount of metered electricity
19            (megawatt-hours) delivered by the alternative
20            retail electric supplier to Illinois retail
21            customers during the delivery year ending May 31,
22            2016.
23                For delivery years beginning June 1, 2019 and
24            each year thereafter, the maximum amount of
25            renewable energy credits to be supplied by an
26            alternative retail electric supplier under this

 

 

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1            subparagraph (H) shall be 68% multiplied by 50%
2            multiplied by 16% multiplied by the amount of
3            metered electricity (megawatt-hours) delivered by
4            the alternative retail electric supplier to
5            Illinois retail customers during the delivery year
6            ending May 31, 2016, provided that the 16% value
7            shall increase by 1.5% each delivery year
8            thereafter to 25% by the delivery year beginning
9            June 1, 2025, and thereafter the 25% value shall
10            apply to each delivery year.
11            For each delivery year, the total amount of
12        renewable energy credits supplied by all alternative
13        retail electric suppliers under this subparagraph (H)
14        shall not exceed 9% of the Illinois target renewable
15        energy credit quantity. The Illinois target renewable
16        energy credit quantity for the delivery year beginning
17        June 1, 2018 is 14.5% multiplied by the total amount of
18        metered electricity (megawatt-hours) delivered in the
19        delivery year immediately preceding that delivery
20        year, provided that the 14.5% shall increase by 1.5%
21        each delivery year thereafter to 25% by the delivery
22        year beginning June 1, 2025, and thereafter the 25%
23        value shall apply to each delivery year.
24            If the requirements set forth in items (i) through
25        (iii) of this subparagraph (H) are met, the charges
26        that would otherwise be applicable to the retail

 

 

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1        customers of the alternative retail electric supplier
2        under paragraph (6) of this subsection (c) for the
3        applicable delivery year shall be reduced by the ratio
4        of the quantity of renewable energy credits supplied
5        by the alternative retail electric supplier compared
6        to that supplier's target renewable energy credit
7        quantity. The supplier's target renewable energy
8        credit quantity for the delivery year beginning June
9        1, 2018 is 14.5% multiplied by the total amount of
10        metered electricity (megawatt-hours) delivered by the
11        alternative retail supplier in that delivery year,
12        provided that the 14.5% shall increase by 1.5% each
13        delivery year thereafter to 25% by the delivery year
14        beginning June 1, 2025, and thereafter the 25% value
15        shall apply to each delivery year.
16            On or before April 1 of each year, the Agency shall
17        annually publish a report on its website that
18        identifies the aggregate amount of renewable energy
19        credits supplied by alternative retail electric
20        suppliers under this subparagraph (H).
21        (I) The Agency shall design its long-term renewable
22    energy procurement plan to maximize the State's interest
23    in the health, safety, and welfare of its residents,
24    including but not limited to minimizing sulfur dioxide,
25    nitrogen oxide, particulate matter and other pollution
26    that adversely affects public health in this State,

 

 

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1    increasing fuel and resource diversity in this State,
2    enhancing the reliability and resiliency of the
3    electricity distribution system in this State, meeting
4    goals to limit carbon dioxide emissions under federal or
5    State law, and contributing to a cleaner and healthier
6    environment for the citizens of this State. In order to
7    further these legislative purposes, renewable energy
8    credits shall be eligible to be counted toward the
9    renewable energy requirements of this subsection (c) if
10    they are generated from facilities located in this State.
11    The Agency may qualify renewable energy credits from
12    facilities located in states adjacent to Illinois if the
13    generator demonstrates and the Agency determines that the
14    operation of such facility or facilities will help promote
15    the State's interest in the health, safety, and welfare of
16    its residents based on the public interest criteria
17    described above. To ensure that the public interest
18    criteria are applied to the procurement and given full
19    effect, the Agency's long-term procurement plan shall
20    describe in detail how each public interest factor shall
21    be considered and weighted for facilities located in
22    states adjacent to Illinois.
23        (J) In order to promote the competitive development of
24    renewable energy resources in furtherance of the State's
25    interest in the health, safety, and welfare of its
26    residents, renewable energy credits shall not be eligible

 

 

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1    to be counted toward the renewable energy requirements of
2    this subsection (c) if they are sourced from a generating
3    unit whose costs were being recovered through rates
4    regulated by this State or any other state or states on or
5    after January 1, 2017. Each contract executed to purchase
6    renewable energy credits under this subsection (c) shall
7    provide for the contract's termination if the costs of the
8    generating unit supplying the renewable energy credits
9    subsequently begin to be recovered through rates regulated
10    by this State or any other state or states; and each
11    contract shall further provide that, in that event, the
12    supplier of the credits must return 110% of all payments
13    received under the contract. Amounts returned under the
14    requirements of this subparagraph (J) shall be retained by
15    the utility and all of these amounts shall be used for the
16    procurement of additional renewable energy credits from
17    new wind or new photovoltaic resources as defined in this
18    subsection (c). The long-term plan shall provide that
19    these renewable energy credits shall be procured in the
20    next procurement event.
21        Notwithstanding the limitations of this subparagraph
22    (J), renewable energy credits sourced from generating
23    units that are constructed, purchased, owned, or leased by
24    an electric utility as part of an approved project,
25    program, or pilot under Section 1-56 of this Act shall be
26    eligible to be counted toward the renewable energy

 

 

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1    requirements of this subsection (c), regardless of how the
2    costs of these units are recovered.
3        (K) The long-term renewable resources procurement plan
4    developed by the Agency in accordance with subparagraph
5    (A) of this paragraph (1) shall include an Adjustable
6    Block program for the procurement of renewable energy
7    credits from new photovoltaic projects that are
8    distributed renewable energy generation devices or new
9    photovoltaic community renewable generation projects. The
10    Adjustable Block program shall generally be designed to
11    provide for the predictable, sustainable growth of new
12    solar photovoltaic development in Illinois, while also
13    ensuring that any unnecessary costs and margins are
14    minimized. The Agency shall design the program, the
15    prices, terms and conditions, and consumer protections to
16    ensure projects are able to be financed. To this end, and
17    unless otherwise required by the Illinois Commerce
18    Commission, the Adjustable Block program shall provide a
19    transparent annual schedule of prices and quantities to
20    enable the photovoltaic market to scale up and for
21    renewable energy credit prices to adjust at a predictable
22    rate over time. If administratively established, the The
23    prices set by the Adjustable Block program can be
24    reflected as a set value or as the product of a formula.
25        The Adjustable Block program shall include for each
26    category of eligible projects for each delivery year: a

 

 

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1    single block of nameplate capacity, a price for renewable
2    energy credits within that block, and the terms and
3    conditions for securing a spot on a waitlist once the
4    block is : a schedule of standard block purchase prices to
5    be offered; a series of steps, with associated nameplate
6    capacity and purchase prices that adjust from step to
7    step; and automatic opening of the next step as soon as the
8    nameplate capacity and available purchase prices for an
9    open step are fully committed or reserved. Except as
10    outlined below, the waitlist of projects in a given year
11    will carry over to apply to the subsequent year when
12    another block is opened. Only projects energized on or
13    after June 1, 2017 shall be eligible for the Adjustable
14    Block program. For each category for each delivery year
15    block group the Agency shall determine the number of
16    blocks, the amount of generation capacity in each block,
17    and the purchase price for each block, provided that the
18    purchase price provided and the total amount of generation
19    in all blocks for all categories block groups shall be
20    sufficient to meet the goals in this subsection (c). The
21    Agency shall strive to issue a single block sized to
22    provide for stability and market growth. The Agency shall
23    establish program eligibility requirements that ensure
24    that projects that enter the program are sufficiently
25    mature to indicate a demonstrable path to completion. The
26    Agency may periodically review its prior decisions

 

 

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1    establishing the number of blocks, the amount of
2    generation capacity in each block, and the purchase price
3    for each block, and may propose, on an expedited basis,
4    changes to these previously set values, including but not
5    limited to redistributing these amounts and the available
6    funds as necessary and appropriate, subject to Commission
7    approval as part of the periodic plan revision process
8    described in Section 16-111.5 of the Public Utilities Act.
9    The Agency may define different block sizes, purchase
10    prices, or other distinct terms and conditions for
11    projects located in different utility service territories
12    if the Agency deems it necessary to meet the goals in this
13    subsection (c). The Agency may also consider and propose
14    alternative pricing and participation procedures for
15    projects participating in item (iii) of this subparagraph
16    (K), including competitive procurement processes or other
17    approaches used to ensure that renewable energy credit
18    prices remain low, with any such alternative pricing and
19    participation procedures subject to approval of the
20    Illinois Commerce Commission.
21        The Adjustable Block program shall include at least
22    the following categories block groups in at least the
23    following amounts, which may be adjusted upon review by
24    the Agency and approval by the Commission as described in
25    this subparagraph (K):
26            (i) At least 25% from distributed renewable energy

 

 

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1        generation devices with a nameplate capacity of no
2        more than 25 10 kilowatts. Any projects sized 10
3        kilowatts to 25 kilowatts on a waitlist for capacity
4        in item (ii) of this subparagraph (K) as of the
5        effective date of this amendatory Act of the 102nd
6        General Assembly shall not need to reapply to the
7        program or pay additional application fees. The Agency
8        may by rule create sub-categories within this category
9        to ensure adequate levels of residential customer
10        participation.
11            (ii) At least 30% 25% from distributed renewable
12        energy generation devices with a nameplate capacity of
13        more than 25 10 kilowatts and no more than 5,000 2,000
14        kilowatts. The Agency may create sub-categories within
15        this category to account for the differences between
16        projects for small commercial customers, large
17        commercial customers, and public or non-profit
18        customers.
19            (iii) At least 40% 25% from photovoltaic community
20        renewable generation projects described in items (I)
21        and (II) of this item (iii) of this subparagraph (K): .
22                (I) 75% of renewable energy credits from
23            projects selected to maximize cost efficiencies in
24            community solar project development and provide
25            cost-effective subscription costs. For the first
26            three delivery years after the Amendatory date of

 

 

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1            this Act (including the delivery year in which
2            this Amendatory Act is enacted), projects shall be
3            selected from existing ordinal waitlists as
4            established by the Agency and shall be no greater
5            than 2,000 kilowatts in size. For all delivery
6            years thereafter, projects may be up to 10,000
7            kilowatts in size and shall be selected in
8            accordance with a new project application process
9            determined through the Agency's long-term
10            renewable resources procurement plan. The Agency
11            may also propose and the Commission may consider,
12            as part of the Agency's long-term renewable
13            resources procurement plan, alternative methods
14            for determining the renewable energy credit prices
15            applicable to projects participating in this
16            subparagraph, including competitive procurements
17            if so warranted.
18                (II) 5% of renewable energy credits from
19            projects selected intended to increase the variety
20            of community solar locations, models, and options
21            in Illinois, with those projects required to
22            provide more direct and tangible benefits to the
23            communities in which they operate. As part of its
24            long-term renewable resources procurement plan,
25            the Agency shall develop selection criteria for
26            projects participating in this category and shall

 

 

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1            propose administratively established renewable
2            energy credit prices reflecting any increases in a
3            project's cost structure resultant from identified
4            beneficial project attributes. Selection criteria
5            may include, but need not be limited to,
6            development density of the community in which the
7            project is physically located, whether the project
8            was developed in response to a site-specific RFP
9            issued by a municipality or community group,
10            planned subscriber proximity to the project's
11            physical location, and other direct benefits to
12            the community in which the project is physically
13            located. Projects participating in this
14            subparagraph shall be no greater than 500
15            kilowatts in size.
16            (iv) The remaining 25% shall be allocated as
17        specified by the Agency in the long-term renewable
18        resources procurement plan. The IPA shall allocate any
19        discretionary capacity prior to the beginning of each
20        delivery year.
21            (v) To the extent there is uncontracted capacity
22        from any block in any of categories (i)-(iii) above at
23        the end of a delivery year, the Agency may
24        redistribute that capacity to one or more other
25        categories. The redistributed capacity shall be added
26        to the annual capacity in the subsequent delivery

 

 

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1        year, and the applicable price for renewable energy
2        credits for that category shall be the price for the
3        new delivery year.
4        The Adjustable Block program shall be designed to
5    ensure that renewable energy credits are procured from
6    photovoltaic distributed renewable energy generation
7    devices and new photovoltaic community renewable energy
8    generation projects in diverse locations and are not
9    concentrated in a few regional geographic areas.
10        (L) The procurement of photovoltaic renewable energy
11    credits under items (i) through (iv) of subparagraph (K)
12    of this paragraph (1) shall be subject to the following
13    contract and payment terms:
14            (i) The Agency shall procure contracts of at least
15        15 years in length.
16            (ii) For those renewable energy credits that
17        qualify and are procured under item (i) of
18        subparagraph (K) of this paragraph (1), the renewable
19        energy credit delivery contract value purchase price
20        shall be paid in full, based upon the estimated
21        generation during the first 15 years of operation, by
22        the contracting utilities at the time that the
23        facility producing the renewable energy credits is
24        interconnected at the distribution system level of the
25        utility and verified as energized and compliant by the
26        Program Administrator and energized. The electric

 

 

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1        utility shall receive and retire all renewable energy
2        credits generated by the project for the first 15
3        years of operation. Renewable energy credits generated
4        by the project thereafter shall not be transferred
5        under the renewable energy credit delivery contract
6        with the counterparty electric utility.
7            (iii) For those renewable energy credits that
8        qualify and are procured under item (ii) and (iii)(b)
9        of subparagraph (K) of this paragraph (1), 15 and any
10        additional categories of distributed generation
11        included in the long-term renewable resources
12        procurement plan and approved by the Commission, 20
13        percent of the renewable energy credit delivery
14        contract value, based upon the estimated generation
15        during the first 15 years of operation, purchase price
16        shall be paid by the contracting utilities at the time
17        that the facility producing the renewable energy
18        credits is interconnected at the distribution system
19        level of the utility and verified as and energized and
20        compliant by the Program Administrator. The remaining
21        portion shall be paid ratably over the subsequent
22        4-year period. The electric utility shall receive and
23        retire all renewable energy credits generated by the
24        project for the first 15 years of operation. Renewable
25        energy credits generated by the project thereafter
26        shall not be transferred under the renewable energy

 

 

SB2896- 282 -LRB102 17909 JWD 25989 b

1        credit delivery contract with the counterparty
2        electric utility.
3            (iv) For those renewable energy credits that
4        qualify and are procured under item (iii)(a) of
5        subparagraph (K) of this paragraph (1), the renewable
6        energy credit delivery contract shall be paid over the
7        delivery term based on actual deliveries up to an
8        annual cap based upon the estimated generation during
9        the first 15 years of operation, adjusted for actual
10        subscription levels calculated on an annual basis. The
11        electric utility shall receive and retire all
12        renewable energy credits generated by the project
13        during the first 15 years of operation. Renewable
14        energy credits generated by the project thereafter
15        shall not be transferred under the renewable energy
16        credit delivery contract with the counterparty
17        electric utility.
18            (v) (iv) Each contract shall include provisions to
19        ensure the delivery of the estimated quantity of
20        renewable energy credits including ongoing collateral
21        requirements and other contract provisions deemed
22        appropriate by the Agency for the full term of the
23        contract.
24            (vi) (v) The utility shall be the counterparty to
25        the contracts executed under this subparagraph (L)
26        that are approved by the Commission under the process

 

 

SB2896- 283 -LRB102 17909 JWD 25989 b

1        described in Section 16-111.5 of the Public Utilities
2        Act. No contract shall be executed for an amount that
3        is less than one renewable energy credit per year.
4            (vii) (vi) If, at any time, approved applications
5        for the Adjustable Block program exceed funds
6        collected by the electric utility or would cause the
7        Agency to exceed the limitation described in
8        subparagraph (E) of this paragraph (1) on the amount
9        of renewable energy resources that may be procured,
10        then the Agency may shall consider future uncommitted
11        funds to be reserved for these contracts on a
12        first-come, first-served basis, with the delivery of
13        renewable energy credits required beginning at the
14        time that the reserved funds become available.
15            (viii) (vii) Nothing in this Section shall require
16        the utility to advance any payment or pay any amounts
17        that exceed the actual amount of revenues anticipated
18        to be collected by the utility under paragraph (6) of
19        this subsection (c) and subsection (k) of Section
20        16-108 of the Public Utilities Act, inclusive of
21        eligible funds collected in prior years and
22        alternative compliance payments available for use by
23        the utility, and contracts executed under this Section
24        shall expressly incorporate this limitation.
25            (ix) Notwithstanding other requirements of this
26        subparagraph (L), no modification shall be required to

 

 

SB2896- 284 -LRB102 17909 JWD 25989 b

1        Adjustable Block Program renewable energy credit
2        delivery contracts if those contracts were executed
3        before new contract forms reflecting changes resultant
4        from this amendatory Act of the 102nd General Assembly
5        are finalized.
6        (M) The Agency shall be authorized to retain one or
7    more experts or expert consulting firms to develop,
8    administer, implement, operate, and evaluate the
9    Adjustable Block program described in subparagraph (K) of
10    this paragraph (1), and the Agency shall retain the
11    consultant or consultants in the same manner, to the
12    extent practicable, as the Agency retains others to
13    administer provisions of this Act, including, but not
14    limited to, the procurement administrator. The selection
15    of experts and expert consulting firms and the procurement
16    process described in this subparagraph (M) are exempt from
17    the requirements of Section 20-10 of the Illinois
18    Procurement Code, under Section 20-10 of that Code. The
19    Agency shall strive to minimize administrative expenses in
20    the implementation of the Adjustable Block program. Funds
21    needed to cover the administrative expenses for the
22    implementation of the Adjustable Block program shall not
23    be included as part of the limitations described in
24    subparagraph (E) of this subsection (c). Participating
25    electric utilities shall be entitled to recover any costs
26    detailed in this subparagraph (M) applicable to those

 

 

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1    utilities through the automatic adjustment clause tariff
2    under subsection (k) of Section 16-108 of the Public
3    Utilities Act, regardless of whether the costs are subject
4    to the limitations described in subparagraph (E) of this
5    subsection (c).
6        The Program Administrator may also charge application
7    fees to participating firms to cover the cost of program
8    administration. Any application fee amounts shall
9    initially be determined through the long-term renewable
10    resources procurement plan, and modifications to any
11    application fee that deviate more than 25% from the
12    Commission's approved value must be approved by the
13    Commission as a long-term plan revision under Section
14    16-111.5 of the Public Utilities Act. The Agency shall
15    consider stakeholder feedback when making adjustments to
16    application fees and shall notify stakeholders in advance
17    of any planned changes.
18        In addition to covering the costs of program
19    administration, the Agency, in conjunction with its
20    Program Administrator, may also use the proceeds of such
21    fees charged to participating firms to support public
22    education and ongoing regional and national coordination
23    with nonprofit organizations, public bodies, and others
24    engaged in the implementation of renewable energy
25    incentive programs or similar initiatives. This work may
26    include developing papers and reports, hosting regional

 

 

SB2896- 286 -LRB102 17909 JWD 25989 b

1    and national conferences, and other work deemed necessary
2    by the Agency to position the State of Illinois as a
3    national leader in renewable energy incentive program
4    development and administration.
5        The Agency and its consultant or consultants shall
6    monitor block activity, share program activity with
7    stakeholders and conduct quarterly regularly scheduled
8    meetings to discuss program activity and market
9    conditions. If necessary, the Agency may make prospective
10    administrative adjustments to the Adjustable Block program
11    design, such as redistributing available funds or making
12    adjustments to purchase prices as necessary to achieve the
13    goals of this subsection (c). Program modifications to any
14    block price, capacity block, or other program element that
15    do not deviate from the Commission's approved value by
16    more than 10% 25% shall take effect immediately and are
17    not subject to Commission review and approval. Program
18    modifications to any block price, capacity block, or other
19    program element that deviate more than 10% 25% from the
20    Commission's approved value must be approved by the
21    Commission as a long-term plan amendment under Section
22    16-111.5 of the Public Utilities Act. The Agency shall
23    consider stakeholder feedback when making adjustments to
24    the Adjustable Block design and shall notify stakeholders
25    in advance of any planned changes.
26        The Agency and its program administrator shall,

 

 

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1    consistent with the requirements of this subsection (c),
2    propose the Adjustable Block Program terms, conditions,
3    and requirements, including the prices to be paid for
4    renewable energy credits, where applicable, and
5    requirements applicable to participating entities and
6    project applications, through the development, review, and
7    approval of the Agency's long-term renewable resources
8    procurement plan described in subsection (c) of Section
9    1-75 of this Act and paragraph (5) of subsection (b) of
10    Section 16-111.5 of the Public Utilities Act. Revisions to
11    program terms, conditions, and requirements may be made by
12    the Agency between long-term renewable resource
13    procurement plan approval proceedings if accompanied by a
14    stakeholder review and comment process.
15        (N) The long-term renewable resources procurement plan
16    required by this subsection (c) shall include a community
17    renewable generation program. The Agency shall establish
18    the terms, conditions, and program requirements for
19    photovoltaic community renewable generation projects with
20    a goal to expand renewable energy generating facility
21    access to a broader group of energy consumers, to ensure
22    robust participation opportunities for residential and
23    small commercial customers and those who cannot install
24    renewable energy on their own properties. Subject to
25    reasonable limitations, any Any plan approved by the
26    Commission shall allow subscriptions to community

 

 

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1    renewable generation projects to be portable and
2    transferable. For purposes of this subparagraph (N),
3    "portable" means that subscriptions may be retained by the
4    subscriber even if the subscriber relocates or changes its
5    address within the same utility service territory; and
6    "transferable" means that a subscriber may assign or sell
7    subscriptions to another person within the same utility
8    service territory.
9        Through the development of its long-term renewable
10    resources procurement plan, the Agency may consider
11    whether community renewable generation projects utilizing
12    technologies other than photovoltaics should be supported
13    through State-administered incentive funding, and may
14    issue requests for information to gauge market demand.
15        Electric utilities shall provide a monetary credit to
16    a subscriber's subsequent bill for service for the
17    proportional output of a community renewable generation
18    project attributable to that subscriber as specified in
19    Section 16-107.5 of the Public Utilities Act.
20        The Agency shall purchase renewable energy credits
21    from subscribed shares of photovoltaic community renewable
22    generation projects through the Adjustable Block program
23    described in subparagraph (K) of this paragraph (1) or
24    through the Illinois Solar for All Program described in
25    Section 1-56 of this Act. The project shall be deemed to be
26    fully subscribed and the contracting utility shall

 

 

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1    purchase all of the renewable energy credits from a
2    photovoltaic community renewable generation project as
3    long as a minimum of 90% of the project is subscribed. The
4    electric utility shall purchase any unsubscribed energy
5    from community renewable generation projects that are
6    Qualifying Facilities ("QF") under the electric utility's
7    tariff for purchasing the output from QFs under Public
8    Utilities Regulatory Policies Act of 1978.
9        The owners of and any subscribers to a community
10    renewable generation project shall not be considered
11    public utilities or alternative retail electricity
12    suppliers under the Public Utilities Act solely as a
13    result of their interest in or subscription to a community
14    renewable generation project and shall not be required to
15    become an alternative retail electric supplier by
16    participating in a community renewable generation project
17    with a public utility.
18        (O) For the delivery year beginning June 1, 2018, the
19    long-term renewable resources procurement plan required by
20    this subsection (c) shall provide for the Agency to
21    procure contracts to continue offering the Illinois Solar
22    for All Program described in subsection (b) of Section
23    1-56 of this Act, and the contracts approved by the
24    Commission shall be executed by the utilities that are
25    subject to this subsection (c). The long-term renewable
26    resources procurement plan shall allocate $50,000,000 per

 

 

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1    delivery year 5% of the funds available under the plan for
2    the applicable delivery year, or $10,000,000 per delivery
3    year, whichever is greater, to fund the programs, and the
4    plan shall determine the amount of funding to be
5    apportioned to the programs identified in subsection (b)
6    of Section 1-56 of this Act; provided that for the
7    delivery years beginning June 1, 2017, June 1, 2021, and
8    June 1, 2024 2025, June 1, 2027, and June 1, 2030, an
9    additional $30,000,000 the long-term renewable resources
10    procurement plan shall allocate 10% of the funds available
11    under the plan for the applicable delivery year, or
12    $20,000,000 per delivery year, whichever is greater, and
13    $10,000,000 of such funds in such year shall be provided
14    to the Department of Commerce and Economic Opportunity to
15    implement the workforce development programs and reporting
16    as outlined in used by an electric utility that serves
17    more than 3,000,000 retail customers in the State to
18    implement a Commission-approved plan under Section
19    16-108.12 of the Public Utilities Act. Funds allocated
20    under this subparagraph (O) shall not be included as part
21    of the limitations described in subparagraph (E) of this
22    subsection (c). The utilities shall be entitled to recover
23    the total cost associated with procuring renewable energy
24    credits detailed in this subparagraph (O) regardless of
25    whether the costs are subject to the limitations described
26    in subparagraph (E) of this subsection (c) through the

 

 

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1    automatic adjustment clause tariff under subsection (k) of
2    Section 16-108 of the Public Utilities Act. In making the
3    determinations required under this subparagraph (O), the
4    Commission shall consider the experience and performance
5    under the programs and any evaluation reports. The
6    Commission shall also provide for an independent
7    evaluation of those programs on a periodic basis that are
8    funded under this subparagraph (O).
9        (P) All programs and procurements under this
10    subsection (c) shall be designed to encourage
11    participating projects to use a diverse and equitable
12    workforce and a diverse set of contractors, including
13    minority-owned businesses, disadvantaged businesses,
14    trade unions, graduates of any workforce training programs
15    administered under this statute, and small businesses. As
16    part of its Long-Term Renewable Resources Procurement
17    Plan, the Agency shall create baseline labor standards for
18    firms participating in programs and procurements under
19    this subsection (c), including but not limited to project
20    labor agreements as required by Section 1-135.
21    Additionally, where applicable, the Agency shall
22    incorporate an equity points scoring system into its
23    project participation and selection processes conducted
24    under this subsection (c), as required by Section 1-145.
25    Participants determined to fail to meet those baseline
26    standards may be at risk of termination of renewable

 

 

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1    energy credit delivery contracts or restrictions on
2    participation in any future programs and competitive
3    procurements conducted under this subsection or under
4    subsection (b) of Section 1-56 of this Act.
5        (2) (Blank).
6        (3) (Blank).
7        (4) The counterparty electric utility shall retire all
8    renewable energy credits used to comply with the standard.
9        (5) Beginning with the 2010 delivery year and ending
10    June 1, 2017, an electric utility subject to this
11    subsection (c) shall apply the lesser of the maximum
12    alternative compliance payment rate or the most recent
13    estimated alternative compliance payment rate for its
14    service territory for the corresponding compliance period,
15    established pursuant to subsection (d) of Section 16-115D
16    of the Public Utilities Act to its retail customers that
17    take service pursuant to the electric utility's hourly
18    pricing tariff or tariffs. The electric utility shall
19    retain all amounts collected as a result of the
20    application of the alternative compliance payment rate or
21    rates to such customers, and, beginning in 2011, the
22    utility shall include in the information provided under
23    item (1) of subsection (d) of Section 16-111.5 of the
24    Public Utilities Act the amounts collected under the
25    alternative compliance payment rate or rates for the prior
26    year ending May 31. Notwithstanding any limitation on the

 

 

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1    procurement of renewable energy resources imposed by item
2    (2) of this subsection (c), the Agency shall increase its
3    spending on the purchase of renewable energy resources to
4    be procured by the electric utility for the next plan year
5    by an amount equal to the amounts collected by the utility
6    under the alternative compliance payment rate or rates in
7    the prior year ending May 31.
8        (6) The electric utility shall be entitled to recover
9    all of its costs associated with the procurement of
10    renewable energy credits under plans approved under this
11    Section and Section 16-111.5 of the Public Utilities Act.
12    These costs shall include associated reasonable expenses
13    for implementing the procurement programs, including, but
14    not limited to, the costs of administering and evaluating
15    the Adjustable Block program, through an automatic
16    adjustment clause tariff in accordance with subsection (k)
17    of Section 16-108 of the Public Utilities Act. The
18    administrative costs associated with implementing
19    procurement programs, including, but not limited to, the
20    costs of administering and evaluating the Adjustable Block
21    program shall not be included as part of the limitations
22    described in subparagraph (E) of this subsection (c).
23        (7) Renewable energy credits procured from new
24    photovoltaic projects or new distributed renewable energy
25    generation devices under this Section after June 1, 2017
26    (the effective date of Public Act 99-906) must be procured

 

 

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1    from devices installed by a qualified person in compliance
2    with the requirements of Section 16-128A of the Public
3    Utilities Act and any rules or regulations adopted
4    thereunder.
5        In meeting the renewable energy requirements of this
6    subsection (c), to the extent feasible and consistent with
7    State and federal law, the renewable energy credit
8    procurements, Adjustable Block solar program, and
9    community renewable generation program shall provide
10    employment opportunities for all segments of the
11    population and workforce, including minority-owned and
12    female-owned business enterprises, and shall not,
13    consistent with State and federal law, discriminate based
14    on race or socioeconomic status.
15        (8) For the purposes of this Section, "install" means
16    to complete the electrical wiring and connections
17    necessary to interconnect the distributed generation
18    facility with the electric utility's distribution system
19    at the point of interconnection between the facility and
20    the utility. "Install" does not include:
21            (i) electrical wiring and connections to
22        interconnect the distributed generation facility
23        performed by utility workers on the electric utility's
24        distribution system;
25            (ii) electrical wiring and connections internal to
26        the distributed generation facility performed by the

 

 

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1        manufacturer; or
2            (iii) tasks not associated with the electrical
3        interconnection of the distributed generation facility
4        and the utility, including those relating to planning
5        and project management performed by individuals such
6        as an inspector, management planner, consultant,
7        project designer, contractor or supervisor for the
8        project.
9    (d) Clean coal portfolio standard.
10        (1) The procurement plans shall include electricity
11    generated using clean coal. Each utility shall enter into
12    one or more sourcing agreements with the initial clean
13    coal facility, as provided in paragraph (3) of this
14    subsection (d), covering electricity generated by the
15    initial clean coal facility representing at least 5% of
16    each utility's total supply to serve the load of eligible
17    retail customers in 2015 and each year thereafter, as
18    described in paragraph (3) of this subsection (d), subject
19    to the limits specified in paragraph (2) of this
20    subsection (d). It is the goal of the State that by January
21    1, 2025, 25% of the electricity used in the State shall be
22    generated by cost-effective clean coal facilities. For
23    purposes of this subsection (d), "cost-effective" means
24    that the expenditures pursuant to such sourcing agreements
25    do not cause the limit stated in paragraph (2) of this
26    subsection (d) to be exceeded and do not exceed cost-based

 

 

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1    benchmarks, which shall be developed to assess all
2    expenditures pursuant to such sourcing agreements covering
3    electricity generated by clean coal facilities, other than
4    the initial clean coal facility, by the procurement
5    administrator, in consultation with the Commission staff,
6    Agency staff, and the procurement monitor and shall be
7    subject to Commission review and approval.
8        A utility party to a sourcing agreement shall
9    immediately retire any emission credits that it receives
10    in connection with the electricity covered by such
11    agreement.
12        Utilities shall maintain adequate records documenting
13    the purchases under the sourcing agreement to comply with
14    this subsection (d) and shall file an accounting with the
15    load forecast that must be filed with the Agency by July 15
16    of each year, in accordance with subsection (d) of Section
17    16-111.5 of the Public Utilities Act.
18        A utility shall be deemed to have complied with the
19    clean coal portfolio standard specified in this subsection
20    (d) if the utility enters into a sourcing agreement as
21    required by this subsection (d).
22        (2) For purposes of this subsection (d), the required
23    execution of sourcing agreements with the initial clean
24    coal facility for a particular year shall be measured as a
25    percentage of the actual amount of electricity
26    (megawatt-hours) supplied by the electric utility to

 

 

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1    eligible retail customers in the planning year ending
2    immediately prior to the agreement's execution. For
3    purposes of this subsection (d), the amount paid per
4    kilowatthour means the total amount paid for electric
5    service expressed on a per kilowatthour basis. For
6    purposes of this subsection (d), the total amount paid for
7    electric service includes without limitation amounts paid
8    for supply, transmission, distribution, surcharges and
9    add-on taxes.
10        Notwithstanding the requirements of this subsection
11    (d), the total amount paid under sourcing agreements with
12    clean coal facilities pursuant to the procurement plan for
13    any given year shall be reduced by an amount necessary to
14    limit the annual estimated average net increase due to the
15    costs of these resources included in the amounts paid by
16    eligible retail customers in connection with electric
17    service to:
18            (A) in 2010, no more than 0.5% of the amount paid
19        per kilowatthour by those customers during the year
20        ending May 31, 2009;
21            (B) in 2011, the greater of an additional 0.5% of
22        the amount paid per kilowatthour by those customers
23        during the year ending May 31, 2010 or 1% of the amount
24        paid per kilowatthour by those customers during the
25        year ending May 31, 2009;
26            (C) in 2012, the greater of an additional 0.5% of

 

 

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1        the amount paid per kilowatthour by those customers
2        during the year ending May 31, 2011 or 1.5% of the
3        amount paid per kilowatthour by those customers during
4        the year ending May 31, 2009;
5            (D) in 2013, the greater of an additional 0.5% of
6        the amount paid per kilowatthour by those customers
7        during the year ending May 31, 2012 or 2% of the amount
8        paid per kilowatthour by those customers during the
9        year ending May 31, 2009; and
10            (E) thereafter, the total amount paid under
11        sourcing agreements with clean coal facilities
12        pursuant to the procurement plan for any single year
13        shall be reduced by an amount necessary to limit the
14        estimated average net increase due to the cost of
15        these resources included in the amounts paid by
16        eligible retail customers in connection with electric
17        service to no more than the greater of (i) 2.015% of
18        the amount paid per kilowatthour by those customers
19        during the year ending May 31, 2009 or (ii) the
20        incremental amount per kilowatthour paid for these
21        resources in 2013. These requirements may be altered
22        only as provided by statute.
23        No later than June 30, 2015, the Commission shall
24    review the limitation on the total amount paid under
25    sourcing agreements, if any, with clean coal facilities
26    pursuant to this subsection (d) and report to the General

 

 

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1    Assembly its findings as to whether that limitation unduly
2    constrains the amount of electricity generated by
3    cost-effective clean coal facilities that is covered by
4    sourcing agreements.
5        (3) Initial clean coal facility. In order to promote
6    development of clean coal facilities in Illinois, each
7    electric utility subject to this Section shall execute a
8    sourcing agreement to source electricity from a proposed
9    clean coal facility in Illinois (the "initial clean coal
10    facility") that will have a nameplate capacity of at least
11    500 MW when commercial operation commences, that has a
12    final Clean Air Act permit on June 1, 2009 (the effective
13    date of Public Act 95-1027), and that will meet the
14    definition of clean coal facility in Section 1-10 of this
15    Act when commercial operation commences. The sourcing
16    agreements with this initial clean coal facility shall be
17    subject to both approval of the initial clean coal
18    facility by the General Assembly and satisfaction of the
19    requirements of paragraph (4) of this subsection (d) and
20    shall be executed within 90 days after any such approval
21    by the General Assembly. The Agency and the Commission
22    shall have authority to inspect all books and records
23    associated with the initial clean coal facility during the
24    term of such a sourcing agreement. A utility's sourcing
25    agreement for electricity produced by the initial clean
26    coal facility shall include:

 

 

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1            (A) a formula contractual price (the "contract
2        price") approved pursuant to paragraph (4) of this
3        subsection (d), which shall:
4                (i) be determined using a cost of service
5            methodology employing either a level or deferred
6            capital recovery component, based on a capital
7            structure consisting of 45% equity and 55% debt,
8            and a return on equity as may be approved by the
9            Federal Energy Regulatory Commission, which in any
10            case may not exceed the lower of 11.5% or the rate
11            of return approved by the General Assembly
12            pursuant to paragraph (4) of this subsection (d);
13            and
14                (ii) provide that all miscellaneous net
15            revenue, including but not limited to net revenue
16            from the sale of emission allowances, if any,
17            substitute natural gas, if any, grants or other
18            support provided by the State of Illinois or the
19            United States Government, firm transmission
20            rights, if any, by-products produced by the
21            facility, energy or capacity derived from the
22            facility and not covered by a sourcing agreement
23            pursuant to paragraph (3) of this subsection (d)
24            or item (5) of subsection (d) of Section 16-115 of
25            the Public Utilities Act, whether generated from
26            the synthesis gas derived from coal, from SNG, or

 

 

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1            from natural gas, shall be credited against the
2            revenue requirement for this initial clean coal
3            facility;
4            (B) power purchase provisions, which shall:
5                (i) provide that the utility party to such
6            sourcing agreement shall pay the contract price
7            for electricity delivered under such sourcing
8            agreement;
9                (ii) require delivery of electricity to the
10            regional transmission organization market of the
11            utility that is party to such sourcing agreement;
12                (iii) require the utility party to such
13            sourcing agreement to buy from the initial clean
14            coal facility in each hour an amount of energy
15            equal to all clean coal energy made available from
16            the initial clean coal facility during such hour
17            times a fraction, the numerator of which is such
18            utility's retail market sales of electricity
19            (expressed in kilowatthours sold) in the State
20            during the prior calendar month and the
21            denominator of which is the total retail market
22            sales of electricity (expressed in kilowatthours
23            sold) in the State by utilities during such prior
24            month and the sales of electricity (expressed in
25            kilowatthours sold) in the State by alternative
26            retail electric suppliers during such prior month

 

 

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1            that are subject to the requirements of this
2            subsection (d) and paragraph (5) of subsection (d)
3            of Section 16-115 of the Public Utilities Act,
4            provided that the amount purchased by the utility
5            in any year will be limited by paragraph (2) of
6            this subsection (d); and
7                (iv) be considered pre-existing contracts in
8            such utility's procurement plans for eligible
9            retail customers;
10            (C) contract for differences provisions, which
11        shall:
12                (i) require the utility party to such sourcing
13            agreement to contract with the initial clean coal
14            facility in each hour with respect to an amount of
15            energy equal to all clean coal energy made
16            available from the initial clean coal facility
17            during such hour times a fraction, the numerator
18            of which is such utility's retail market sales of
19            electricity (expressed in kilowatthours sold) in
20            the utility's service territory in the State
21            during the prior calendar month and the
22            denominator of which is the total retail market
23            sales of electricity (expressed in kilowatthours
24            sold) in the State by utilities during such prior
25            month and the sales of electricity (expressed in
26            kilowatthours sold) in the State by alternative

 

 

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1            retail electric suppliers during such prior month
2            that are subject to the requirements of this
3            subsection (d) and paragraph (5) of subsection (d)
4            of Section 16-115 of the Public Utilities Act,
5            provided that the amount paid by the utility in
6            any year will be limited by paragraph (2) of this
7            subsection (d);
8                (ii) provide that the utility's payment
9            obligation in respect of the quantity of
10            electricity determined pursuant to the preceding
11            clause (i) shall be limited to an amount equal to
12            (1) the difference between the contract price
13            determined pursuant to subparagraph (A) of
14            paragraph (3) of this subsection (d) and the
15            day-ahead price for electricity delivered to the
16            regional transmission organization market of the
17            utility that is party to such sourcing agreement
18            (or any successor delivery point at which such
19            utility's supply obligations are financially
20            settled on an hourly basis) (the "reference
21            price") on the day preceding the day on which the
22            electricity is delivered to the initial clean coal
23            facility busbar, multiplied by (2) the quantity of
24            electricity determined pursuant to the preceding
25            clause (i); and
26                (iii) not require the utility to take physical

 

 

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1            delivery of the electricity produced by the
2            facility;
3            (D) general provisions, which shall:
4                (i) specify a term of no more than 30 years,
5            commencing on the commercial operation date of the
6            facility;
7                (ii) provide that utilities shall maintain
8            adequate records documenting purchases under the
9            sourcing agreements entered into to comply with
10            this subsection (d) and shall file an accounting
11            with the load forecast that must be filed with the
12            Agency by July 15 of each year, in accordance with
13            subsection (d) of Section 16-111.5 of the Public
14            Utilities Act;
15                (iii) provide that all costs associated with
16            the initial clean coal facility will be
17            periodically reported to the Federal Energy
18            Regulatory Commission and to purchasers in
19            accordance with applicable laws governing
20            cost-based wholesale power contracts;
21                (iv) permit the Illinois Power Agency to
22            assume ownership of the initial clean coal
23            facility, without monetary consideration and
24            otherwise on reasonable terms acceptable to the
25            Agency, if the Agency so requests no less than 3
26            years prior to the end of the stated contract

 

 

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1            term;
2                (v) require the owner of the initial clean
3            coal facility to provide documentation to the
4            Commission each year, starting in the facility's
5            first year of commercial operation, accurately
6            reporting the quantity of carbon emissions from
7            the facility that have been captured and
8            sequestered and report any quantities of carbon
9            released from the site or sites at which carbon
10            emissions were sequestered in prior years, based
11            on continuous monitoring of such sites. If, in any
12            year after the first year of commercial operation,
13            the owner of the facility fails to demonstrate
14            that the initial clean coal facility captured and
15            sequestered at least 50% of the total carbon
16            emissions that the facility would otherwise emit
17            or that sequestration of emissions from prior
18            years has failed, resulting in the release of
19            carbon dioxide into the atmosphere, the owner of
20            the facility must offset excess emissions. Any
21            such carbon offsets must be permanent, additional,
22            verifiable, real, located within the State of
23            Illinois, and legally and practicably enforceable.
24            The cost of such offsets for the facility that are
25            not recoverable shall not exceed $15 million in
26            any given year. No costs of any such purchases of

 

 

SB2896- 306 -LRB102 17909 JWD 25989 b

1            carbon offsets may be recovered from a utility or
2            its customers. All carbon offsets purchased for
3            this purpose and any carbon emission credits
4            associated with sequestration of carbon from the
5            facility must be permanently retired. The initial
6            clean coal facility shall not forfeit its
7            designation as a clean coal facility if the
8            facility fails to fully comply with the applicable
9            carbon sequestration requirements in any given
10            year, provided the requisite offsets are
11            purchased. However, the Attorney General, on
12            behalf of the People of the State of Illinois, may
13            specifically enforce the facility's sequestration
14            requirement and the other terms of this contract
15            provision. Compliance with the sequestration
16            requirements and offset purchase requirements
17            specified in paragraph (3) of this subsection (d)
18            shall be reviewed annually by an independent
19            expert retained by the owner of the initial clean
20            coal facility, with the advance written approval
21            of the Attorney General. The Commission may, in
22            the course of the review specified in item (vii),
23            reduce the allowable return on equity for the
24            facility if the facility willfully fails to comply
25            with the carbon capture and sequestration
26            requirements set forth in this item (v);

 

 

SB2896- 307 -LRB102 17909 JWD 25989 b

1                (vi) include limits on, and accordingly
2            provide for modification of, the amount the
3            utility is required to source under the sourcing
4            agreement consistent with paragraph (2) of this
5            subsection (d);
6                (vii) require Commission review: (1) to
7            determine the justness, reasonableness, and
8            prudence of the inputs to the formula referenced
9            in subparagraphs (A)(i) through (A)(iii) of
10            paragraph (3) of this subsection (d), prior to an
11            adjustment in those inputs including, without
12            limitation, the capital structure and return on
13            equity, fuel costs, and other operations and
14            maintenance costs and (2) to approve the costs to
15            be passed through to customers under the sourcing
16            agreement by which the utility satisfies its
17            statutory obligations. Commission review shall
18            occur no less than every 3 years, regardless of
19            whether any adjustments have been proposed, and
20            shall be completed within 9 months;
21                (viii) limit the utility's obligation to such
22            amount as the utility is allowed to recover
23            through tariffs filed with the Commission,
24            provided that neither the clean coal facility nor
25            the utility waives any right to assert federal
26            pre-emption or any other argument in response to a

 

 

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1            purported disallowance of recovery costs;
2                (ix) limit the utility's or alternative retail
3            electric supplier's obligation to incur any
4            liability until such time as the facility is in
5            commercial operation and generating power and
6            energy and such power and energy is being
7            delivered to the facility busbar;
8                (x) provide that the owner or owners of the
9            initial clean coal facility, which is the
10            counterparty to such sourcing agreement, shall
11            have the right from time to time to elect whether
12            the obligations of the utility party thereto shall
13            be governed by the power purchase provisions or
14            the contract for differences provisions;
15                (xi) append documentation showing that the
16            formula rate and contract, insofar as they relate
17            to the power purchase provisions, have been
18            approved by the Federal Energy Regulatory
19            Commission pursuant to Section 205 of the Federal
20            Power Act;
21                (xii) provide that any changes to the terms of
22            the contract, insofar as such changes relate to
23            the power purchase provisions, are subject to
24            review under the public interest standard applied
25            by the Federal Energy Regulatory Commission
26            pursuant to Sections 205 and 206 of the Federal

 

 

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1            Power Act; and
2                (xiii) conform with customary lender
3            requirements in power purchase agreements used as
4            the basis for financing non-utility generators.
5        (4) Effective date of sourcing agreements with the
6    initial clean coal facility. Any proposed sourcing
7    agreement with the initial clean coal facility shall not
8    become effective unless the following reports are prepared
9    and submitted and authorizations and approvals obtained:
10            (i) Facility cost report. The owner of the initial
11        clean coal facility shall submit to the Commission,
12        the Agency, and the General Assembly a front-end
13        engineering and design study, a facility cost report,
14        method of financing (including but not limited to
15        structure and associated costs), and an operating and
16        maintenance cost quote for the facility (collectively
17        "facility cost report"), which shall be prepared in
18        accordance with the requirements of this paragraph (4)
19        of subsection (d) of this Section, and shall provide
20        the Commission and the Agency access to the work
21        papers, relied upon documents, and any other backup
22        documentation related to the facility cost report.
23            (ii) Commission report. Within 6 months following
24        receipt of the facility cost report, the Commission,
25        in consultation with the Agency, shall submit a report
26        to the General Assembly setting forth its analysis of

 

 

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1        the facility cost report. Such report shall include,
2        but not be limited to, a comparison of the costs
3        associated with electricity generated by the initial
4        clean coal facility to the costs associated with
5        electricity generated by other types of generation
6        facilities, an analysis of the rate impacts on
7        residential and small business customers over the life
8        of the sourcing agreements, and an analysis of the
9        likelihood that the initial clean coal facility will
10        commence commercial operation by and be delivering
11        power to the facility's busbar by 2016. To assist in
12        the preparation of its report, the Commission, in
13        consultation with the Agency, may hire one or more
14        experts or consultants, the costs of which shall be
15        paid for by the owner of the initial clean coal
16        facility. The Commission and Agency may begin the
17        process of selecting such experts or consultants prior
18        to receipt of the facility cost report.
19            (iii) General Assembly approval. The proposed
20        sourcing agreements shall not take effect unless,
21        based on the facility cost report and the Commission's
22        report, the General Assembly enacts authorizing
23        legislation approving (A) the projected price, stated
24        in cents per kilowatthour, to be charged for
25        electricity generated by the initial clean coal
26        facility, (B) the projected impact on residential and

 

 

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1        small business customers' bills over the life of the
2        sourcing agreements, and (C) the maximum allowable
3        return on equity for the project; and
4            (iv) Commission review. If the General Assembly
5        enacts authorizing legislation pursuant to
6        subparagraph (iii) approving a sourcing agreement, the
7        Commission shall, within 90 days of such enactment,
8        complete a review of such sourcing agreement. During
9        such time period, the Commission shall implement any
10        directive of the General Assembly, resolve any
11        disputes between the parties to the sourcing agreement
12        concerning the terms of such agreement, approve the
13        form of such agreement, and issue an order finding
14        that the sourcing agreement is prudent and reasonable.
15        The facility cost report shall be prepared as follows:
16            (A) The facility cost report shall be prepared by
17        duly licensed engineering and construction firms
18        detailing the estimated capital costs payable to one
19        or more contractors or suppliers for the engineering,
20        procurement and construction of the components
21        comprising the initial clean coal facility and the
22        estimated costs of operation and maintenance of the
23        facility. The facility cost report shall include:
24                (i) an estimate of the capital cost of the
25            core plant based on one or more front end
26            engineering and design studies for the

 

 

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1            gasification island and related facilities. The
2            core plant shall include all civil, structural,
3            mechanical, electrical, control, and safety
4            systems.
5                (ii) an estimate of the capital cost of the
6            balance of the plant, including any capital costs
7            associated with sequestration of carbon dioxide
8            emissions and all interconnects and interfaces
9            required to operate the facility, such as
10            transmission of electricity, construction or
11            backfeed power supply, pipelines to transport
12            substitute natural gas or carbon dioxide, potable
13            water supply, natural gas supply, water supply,
14            water discharge, landfill, access roads, and coal
15            delivery.
16            The quoted construction costs shall be expressed
17        in nominal dollars as of the date that the quote is
18        prepared and shall include capitalized financing costs
19        during construction, taxes, insurance, and other
20        owner's costs, and an assumed escalation in materials
21        and labor beyond the date as of which the construction
22        cost quote is expressed.
23            (B) The front end engineering and design study for
24        the gasification island and the cost study for the
25        balance of plant shall include sufficient design work
26        to permit quantification of major categories of

 

 

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1        materials, commodities and labor hours, and receipt of
2        quotes from vendors of major equipment required to
3        construct and operate the clean coal facility.
4            (C) The facility cost report shall also include an
5        operating and maintenance cost quote that will provide
6        the estimated cost of delivered fuel, personnel,
7        maintenance contracts, chemicals, catalysts,
8        consumables, spares, and other fixed and variable
9        operations and maintenance costs. The delivered fuel
10        cost estimate will be provided by a recognized third
11        party expert or experts in the fuel and transportation
12        industries. The balance of the operating and
13        maintenance cost quote, excluding delivered fuel
14        costs, will be developed based on the inputs provided
15        by duly licensed engineering and construction firms
16        performing the construction cost quote, potential
17        vendors under long-term service agreements and plant
18        operating agreements, or recognized third party plant
19        operator or operators.
20            The operating and maintenance cost quote
21        (including the cost of the front end engineering and
22        design study) shall be expressed in nominal dollars as
23        of the date that the quote is prepared and shall
24        include taxes, insurance, and other owner's costs, and
25        an assumed escalation in materials and labor beyond
26        the date as of which the operating and maintenance

 

 

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1        cost quote is expressed.
2            (D) The facility cost report shall also include an
3        analysis of the initial clean coal facility's ability
4        to deliver power and energy into the applicable
5        regional transmission organization markets and an
6        analysis of the expected capacity factor for the
7        initial clean coal facility.
8            (E) Amounts paid to third parties unrelated to the
9        owner or owners of the initial clean coal facility to
10        prepare the core plant construction cost quote,
11        including the front end engineering and design study,
12        and the operating and maintenance cost quote will be
13        reimbursed through Coal Development Bonds.
14        (5) Re-powering and retrofitting coal-fired power
15    plants previously owned by Illinois utilities to qualify
16    as clean coal facilities. During the 2009 procurement
17    planning process and thereafter, the Agency and the
18    Commission shall consider sourcing agreements covering
19    electricity generated by power plants that were previously
20    owned by Illinois utilities and that have been or will be
21    converted into clean coal facilities, as defined by
22    Section 1-10 of this Act. Pursuant to such procurement
23    planning process, the owners of such facilities may
24    propose to the Agency sourcing agreements with utilities
25    and alternative retail electric suppliers required to
26    comply with subsection (d) of this Section and item (5) of

 

 

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1    subsection (d) of Section 16-115 of the Public Utilities
2    Act, covering electricity generated by such facilities. In
3    the case of sourcing agreements that are power purchase
4    agreements, the contract price for electricity sales shall
5    be established on a cost of service basis. In the case of
6    sourcing agreements that are contracts for differences,
7    the contract price from which the reference price is
8    subtracted shall be established on a cost of service
9    basis. The Agency and the Commission may approve any such
10    utility sourcing agreements that do not exceed cost-based
11    benchmarks developed by the procurement administrator, in
12    consultation with the Commission staff, Agency staff and
13    the procurement monitor, subject to Commission review and
14    approval. The Commission shall have authority to inspect
15    all books and records associated with these clean coal
16    facilities during the term of any such contract.
17        (6) Costs incurred under this subsection (d) or
18    pursuant to a contract entered into under this subsection
19    (d) shall be deemed prudently incurred and reasonable in
20    amount and the electric utility shall be entitled to full
21    cost recovery pursuant to the tariffs filed with the
22    Commission.
23    (d-5) Zero emission standard.
24        (1) Beginning with the delivery year commencing on
25    June 1, 2017, the Agency shall, for electric utilities
26    that serve at least 100,000 retail customers in this

 

 

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1    State, procure contracts with zero emission facilities
2    that are reasonably capable of generating cost-effective
3    zero emission credits in an amount approximately equal to
4    16% of the actual amount of electricity delivered by each
5    electric utility to retail customers in the State during
6    calendar year 2014. For an electric utility serving fewer
7    than 100,000 retail customers in this State that
8    requested, under Section 16-111.5 of the Public Utilities
9    Act, that the Agency procure power and energy for all or a
10    portion of the utility's Illinois load for the delivery
11    year commencing June 1, 2016, the Agency shall procure
12    contracts with zero emission facilities that are
13    reasonably capable of generating cost-effective zero
14    emission credits in an amount approximately equal to 16%
15    of the portion of power and energy to be procured by the
16    Agency for the utility. The duration of the contracts
17    procured under this subsection (d-5) shall be for a term
18    of 10 years ending May 31, 2027. The quantity of zero
19    emission credits to be procured under the contracts shall
20    be all of the zero emission credits generated by the zero
21    emission facility in each delivery year; however, if the
22    zero emission facility is owned by more than one entity,
23    then the quantity of zero emission credits to be procured
24    under the contracts shall be the amount of zero emission
25    credits that are generated from the portion of the zero
26    emission facility that is owned by the winning supplier.

 

 

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1        The 16% value identified in this paragraph (1) is the
2    average of the percentage targets in subparagraph (B) of
3    paragraph (1) of subsection (c) of this Section for the 5
4    delivery years beginning June 1, 2017.
5        The procurement process shall be subject to the
6    following provisions:
7            (A) Those zero emission facilities that intend to
8        participate in the procurement shall submit to the
9        Agency the following eligibility information for each
10        zero emission facility on or before the date
11        established by the Agency:
12                (i) the in-service date and remaining useful
13            life of the zero emission facility;
14                (ii) the amount of power generated annually
15            for each of the years 2005 through 2015, and the
16            projected zero emission credits to be generated
17            over the remaining useful life of the zero
18            emission facility, which shall be used to
19            determine the capability of each facility;
20                (iii) the annual zero emission facility cost
21            projections, expressed on a per megawatthour
22            basis, over the next 6 delivery years, which shall
23            include the following: operation and maintenance
24            expenses; fully allocated overhead costs, which
25            shall be allocated using the methodology developed
26            by the Institute for Nuclear Power Operations;

 

 

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1            fuel expenditures; non-fuel capital expenditures;
2            spent fuel expenditures; a return on working
3            capital; the cost of operational and market risks
4            that could be avoided by ceasing operation; and
5            any other costs necessary for continued
6            operations, provided that "necessary" means, for
7            purposes of this item (iii), that the costs could
8            reasonably be avoided only by ceasing operations
9            of the zero emission facility; and
10                (iv) a commitment to continue operating, for
11            the duration of the contract or contracts executed
12            under the procurement held under this subsection
13            (d-5), the zero emission facility that produces
14            the zero emission credits to be procured in the
15            procurement.
16            The information described in item (iii) of this
17        subparagraph (A) may be submitted on a confidential
18        basis and shall be treated and maintained by the
19        Agency, the procurement administrator, and the
20        Commission as confidential and proprietary and exempt
21        from disclosure under subparagraphs (a) and (g) of
22        paragraph (1) of Section 7 of the Freedom of
23        Information Act. The Office of Attorney General shall
24        have access to, and maintain the confidentiality of,
25        such information pursuant to Section 6.5 of the
26        Attorney General Act.

 

 

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1            (B) The price for each zero emission credit
2        procured under this subsection (d-5) for each delivery
3        year shall be in an amount that equals the Social Cost
4        of Carbon, expressed on a price per megawatthour
5        basis. However, to ensure that the procurement remains
6        affordable to retail customers in this State if
7        electricity prices increase, the price in an
8        applicable delivery year shall be reduced below the
9        Social Cost of Carbon by the amount ("Price
10        Adjustment") by which the market price index for the
11        applicable delivery year exceeds the baseline market
12        price index for the consecutive 12-month period ending
13        May 31, 2016. If the Price Adjustment is greater than
14        or equal to the Social Cost of Carbon in an applicable
15        delivery year, then no payments shall be due in that
16        delivery year. The components of this calculation are
17        defined as follows:
18                (i) Social Cost of Carbon: The Social Cost of
19            Carbon is $16.50 per megawatthour, which is based
20            on the U.S. Interagency Working Group on Social
21            Cost of Carbon's price in the August 2016
22            Technical Update using a 3% discount rate,
23            adjusted for inflation for each year of the
24            program. Beginning with the delivery year
25            commencing June 1, 2023, the price per
26            megawatthour shall increase by $1 per

 

 

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1            megawatthour, and continue to increase by an
2            additional $1 per megawatthour each delivery year
3            thereafter.
4                (ii) Baseline market price index: The baseline
5            market price index for the consecutive 12-month
6            period ending May 31, 2016 is $31.40 per
7            megawatthour, which is based on the sum of (aa)
8            the average day-ahead energy price across all
9            hours of such 12-month period at the PJM
10            Interconnection LLC Northern Illinois Hub, (bb)
11            50% multiplied by the Base Residual Auction, or
12            its successor, capacity price for the rest of the
13            RTO zone group determined by PJM Interconnection
14            LLC, divided by 24 hours per day, and (cc) 50%
15            multiplied by the Planning Resource Auction, or
16            its successor, capacity price for Zone 4
17            determined by the Midcontinent Independent System
18            Operator, Inc., divided by 24 hours per day.
19                (iii) Market price index: The market price
20            index for a delivery year shall be the sum of
21            projected energy prices and projected capacity
22            prices determined as follows:
23                    (aa) Projected energy prices: the
24                projected energy prices for the applicable
25                delivery year shall be calculated once for the
26                year using the forward market price for the

 

 

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1                PJM Interconnection, LLC Northern Illinois
2                Hub. The forward market price shall be
3                calculated as follows: the energy forward
4                prices for each month of the applicable
5                delivery year averaged for each trade date
6                during the calendar year immediately preceding
7                that delivery year to produce a single energy
8                forward price for the delivery year. The
9                forward market price calculation shall use
10                data published by the Intercontinental
11                Exchange, or its successor.
12                    (bb) Projected capacity prices:
13                        (I) For the delivery years commencing
14                    June 1, 2017, June 1, 2018, and June 1,
15                    2019, the projected capacity price shall
16                    be equal to the sum of (1) 50% multiplied
17                    by the Base Residual Auction, or its
18                    successor, price for the rest of the RTO
19                    zone group as determined by PJM
20                    Interconnection LLC, divided by 24 hours
21                    per day and, (2) 50% multiplied by the
22                    resource auction price determined in the
23                    resource auction administered by the
24                    Midcontinent Independent System Operator,
25                    Inc., in which the largest percentage of
26                    load cleared for Local Resource Zone 4,

 

 

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1                    divided by 24 hours per day, and where
2                    such price is determined by the
3                    Midcontinent Independent System Operator,
4                    Inc.
5                        (II) For the delivery year commencing
6                    June 1, 2020, and each year thereafter,
7                    the projected capacity price shall be
8                    equal to the sum of (1) 50% multiplied by
9                    the Base Residual Auction, or its
10                    successor, price for the ComEd zone as
11                    determined by PJM Interconnection LLC,
12                    divided by 24 hours per day, and (2) 50%
13                    multiplied by the resource auction price
14                    determined in the resource auction
15                    administered by the Midcontinent
16                    Independent System Operator, Inc., in
17                    which the largest percentage of load
18                    cleared for Local Resource Zone 4, divided
19                    by 24 hours per day, and where such price
20                    is determined by the Midcontinent
21                    Independent System Operator, Inc.
22            For purposes of this subsection (d-5):
23                "Rest of the RTO" and "ComEd Zone" shall have
24            the meaning ascribed to them by PJM
25            Interconnection, LLC.
26                "RTO" means regional transmission

 

 

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1            organization.
2            (C) No later than 45 days after June 1, 2017 (the
3        effective date of Public Act 99-906), the Agency shall
4        publish its proposed zero emission standard
5        procurement plan. The plan shall be consistent with
6        the provisions of this paragraph (1) and shall provide
7        that winning bids shall be selected based on public
8        interest criteria that include, but are not limited
9        to, minimizing carbon dioxide emissions that result
10        from electricity consumed in Illinois and minimizing
11        sulfur dioxide, nitrogen oxide, and particulate matter
12        emissions that adversely affect the citizens of this
13        State. In particular, the selection of winning bids
14        shall take into account the incremental environmental
15        benefits resulting from the procurement, such as any
16        existing environmental benefits that are preserved by
17        the procurements held under Public Act 99-906 and
18        would cease to exist if the procurements were not
19        held, including the preservation of zero emission
20        facilities. The plan shall also describe in detail how
21        each public interest factor shall be considered and
22        weighted in the bid selection process to ensure that
23        the public interest criteria are applied to the
24        procurement and given full effect.
25            For purposes of developing the plan, the Agency
26        shall consider any reports issued by a State agency,

 

 

SB2896- 324 -LRB102 17909 JWD 25989 b

1        board, or commission under House Resolution 1146 of
2        the 98th General Assembly and paragraph (4) of
3        subsection (d) of this Section, as well as publicly
4        available analyses and studies performed by or for
5        regional transmission organizations that serve the
6        State and their independent market monitors.
7            Upon publishing of the zero emission standard
8        procurement plan, copies of the plan shall be posted
9        and made publicly available on the Agency's website.
10        All interested parties shall have 10 days following
11        the date of posting to provide comment to the Agency on
12        the plan. All comments shall be posted to the Agency's
13        website. Following the end of the comment period, but
14        no more than 60 days later than June 1, 2017 (the
15        effective date of Public Act 99-906), the Agency shall
16        revise the plan as necessary based on the comments
17        received and file its zero emission standard
18        procurement plan with the Commission.
19            If the Commission determines that the plan will
20        result in the procurement of cost-effective zero
21        emission credits, then the Commission shall, after
22        notice and hearing, but no later than 45 days after the
23        Agency filed the plan, approve the plan or approve
24        with modification. For purposes of this subsection
25        (d-5), "cost effective" means the projected costs of
26        procuring zero emission credits from zero emission

 

 

SB2896- 325 -LRB102 17909 JWD 25989 b

1        facilities do not cause the limit stated in paragraph
2        (2) of this subsection to be exceeded.
3            (C-5) As part of the Commission's review and
4        acceptance or rejection of the procurement results,
5        the Commission shall, in its public notice of
6        successful bidders:
7                (i) identify how the winning bids satisfy the
8            public interest criteria described in subparagraph
9            (C) of this paragraph (1) of minimizing carbon
10            dioxide emissions that result from electricity
11            consumed in Illinois and minimizing sulfur
12            dioxide, nitrogen oxide, and particulate matter
13            emissions that adversely affect the citizens of
14            this State;
15                (ii) specifically address how the selection of
16            winning bids takes into account the incremental
17            environmental benefits resulting from the
18            procurement, including any existing environmental
19            benefits that are preserved by the procurements
20            held under Public Act 99-906 and would have ceased
21            to exist if the procurements had not been held,
22            such as the preservation of zero emission
23            facilities;
24                (iii) quantify the environmental benefit of
25            preserving the resources identified in item (ii)
26            of this subparagraph (C-5), including the

 

 

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1            following:
2                    (aa) the value of avoided greenhouse gas
3                emissions measured as the product of the zero
4                emission facilities' output over the contract
5                term multiplied by the U.S. Environmental
6                Protection Agency eGrid subregion carbon
7                dioxide emission rate and the U.S. Interagency
8                Working Group on Social Cost of Carbon's price
9                in the August 2016 Technical Update using a 3%
10                discount rate, adjusted for inflation for each
11                delivery year; and
12                    (bb) the costs of replacement with other
13                zero carbon dioxide resources, including wind
14                and photovoltaic, based upon the simple
15                average of the following:
16                        (I) the price, or if there is more
17                    than one price, the average of the prices,
18                    paid for renewable energy credits from new
19                    utility-scale wind projects in the
20                    procurement events specified in item (i)
21                    of subparagraph (G) of paragraph (1) of
22                    subsection (c) of this Section; and
23                        (II) the price, or if there is more
24                    than one price, the average of the prices,
25                    paid for renewable energy credits from new
26                    utility-scale solar projects and

 

 

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1                    brownfield site photovoltaic projects in
2                    the procurement events specified in item
3                    (ii) of subparagraph (G) of paragraph (1)
4                    of subsection (c) of this Section and,
5                    after January 1, 2015, renewable energy
6                    credits from photovoltaic distributed
7                    generation projects in procurement events
8                    held under subsection (c) of this Section.
9            Each utility shall enter into binding contractual
10        arrangements with the winning suppliers.
11            The procurement described in this subsection
12        (d-5), including, but not limited to, the execution of
13        all contracts procured, shall be completed no later
14        than May 10, 2017. Based on the effective date of
15        Public Act 99-906, the Agency and Commission may, as
16        appropriate, modify the various dates and timelines
17        under this subparagraph and subparagraphs (C) and (D)
18        of this paragraph (1). The procurement and plan
19        approval processes required by this subsection (d-5)
20        shall be conducted in conjunction with the procurement
21        and plan approval processes required by subsection (c)
22        of this Section and Section 16-111.5 of the Public
23        Utilities Act, to the extent practicable.
24        Notwithstanding whether a procurement event is
25        conducted under Section 16-111.5 of the Public
26        Utilities Act, the Agency shall immediately initiate a

 

 

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1        procurement process on June 1, 2017 (the effective
2        date of Public Act 99-906).
3            (D) Following the procurement event described in
4        this paragraph (1) and consistent with subparagraph
5        (B) of this paragraph (1), the Agency shall calculate
6        the payments to be made under each contract for the
7        next delivery year based on the market price index for
8        that delivery year. The Agency shall publish the
9        payment calculations no later than May 25, 2017 and
10        every May 25 thereafter.
11            (E) Notwithstanding the requirements of this
12        subsection (d-5), the contracts executed under this
13        subsection (d-5) shall provide that the zero emission
14        facility may, as applicable, suspend or terminate
15        performance under the contracts in the following
16        instances:
17                (i) A zero emission facility shall be excused
18            from its performance under the contract for any
19            cause beyond the control of the resource,
20            including, but not restricted to, acts of God,
21            flood, drought, earthquake, storm, fire,
22            lightning, epidemic, war, riot, civil disturbance
23            or disobedience, labor dispute, labor or material
24            shortage, sabotage, acts of public enemy,
25            explosions, orders, regulations or restrictions
26            imposed by governmental, military, or lawfully

 

 

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1            established civilian authorities, which, in any of
2            the foregoing cases, by exercise of commercially
3            reasonable efforts the zero emission facility
4            could not reasonably have been expected to avoid,
5            and which, by the exercise of commercially
6            reasonable efforts, it has been unable to
7            overcome. In such event, the zero emission
8            facility shall be excused from performance for the
9            duration of the event, including, but not limited
10            to, delivery of zero emission credits, and no
11            payment shall be due to the zero emission facility
12            during the duration of the event.
13                (ii) A zero emission facility shall be
14            permitted to terminate the contract if legislation
15            is enacted into law by the General Assembly that
16            imposes or authorizes a new tax, special
17            assessment, or fee on the generation of
18            electricity, the ownership or leasehold of a
19            generating unit, or the privilege or occupation of
20            such generation, ownership, or leasehold of
21            generation units by a zero emission facility.
22            However, the provisions of this item (ii) do not
23            apply to any generally applicable tax, special
24            assessment or fee, or requirements imposed by
25            federal law.
26                (iii) A zero emission facility shall be

 

 

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1            permitted to terminate the contract in the event
2            that the resource requires capital expenditures in
3            excess of $40,000,000 that were neither known nor
4            reasonably foreseeable at the time it executed the
5            contract and that a prudent owner or operator of
6            such resource would not undertake.
7                (iv) A zero emission facility shall be
8            permitted to terminate the contract in the event
9            the Nuclear Regulatory Commission terminates the
10            resource's license.
11            (F) If the zero emission facility elects to
12        terminate a contract under subparagraph (E) of this
13        paragraph (1), then the Commission shall reopen the
14        docket in which the Commission approved the zero
15        emission standard procurement plan under subparagraph
16        (C) of this paragraph (1) and, after notice and
17        hearing, enter an order acknowledging the contract
18        termination election if such termination is consistent
19        with the provisions of this subsection (d-5).
20        (2) For purposes of this subsection (d-5), the amount
21    paid per kilowatthour means the total amount paid for
22    electric service expressed on a per kilowatthour basis.
23    For purposes of this subsection (d-5), the total amount
24    paid for electric service includes, without limitation,
25    amounts paid for supply, transmission, distribution,
26    surcharges, and add-on taxes.

 

 

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1        Notwithstanding the requirements of this subsection
2    (d-5), the contracts executed under this subsection (d-5)
3    shall provide that the total of zero emission credits
4    procured under a procurement plan shall be subject to the
5    limitations of this paragraph (2). For each delivery year,
6    the contractual volume receiving payments in such year
7    shall be reduced for all retail customers based on the
8    amount necessary to limit the net increase that delivery
9    year to the costs of those credits included in the amounts
10    paid by eligible retail customers in connection with
11    electric service to no more than 1.65% of the amount paid
12    per kilowatthour by eligible retail customers during the
13    year ending May 31, 2009. The result of this computation
14    shall apply to and reduce the procurement for all retail
15    customers, and all those customers shall pay the same
16    single, uniform cents per kilowatthour charge under
17    subsection (k) of Section 16-108 of the Public Utilities
18    Act. To arrive at a maximum dollar amount of zero emission
19    credits to be paid for the particular delivery year, the
20    resulting per kilowatthour amount shall be applied to the
21    actual amount of kilowatthours of electricity delivered by
22    the electric utility in the delivery year immediately
23    prior to the procurement, to all retail customers in its
24    service territory. Unpaid contractual volume for any
25    delivery year shall be paid in any subsequent delivery
26    year in which such payments can be made without exceeding

 

 

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1    the amount specified in this paragraph (2). The
2    calculations required by this paragraph (2) shall be made
3    only once for each procurement plan year. Once the
4    determination as to the amount of zero emission credits to
5    be paid is made based on the calculations set forth in this
6    paragraph (2), no subsequent rate impact determinations
7    shall be made and no adjustments to those contract amounts
8    shall be allowed. All costs incurred under those contracts
9    and in implementing this subsection (d-5) shall be
10    recovered by the electric utility as provided in this
11    Section.
12        No later than June 30, 2019, the Commission shall
13    review the limitation on the amount of zero emission
14    credits procured under this subsection (d-5) and report to
15    the General Assembly its findings as to whether that
16    limitation unduly constrains the procurement of
17    cost-effective zero emission credits.
18        (3) Six years after the execution of a contract under
19    this subsection (d-5), the Agency shall determine whether
20    the actual zero emission credit payments received by the
21    supplier over the 6-year period exceed the Average ZEC
22    Payment. In addition, at the end of the term of a contract
23    executed under this subsection (d-5), or at the time, if
24    any, a zero emission facility's contract is terminated
25    under subparagraph (E) of paragraph (1) of this subsection
26    (d-5), then the Agency shall determine whether the actual

 

 

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1    zero emission credit payments received by the supplier
2    over the term of the contract exceed the Average ZEC
3    Payment, after taking into account any amounts previously
4    credited back to the utility under this paragraph (3). If
5    the Agency determines that the actual zero emission credit
6    payments received by the supplier over the relevant period
7    exceed the Average ZEC Payment, then the supplier shall
8    credit the difference back to the utility. The amount of
9    the credit shall be remitted to the applicable electric
10    utility no later than 120 days after the Agency's
11    determination, which the utility shall reflect as a credit
12    on its retail customer bills as soon as practicable;
13    however, the credit remitted to the utility shall not
14    exceed the total amount of payments received by the
15    facility under its contract.
16        For purposes of this Section, the Average ZEC Payment
17    shall be calculated by multiplying the quantity of zero
18    emission credits delivered under the contract times the
19    average contract price. The average contract price shall
20    be determined by subtracting the amount calculated under
21    subparagraph (B) of this paragraph (3) from the amount
22    calculated under subparagraph (A) of this paragraph (3),
23    as follows:
24            (A) The average of the Social Cost of Carbon, as
25        defined in subparagraph (B) of paragraph (1) of this
26        subsection (d-5), during the term of the contract.

 

 

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1            (B) The average of the market price indices, as
2        defined in subparagraph (B) of paragraph (1) of this
3        subsection (d-5), during the term of the contract,
4        minus the baseline market price index, as defined in
5        subparagraph (B) of paragraph (1) of this subsection
6        (d-5).
7        If the subtraction yields a negative number, then the
8    Average ZEC Payment shall be zero.
9        (4) Cost-effective zero emission credits procured from
10    zero emission facilities shall satisfy the applicable
11    definitions set forth in Section 1-10 of this Act.
12        (5) The electric utility shall retire all zero
13    emission credits used to comply with the requirements of
14    this subsection (d-5).
15        (6) Electric utilities shall be entitled to recover
16    all of the costs associated with the procurement of zero
17    emission credits through an automatic adjustment clause
18    tariff in accordance with subsection (k) and (m) of
19    Section 16-108 of the Public Utilities Act, and the
20    contracts executed under this subsection (d-5) shall
21    provide that the utilities' payment obligations under such
22    contracts shall be reduced if an adjustment is required
23    under subsection (m) of Section 16-108 of the Public
24    Utilities Act.
25        (7) This subsection (d-5) shall become inoperative on
26    January 1, 2028.

 

 

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1    (e) The draft procurement plans are subject to public
2comment, as required by Section 16-111.5 of the Public
3Utilities Act.
4    (f) The Agency shall submit the final procurement plan to
5the Commission. The Agency shall revise a procurement plan if
6the Commission determines that it does not meet the standards
7set forth in Section 16-111.5 of the Public Utilities Act.
8    (g) The Agency shall assess fees to each affected utility
9to recover the costs incurred in preparation of the annual
10procurement plan for the utility.
11    (h) The Agency shall assess fees to each bidder to recover
12the costs incurred in connection with a competitive
13procurement process.
14    (i) A renewable energy credit, carbon emission credit, or
15zero emission credit can only be used once to comply with a
16single portfolio or other standard as set forth in subsection
17(c), subsection (d), or subsection (d-5) of this Section,
18respectively. A renewable energy credit, carbon emission
19credit, or zero emission credit cannot be used to satisfy the
20requirements of more than one standard. If more than one type
21of credit is issued for the same megawatt hour of energy, only
22one credit can be used to satisfy the requirements of a single
23standard. After such use, the credit must be retired together
24with any other credits issued for the same megawatt hour of
25energy.
26(Source: P.A. 100-863, eff. 8-14-18; 101-81, eff. 7-12-19;

 

 

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1101-113, eff. 1-1-20.)
 
2    (20 ILCS 3855/1-92)
3    Sec. 1-92. Aggregation of electrical load by
4municipalities, townships, and counties.
5    (a) The corporate authorities of a municipality, township
6board, or county board of a county may adopt an ordinance under
7which it may aggregate in accordance with this Section
8residential and small commercial retail electrical loads
9located, respectively, within the municipality, the township,
10or the unincorporated areas of the county and, for that
11purpose, may solicit bids and enter into service agreements to
12facilitate for those loads the sale and purchase of
13electricity and related services and equipment.
14    The corporate authorities, township board, or county board
15may also exercise such authority jointly with any other
16municipality, township, or county. Two or more municipalities,
17townships, or counties, or a combination of both, may initiate
18a process jointly to authorize aggregation by a majority vote
19of each particular municipality, township, or county as
20required by this Section.
21    If the corporate authorities, township board, or the
22county board seek to operate the aggregation program as an
23opt-out program for residential and small commercial retail
24customers, then prior to the adoption of an ordinance with
25respect to aggregation of residential and small commercial

 

 

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1retail electric loads, the corporate authorities of a
2municipality, the township board, or the county board of a
3county shall submit a referendum to its residents to determine
4whether or not the aggregation program shall operate as an
5opt-out program for residential and small commercial retail
6customers. Any county board that seeks to submit such a
7referendum to its residents shall do so only in unincorporated
8areas of the county where no electric aggregation ordinance
9has been adopted.
10    In addition to the notice and conduct requirements of the
11general election law, notice of the referendum shall state
12briefly the purpose of the referendum. The question of whether
13the corporate authorities, the township board, or the county
14board shall adopt an opt-out aggregation program for
15residential and small commercial retail customers shall be
16submitted to the electors of the municipality, township board,
17or county board at a regular election and approved by a
18majority of the electors voting on the question. The corporate
19authorities, township board, or county board must certify to
20the proper election authority, which must submit the question
21at an election in accordance with the Election Code.
22    The election authority must submit the question in
23substantially the following form:
24        Shall the (municipality, township, or county in which
25    the question is being voted upon) have the authority to
26    arrange for the supply of electricity for its residential

 

 

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1    and small commercial retail customers who have not opted
2    out of such program?
3The election authority must record the votes as "Yes" or "No".
4    If a majority of the electors voting on the question vote
5in the affirmative, then the corporate authorities, township
6board, or county board may implement an opt-out aggregation
7program for residential and small commercial retail customers.
8    A referendum must pass in each particular municipality,
9township, or county that is engaged in the aggregation
10program. If the referendum fails, then the corporate
11authorities, township board, or county board shall operate the
12aggregation program as an opt-in program for residential and
13small commercial retail customers.
14    An ordinance under this Section shall specify whether the
15aggregation will occur only with the prior consent of each
16person owning, occupying, controlling, or using an electric
17load center proposed to be aggregated. Nothing in this
18Section, however, authorizes the aggregation of electric loads
19that are served or authorized to be served by an electric
20cooperative as defined by and pursuant to the Electric
21Supplier Act or loads served by a municipality that owns and
22operates its own electric distribution system. No aggregation
23shall take effect unless approved by a majority of the members
24of the corporate authority, township board, or county board
25voting upon the ordinance.
26    A governmental aggregator under this Section is not a

 

 

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1public utility or an alternative retail electric supplier.
2    For purposes of this Section, "township" means the portion
3of a township that is an unincorporated portion of a county
4that is not otherwise a part of a municipality. In addition to
5such other limitations as are included in this Section, a
6township board shall only have authority to aggregate
7residential and small commercial customer loads in accordance
8with this Section if the county board of the county in which
9the township is located (i) is not also submitting a
10referendum to its residents at the same general election that
11the township board proposes to submit a referendum under this
12subsection (a), (ii) has not received authorization through
13passage of a referendum to operate an opt-out aggregation
14program for residential and small commercial retail customers
15under this subsection (a), and (iii) has not otherwise enacted
16an ordinance under this subsection (a) authorizing the
17operation of an opt-in aggregation program for residential and
18small commercial retail customers as described in this
19Section.
20    (b) Upon the applicable requisite authority under this
21Section, the corporate authorities, the township board, or the
22county board, with assistance from the Illinois Power Agency,
23shall develop a plan of operation and governance for the
24aggregation program so authorized. Before adopting a plan
25under this Section, the corporate authorities, township board,
26or county board shall hold at least 2 public hearings on the

 

 

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1plan. Before the first hearing, the corporate authorities,
2township board, or county board shall publish notice of the
3hearings once a week for 2 consecutive weeks in a newspaper of
4general circulation in the jurisdiction. The notice shall
5summarize the plan and state the date, time, and location of
6each hearing. Any load aggregation plan established pursuant
7to this Section shall:
8        (1) provide for universal access to all applicable
9    residential customers and equitable treatment of
10    applicable residential customers;
11        (2) describe demand management and energy efficiency
12    services to be provided to each class of customers; and
13        (3) meet any requirements established by law
14    concerning aggregated service offered pursuant to this
15    Section.
16    (c) The process for soliciting bids for electricity and
17other related services and awarding proposed agreements for
18the purchase of electricity and other related services shall
19be conducted in the following order:
20        (1) The corporate authorities, township board, or
21    county board may solicit bids for electricity and other
22    related services. The bid specifications may include a
23    provision requiring the bidder to disclose the fuel type
24    of electricity to be procured or generated on behalf of
25    the aggregation program customers. The corporate
26    authorities, township board, or county board may consider

 

 

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1    the proposed source of electricity to be procured or
2    generated to be put into the grid on behalf of aggregation
3    program customers in the competitive bidding process. The
4    Agency and Commission may collaborate to issue joint
5    guidance on voluntary uniform standards for bidder
6    disclosures of the source of electricity to be procured or
7    generated to be put into the grid on behalf of aggregation
8    program customers.
9        (1.5) A township board shall request from the electric
10    utility those residential and small commercial customers
11    within their aggregate area either by zip code or zip
12    codes or other means as determined by the electric
13    utility. The electric utility shall then provide to the
14    township board the residential and small commercial
15    customers, including the names and addresses of
16    residential and small commercial customers,
17    electronically. The township board shall be responsible
18    for authenticating the residential and small commercial
19    customers contained in this listing and providing edits of
20    the data to affirm, add, or delete the residential and
21    small commercial customers located within its
22    jurisdiction. The township board shall provide the edited
23    list to the electric utility in an electronic format or
24    other means selected by the electric utility and certify
25    that the information is accurate.
26        (2) Notwithstanding Section 16-122 of the Public

 

 

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1    Utilities Act and Section 2HH of the Consumer Fraud and
2    Deceptive Business Practices Act, an electric utility that
3    provides residential and small commercial retail electric
4    service in the aggregate area must, upon request of the
5    corporate authorities, township board, or the county board
6    in the aggregate area, submit to the requesting party, in
7    an electronic format, those account numbers, names, and
8    addresses of residential and small commercial retail
9    customers in the aggregate area that are reflected in the
10    electric utility's records at the time of the request;
11    provided, however, that any township board has first
12    provided an accurate customer list to the electric utility
13    as provided for herein.
14    Any corporate authority, township board, or county board
15receiving customer information from an electric utility shall
16be subject to the limitations on the disclosure of the
17information described in Section 16-122 of the Public
18Utilities Act and Section 2HH of the Consumer Fraud and
19Deceptive Business Practices Act, and an electric utility
20shall not be held liable for any claims arising out of the
21provision of information pursuant to this item (2).
22    (d) If the corporate authorities, township board, or
23county board operate under an opt-in program for residential
24and small commercial retail customers, then the corporate
25authorities, township board, or county board shall comply with
26all of the following:

 

 

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1        (1) Within 60 days after receiving the bids, the
2    corporate authorities, township board, or county board
3    shall allow residential and small commercial retail
4    customers to commit to the terms and conditions of a bid
5    that has been selected by the corporate authorities,
6    township board, or county board.
7        (2) If (A) the corporate authorities, township board,
8    or county board award proposed agreements for the purchase
9    of electricity and other related services and (B) an
10    agreement is reached between the corporate authorities,
11    township board, or county board for those services, then
12    customers committed to the terms and conditions according
13    to item (1) of this subsection (d) shall be committed to
14    the agreement.
15    (e) If the corporate authorities, township board, or
16county board operate as an opt-out program for residential and
17small commercial retail customers, then it shall be the duty
18of the aggregated entity to fully inform residential and small
19commercial retail customers in advance that they have the
20right to opt out of the aggregation program. The disclosure
21shall prominently state all charges to be made and shall
22include full disclosure of the cost to obtain service pursuant
23to Section 16-103 of the Public Utilities Act, how to access
24it, and the fact that it is available to them without penalty,
25if they are currently receiving service under that Section.
26The Illinois Power Agency shall furnish, without charge, to

 

 

SB2896- 344 -LRB102 17909 JWD 25989 b

1any citizen a list of all supply options available to them in a
2format that allows comparison of prices and products.
3    (f) Any person or entity retained by a municipality or
4county, or jointly by more than one such unit of local
5government, to provide input, guidance, or advice in the
6selection of an electricity supplier for an aggregation
7program shall disclose in writing to the involved units of
8local government the nature of any relationship through which
9the person or entity may receive, either directly or
10indirectly, commissions or other remuneration as a result of
11the selection of any particular electricity supplier. The
12written disclosure must be made prior to formal approval by
13the involved units of local government of any professional
14services agreement with the person or entity, or no later than
15October 1, 2012 with respect to any such professional services
16agreement entered into prior to the effective date of this
17amendatory Act of the 97th General Assembly. The disclosure
18shall cover all direct and indirect relationships through
19which commissions or remuneration may result, including the
20pooling of commissions or remuneration among multiple persons
21or entities, and shall identify all involved electricity
22suppliers. The disclosure requirements in this subsection (f)
23are to be liberally construed to ensure that the nature of
24financial interests are fully revealed, and these disclosure
25requirements shall apply regardless of whether the involved
26person or entity is licensed under Section 16-115C of the

 

 

SB2896- 345 -LRB102 17909 JWD 25989 b

1Public Utilities Act. Any person or entity that fails to make
2the disclosure required under this subsection (f) is liable to
3the involved units of local government in an amount equal to
4all compensation paid to such person or entity by the units of
5local government for the input, guidance, or advice in the
6selection of an electricity supplier, plus reasonable
7attorneys fees and court costs incurred by the units of local
8government in connection with obtaining such amount.
9    (g) The Illinois Power Agency shall provide assistance to
10municipalities, townships, counties, or associations working
11with municipalities to help complete the plan and bidding
12process.
13    (h) This Section does not prohibit municipalities or
14counties from entering into an intergovernmental agreement to
15aggregate residential and small commercial retail electric
16loads.
17    (i) No later than December 31, 2022, the Illinois Power
18Agency shall produce a report assessing how aggregation of
19electrical load by municipalities, townships, and counties can
20be used to help meet the renewable energy goals outlined in
21this Act. This report shall contain, at minimum, an assessment
22of other states' utilization of load aggregation in meeting
23renewable energy goals, any known or expected barriers in
24utilizing load aggregation for meeting renewable energy goals,
25and recommendations for possible changes in State law
26necessary for electrical load aggregation to be a driver of

 

 

SB2896- 346 -LRB102 17909 JWD 25989 b

1new renewable energy project development. This report shall be
2published on the Agency's website and delivered to the
3Governor and General Assembly. To assist with developing this
4report, the Agency may retain the services of its expert
5consulting firm used to develop its procurement plans as
6outlined in Section 1-75(a)(1) of this Act.
7(Source: P.A. 97-338, eff. 8-12-11; 97-823, eff. 7-18-12;
897-1067, eff. 8-24-12; 98-404, eff. 1-1-14; 98-434, eff.
91-1-14; 98-463, eff. 8-16-13; 98-756, eff. 7-16-14.)
 
10    (20 ILCS 3855/1-125)
11    Sec. 1-125. Agency annual reports.
12    (a) By February 15 of each year, the Agency shall report
13annually to the Governor and the General Assembly on the
14operations and transactions of the Agency. The annual report
15shall include, but not be limited to, each of the following:
16        (1) The average quantity, price, and term of all
17    contracts for electricity procured under the procurement
18    plans for electric utilities.
19        (2) (Blank).
20        (3) The quantity, price, and rate impact of all energy
21    efficiency and demand response measures purchased for
22    electric utilities, and any measures included in the
23    procurement plan pursuant to Section 16-111.5B of the
24    Public Utilities Act.
25        (4) The amount of power and energy produced by each

 

 

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1    Agency facility.
2        (5) The quantity of electricity supplied by each
3    Agency facility to municipal electric systems,
4    governmental aggregators, or rural electric cooperatives
5    in Illinois.
6        (6) The revenues as allocated by the Agency to each
7    facility.
8        (7) The costs as allocated by the Agency to each
9    facility.
10        (8) The accumulated depreciation for each facility.
11        (9) The status of any projects under development.
12        (10) Basic financial and operating information
13    specifically detailed for the reporting year and
14    including, but not limited to, income and expense
15    statements, balance sheets, and changes in financial
16    position, all in accordance with generally accepted
17    accounting principles, debt structure, and a summary of
18    funds on a cash basis.
19        (11) The average quantity, price, contract type and
20    term, and rate impact of all renewable resources procured
21    purchased under the long-term renewable resources
22    electricity procurement plans for electric utilities.
23        (12) A comparison of the costs associated with the
24    Agency's procurement of renewable energy resources to (A)
25    the Agency's costs associated with electricity generated
26    by other types of generation facilities and (B) the

 

 

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1    benefits associated with the Agency's procurement of
2    renewable energy resources.
3        (13) An analysis of the rate impacts associated with
4    the Illinois Power Agency's procurement of renewable
5    resources, including, but not limited to, any long-term
6    contracts, on the eligible retail customers of electric
7    utilities. The analysis shall include the Agency's
8    estimate of the total dollar impact that the Agency's
9    procurement of renewable resources has had on the annual
10    electricity bills of the customer classes that comprise
11    each eligible retail customer class taking service from an
12    electric utility.
13        (14) (Blank). An analysis of how the operation of the
14    alternative compliance payment mechanism, any long-term
15    contracts, or other aspects of the applicable renewable
16    portfolio standards impacts the rates of customers of
17    alternative retail electric suppliers.
18    (b) In addition to reporting on the transactions and
19operations of the Agency, the Agency shall also endeavor to
20report on the following items through its annual report,
21recognizing that full and accurate information may not be
22available for certain items:
23        (1) The overall nameplate capacity amount of installed
24    and scheduled renewable energy generation capacity
25    physically located in Illinois.
26        (2) The percentage of installed and scheduled

 

 

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1    renewable energy generation capacity as a share of overall
2    electricity generation capacity physically located in
3    Illinois.
4        (3) The amount of megawatt hours produced by renewable
5    energy generation capacity physically located in Illinois
6    for the preceding delivery year.
7        (4) The percentage of megawatt hours produced by
8    renewable energy generation capacity physically located in
9    Illinois as a share of overall electricity generation from
10    facilities physically located in Illinois for the
11    preceding delivery year.
12    The Agency may seek assistance from the Illinois Commerce
13Commission in developing its annual report and may also retain
14the services of its expert consulting firm used to develop its
15procurement plans as outlined in paragraph (1) of subsection
16(a) of Section 1-75. Confidential or commercially sensitive
17business information provided by retail customers, alternative
18retail electric suppliers, or other parties shall be kept
19confidential by the Agency consistent with Section 1-120, but
20may be publicly reported in aggregate form.
21(Source: P.A. 99-536, eff. 7-8-16.)
 
22    (20 ILCS 3855/1-135 new)
23    Sec. 1-135. Project labor agreements. Projects greater
24than 10,000 kilowatts in nameplate capacity shall include a
25project labor agreement as defined by Section 1-75.

 

 

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1    (a) The project labor agreement must include the
2following:
3        (1) provisions establishing the minimum hourly wage
4    for each class of labor organization employee;
5        (2) provisions establishing the benefits and other
6    compensation for each class of labor organization
7    employee;
8        (3) provisions establishing that no strike or disputes
9    will be engaged in by the labor organization employees;
10    and
11        (4) provisions for minorities and women as defined
12    under the Business Enterprise for Minorities, Women, and
13    Persons with Disabilities Act, setting forth goals for
14    apprenticeship hours to be performed by minorities and
15    women and setting forth goals for total hours to be
16    performed by underrepresented minorities and women.
17    The owner of the facility and the labor organizations
18shall have the authority to include other terms and conditions
19as they deem necessary.
20    (b) The project labor agreement shall be filed with the
21Director in accordance with procedures established by the
22Illinois Power Agency. At a minimum, the project labor
23agreement must provide the names, addresses, and occupations
24of the owner of the plant and the individuals representing the
25labor organization employees participating in the project
26labor agreement consistent with the Project Labor Agreements

 

 

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1Act. The agreement must also specify the terms and conditions
2required in subsection (a).
 
3    (20 ILCS 3855/1-140 new)
4    Sec. 1-140. Equity points system.
5    (a) As used in this Section:
6    "Equity investment eligible community" or "eligible
7community" mean people living in geographic areas throughout
8Illinois who will most benefit from equitable investments by
9the State that are designed to combat historic inequities and
10the effects of discrimination. "Eligible community" includes
11census tracts that meet the following characteristics:
12        (1) At least 15% of the population or at least 20% of
13    the population 18 or under fall below the federal poverty
14    level; and
15        (2) falls in the top 25th percentile in the State on
16    measured levels for one or more of the following
17    environmental indicators from the United States
18    Environmental Protection Agency's EJSCREEN screening tool:
19            (A) Diesel particulate matter level in air.
20            (B) Air toxics cancer risk.
21            (C) Air toxics respiratory hazard index.
22            (D) Indicator for major direct dischargers to
23        water.
24            (E) Proximity to National Priorities List (NPL)
25        sites.

 

 

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1            (F) Proximity to Risk Management Plan (RMP)
2        facilities.
3            (G) Proximity to Treatment and Storage and
4        Disposal (TSDF) facilities.
5            (H) Ozone level in air.
6            (I) PM2.5 (particulate matter with diameters that
7        are 2.5 micrometers and smaller) level in the air.
8    "Equity investment eligible persons" or "eligible persons"
9means persons who would most benefit from equitable
10investments by the State designed to combat discrimination,
11specifically:
12        (1) persons whose primary residence is in an equity
13    investment eligible community;
14        (2) persons whose primary residence is in a
15    municipality or a county with a population under 100,000
16    where the closure of an electric generating unit or coal
17    mine has been publicly announced, or the electric
18    generating unit or coal mine is in the process of closing
19    or has closed within the last 5 years;
20        (3) persons who are graduates of or currently enrolled
21    in the foster care system; or
22        (4) persons who were formerly incarcerated.
23    "Labor peace agreement" means an agreement between an
24entity and any labor organization recognized under the federal
25National Labor Relations Act, that may prohibit the labor
26organization and members from engaging in picketing, work

 

 

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1stoppages, boycotts, and any other economic interference with
2the entity on photovoltaic distributed generation and
3photovoltaic community renewable generation projects
4participating in the Adjustable Block Program. Such an
5agreement also provides that the entity has agreed not to
6disrupt efforts by the labor organization to communicate with,
7and attempt to organize and represent, the entity's employees
8and affords the labor organization access at reasonable times
9to areas in which the entity's employees work, for the purpose
10of meeting with employees to discuss their right to
11representation, employment rights under State law, and terms
12and conditions of employment.
13    (b) Utility-scale wind and solar.
14        (1) The Illinois Power Agency shall revise the
15    long-term renewable resources procurement plan as provided
16    for in subparagraph (a) of paragraph (1) of subsection (c)
17    of Section 1-75 to implement this subsection. The Illinois
18    Power Agency, using alternative bidding procedures as
19    provided for in subsection (i) of Section 20-10 of the
20    Illinois Procurement Code, shall award equity action
21    points for the evaluation of bids in competitive
22    procurements for renewable energy credits delivered from
23    utility-scale wind, utility-scale solar, and brownfield
24    site photovoltaic projects, where applicable, as described
25    in this paragraph (1). Each company or entity may receive
26    up to a maximum of 20 points for each equity action. The

 

 

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1    maximum number of points that can be awarded is 80 points.
2    This equity points system shall consider equity actions
3    and bid prices. As part of its bid, each company or entity
4    must agree that they will demonstrate to the Agency that
5    they met each of the equity commitments as described in
6    subsection (g).
7        (2) Equity action points shall be assigned as follows:
8            (A) Equity eligible communities equity action.
9        Awarded based on a commitment that a percentage of the
10        workforce on the project, including the workforce of
11        contractors and subcontractors (measured by full-time
12        equivalents as defined by the Government
13        Accountability Office of the United States Congress),
14        will live in eligible communities. One point shall be
15        awarded for each 5% of the workforce composed of
16        workers who live in equity eligible communities and
17        one point to an entity that is majority-owned by one or
18        more eligible persons, up to a maximum of 20 points.
19            (B) Clean energy economy workforce participants
20        equity action. Awarded based on a commitment that a
21        percentage of the workforce on the project, including
22        the workforce of contractors and vendors, will be
23        reserved for workers who participated in the
24        Department of Commerce and Economic Opportunity's
25        Clean Jobs Workforce Hubs Network or Energy Transition
26        Barrier Reduction Program. One point shall be awarded

 

 

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1        for each 5% of the workforce composed of current or
2        former participants of those programs, up to a maximum
3        of 20 points.
4            (C) Project labor agreement equity action. Awarded
5        based on a commitment to enter into a pre-hire
6        collective bargaining or project labor agreement
7        consistent with the Project Labor Agreements Act. Up
8        to a maximum of 20 points shall be awarded for a
9        project labor agreement on a utility-scale wind or
10        solar project.
11            (D) Contracting equity action. Awarded based on a
12        commitment that a percentage of the company's or
13        entity's subcontractors or vendors for the project
14        will be businesses owned by one or more eligible
15        persons or that a percentage of the subcontractors' or
16        vendors' workforce on the project will be composed of
17        workers who live in eligible communities. Five points
18        shall be awarded for each 10% of subcontractors or
19        vendors that are businesses majority-owned by one or
20        more eligible persons or for each 10% of the
21        subcontractors' or vendors' workforce who live in
22        equity eligible communities, up to a maximum of 20
23        points. Bidders are not eligible for points under this
24        subsection unless they plan to use subcontractors.
25        (3) Competitive procurements shall follow the
26    procurement processes and procedures described in this

 

 

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1    Section and Section 16-111.5 of the Public Utilities Act
2    to the extent practicable with the following additional
3    provisions for the evaluation of bids. Bids shall be
4    placed into tiers based upon the number of equity action
5    points awarded. Bids shall first be selected from the top
6    tier based upon price, subject to a confidential
7    benchmark. If the bids in the top tier do not fill the
8    procurement target, then the process shall be repeated for
9    the next tier until either the procurement target is met,
10    or all bids under the benchmark are selected. The
11    methodology to determine tier sizes and allocations shall
12    be established in the Long-Term Renewable Resources
13    Procurement Plan.
14        (4) Upon request, the Agency shall provide
15    unsuccessful bidders with an explanation of how their bid
16    was scored and modifications that could be made in the
17    future to improve the score. This explanation shall not
18    reveal competitor bid information or other confidential
19    bid information.
20    (c) Adjustable block program.
21        (1) The Illinois Power Agency shall revise the
22    long-term renewable resources procurement plan as provided
23    for in subparagraph (a) of paragraph (1) of subsection (c)
24    of Section 1-75 to implement this subsection. The Agency,
25    using procedures as provided for in the Long-Term
26    Renewable Resources Procurement Plan, shall award equity

 

 

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1    action points to score applications for projects seeking
2    contracts for the delivery of renewable energy credits
3    through the adjustable block program. Each applicant may
4    receive up to a maximum of 20 points for each equity
5    action. The maximum number of points that can be awarded
6    is 80 points. This equity points system shall consider
7    equity actions and bid prices. As part of its bid, each
8    company or entity must agree that they will demonstrate to
9    the Agency that they met each of the equity commitments as
10    described in subsection (g).
11        (2) Equity action points shall be assigned as follows:
12            (A) Living wage equity action. Awarded based on a
13        commitment that a percentage of the workforce on the
14        project, including the workforce of contractors and
15        vendors, (measured by full-time equivalents as defined
16        by the Government Accountability Office of the United
17        States Congress) will be paid at or above a living
18        wage. One point shall be awarded for each 5% of the
19        workforce composed of workers paid at or above a
20        living wage, up to a maximum of 20 points. For purposes
21        of this Section, a living wage shall be defined as
22        twice the minimum wage in effect pursuant to the
23        Minimum Wage Law or any applicable minimum wage set by
24        the municipality in which the work is performed,
25        whichever is greater.
26            (B) Equity eligible communities equity action.

 

 

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1        Awarded based on a commitment that a percentage of the
2        workforce on the project, including the workforce of
3        contractors and vendors, (measured by full-time
4        equivalents) will live in eligible communities. One
5        point shall be awarded for each 5% of the workforce
6        that the company or entity commits will be composed of
7        workers who live in equity eligible Communities. As an
8        alternative, up to 20 points may be awarded to an
9        entity that is majority-owned by eligible persons.
10            (C) Clean energy economy workforce participants
11        equity action. Awarded based on a commitment that a
12        percentage of the workforce on the project, including
13        the workforce of contractors and vendors, (measured by
14        full-time equivalents) will be workers who
15        participated in the Department of Commerce and
16        Economic Opportunity's Clean Jobs Workforce Hubs
17        Network or Energy Transition Barrier Reduction
18        Program. One point shall be awarded for each 5% of the
19        workforce that the company or entity commits will be
20        composed of current or former participants of those
21        programs, up to a maximum of 20 points.
22            (D) Labor peace agreement action. Awarded based on
23        one of the following: (i) the bidder attests that the
24        bidder has entered into a labor peace agreement
25        applicable to the renewable energy project, will abide
26        by the terms of the agreement, and will submit a copy

 

 

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1        of the page of the labor peace agreement to the Agency;
2        or (ii) the bidder submits an attestation to the
3        Agency affirming its commitment to enter into a labor
4        peace agreement if approached by a bona fide labor
5        organization that is actively seeking to represent
6        workers in Illinois on the renewable energy project
7        that is the subject of this procurement.
8        (3) The adjustable block program shall reserve 40% of
9    each block's capacity to be available for project
10    applications that score no less than 40 points in the
11    equity points system. The Agency shall establish in its
12    Long-Term Renewable Resource Procurement Plan a process
13    for allocating the block capacity if applications scoring
14    40 or more points do not fill the 40% set-aside until all
15    contracts for that enrollment period are awarded.
16    Beginning with the update to the Long-Term Renewable
17    Resources Procurement Plan that commences in 2023, the
18    Agency shall review the reserved capacity level for future
19    blocks. In developing its annual block capacity, the
20    Agency shall project the amount of development in each
21    block, at the prices of each block, expected to occur in
22    the timeframe.
23    (d) Accountability in the equity points system.
24        (1) Purpose. It is the purpose of this subsection to
25    ensure the equity points system is successful in advancing
26    equity across Illinois by providing access to the clean

 

 

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1    energy economy for businesses and workers from communities
2    that have been historically excluded from economic
3    opportunities in the energy sector, have been subject to
4    disproportionate levels of pollution, and have
5    disproportionately experienced negative public health
6    outcomes.
7        (2) Modifications to the equity points system. As part
8    of the update of the Long-Term Renewable Resources
9    Procurement Plan to be initiated in 2023, or sooner if the
10    Agency deems necessary, the Agency shall determine to what
11    extent the equity points system described in this Section
12    resulted in the procurement of renewable energy credits
13    from projects in eligible communities. If the Agency finds
14    that the equity points system failed to meet that goal,
15    the Agency may propose in that updated Long-Term Renewable
16    Resources Procurement Plan to revise the following
17    criteria for future Agency procurements, notwithstanding
18    the criteria established in subsections (b) and (c): (i)
19    the number of points allocated for each equity action;
20    (ii) definitions for equity investment eligible persons
21    and equity investment eligible community; and (iii) the
22    number of points required for qualified vendors to be
23    eligible for the 40% capacity reservation of each block's
24    price in the adjustable block program. Such revised
25    criteria may also establish a distinct equity points
26    system for different types of procurements if the Agency

 

 

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1    finds that doing so will further the purpose of such
2    programs.
3    (e) Racial discrimination elimination powers and process.
4        (1) Purpose. It is the purpose of this subsection to
5    empower the Agency to assess and begin to reduce racial
6    discrimination in Illinois' clean energy economy,
7    including through the use of race-conscious remedies, such
8    as race-conscious contracting and hiring goals, consistent
9    with State and federal law.
10        (2) Racial disparity and discrimination review
11    process.
12            (A) Within one year of the awarding of contracts
13        using the equity actions processes established in this
14        Section, the Agency shall publish a report evaluating
15        the effectiveness of the equity actions point criteria
16        of this Section in increasing participation of equity
17        investment eligible individuals. Such report shall be
18        forwarded to the Governor, the General Assembly, and
19        the Illinois Commerce Commission.
20            (B) At any point thereafter, the Agency may
21        commission and publish a disparity and availability
22        study that measures the impact of discrimination on
23        minority businesses and workers. The Agency may hire
24        consultants and experts to conduct the disparity and
25        availability study, with the retention of those
26        consultants and experts exempt from the requirements

 

 

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1        of Section 20-10 of the Illinois Procurement Code. The
2        study shall: (i) evaluate whether using the equity
3        points system described in this Section result in
4        discrimination in the State's renewable energy
5        industry; and (ii) if so, evaluate the impact of such
6        discrimination on the State and include
7        recommendations for reducing or eliminating any
8        identified barriers to entry in the renewable energy
9        industry. The Illinois Power Agency shall forward a
10        copy of its findings and recommendations to the
11        Governor, the General Assembly, and the Illinois
12        Commerce Commission.
13            Should the disparity and availability study
14        demonstrate that using the equity points system
15        described in this Section result in discrimination in
16        the State's renewable energy industry, the Agency
17        shall utilize the recommendations to inform its
18        modification of the equity points system as described
19        in paragraph (2) of subsection (d). Any modifications
20        shall be designed to address disparities in the
21        renewable energy industry.
22    (f) Program data collection.
23        (1) Purpose. Data collection, data analysis, and
24    reporting are critical to ensure that the benefits of the
25    clean energy economy provided to Illinois residents and
26    businesses are equitably distributed across the State.

 

 

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1    Thus, the Agency requires proper authority to collect data
2    from program applicants in order to track and improve
3    equitable distribution of benefits across Illinois
4    communities for all procurements the Agency conducts. The
5    Agency shall use this data to, among other things, measure
6    any potential impact of racial discrimination on the
7    distribution of benefits and provide information necessary
8    to correct any discrimination through methods consistent
9    with State and federal law as described in subsection (e).
10        (2) Agency authority to collect program data. The
11    Agency shall collect demographic and geographic data for
12    each entity awarded contracts under any
13    Agency-administered program.
14        (3) Required information to be collected. The Agency
15    shall collect the following information from applicants
16    and program participants where applicable:
17            (A) demographic information, including racial or
18        ethnic identity for real persons employed, contracted,
19        or subcontracted through the program and owners of
20        businesses or entities that apply to receive renewable
21        energy credits from the Agency;
22            (B) geographic location of the residency of real
23        persons employed, contracted, or subcontracted through
24        the program and geographic location of the
25        headquarters of the business or entity that applies to
26        receive renewable energy credits from the Agency; and

 

 

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1            (C) any other information the Agency determines is
2        necessary for the purpose of achieving the purpose of
3        this subsection (f).
4        (4) Publication of collected information. The Agency
5    shall publish, at least annually, information on the
6    demographics of program participants on an aggregate
7    basis.
8        (5) Nothing in this subsection (f) shall be
9    interpreted to limit the authority of the Agency, or other
10    agency or department of the State, to require or collect
11    demographic information from applicants of other State
12    programs.
13    (g) Enforcement of equity commitments in procurement
14agreements.
15        (1) Any applicant awarded a REC contract under
16    procurement programs administered by the Agency that use
17    the equity points system shall be required to maintain,
18    for the duration of the contract, any activities and
19    commitments for which they obtained equity points at the
20    time of application. The Agency shall establish processes
21    and procedures for enforcement and monitoring of such
22    commitments, as set forth in this Section, in the
23    Long-Term Renewable Resources Procurement Plan.
24        (2) Any applicable contracts entered into as a result
25    of procurements by the Agency shall have provisions for
26    the monitoring and enforcement of the applicant's equity

 

 

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1    commitments by the Agency, to be set forth in the
2    Long-Term Renewal Resources Procurement Plan, including
3    provisions for entering into a corrective action plan,
4    return of payments or reduction or suspension of future
5    payments if the Agency determines that the company or
6    entity has failed to maintain any equity commitments it
7    made at the time of application. Such contracts shall also
8    provide the following:
9            (A) that the company or entity receiving points
10        for equity points actions will provide the Agency with
11        an annual report demonstrating compliance with each of
12        the equity commitments contained in their bid;
13            (B) if at any point the Agency concludes that the
14        company or entity has not maintained the commitments
15        they provided at the time of their application, the
16        Agency may require the company or entity to enter into
17        a corrective action plan. A corrective action plan may
18        require changes in hiring and contracting practices,
19        contributions to the Clean Jobs Workforce Hubs Network
20        or Energy Transition Barrier Reduction Program, a halt
21        or reduction of future payments, or other remedies to
22        ensure the company or entity maintains its equity
23        commitments; and
24            (C) if, at the conclusion of the REC contract
25        period, the Agency determines that the company or
26        entity failed to meet the commitments provided at the

 

 

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1        time of their application, the Agency may require the
2        return of payment or other remedies.
3    (h) All applicants shall be required to maintain all
4pertinent documents, employment records, and other relevant
5information about the activities and commitments for which
6they obtained equity points. The Agency may require periodic
7reports from each vendor that describes the status of each
8equity action.
9    (i) If the Agency concludes that a company or entity
10failed to achieve the equity commitments at the conclusion of
11the renewable energy contract period, the Agency may preclude
12that company from being awarded renewable energy credit
13procurement contracts in subsequent procurement cycles or open
14enrollment periods.
 
15    Section 30-28. The State Finance Act is amended by adding
16Sections 5.938 and 5.939 as follows:
 
17    (30 ILCS 105/5.938 new)
18    Sec. 5.938. The Energy Transition Assistance Fund.
 
19    (30 ILCS 105/5.939 new)
20    Sec. 5.939. The Greenhouse Gas Emissions Reinvestment
21Fund.
 
22    Section 30-30. The Illinois Procurement Code is amended by

 

 

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1changing Section 1-10 as follows:
 
2    (30 ILCS 500/1-10)
3    Sec. 1-10. Application.
4    (a) This Code applies only to procurements for which
5bidders, offerors, potential contractors, or contractors were
6first solicited on or after July 1, 1998. This Code shall not
7be construed to affect or impair any contract, or any
8provision of a contract, entered into based on a solicitation
9prior to the implementation date of this Code as described in
10Article 99, including, but not limited to, any covenant
11entered into with respect to any revenue bonds or similar
12instruments. All procurements for which contracts are
13solicited between the effective date of Articles 50 and 99 and
14July 1, 1998 shall be substantially in accordance with this
15Code and its intent.
16    (b) This Code shall apply regardless of the source of the
17funds with which the contracts are paid, including federal
18assistance moneys. This Code shall not apply to:
19        (1) Contracts between the State and its political
20    subdivisions or other governments, or between State
21    governmental bodies, except as specifically provided in
22    this Code.
23        (2) Grants, except for the filing requirements of
24    Section 20-80.
25        (3) Purchase of care, except as provided in Section

 

 

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1    5-30.6 of the Illinois Public Aid Code and this Section.
2        (4) Hiring of an individual as employee and not as an
3    independent contractor, whether pursuant to an employment
4    code or policy or by contract directly with that
5    individual.
6        (5) Collective bargaining contracts.
7        (6) Purchase of real estate, except that notice of
8    this type of contract with a value of more than $25,000
9    must be published in the Procurement Bulletin within 10
10    calendar days after the deed is recorded in the county of
11    jurisdiction. The notice shall identify the real estate
12    purchased, the names of all parties to the contract, the
13    value of the contract, and the effective date of the
14    contract.
15        (7) Contracts necessary to prepare for anticipated
16    litigation, enforcement actions, or investigations,
17    provided that the chief legal counsel to the Governor
18    shall give his or her prior approval when the procuring
19    agency is one subject to the jurisdiction of the Governor,
20    and provided that the chief legal counsel of any other
21    procuring entity subject to this Code shall give his or
22    her prior approval when the procuring entity is not one
23    subject to the jurisdiction of the Governor.
24        (8) (Blank).
25        (9) Procurement expenditures by the Illinois
26    Conservation Foundation when only private funds are used.

 

 

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1        (10) (Blank).
2        (11) Public-private agreements entered into according
3    to the procurement requirements of Section 20 of the
4    Public-Private Partnerships for Transportation Act and
5    design-build agreements entered into according to the
6    procurement requirements of Section 25 of the
7    Public-Private Partnerships for Transportation Act.
8        (12) Contracts for legal, financial, and other
9    professional and artistic services entered into on or
10    before December 31, 2018 by the Illinois Finance Authority
11    in which the State of Illinois is not obligated. Such
12    contracts shall be awarded through a competitive process
13    authorized by the Board of the Illinois Finance Authority
14    and are subject to Sections 5-30, 20-160, 50-13, 50-20,
15    50-35, and 50-37 of this Code, as well as the final
16    approval by the Board of the Illinois Finance Authority of
17    the terms of the contract.
18        (13) Contracts for services, commodities, and
19    equipment to support the delivery of timely forensic
20    science services in consultation with and subject to the
21    approval of the Chief Procurement Officer as provided in
22    subsection (d) of Section 5-4-3a of the Unified Code of
23    Corrections, except for the requirements of Sections
24    20-60, 20-65, 20-70, and 20-160 and Article 50 of this
25    Code; however, the Chief Procurement Officer may, in
26    writing with justification, waive any certification

 

 

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1    required under Article 50 of this Code. For any contracts
2    for services which are currently provided by members of a
3    collective bargaining agreement, the applicable terms of
4    the collective bargaining agreement concerning
5    subcontracting shall be followed.
6        On and after January 1, 2019, this paragraph (13),
7    except for this sentence, is inoperative.
8        (14) Contracts for participation expenditures required
9    by a domestic or international trade show or exhibition of
10    an exhibitor, member, or sponsor.
11        (15) Contracts with a railroad or utility that
12    requires the State to reimburse the railroad or utilities
13    for the relocation of utilities for construction or other
14    public purpose. Contracts included within this paragraph
15    (15) shall include, but not be limited to, those
16    associated with: relocations, crossings, installations,
17    and maintenance. For the purposes of this paragraph (15),
18    "railroad" means any form of non-highway ground
19    transportation that runs on rails or electromagnetic
20    guideways and "utility" means: (1) public utilities as
21    defined in Section 3-105 of the Public Utilities Act, (2)
22    telecommunications carriers as defined in Section 13-202
23    of the Public Utilities Act, (3) electric cooperatives as
24    defined in Section 3.4 of the Electric Supplier Act, (4)
25    telephone or telecommunications cooperatives as defined in
26    Section 13-212 of the Public Utilities Act, (5) rural

 

 

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1    water or waste water systems with 10,000 connections or
2    less, (6) a holder as defined in Section 21-201 of the
3    Public Utilities Act, and (7) municipalities owning or
4    operating utility systems consisting of public utilities
5    as that term is defined in Section 11-117-2 of the
6    Illinois Municipal Code.
7        (16) Procurement expenditures necessary for the
8    Department of Public Health to provide the delivery of
9    timely newborn screening services in accordance with the
10    Newborn Metabolic Screening Act.
11        (17) Procurement expenditures necessary for the
12    Department of Agriculture, the Department of Financial and
13    Professional Regulation, the Department of Human Services,
14    and the Department of Public Health to implement the
15    Compassionate Use of Medical Cannabis Program and Opioid
16    Alternative Pilot Program requirements and ensure access
17    to medical cannabis for patients with debilitating medical
18    conditions in accordance with the Compassionate Use of
19    Medical Cannabis Program Act.
20        (18) This Code does not apply to any procurements
21    necessary for the Department of Agriculture, the
22    Department of Financial and Professional Regulation, the
23    Department of Human Services, the Department of Commerce
24    and Economic Opportunity, and the Department of Public
25    Health to implement the Cannabis Regulation and Tax Act if
26    the applicable agency has made a good faith determination

 

 

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1    that it is necessary and appropriate for the expenditure
2    to fall within this exemption and if the process is
3    conducted in a manner substantially in accordance with the
4    requirements of Sections 20-160, 25-60, 30-22, 50-5,
5    50-10, 50-10.5, 50-12, 50-13, 50-15, 50-20, 50-21, 50-35,
6    50-36, 50-37, 50-38, and 50-50 of this Code; however, for
7    Section 50-35, compliance applies only to contracts or
8    subcontracts over $100,000. Notice of each contract
9    entered into under this paragraph (18) that is related to
10    the procurement of goods and services identified in
11    paragraph (1) through (9) of this subsection shall be
12    published in the Procurement Bulletin within 14 calendar
13    days after contract execution. The Chief Procurement
14    Officer shall prescribe the form and content of the
15    notice. Each agency shall provide the Chief Procurement
16    Officer, on a monthly basis, in the form and content
17    prescribed by the Chief Procurement Officer, a report of
18    contracts that are related to the procurement of goods and
19    services identified in this subsection. At a minimum, this
20    report shall include the name of the contractor, a
21    description of the supply or service provided, the total
22    amount of the contract, the term of the contract, and the
23    exception to this Code utilized. A copy of any or all of
24    these contracts shall be made available to the Chief
25    Procurement Officer immediately upon request. The Chief
26    Procurement Officer shall submit a report to the Governor

 

 

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1    and General Assembly no later than November 1 of each year
2    that includes, at a minimum, an annual summary of the
3    monthly information reported to the Chief Procurement
4    Officer. This exemption becomes inoperative 5 years after
5    June 25, 2019 (the effective date of Public Act 101-27)
6    this amendatory Act of the 101st General Assembly.
7        (19) Procurement expenditures necessary for the
8    Illinois Environmental Protection Agency to contract with
9    a firm to perform audits pursuant to Section 8-201.2 of
10    the Public Utilities Act.
11        (20) The retention of expert consulting firms
12    necessary for the Illinois Power Agency to conduct
13    disparity and availability studies regarding participants
14    in and beneficiaries of renewable energy programs and
15    procurements conducted pursuant to the Illinois Power
16    Agency Act.
17    Notwithstanding any other provision of law, for contracts
18entered into on or after October 1, 2017 under an exemption
19provided in any paragraph of this subsection (b), except
20paragraph (1), (2), or (5), each State agency shall post to the
21appropriate procurement bulletin the name of the contractor, a
22description of the supply or service provided, the total
23amount of the contract, the term of the contract, and the
24exception to the Code utilized. The chief procurement officer
25shall submit a report to the Governor and General Assembly no
26later than November 1 of each year that shall include, at a

 

 

SB2896- 374 -LRB102 17909 JWD 25989 b

1minimum, an annual summary of the monthly information reported
2to the chief procurement officer.
3    (c) This Code does not apply to the electric power
4procurement process provided for under Section 1-75 of the
5Illinois Power Agency Act and Section 16-111.5 of the Public
6Utilities Act.
7    (d) Except for Section 20-160 and Article 50 of this Code,
8and as expressly required by Section 9.1 of the Illinois
9Lottery Law, the provisions of this Code do not apply to the
10procurement process provided for under Section 9.1 of the
11Illinois Lottery Law.
12    (e) This Code does not apply to the process used by the
13Capital Development Board to retain a person or entity to
14assist the Capital Development Board with its duties related
15to the determination of costs of a clean coal SNG brownfield
16facility, as defined by Section 1-10 of the Illinois Power
17Agency Act, as required in subsection (h-3) of Section 9-220
18of the Public Utilities Act, including calculating the range
19of capital costs, the range of operating and maintenance
20costs, or the sequestration costs or monitoring the
21construction of clean coal SNG brownfield facility for the
22full duration of construction.
23    (f) (Blank).
24    (g) (Blank).
25    (h) This Code does not apply to the process to procure or
26contracts entered into in accordance with Sections 11-5.2 and

 

 

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111-5.3 of the Illinois Public Aid Code.
2    (i) Each chief procurement officer may access records
3necessary to review whether a contract, purchase, or other
4expenditure is or is not subject to the provisions of this
5Code, unless such records would be subject to attorney-client
6privilege.
7    (j) This Code does not apply to the process used by the
8Capital Development Board to retain an artist or work or works
9of art as required in Section 14 of the Capital Development
10Board Act.
11    (k) This Code does not apply to the process to procure
12contracts, or contracts entered into, by the State Board of
13Elections or the State Electoral Board for hearing officers
14appointed pursuant to the Election Code.
15    (l) This Code does not apply to the processes used by the
16Illinois Student Assistance Commission to procure supplies and
17services paid for from the private funds of the Illinois
18Prepaid Tuition Fund. As used in this subsection (l), "private
19funds" means funds derived from deposits paid into the
20Illinois Prepaid Tuition Trust Fund and the earnings thereon.
21(Source: P.A. 100-43, eff. 8-9-17; 100-580, eff. 3-12-18;
22100-757, eff. 8-10-18; 100-1114, eff. 8-28-18; 101-27, eff.
236-25-19; 101-81, eff. 7-12-19; 101-363, eff. 8-9-19; revised
249-17-19.)
 
25    Section 30-33. The Counties Code is amended by changing

 

 

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1Section 5-12020 and by adding Section 5-12022 as follows:
 
2    (55 ILCS 5/5-12020)
3    Sec. 5-12020. Wind farms, electric-generating wind
4devices, and commercial wind energy facilities.
5    (a) Definitions. As used in this Section:
6    "Commercial wind energy facility" has the meaning provided
7by Section 10 of the Renewable Energy Facilities Agricultural
8Impact Mitigation Act.
9    "Facility owner" means: (i) a person with a direct
10ownership interest in a commercial wind energy facility,
11regardless of whether the person was involved in acquiring the
12necessary rights, permits and approvals or otherwise planning
13for the construction and operation of a wind energy system;
14and (ii) at the time a wind energy system is being developed, a
15person who is acting as a wind energy system developer by
16acquiring the necessary rights, permits and approvals for or
17by planning for the construction and operation of a wind
18energy system, regardless of whether the person will own or
19operate the wind energy system.
20    "Nonparticipating property" means real property that is
21not participating property.
22    "Nonparticipating residence" means an occupied residence
23on nonparticipating property that is existing and occupied as
24of the date of filing of a permit application by the commercial
25wind energy facility.

 

 

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1    "Occupied community building" means an existing structure
2occupied as of the date of filing of a permit application by
3the commercial wind energy facility, including,207 but not
4limited to, a school, place of worship, daycare facility,
5public library, community center, or commercial building.
6    "Participating Property" means real property that is the
7subject of a written agreement between the facility owner and
8the owner of such real property which provides the facility
9owner an easement, option, lease license or other agreement
10for the purpose of constructing a wind tower or supporting
11facilities on such real property.
12    "Participating residence" means a residence on
13participating property occupied as of the date of filing of a
14permit application.
15    "Shadow flicker" means shadows that are given off by wind
16turbines when they are in full rotating motion.
17    "Supporting facilities" means the associated transmission
18lines, substations, access roads located on private property,
19meteorological towers, and other equipment related to the
20generation of electricity from the commercial wind energy
21facility.
22    "Wind tower" means the wind turbine tower, nacelle, and
23blades.
24    (b) Notwithstanding any other provision of law or whether
25the county has formed a zoning commission and adopted formal
26zoning under Section 5-12007, a county may establish standards

 

 

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1for commercial wind energy facilities. wind farms and
2electric-generating wind devices. The standards may include,
3without limitation, the height of the devices and the number
4of devices that may be located within a geographic area. A
5county may also regulate the siting of commercial wind energy
6facilities wind farms and electric-generating wind devices in
7unincorporated areas of the county outside of the zoning
8jurisdiction of a municipality and the 1.5 mile radius
9surrounding the zoning jurisdiction of a municipality. A
10county that establishes standards for items specified in
11subsections (e) through (j) for ground mounted solar energy
12systems shall do so in accordance with this Section. This
13Section applies to home rule and non-home rule counties and is
14a limitation under subsection (i) of Section 6 of Article VII
15of the Illinois Constitution on the concurrent exercise by
16home rule units of powers and functions exercised by the
17State.
18    (c) There shall be at least one public hearing during
19which public comment shall be taken regarding the application
20for siting approval or a special use permit for a commercial
21wind energy facility. The first public hearing shall be
22noticed and shall commence not more than 75 days after the
23filing of an application for siting approval or a special use
24permit for a commercial wind energy facility, and the final
25public hearing shall conclude not more than 90 days following
26the filing. The county board or its designee shall make its

 

 

SB2896- 379 -LRB102 17909 JWD 25989 b

1siting decision not more than 45 days after the conclusion of
2the final public hearing or the conclusion of the special use
3permit hearing by the zoning board of appeals. not more than 30
4days prior to a siting decision by the county board. Notice of
5the hearing shall be published in a newspaper of general
6circulation in the county or on a municipality's or county's
7website. A commercial wind energy facility owner, as defined
8in the Renewable Energy Facilities Agricultural Impact
9Mitigation Act, shall must enter into an agricultural impact
10mitigation agreement with the Department of Agriculture prior
11to the date of the required public hearing. A commercial wind
12energy facility owner seeking an extension of a permit granted
13by a county prior to July 24, 2015 (the effective date of
14Public Act 99-132) must enter into an agricultural impact
15mitigation agreement with the Department of Agriculture prior
16to a decision by the county to grant the permit extension.
17Counties may allow test wind towers to be sited without formal
18approval by the county board. Any provision of a county zoning
19ordinance pertaining to wind farms that is in effect before
20August 16, 2007 (the effective date of Public Act 95-203) may
21continue in effect notwithstanding any requirements of this
22Section.
23    (d) A county with an existing zoning ordinance in conflict
24with this Section shall amend such zoning ordinance to be in
25compliance with this section within 180 days after the
26effective date of this amendatory Act of the 102nd General

 

 

SB2896- 380 -LRB102 17909 JWD 25989 b

1Assembly.
2    (e) This Section does not apply to a commercial wind
3energy facility that began construction or was approved by a
4political subdivision before the effective date of this
5amendatory Act of the 102nd General Assembly.
6    A county may not require:
7        (1) a commercial wind energy facility to be sited with
8    setback distances measured from the center of the base of
9    the wind tower as follows:
10            Occupied Community Buildings: 2.1 times the
11        maximum blade tip height from the nearest point on the
12        outside wall of the structure.
13            Participating Residences: 1.1 times the maximum
14        blade tip height to the nearest point on the outside
15        wall of the structure.
16            Nonparticipating Residences: 2.1 times the maximum
17        blade tip height to the nearest point on the outside
18        wall of the structure.
19            Participating Property Lines: None.
20            Nonparticipating Property Lines: 1.1 times the
21        maximum blade tip height to the nearest point on the
22        property line.
23            Public Road Right-of-Way: 1.1 times the maximum
24        blade tip height to the center point of the public road
25        right-of-way.
26            Overhead Communication and Electric Transmission —

 

 

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1        Not including utility service lines to individual
2        houses or out- buildings: 1.1 times the maximum blade
3        tip height to the center point of the easement
4        containing the overhead line.
5            Overhead Utility Service Lines — Lines to
6        individual houses or outbuildings: None.
7        (2) a wind tower to be sited in a manner such that
8    industry standard computer modeling indicates that any
9    occupied community building or nonparticipating residence
10    will not experience more than 30 hours per year of shadow
11    flicker under planned operating conditions.
12        (3) The requirements set forth in this subsection (e)
13    may be waived subject to the written consent of the owner
14    of the affected nonparticipating property.
15a wind tower or other renewable energy system that is used
16exclusively by an end user to be setback more than 1.1 times
17the height of the renewable energy system from the end user's
18property line.
19    (f) A county may not set a blade tip height limitation that
20is more restrictive than the height allowed under a
21Determination of No Hazard to Air Navigation by the Federal
22Aviation Administration under 14 CFR Part 77.
23    (g) A county may not set a sound limitation that is more
24restrictive than the sound limitations established by the
25Illinois Pollution Control Board under 35 Ill. Adm. Code 900,
26901, and 910.

 

 

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1    (h) A county may not establish standards for items listed
2in this Section, either directly or in effect, on the
3installation or use of a commercial wind energy facility
4except by adopting an ordinance that complies with this
5Section and may not establish siting standards which are less
6restrictive than any terms and conditions included in the
7standard agricultural impact mitigation agreement available
8from the Department of Agriculture in accordance with
9subsection (f) of Section 15 of the Renewable Energy
10Facilities Agricultural Impact Mitigation Act.
11    (i) A county may not require a wind tower or other
12renewable energy system that is used exclusively by an end
13user to be setback more than 1.1 times the height of the
14renewable energy system from the user's property line.
15    (j) Only a county may establish standards for wind farms,
16electric-generating wind devices, wind towers, supporting
17facilities, and commercial wind energy facilities, as that
18term is defined in Section 10 of the Renewable Energy
19Facilities Agricultural Impact Mitigation Act, in
20unincorporated areas of the county outside of the zoning
21jurisdiction of a municipality and outside the 1.5 mile radius
22surrounding the zoning jurisdiction of a municipality.
23(Source: P.A. 100-598, eff. 6-29-18; 101-4, eff. 4-19-19.)
 
24    (55 ILCS 5/5-12022 new)
25    Sec. 5-12022. Ground mounted solar energy systems.

 

 

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1    (a) Definitions. As used in this Section:
2    "Commercial solar energy system" or "CSE system" means a
3system that captures and converts solar energy into
4electricity that is generated primarily: (1) for the purpose
5of selling the electricity at wholesale; and (2) for use in
6locations other than where it is generated.
7    "Dwelling" means any building, structure, or part of a
8building or structure that is occupied as, or is designed or
9intended for occupancy as, a residence by one (1) or more
10families or individuals.
11    "Ground mounted solar energy system" means a solar energy
12system mounted on a rack or pole that is attached to the
13ground, and includes either a commercial solar energy system
14or a community renewable generation project, as that term is
15defined in Section 1-10 of the Illinois Power Agency Act.
16"Ground mounted solar energy system" includes transmission
17lines, substations, ancillary buildings, solar monitoring
18stations, and accessory equipment or structures that are
19associated with the ground mounted solar energy system.
20    "Nonparticipating property" means real property that is
21not participating property.
22    "Nonparticipating residence" means an occupied residence
23on nonparticipating property that is existing and occupied as
24of the date of filing of a permit application by the permit
25applicant.
26    "Participating property" means real property that is the

 

 

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1subject of a written agreement between the facility owner and
2the owner of such real property which provides the facility
3owner an easement, option, lease license or other agreement
4for the purpose of constructing a ground mounted solar energy
5system on such real property.
6    "Participating residence" means an occupied residence on
7participating property.
8    "Permit applicant" means a person who: (1) will own one or
9more ground mounted solar energy systems; (2) owns one or more
10round mounted solar energy systems; or (3) an agent or a
11representative of a person described in item (1) or (2).
12    "Solar energy system" means a device, or array of devices,
13whose purpose is to convert solar energy into electricity.
14    (b) Notwithstanding any other provision of law or whether
15the county has formed a zoning commission and adopted formal
16zoning under Section 5-12007, a county may establish standards
17for ground mounted solar energy systems. The standards may
18include without limitation all of the requirements specified
19in subsections (f) through (q), but may not include
20requirements for ground mounted solar energy systems that are
21more restrictive than specified in subsections (f) through (q)
22unless the restrictions apply to all other uses in the same
23zoning classification. A county may also regulate the siting
24of ground mounted solar energy systems in unincorporated areas
25of the county outside of the zoning jurisdiction of a
26municipality and the 1.5 mile radius surrounding the zoning

 

 

SB2896- 385 -LRB102 17909 JWD 25989 b

1jurisdiction of a municipality. A county that establishes
2standards for items specified in subsections (f) through (q)
3for ground mounted solar energy systems shall do so in
4accordance with this Section. This Section applies to home
5rule and non-home rule counties and is a limitation under
6subsection (i) of Section 6 of Article VII of the Illinois
7Constitution on the concurrent exercise by home rule units of
8powers and functions exercised by the State.
9    (c) There shall be at least one public hearing during
10which public comment shall be taken regarding the application
11for siting approval or a special use permit for a ground
12mounted solar energy system. The first public hearing shall be
13noticed and commenced not more than 75 days after the filing of
14an application for siting approval or a special use permit for
15a ground mounted solar energy system, and the final public
16hearing shall be concluded not more than 90 days following the
17filing. The county board or its designee shall make its siting
18decision not more than 45 days after the conclusion of the
19public hearing or the conclusion of the special use permit
20hearing by the zoning board of appeals. Notice of the hearing
21shall be published in a newspaper of general circulation in
22the county.
23    (d) A county with an existing zoning ordinance in conflict
24with this Section shall amend such zoning ordinance to be in
25compliance with this Section within 180 days from the
26effective date of this amendatory Act of the 102nd General

 

 

SB2896- 386 -LRB102 17909 JWD 25989 b

1Assembly.
2    (e) This Section does not apply to a ground mounted solar
3energy system that began construction or was approved by a
4political subdivision before the effective date of this
5amendatory Act of the 102nd General Assembly.
6    (f) A permit applicant may not install a ground mounted
7solar energy system unless the distance measured from the
8nearest outer edge of the ground mounted solar energy system
9is as follows (subject to State and Federal setback
10requirements):
11        Roadway - federal interstate highway, federal highway,
12    State highway, or county highway: at least 40 feet from
13    the right-of-way.
14        Roadway - collector road: at least 30 feet from the
15    right-of-way.
16        Roadway - local road: at least 10 feet from the
17    right-of-way.
18        Nonparticipating Residences: at least 150 feet from
19    the nearest point on the outside wall of a dwelling.
20        Nonparticipating Property Lines: at least 50 feet from
21    nearest point on the property line.
22    (g) A permit applicant shall install a landscape buffer
23when the nearest outer edge of the ground mounted solar energy
24system is within a distance of 250 feet of the nearest point on
25the outer wall of a dwelling located on a nonparticipating
26property. The permit applicant shall install a landscape

 

 

SB2896- 387 -LRB102 17909 JWD 25989 b

1buffer in the area between the nearest outer edge of the ground
2mounted solar energy system and the outer wall of the dwelling
3located on the nonparticipating property: (i) in a location;
4and (ii) constructed from such materials, as set forth in a
5site plan submitted to the county, if required.
6    (h) The requirements set forth in subsection (g) may be
7waived subject to the written consent of the owner of the
8affected nonparticipating property.
9    (i) A permit applicant shall not install or locate a
10ground mounted solar energy system that is more than 25 feet
11above ground level when the ground mounted solar energy
12system's arrays are at full tilt. However, a county may not
13impose a clearance requirement between the ground and the
14bottom edge of a ground mounted solar energy system's solar
15panels.
16    (j) A permit applicant shall control weeds and vegetation
17on the land where a ground mounted solar energy system is
18located in accordance with the Agricultural Impact Mitigation
19Agreement the permit applicant is required to sign by the
20Renewable Energy Facilities Agricultural Impact Mitigation
21Act. The use of pollinator seed mixes in the planting of ground
22cover shall conform to the Pollinator-Friendly Solar Site Act.
23    (k) A permit applicant shall completely enclose the ground
24mounted solar energy system with fencing that is at least 6
25feet high.
26    (l) A permit applicant shall install and maintain support

 

 

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1structures, aboveground facilities, guy wires and anchors, and
2underground cabling in accordance with the Agricultural Impact
3Mitigation Agreement the permit applicant is required to sign
4by the Renewable Energy Facilities Agricultural Impact
5Mitigation Act.
6    (m) A ground mounted solar energy system is to be designed
7and constructed to: (i) minimize glare on adjacent properties
8and roadways; and (ii) not interfere with vehicular traffic,
9including air traffic.
10    (n) A ground mounted solar energy system shall not
11interfere with: (i) television signals; (ii) microwave
12signals; (iii) agricultural global positioning systems; (iv)
13military defense radar; or (v) radio reception.
14    (o) A permit applicant is to operate a ground mounted
15solar energy system in a manner such that the sound
16attributable to the ground mounted solar energy system will
17not exceed the sound limitations established by the Illinois
18Pollution Control Board under 35 Ill. Adm. Code 900, 901, and
19910.
20    (p) A permit applicant will comply with local road load
21limits and will apply for permits to use overweight vehicles,
22if necessary.
23    (q) A county may not establish standards for items listed
24in subsections (f) through (p), either directly or in effect,
25on the installation or use of a ground mounted solar energy
26system except by adopting an ordinance that complies with this

 

 

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1Section and may not establish siting standards that
2effectively preclude development of ground mounted solar
3energy systems in the county.
4    (r) Only a county may establish standards for ground
5mounted solar energy systems and Commercial Solar Energy
6Facilities, as that term is defined in Section 10 of the
7Renewable Energy Facilities Agricultural Impact Mitigation
8Act, in unincorporated areas of the county outside of the
9zoning jurisdiction of a municipality and outside the 1.5 mile
10radius surrounding the zoning jurisdiction of a municipality.
 
11    Section 30-35. The Illinois Municipal Code is amended by
12adding Section 8-11-2.7 as follows:
 
13    (65 ILCS 5/8-11-2.7 new)
14    Sec. 8-11-2.7. Non-Home Rule Municipal Gas Use Tax.
15    (a) This Section may be cited as the Non-Home Rule
16Municipal Gas Use Tax Law.
17    (b) As used in this Section:
18    "Delivering supplier" means a person engaged in the
19business of delivering gas to another person for use or
20consumption and not for resale, and who, in any case where more
21than one person participates in the delivery of gas to a
22specific purchaser, is the last of the suppliers engaged in
23delivering the gas prior to its receipt by the purchaser.
24    "Delivering supplier maintaining a place of business in

 

 

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1this State" means any delivering supplier having or
2maintaining within this State, directly or by a subsidiary, an
3office, distribution facility, sales office, or other place of
4business, or any employee, agent, or other representative
5operating within this State under the authority of the
6delivering supplier or the delivering supplier's subsidiary,
7irrespective of whether the place of business or agent or
8other representative is located in this State permanently or
9temporarily, or whether the delivering supplier or the
10delivering supplier's subsidiary is licensed to do business in
11this State.
12    "Gas" means any gaseous fuel distributed through a
13pipeline system.
14    "Person" means any natural individual, firm, trust,
15estate, partnership, association, joint stock company, joint
16adventure, corporation, or limited liability company, any
17receiver, trustee, guardian, or other representative appointed
18by order of any court, or any city, town, county, or other
19political subdivision of this State.
20    "Purchase of out-of-state gas" means a transaction for the
21purchase of gas from any supplier in a manner that does not
22subject the seller of that gas to liability for a tax imposed
23under paragraph 2 of Section 8-11-2 of the Illinois Municipal
24Code.
25    "Purchase price" means the consideration paid for the
26distribution, supply, furnishing, sale, transportation, or

 

 

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1delivery of gas to a person for use or consumption and not for
2resale, and for all services directly related to the
3production, transportation, or distribution of gas
4distributed, supplied, furnished, sold, transmitted, or
5delivered for use or consumption, including cash, services,
6and property of every kind and nature. "Purchase price" does
7not include consideration paid for:
8        (1) a charge for a dishonored check;
9        (2) a finance or credit charge, penalty, charge for
10    delayed payment, or discount for prompt payment;
11        (3) a charge for reconnection of service or for
12    replacement or relocation of facilities;
13        (4) an advance or contribution in aid of construction;
14        (5) repair, inspection, or servicing of equipment
15    located on customer premises;
16        (6) leasing or rental of equipment, the leasing or
17    rental of which is not necessary to furnishing, supplying,
18    or selling gas;
19        (7) a purchase by a purchaser if the supplier is
20    prohibited by a federal or State constitution, treaty,
21    convention, statute, or court decision from recovering the
22    related tax liability from such purchaser; or
23        (8) an amount added to a purchaser's bill because of
24    changes made pursuant to the tax imposed by the
25    municipality.
26    (c) The privilege of using or consuming gas acquired in a

 

 

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1purchase at retail and used or consumed within the corporate
2limits of a non-home rule municipality may be taxed at rates
3not to exceed the maximum rates, calculated on a monthly basis
4for each purchaser, as provided in this Section.
5    (d) Beginning January 1, 2022, a non-home rule
6municipality may impose upon the privilege of using in the
7municipality gas obtained in a purchase of out-of-state gas at
8the rate per therm established by the non-home rule
9municipality or 5% of the purchase price for the billing
10period, whichever is the lower rate. This tax rate is the
11self-assessing purchaser tax rate. Beginning with bills issued
12by delivering suppliers on and after January 1, 2022 to
13purchasers within a municipality imposing a tax pursuant to
14this Section, purchasers may elect an alternate tax rate per
15therm established by the non-home rule municipality to be paid
16under the provisions of subsection (e) to a delivering
17supplier maintaining a place of business in this State. The
18non-home rule municipality shall establish this alternate tax
19rate, not less than annually, a rate per therm that would not
20exceed a tax imposed at the rate of 5% of the gross receipts
21for the purchase price for the billing period.
22    (e) Beginning with bills issued on and after January 1,
232022, a delivering supplier maintaining a place of business in
24this State shall collect from the purchasers within a
25municipality imposing a tax pursuant to this Section who have
26elected the alternate tax rate provided in subsection (d) the

 

 

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1tax that is imposed by the municipality at the alternate tax
2rate. The tax imposed at the alternate tax rate shall, when
3collected, be stated as a distinct and separate item apart
4from the selling price of the gas. The tax collected by a
5delivering supplier shall constitute a debt owed by that
6person to the municipality imposing the tax. Upon receipt by a
7delivering supplier of a copy of a certificate of registration
8issued to a self-assessing purchaser under subsection (f), the
9delivering supplier is relieved of the duty to collect the
10alternate tax from that self-assessing purchaser beginning
11with bills issued to that self-assessing purchaser 30 or more
12days after receipt of the copy of that certificate of
13registration.
14    (f) Any purchaser who does not elect the alternate tax
15rate to be paid to a delivering supplier shall register with
16the municipality imposing the tax as a self-assessing
17purchaser and pay the tax imposed directly to the municipality
18imposing the tax at the self-assessing purchaser rate.
19    Application for a certificate of registration as a
20self-assessing purchaser shall be made to the municipality
21imposing the tax on forms furnished by the municipality and
22shall contain any reasonable information that the municipality
23requires. The self-assessing purchaser shall disclose the name
24of the delivering supplier or suppliers who are delivering the
25gas upon which the self-assessing purchaser will be paying tax
26to the municipality imposing the tax.

 

 

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1    Upon receipt of an application for a certificate of
2registration in proper form, the municipality imposing the tax
3shall issue to the applicant a certificate of registration as
4a self-assessing purchaser. The applicant shall provide a copy
5of the certificate of registration as a self-assessing
6purchaser to the applicant's delivering supplier or suppliers.
7A purchaser registering as a self-assessing purchaser may not
8revoke the registration for at least one year after
9registration.
10    (g) Except for purchasers who have chosen the alternate
11tax rate to be paid to a delivering supplier maintaining a
12place of business in this State, the tax imposed by the
13municipality pursuant to subsection (d) shall be paid to the
14municipality imposing the tax directly by each self-assessing
15purchaser that is subject to the tax imposed by the
16municipality. Each self-assessing purchaser shall, on or
17before the 15th day of each month, make a return to the
18municipality imposing the tax for the preceding calendar
19month, stating the following:
20        (1) the self-assessing purchaser's name and principal
21    address;
22        (2) the total number of therms used by the
23    self-assessing purchaser during the preceding calendar
24    month and upon the basis of which the tax is imposed;
25        (3) the purchase price of gas used by the
26    self-assessing purchaser during the preceding calendar

 

 

SB2896- 395 -LRB102 17909 JWD 25989 b

1    month and upon the basis of which the tax is imposed;
2        (4) amount of tax (computed upon items (2) and (3));
3    and
4        (5) any other reasonable information the municipality
5    imposing the tax may require.
6    (h) A delivering supplier maintaining a place of business
7in this State who engages in the delivery of gas to customers
8within a municipality imposing the tax in this State shall
9register with the municipality imposing the tax. A delivering
10supplier, if required to otherwise register pursuant to a tax
11imposed under Section 8-11-2 of this Code, need not obtain an
12additional certificate of registration under this Section, but
13shall be deemed to be sufficiently registered by virtue of
14that registration with the municipality imposing the tax.
15    Application for a certificate of registration shall be
16made to the municipality imposing the tax on forms furnished
17by the municipality and shall contain any reasonable
18information the municipality may require. Upon receipt of a
19completed application for a certificate of registration, the
20municipality imposing the tax shall issue to the applicant a
21certificate of registration. The municipality imposing the tax
22may deny a certificate of registration to any applicant if the
23applicant is in default for moneys due under this Section. A
24person aggrieved by a decision of the municipality imposing
25the tax under this subsection may, within 20 days after notice
26of the decision, protest and request a hearing, whereupon the

 

 

SB2896- 396 -LRB102 17909 JWD 25989 b

1municipality imposing the tax shall give notice to the person
2of the time and place fixed for the hearing, shall hold a
3hearing in conformity with the provisions of this Section, and
4then issue its final administrative decision in the matter to
5the person. In the absence of a protest within 20 days, the
6municipality's decision shall become final without any further
7determination being made or notice given.
8    (i) A delivering supplier who is required under subsection
9(e) to collect the tax imposed by the municipality shall make a
10return to the municipality imposing the tax on or before the
1115th day of each month for the preceding calendar month
12stating the following:
13        (1) the delivering supplier's name;
14        (2) the address of the delivering supplier's principal
15    place of business and the address of the principal place
16    of business (if that is a different address) from which
17    the delivering supplier engages in the business of
18    delivering gas to persons for use or consumption and not
19    for resale;
20        (3) the total number of therms of gas delivered to
21    purchasers within a municipality imposing a tax pursuant
22    to this Section during the preceding calendar month and
23    upon the basis of which the tax is imposed;
24        (4) the amount of tax computed upon item (3); and
25        (5) any other reasonable information as the
26    municipality imposing the tax may require.

 

 

SB2896- 397 -LRB102 17909 JWD 25989 b

1    In making the return, the delivering supplier engaged in
2the business of delivering gas to persons for use or
3consumption and not for resale may use any reasonable method
4to derive reportable therms from the delivering supplier's
5billing and payment records.
6    Notwithstanding any other provision in this Section
7concerning the time within which a delivering supplier may
8file its return, in the case of a delivering supplier who
9ceases to engage in a kind of business that makes it
10responsible for filing returns with a municipality imposing a
11tax under this Section, the delivering supplier shall file a
12final return under this Section with the affected municipality
13not more than one month after discontinuing a kind of business
14that makes it responsible for filing returns with a
15municipality.
16    The delivering supplier making the return provided for in
17this Section shall, at the time of making the return, pay to
18the municipality the amount of tax imposed by the
19municipality.
 
20    Section 30-40. The Public Utilities Act is amended by
21changing Sections 3-105, 5-117, 8-103B, 8-406, 9-201, 9-220.3,
229-221, 9-227, 9-229, 9-241, 16-107.5, 16-107.6, 16-108,
2316-108.5, 16-111.5, 16-111.8, 16-115, 16-115C, 19-110, and
2419-145 and by adding Sections 4-604, 8-103C, 8-104.1, 8-201.7,
258-201.8, 8-201.9, 8-201.10, 8-201.11, 8-201.12, 8-201.13,

 

 

SB2896- 398 -LRB102 17909 JWD 25989 b

18-201.14, 8-512, 16-108.17, 16-108.18, 16-108.19, 16-108.20,
216-108.21, and 16-108.22 as follows:
 
3    (220 ILCS 5/3-105)  (from Ch. 111 2/3, par. 3-105)
4    Sec. 3-105. Public utility.
5    (a) "Public utility" means and includes, except where
6otherwise expressly provided in this Section, every
7corporation, company, limited liability company, association,
8joint stock company or association, firm, partnership or
9individual, their lessees, trustees, or receivers appointed by
10any court whatsoever that now or hereafter owns, controls,
11operates or manages, within this State, directly or
12indirectly, for public use, any plant, equipment or property
13used or to be used for or in connection with, or now owns or
14controls or currently seeks Commission approval to own or
15control any franchise, license, permit or right to engage in:
16        (1) the production, storage, transmission, sale,
17    delivery or furnishing of heat, cold, power, electricity,
18    water, or light, except when used solely for
19    communications purposes;
20        (2) the disposal of sewerage; or
21        (3) the conveyance of oil or gas by pipe line.
22    (b) "Public utility" does not include, however:
23        (1) public utilities that are owned and operated by
24    any political subdivision, public institution of higher
25    education or municipal corporation of this State, or

 

 

SB2896- 399 -LRB102 17909 JWD 25989 b

1    public utilities that are owned by such political
2    subdivision, public institution of higher education, or
3    municipal corporation and operated by any of its lessees
4    or operating agents;
5        (2) water companies which are purely mutual concerns,
6    having no rates or charges for services, but paying the
7    operating expenses by assessment upon the members of such
8    a company and no other person;
9        (3) electric cooperatives as defined in Section 3-119;
10        (4) the following natural gas cooperatives:
11            (A) residential natural gas cooperatives that are
12        not-for-profit corporations established for the
13        purpose of administering and operating, on a
14        cooperative basis, the furnishing of natural gas to
15        residences for the benefit of their members who are
16        residential consumers of natural gas. For entities
17        qualifying as residential natural gas cooperatives and
18        recognized by the Illinois Commerce Commission as
19        such, the State shall guarantee legally binding
20        contracts entered into by residential natural gas
21        cooperatives for the express purpose of acquiring
22        natural gas supplies for their members. The Illinois
23        Commerce Commission shall establish rules and
24        regulations providing for such guarantees. The total
25        liability of the State in providing all such
26        guarantees shall not at any time exceed $1,000,000,

 

 

SB2896- 400 -LRB102 17909 JWD 25989 b

1        nor shall the State provide such a guarantee to a
2        residential natural gas cooperative for more than 3
3        consecutive years; and
4            (B) natural gas cooperatives that are
5        not-for-profit corporations operated for the purpose
6        of administering, on a cooperative basis, the
7        furnishing of natural gas for the benefit of their
8        members and that, prior to 90 days after the effective
9        date of this amendatory Act of the 94th General
10        Assembly, either had acquired or had entered into an
11        asset purchase agreement to acquire all or
12        substantially all of the operating assets of a public
13        utility or natural gas cooperative with the intention
14        of operating those assets as a natural gas
15        cooperative;
16        (5) sewage disposal companies which provide sewage
17    disposal services on a mutual basis without establishing
18    rates or charges for services, but paying the operating
19    expenses by assessment upon the members of the company and
20    no others;
21        (6) (blank);
22        (7) cogeneration facilities, small power production
23    facilities, and other qualifying facilities, as defined in
24    the Public Utility Regulatory Policies Act and regulations
25    promulgated thereunder, except to the extent State
26    regulatory jurisdiction and action is required or

 

 

SB2896- 401 -LRB102 17909 JWD 25989 b

1    authorized by federal law, regulations, regulatory
2    decisions or the decisions of federal or State courts of
3    competent jurisdiction;
4        (8) the ownership or operation of a facility that
5    sells compressed natural gas at retail to the public for
6    use only as a motor vehicle fuel and the selling of
7    compressed natural gas at retail to the public for use
8    only as a motor vehicle fuel;
9        (9) alternative retail electric suppliers as defined
10    in Article XVI; and
11        (10) the Illinois Power Agency.
12    (c) An entity that furnishes the service of charging
13electric vehicles does not and shall not be deemed to sell
14electricity and is not and shall not be deemed a public utility
15notwithstanding the basis on which the service is provided or
16billed. If, however, the entity is otherwise deemed a public
17utility under this Act, or is otherwise subject to regulation
18under this Act, then that entity is not exempt from and remains
19subject to the otherwise applicable provisions of this Act.
20The installation, maintenance, and repair of an electric
21vehicle charging station shall comply with the requirements of
22subsection (a) of Section 16-128 and Section 16-128A of this
23Act.
24    For purposes of this subsection, the term "electric
25vehicles" has the meaning ascribed to that term in Section 10
26of the Electric Vehicle Act.

 

 

SB2896- 402 -LRB102 17909 JWD 25989 b

1(Source: P.A. 97-1128, eff. 8-28-12.)
 
2    (220 ILCS 5/4-604 new)
3    Sec. 4-604. Restitution for misconduct.
4    (a) It is the policy of this State that public utility
5ethical and criminal misconduct shall not be tolerated. The
6General Assembly finds it necessary to collect restitution, to
7be distributed as described in subsection (e), from a public
8utility that has been found guilty of violations of criminal
9law or that has entered into a Deferred Prosecution Agreement
10that details violations of criminal law that result in harm to
11ratepayers.
12    (b) In light of such violations, the Illinois Commerce
13Commission shall, within 150 days after the effective date of
14this amendatory Act of the 102nd General Assembly, initiate an
15investigation as to whether Commonwealth Edison collected,
16spent, allocated, transferred, remitted, or caused in any
17other way to be expended ratepayer funds in connection with
18the conduct detailed in the Deferred Prosecution Agreement of
19July 16, 2020 between the United States Attorney for the
20Northern District of Illinois and Commonwealth Edison. The
21investigation shall also determine whether any ratepayer funds
22were used to pay the criminal penalty agreed to in the Deferred
23Prosecution Agreement. The investigation shall determine
24whether the public utility collected, spent, allocated,
25transferred, remitted, or caused in any other way to be

 

 

SB2896- 403 -LRB102 17909 JWD 25989 b

1expended ratepayer funds that were not lawfully recoverable
2through rates, and which should accordingly be refunded to
3ratepayers and calculate such benefits to initiate a refund to
4ratepayers as a result of such conduct. The investigation
5shall conclude no later than 330 days following initiation and
6shall be conducted as a "contested case" as defined in Section
71-30 of the Illinois Administrative Procedure Act.
8    (c) In the event that regulated entities are found guilty
9of criminal conduct, the Commission may initiate an
10investigation, impose penalties, order restitution and such
11other remedies it deems necessary, and initiate refunds to
12ratepayers as described in subsection (b). Such investigation
13and proceeding may commence within 150 days of a finding of
14guilt. Any funds collected pursuant to this subsection shall
15be distributed as described in subsection (e). The Commission
16may order any other remedies it deems necessary.
17    (d) Pursuant to subsection (e), the investigation shall
18calculate a schedule for remittance to State funds and to
19ratepayers, over a period of no more than 4 years, to be paid
20by the public utility from profits, returns, or shareholder
21dollars. No costs related to the investigation or contested
22proceeding authorized by this Section, restitution, or refunds
23may be recoverable through rates.
24    (e) Funds collected pursuant to this Section, for the
25purposes of restitution, shall be repaid by the public utility
26in the following manner: (1) 25% shall be contributed to

 

 

SB2896- 404 -LRB102 17909 JWD 25989 b

1expand the Percentage of Income Payment Program; (2) 25% shall
2be contributed to funding to assist intervenors in Commission
3dockets; and (3) the remaining percentage of funds collected
4shall be provided as a per therm or per-kilowatt-hour credit
5to the public utility's ratepayers.
6    (f) No public utility may use ratepayer funds to pay a
7criminal penalty imposed by any local, State or federal law
8enforcement entity or court.
 
9    (220 ILCS 5/5-117)
10    Sec. 5-117. Supplier diversity goals.
11    (a) The public policy of this State is to collaboratively
12work with companies that serve Illinois residents to improve
13their supplier diversity in a non-antagonistic manner.
14    (b) The Commission shall require all gas, electric, and
15water utilities serving companies with at least 100,000
16customers under its authority, holders of Certificates in Good
17Standing under Section 15-401 of this Act, Alternative Retail
18Electric Suppliers, Alternative Gas Suppliers, and
19utility-scale generators as well as suppliers of wind energy,
20solar energy, hydroelectricity, nuclear energy, and any other
21supplier of energy within this State, to submit annually an
22annual report by April 15, 2015 and every April 15 thereafter,
23in a searchable Adobe PDF format and other formats as
24designated by Commission staff, a report containing all
25information set forth in subsection (c) of this Section. For

 

 

SB2896- 405 -LRB102 17909 JWD 25989 b

1purposes of this Section, the terms "minority person",
2"woman", "person with a disability", "minority-owned
3business", "women-owned business", and "business owned by a
4person with a disability" have the meanings given to those
5terms in Section 2 of the Business Enterprise for Minorities,
6Women, and Persons with Disabilities Act. For purposes of this
7Section, "veteran-owned business" means a business that is at
8least 51% owned by one or more veterans, in the case of a
9corporation, at least 51% of the stock of which is owned by one
10or more veterans, or in the case of a limited liability
11company, at least 51% of the membership interest of which is
12owned by one or more veterans. , on all procurement goals and
13actual spending for female-owned, minority-owned,
14veteran-owned, and small business enterprises in the previous
15calendar year. These goals shall be expressed as a percentage
16of the total work performed by the entity submitting the
17report, and the actual spending for all female-owned,
18minority-owned, veteran-owned, and small business enterprises
19shall also be expressed as a percentage of the total work
20performed by the entity submitting the report.
21    (c) Each reporting entity shall include in its annual
22report participating company in its annual report shall
23include the following information:
24        (0.5) procurement goals and actual spending for
25    women-owned, minority-owned, veteran-owned, and small
26    businesses in the previous calendar year, which shall be

 

 

SB2896- 406 -LRB102 17909 JWD 25989 b

1    expressed as a percentage of the total work performed by
2    the entity submitting the report, and the actual spending
3    for all women-owned, minority-owned, veteran-owned, and
4    small businesses, and business owned by a person with a
5    disability, which shall:
6            (A) be expressed as a percentage of the total work
7        performed by the entity submitting the report, and the
8        actual spending for all women-owned, minority-owned,
9        veteran-owned, and small businesses, and businesses
10        owned a person with a disability; and
11            (B) indicate the types of services provided by
12        category, including but not limited to professional
13        services, financial services, construction,
14        installation, maintenance, other services;
15        (1) an explanation of the plan for the next year to
16    increase participation;
17        (2) an explanation of the plan to increase the goals;
18        (3) the areas of procurement each reporting entity
19    company shall be actively seeking more participation in in
20    the next year;
21        (4) an outline of the plan to alert and encourage
22    potential vendors in that area to seek business from the
23    reporting entity company;
24        (5) an explanation of the challenges faced in finding
25    quality vendors and offer any suggestions for what the
26    Commission could do to be helpful to identify those

 

 

SB2896- 407 -LRB102 17909 JWD 25989 b

1    vendors;
2        (6) a list of the certifications the reporting entity
3    company recognizes;
4        (7) the point of contact for any potential vendor who
5    wishes to do business with the reporting entity company
6    and explain the process for a vendor to enroll with the
7    company as a minority-owned, women-owned, or veteran-owned
8    company; and
9        (8) any particular success stories to encourage other
10    entities companies to emulate as best practices;
11        (9) if the reporting entity is a corporation, the
12    number of minority persons, women and persons with a
13    disability who are directors or officers of the
14    corporation, and the percentage of the total number of
15    directors and officers that minority persons, women and
16    persons with a disability constitute; and
17        (10) if the reporting entity is a limited liability
18    company, the number of minority persons, women and persons
19    with a disability who are members or managers of the
20    limited liability company, and the percentage of the total
21    number of members and managers that minority persons,
22    women and persons with a disability constitute.
23    (d) Each annual report shall provide include as much
24State-specific data in reporting the information required in
25subsection (c) as possible. If the submitting entity does not
26submit State-specific data, then the company shall include any

 

 

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1national data it does have and explain why it could not submit
2State-specific data and how it intends to do so in future
3reports, if possible.
4    (e) Each annual report shall include the rules,
5regulations, and definitions used for the procurement goals in
6the company's annual report.
7    (e-5) If any entity required to submit an annual report
8under this Section fails to submit its report as prescribed in
9subsection (b), the Commission shall assess a penalty of $100
10per day for each day that the entity fails to submit its report
11after the date upon which it is due to be filed. If the entity
12fails to submit an annual report within 120 days after the date
13upon which it is due, the Commission may suspend or revoke any
14license, certificate or other authority issued by the
15Commission that the entity holds or possesses.
16    (f) The Commission and all reporting participating
17entities shall hold an annual workshop open to the public in
182015 and every year thereafter on the state of supplier
19diversity to collaboratively seek solutions to structural
20impediments to achieving stated goals, including testimony
21from each participating entity as well as subject matter
22experts and advocates. The Commission shall publish a database
23on its website of the point of contact for each participating
24entity for supplier diversity, along with a list of
25certifications each company recognizes from the information
26submitted in each annual report. The Commission shall publish

 

 

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1each annual report on its website and shall maintain each
2annual report for at least 5 years.
3(Source: P.A. 98-1056, eff. 8-26-14; 99-906, eff. 6-1-17;
4revised 7-22-19.)
 
5    (220 ILCS 5/8-103B)
6    Sec. 8-103B. Energy efficiency and demand-response
7measures.
8    (a) It is the policy of the State that electric utilities
9are required to use cost-effective energy efficiency and
10demand-response measures to reduce delivery load. Requiring
11investment in cost-effective energy efficiency and
12demand-response measures will reduce direct and indirect costs
13to consumers by decreasing environmental impacts and by
14avoiding or delaying the need for new generation,
15transmission, and distribution infrastructure. It serves the
16public interest to allow electric utilities to recover costs
17for reasonably and prudently incurred expenditures for energy
18efficiency and demand-response measures. As used in this
19Section, "cost-effective" means that the measures satisfy the
20total resource cost test. The low-income measures described in
21subsection (c) of this Section shall not be required to meet
22the total resource cost test. For purposes of this Section,
23the terms "energy-efficiency", "demand-response", "electric
24utility", and "total resource cost test" have the meanings set
25forth in the Illinois Power Agency Act.

 

 

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1    (a-5) This Section applies to electric utilities serving
2more than 500,000 retail customers in the State for those
3multi-year plans commencing after December 31, 2017.
4    (b) For purposes of this Section, electric utilities
5subject to this Section that serve more than 3,000,000 retail
6customers in the State shall be deemed to have achieved a
7cumulative persisting annual savings of 6.6% from energy
8efficiency measures and programs implemented during the period
9beginning January 1, 2012 and ending December 31, 2017, which
10percent is based on the deemed average weather normalized
11sales of electric power and energy during calendar years 2014,
122015, and 2016 of 88,000,000 MWhs. For the purposes of this
13subsection (b) and subsection (b-5), the 88,000,000 MWhs of
14deemed electric power and energy sales shall be reduced by the
15number of MWhs equal to the sum of the annual consumption of
16customers that have opted out of are exempt from subsections
17(a) through (j) of this Section under paragraph (1) of
18subsection (l) of this Section, as averaged across the
19calendar years 2014, 2015, and 2016. After 2017, the deemed
20value of cumulative persisting annual savings from energy
21efficiency measures and programs implemented during the period
22beginning January 1, 2012 and ending December 31, 2017, shall
23be reduced each year, as follows, and the applicable value
24shall be applied to and count toward the utility's achievement
25of the cumulative persisting annual savings goals set forth in
26subsection (b-5):

 

 

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1        (1) 5.8% deemed cumulative persisting annual savings
2    for the year ending December 31, 2018;
3        (2) 5.2% deemed cumulative persisting annual savings
4    for the year ending December 31, 2019;
5        (3) 4.5% deemed cumulative persisting annual savings
6    for the year ending December 31, 2020;
7        (4) 4.0% deemed cumulative persisting annual savings
8    for the year ending December 31, 2021;
9        (5) 3.5% deemed cumulative persisting annual savings
10    for the year ending December 31, 2022;
11        (6) 3.1% deemed cumulative persisting annual savings
12    for the year ending December 31, 2023;
13        (7) 2.8% deemed cumulative persisting annual savings
14    for the year ending December 31, 2024;
15        (8) 2.5% deemed cumulative persisting annual savings
16    for the year ending December 31, 2025;
17        (9) 2.3% deemed cumulative persisting annual savings
18    for the year ending December 31, 2026;
19        (10) 2.1% deemed cumulative persisting annual savings
20    for the year ending December 31, 2027;
21        (11) 1.8% deemed cumulative persisting annual savings
22    for the year ending December 31, 2028;
23        (12) 1.7% deemed cumulative persisting annual savings
24    for the year ending December 31, 2029; and
25        (13) 1.5% deemed cumulative persisting annual savings
26    for the year ending December 31, 2030.

 

 

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1    For purposes of this Section, "cumulative persisting
2annual savings" means the total electric energy savings in a
3given year from measures installed in that year or in previous
4years, but no earlier than January 1, 2012, that are still
5operational and providing savings in that year because the
6measures have not yet reached the end of their useful lives.
7    (b-5) Beginning in 2018, electric utilities subject to
8this Section that serve more than 3,000,000 retail customers
9in the State shall achieve the following cumulative persisting
10annual savings goals, as modified by subsection (f) of this
11Section and as compared to the deemed baseline of 88,000,000
12MWhs of electric power and energy sales set forth in
13subsection (b), as reduced by the number of MWhs equal to the
14sum of the annual consumption of customers that have opted out
15of are exempt from subsections (a) through (j) of this Section
16under paragraph (1) of subsection (l) of this Section as
17averaged across the calendar years 2014, 2015, and 2016,
18through the implementation of energy efficiency measures
19during the applicable year and in prior years, but no earlier
20than January 1, 2012:
21        (1) 7.8% cumulative persisting annual savings for the
22    year ending December 31, 2018;
23        (2) 9.1% cumulative persisting annual savings for the
24    year ending December 31, 2019;
25        (3) 10.4% cumulative persisting annual savings for the
26    year ending December 31, 2020;

 

 

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1        (4) 11.8% cumulative persisting annual savings for the
2    year ending December 31, 2021;
3        (5) 13.1% cumulative persisting annual savings for the
4    year ending December 31, 2022;
5        (6) 14.4% cumulative persisting annual savings for the
6    year ending December 31, 2023;
7        (7) 15.7% cumulative persisting annual savings for the
8    year ending December 31, 2024;
9        (8) 17% cumulative persisting annual savings for the
10    year ending December 31, 2025;
11        (9) 17.9% cumulative persisting annual savings for the
12    year ending December 31, 2026;
13        (10) 18.8% cumulative persisting annual savings for
14    the year ending December 31, 2027;
15        (11) 19.7% cumulative persisting annual savings for
16    the year ending December 31, 2028;
17        (12) 20.6% cumulative persisting annual savings for
18    the year ending December 31, 2029; and
19        (13) 21.5% cumulative persisting annual savings for
20    the year ending December 31, 2030.
21    (b-10) For purposes of this Section, electric utilities
22subject to this Section that serve less than 3,000,000 retail
23customers but more than 500,000 retail customers in the State
24shall be deemed to have achieved a cumulative persisting
25annual savings of 6.6% from energy efficiency measures and
26programs implemented during the period beginning January 1,

 

 

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12012 and ending December 31, 2017, which is based on the deemed
2average weather normalized sales of electric power and energy
3during calendar years 2014, 2015, and 2016 of 36,900,000 MWhs.
4For the purposes of this subsection (b-10) and subsection
5(b-15), the 36,900,000 MWhs of deemed electric power and
6energy sales shall be reduced by the number of MWhs equal to
7the sum of the annual consumption of customers that have opted
8out of are exempt from subsections (a) through (j) of this
9Section under paragraph (1) of subsection (l) of this Section,
10as averaged across the calendar years 2014, 2015, and 2016.
11After 2017, the deemed value of cumulative persisting annual
12savings from energy efficiency measures and programs
13implemented during the period beginning January 1, 2012 and
14ending December 31, 2017, shall be reduced each year, as
15follows, and the applicable value shall be applied to and
16count toward the utility's achievement of the cumulative
17persisting annual savings goals set forth in subsection
18(b-15):
19        (1) 5.8% deemed cumulative persisting annual savings
20    for the year ending December 31, 2018;
21        (2) 5.2% deemed cumulative persisting annual savings
22    for the year ending December 31, 2019;
23        (3) 4.5% deemed cumulative persisting annual savings
24    for the year ending December 31, 2020;
25        (4) 4.0% deemed cumulative persisting annual savings
26    for the year ending December 31, 2021;

 

 

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1        (5) 3.5% deemed cumulative persisting annual savings
2    for the year ending December 31, 2022;
3        (6) 3.1% deemed cumulative persisting annual savings
4    for the year ending December 31, 2023;
5        (7) 2.8% deemed cumulative persisting annual savings
6    for the year ending December 31, 2024;
7        (8) 2.5% deemed cumulative persisting annual savings
8    for the year ending December 31, 2025;
9        (9) 2.3% deemed cumulative persisting annual savings
10    for the year ending December 31, 2026;
11        (10) 2.1% deemed cumulative persisting annual savings
12    for the year ending December 31, 2027;
13        (11) 1.8% deemed cumulative persisting annual savings
14    for the year ending December 31, 2028;
15        (12) 1.7% deemed cumulative persisting annual savings
16    for the year ending December 31, 2029; and
17        (13) 1.5% deemed cumulative persisting annual savings
18    for the year ending December 31, 2030.
19    (b-15) Beginning in 2018, electric utilities subject to
20this Section that serve less than 3,000,000 retail customers
21but more than 500,000 retail customers in the State shall
22achieve the following cumulative persisting annual savings
23goals, as modified by subsection (b-20) and subsection (f) of
24this Section and as compared to the deemed baseline as reduced
25by the number of MWhs equal to the sum of the annual
26consumption of customers that have opted out of are exempt

 

 

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1from subsections (a) through (j) of this Section under
2paragraph (1) of subsection (l) of this Section as averaged
3across the calendar years 2014, 2015, and 2016, through the
4implementation of energy efficiency measures during the
5applicable year and in prior years, but no earlier than
6January 1, 2012:
7        (1) 7.4% cumulative persisting annual savings for the
8    year ending December 31, 2018;
9        (2) 8.2% cumulative persisting annual savings for the
10    year ending December 31, 2019;
11        (3) 9.0% cumulative persisting annual savings for the
12    year ending December 31, 2020;
13        (4) 9.8% cumulative persisting annual savings for the
14    year ending December 31, 2021;
15        (5) 10.6% cumulative persisting annual savings for the
16    year ending December 31, 2022;
17        (6) 11.4% cumulative persisting annual savings for the
18    year ending December 31, 2023;
19        (7) 12.2% cumulative persisting annual savings for the
20    year ending December 31, 2024;
21        (8) 13% cumulative persisting annual savings for the
22    year ending December 31, 2025;
23        (9) 13.6% cumulative persisting annual savings for the
24    year ending December 31, 2026;
25        (10) 14.2% cumulative persisting annual savings for
26    the year ending December 31, 2027;

 

 

SB2896- 417 -LRB102 17909 JWD 25989 b

1        (11) 14.8% cumulative persisting annual savings for
2    the year ending December 31, 2028;
3        (12) 15.4% cumulative persisting annual savings for
4    the year ending December 31, 2029; and
5        (13) 16% cumulative persisting annual savings for the
6    year ending December 31, 2030.
7    The difference between the cumulative persisting annual
8savings goal for the applicable calendar year and the
9cumulative persisting annual savings goal for the immediately
10preceding calendar year is 0.8% for the period of January 1,
112018 through December 31, 2025 and 0.6% for the period of
12January 1, 2026 through December 31, 2030.
13    (b-20) Each electric utility subject to this Section may
14include cost-effective voltage optimization measures in its
15plans submitted under subsections (f) and (g) of this Section,
16and the costs incurred by a utility to implement the measures
17under a Commission-approved plan shall be recovered under the
18provisions of Article IX or Section 16-108.5 of this Act. For
19purposes of this Section, the measure life of voltage
20optimization measures shall be 15 years. The measure life
21period is independent of the depreciation rate of the voltage
22optimization assets deployed.
23    Within 270 days after June 1, 2017 (the effective date of
24Public Act 99-906), an electric utility that serves less than
253,000,000 retail customers but more than 500,000 retail
26customers in the State shall file a plan with the Commission

 

 

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1that identifies the cost-effective voltage optimization
2investment the electric utility plans to undertake through
3December 31, 2024. The Commission, after notice and hearing,
4shall approve or approve with modification the plan within 120
5days after the plan's filing and, in the order approving or
6approving with modification the plan, the Commission shall
7adjust the applicable cumulative persisting annual savings
8goals set forth in subsection (b-15) to reflect any amount of
9cost-effective energy savings approved by the Commission that
10is greater than or less than the following cumulative
11persisting annual savings values attributable to voltage
12optimization for the applicable year:
13        (1) 0.0% of cumulative persisting annual savings for
14    the year ending December 31, 2018;
15        (2) 0.17% of cumulative persisting annual savings for
16    the year ending December 31, 2019;
17        (3) 0.17% of cumulative persisting annual savings for
18    the year ending December 31, 2020;
19        (4) 0.33% of cumulative persisting annual savings for
20    the year ending December 31, 2021;
21        (5) 0.5% of cumulative persisting annual savings for
22    the year ending December 31, 2022;
23        (6) 0.67% of cumulative persisting annual savings for
24    the year ending December 31, 2023;
25        (7) 0.83% of cumulative persisting annual savings for
26    the year ending December 31, 2024; and

 

 

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1        (8) 1.0% of cumulative persisting annual savings for
2    the year ending December 31, 2025.
3    (b-25) In the event an electric utility jointly offers an
4energy efficiency measure or program with a gas utility under
5plans approved under this Section and Section 8-104 of this
6Act, the electric utility may continue offering the program,
7including the gas energy efficiency measures, in the event the
8gas utility discontinues funding the program. In that event,
9the energy savings value associated with such other fuels
10shall be converted to electric energy savings on an equivalent
11Btu basis for the premises. However, the electric utility
12shall prioritize programs for low-income residential customers
13to the extent practicable. An electric utility may recover the
14costs of offering the gas energy efficiency measures under
15this subsection (b-25).
16    For those energy efficiency measures or programs that save
17both electricity and other fuels but are not jointly offered
18with a gas utility under plans approved under this Section and
19Section 8-104 or not offered with an affiliated gas utility
20under paragraph (6) of subsection (f) of Section 8-104 of this
21Act, the electric utility may count savings of fuels other
22than electricity toward the achievement of its annual savings
23goal, and the energy savings value associated with such other
24fuels shall be converted to electric energy savings on an
25equivalent Btu basis at the premises.
26    In no event shall more than 10% of each year's applicable

 

 

SB2896- 420 -LRB102 17909 JWD 25989 b

1annual incremental goal as defined in paragraph (7) of
2subsection (g) of this Section be met through savings of fuels
3other than electricity.
4    (c) Electric utilities shall be responsible for overseeing
5the design, development, and filing of energy efficiency plans
6with the Commission and may, as part of that implementation,
7outsource various aspects of program development and
8implementation. A minimum of 10%, for electric utilities that
9serve more than 3,000,000 retail customers in the State, and a
10minimum of 7%, for electric utilities that serve less than
113,000,000 retail customers but more than 500,000 retail
12customers in the State, of the utility's entire portfolio
13funding level for a given year shall be used to procure
14cost-effective energy efficiency measures from units of local
15government, municipal corporations, school districts, public
16housing, and community college districts, provided that a
17minimum percentage of available funds shall be used to procure
18energy efficiency from public housing, which percentage shall
19be equal to public housing's share of public building energy
20consumption.
21    The utilities shall also implement energy efficiency
22measures specifically dedicated to targeted at low-income
23households, which, for purposes of this Section, shall be
24defined as households at or below 80% of area median income,
25and expenditures to implement the measures shall be no less
26than 25% of the total portfolio budget $25,000,000 per year

 

 

SB2896- 421 -LRB102 17909 JWD 25989 b

1for electric utilities that serve more than 3,000,000 retail
2customers in the State and no less than 25% of the total
3portfolio budget $8,350,000 per year for electric utilities
4that serve less than 3,000,000 retail customers but more than
5500,000 retail customers in the State. The 25% budget shall
6exclude any portfolio-level and research and development
7budget costs.
8    Each electric utility shall assess opportunities to
9implement cost-effective energy efficiency measures and
10programs through a public housing authority or authorities
11located in its service territory. If such opportunities are
12identified, the utility shall propose such measures and
13programs to address the opportunities. Expenditures to address
14such opportunities shall be credited toward the minimum
15procurement and expenditure requirements set forth in this
16subsection (c).
17    Implementation of energy efficiency measures and programs
18targeted at low-income households should be contracted, when
19it is practicable, to independent third parties that have
20demonstrated capabilities to serve such households, with a
21preference for not-for-profit entities and government agencies
22that have existing relationships with or experience serving
23low-income communities in the State.
24    Each electric utility shall develop and implement
25reporting procedures that address and assist in determining
26the amount of energy savings that can be applied to the

 

 

SB2896- 422 -LRB102 17909 JWD 25989 b

1low-income procurement and expenditure requirements set forth
2in this subsection (c).
3    The electric utilities shall also convene a low-income
4energy efficiency advisory committee to assist in the design
5and evaluation of the low-income energy efficiency programs.
6The committee shall be comprised of the electric utilities
7subject to the requirements of this Section, the gas utilities
8subject to the requirements of Section 8-104 of this Act, the
9utilities' low-income energy efficiency implementation
10contractors, and representatives of community-based
11organizations.
12    (d) Notwithstanding any other provision of law to the
13contrary, a utility providing approved energy efficiency
14measures and, if applicable, demand-response measures in the
15State shall be permitted to recover all reasonable and
16prudently incurred costs of those measures from all retail
17customers, except as provided in subsection (l) of this
18Section, as follows, provided that nothing in this subsection
19(d) permits the double recovery of such costs from customers:
20        (1) The utility may recover its costs through an
21    automatic adjustment clause tariff filed with and approved
22    by the Commission. The tariff shall be established outside
23    the context of a general rate case. Each year the
24    Commission shall initiate a review to reconcile any
25    amounts collected with the actual costs and to determine
26    the required adjustment to the annual tariff factor to

 

 

SB2896- 423 -LRB102 17909 JWD 25989 b

1    match annual expenditures. To enable the financing of the
2    incremental capital expenditures, including regulatory
3    assets, for electric utilities that serve less than
4    3,000,000 retail customers but more than 500,000 retail
5    customers in the State, the utility's actual year-end
6    capital structure that includes a common equity ratio,
7    excluding goodwill, of up to and including 50% of the
8    total capital structure shall be deemed reasonable and
9    used to set rates.
10        (2) A utility may recover its costs through an energy
11    efficiency formula rate approved by the Commission under a
12    filing under subsections (f) and (g) of this Section,
13    which shall specify the cost components that form the
14    basis of the rate charged to customers with sufficient
15    specificity to operate in a standardized manner and be
16    updated annually with transparent information that
17    reflects the utility's actual costs to be recovered during
18    the applicable rate year, which is the period beginning
19    with the first billing day of January and extending
20    through the last billing day of the following December.
21    The energy efficiency formula rate shall be implemented
22    through a tariff filed with the Commission under
23    subsections (f) and (g) of this Section that is consistent
24    with the provisions of this paragraph (2) and that shall
25    be applicable to all delivery services customers. The
26    Commission shall conduct an investigation of the tariff in

 

 

SB2896- 424 -LRB102 17909 JWD 25989 b

1    a manner consistent with the provisions of this paragraph
2    (2), subsections (f) and (g) of this Section, and the
3    provisions of Article IX of this Act to the extent they do
4    not conflict with this paragraph (2). The energy
5    efficiency formula rate approved by the Commission shall
6    remain in effect at the discretion of the utility and
7    shall do the following:
8            (A) Provide for the recovery of the utility's
9        actual costs incurred under this Section that are
10        prudently incurred and reasonable in amount consistent
11        with Commission practice and law. The sole fact that a
12        cost differs from that incurred in a prior calendar
13        year or that an investment is different from that made
14        in a prior calendar year shall not imply the
15        imprudence or unreasonableness of that cost or
16        investment.
17            (B) Reflect the utility's actual year-end capital
18        structure for the applicable calendar year, excluding
19        goodwill, subject to a determination of prudence and
20        reasonableness consistent with Commission practice and
21        law. To enable the financing of the incremental
22        capital expenditures, including regulatory assets, for
23        electric utilities that serve less than 3,000,000
24        retail customers but more than 500,000 retail
25        customers in the State, a participating electric
26        utility's actual year-end capital structure that

 

 

SB2896- 425 -LRB102 17909 JWD 25989 b

1        includes a common equity ratio, excluding goodwill, of
2        up to and including 50% of the total capital structure
3        shall be deemed reasonable and used to set rates.
4            (C) Include a cost of equity, which shall be
5        calculated as the sum of the following:
6                (i) the average for the applicable calendar
7            year of the monthly average yields of 30-year U.S.
8            Treasury bonds published by the Board of Governors
9            of the Federal Reserve System in its weekly H.15
10            Statistical Release or successor publication; and
11                (ii) 580 basis points.
12            At such time as the Board of Governors of the
13        Federal Reserve System ceases to include the monthly
14        average yields of 30-year U.S. Treasury bonds in its
15        weekly H.15 Statistical Release or successor
16        publication, the monthly average yields of the U.S.
17        Treasury bonds then having the longest duration
18        published by the Board of Governors in its weekly H.15
19        Statistical Release or successor publication shall
20        instead be used for purposes of this paragraph (2).
21            (D) Permit and set forth protocols, subject to a
22        determination of prudence and reasonableness
23        consistent with Commission practice and law, for the
24        following:
25                (i) recovery of incentive compensation expense
26            that is based on the achievement of operational

 

 

SB2896- 426 -LRB102 17909 JWD 25989 b

1            metrics, including metrics related to budget
2            controls, outage duration and frequency, safety,
3            customer service, efficiency and productivity, and
4            environmental compliance; however, this protocol
5            shall not apply if such expense related to costs
6            incurred under this Section is recovered under
7            Article IX or Section 16-108.5 of this Act;
8            incentive compensation expense that is based on
9            net income or an affiliate's earnings per share
10            shall not be recoverable under the energy
11            efficiency formula rate;
12                (ii) recovery of pension and other
13            post-employment benefits expense, provided that
14            such costs are supported by an actuarial study;
15            however, this protocol shall not apply if such
16            expense related to costs incurred under this
17            Section is recovered under Article IX or Section
18            16-108.5 of this Act;
19                (iii) recovery of existing regulatory assets
20            over the periods previously authorized by the
21            Commission;
22                (iv) as described in subsection (e),
23            amortization of costs incurred under this Section;
24            and
25                (v) projected, weather normalized billing
26            determinants for the applicable rate year.

 

 

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1            (E) Provide for an annual reconciliation, as
2        described in paragraph (3) of this subsection (d),
3        less any deferred taxes related to the reconciliation,
4        with interest at an annual rate of return equal to the
5        utility's weighted average cost of capital, including
6        a revenue conversion factor calculated to recover or
7        refund all additional income taxes that may be payable
8        or receivable as a result of that return, of the energy
9        efficiency revenue requirement reflected in rates for
10        each calendar year, beginning with the calendar year
11        in which the utility files its energy efficiency
12        formula rate tariff under this paragraph (2), with
13        what the revenue requirement would have been had the
14        actual cost information for the applicable calendar
15        year been available at the filing date.
16        The utility shall file, together with its tariff, the
17    projected costs to be incurred by the utility during the
18    rate year under the utility's multi-year plan approved
19    under subsections (f) and (g) of this Section, including,
20    but not limited to, the projected capital investment costs
21    and projected regulatory asset balances with
22    correspondingly updated depreciation and amortization
23    reserves and expense, that shall populate the energy
24    efficiency formula rate and set the initial rates under
25    the formula.
26        The Commission shall review the proposed tariff in

 

 

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1    conjunction with its review of a proposed multi-year plan,
2    as specified in paragraph (5) of subsection (g) of this
3    Section. The review shall be based on the same evidentiary
4    standards, including, but not limited to, those concerning
5    the prudence and reasonableness of the costs incurred by
6    the utility, the Commission applies in a hearing to review
7    a filing for a general increase in rates under Article IX
8    of this Act. The initial rates shall take effect beginning
9    with the January monthly billing period following the
10    Commission's approval.
11        The tariff's rate design and cost allocation across
12    customer classes shall be consistent with the utility's
13    automatic adjustment clause tariff in effect on June 1,
14    2017 (the effective date of Public Act 99-906); however,
15    the Commission may revise the tariff's rate design and
16    cost allocation in subsequent proceedings under paragraph
17    (3) of this subsection (d).
18        If the energy efficiency formula rate is terminated,
19    the then current rates shall remain in effect until such
20    time as the energy efficiency costs are incorporated into
21    new rates that are set under this subsection (d) or
22    Article IX of this Act, subject to retroactive rate
23    adjustment, with interest, to reconcile rates charged with
24    actual costs.
25        (3) The provisions of this paragraph (3) shall only
26    apply to an electric utility that has elected to file an

 

 

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1    energy efficiency formula rate under paragraph (2) of this
2    subsection (d). Subsequent to the Commission's issuance of
3    an order approving the utility's energy efficiency formula
4    rate structure and protocols, and initial rates under
5    paragraph (2) of this subsection (d), the utility shall
6    file, on or before June 1 of each year, with the Chief
7    Clerk of the Commission its updated cost inputs to the
8    energy efficiency formula rate for the applicable rate
9    year and the corresponding new charges, as well as the
10    information described in paragraph (9) of subsection (g)
11    of this Section. Each such filing shall conform to the
12    following requirements and include the following
13    information:
14            (A) The inputs to the energy efficiency formula
15        rate for the applicable rate year shall be based on the
16        projected costs to be incurred by the utility during
17        the rate year under the utility's multi-year plan
18        approved under subsections (f) and (g) of this
19        Section, including, but not limited to, projected
20        capital investment costs and projected regulatory
21        asset balances with correspondingly updated
22        depreciation and amortization reserves and expense.
23        The filing shall also include a reconciliation of the
24        energy efficiency revenue requirement that was in
25        effect for the prior rate year (as set by the cost
26        inputs for the prior rate year) with the actual

 

 

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1        revenue requirement for the prior rate year
2        (determined using a year-end rate base) that uses
3        amounts reflected in the applicable FERC Form 1 that
4        reports the actual costs for the prior rate year. Any
5        over-collection or under-collection indicated by such
6        reconciliation shall be reflected as a credit against,
7        or recovered as an additional charge to, respectively,
8        with interest calculated at a rate equal to the
9        utility's weighted average cost of capital approved by
10        the Commission for the prior rate year, the charges
11        for the applicable rate year. Such over-collection or
12        under-collection shall be adjusted to remove any
13        deferred taxes related to the reconciliation, for
14        purposes of calculating interest at an annual rate of
15        return equal to the utility's weighted average cost of
16        capital approved by the Commission for the prior rate
17        year, including a revenue conversion factor calculated
18        to recover or refund all additional income taxes that
19        may be payable or receivable as a result of that
20        return. Each reconciliation shall be certified by the
21        participating utility in the same manner that FERC
22        Form 1 is certified. The filing shall also include the
23        charge or credit, if any, resulting from the
24        calculation required by subparagraph (E) of paragraph
25        (2) of this subsection (d).
26            Notwithstanding any other provision of law to the

 

 

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1        contrary, the intent of the reconciliation is to
2        ultimately reconcile both the revenue requirement
3        reflected in rates for each calendar year, beginning
4        with the calendar year in which the utility files its
5        energy efficiency formula rate tariff under paragraph
6        (2) of this subsection (d), with what the revenue
7        requirement determined using a year-end rate base for
8        the applicable calendar year would have been had the
9        actual cost information for the applicable calendar
10        year been available at the filing date.
11            For purposes of this Section, "FERC Form 1" means
12        the Annual Report of Major Electric Utilities,
13        Licensees and Others that electric utilities are
14        required to file with the Federal Energy Regulatory
15        Commission under the Federal Power Act, Sections 3,
16        4(a), 304 and 209, modified as necessary to be
17        consistent with 83 Ill. Admin. Code Part 415 as of May
18        1, 2011. Nothing in this Section is intended to allow
19        costs that are not otherwise recoverable to be
20        recoverable by virtue of inclusion in FERC Form 1.
21            (B) The new charges shall take effect beginning on
22        the first billing day of the following January billing
23        period and remain in effect through the last billing
24        day of the next December billing period regardless of
25        whether the Commission enters upon a hearing under
26        this paragraph (3).

 

 

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1            (C) The filing shall include relevant and
2        necessary data and documentation for the applicable
3        rate year. Normalization adjustments shall not be
4        required.
5        Within 45 days after the utility files its annual
6    update of cost inputs to the energy efficiency formula
7    rate, the Commission shall with reasonable notice,
8    initiate a proceeding concerning whether the projected
9    costs to be incurred by the utility and recovered during
10    the applicable rate year, and that are reflected in the
11    inputs to the energy efficiency formula rate, are
12    consistent with the utility's approved multi-year plan
13    under subsections (f) and (g) of this Section and whether
14    the costs incurred by the utility during the prior rate
15    year were prudent and reasonable. The Commission shall
16    also have the authority to investigate the information and
17    data described in paragraph (9) of subsection (g) of this
18    Section, including the proposed adjustment to the
19    utility's return on equity component of its weighted
20    average cost of capital. During the course of the
21    proceeding, each objection shall be stated with
22    particularity and evidence provided in support thereof,
23    after which the utility shall have the opportunity to
24    rebut the evidence. Discovery shall be allowed consistent
25    with the Commission's Rules of Practice, which Rules of
26    Practice shall be enforced by the Commission or the

 

 

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1    assigned administrative law judge. The Commission shall
2    apply the same evidentiary standards, including, but not
3    limited to, those concerning the prudence and
4    reasonableness of the costs incurred by the utility,
5    during the proceeding as it would apply in a proceeding to
6    review a filing for a general increase in rates under
7    Article IX of this Act. The Commission shall not, however,
8    have the authority in a proceeding under this paragraph
9    (3) to consider or order any changes to the structure or
10    protocols of the energy efficiency formula rate approved
11    under paragraph (2) of this subsection (d). In a
12    proceeding under this paragraph (3), the Commission shall
13    enter its order no later than the earlier of 195 days after
14    the utility's filing of its annual update of cost inputs
15    to the energy efficiency formula rate or December 15. The
16    utility's proposed return on equity calculation, as
17    described in paragraphs (7) through (9) of subsection (g)
18    of this Section, shall be deemed the final, approved
19    calculation on December 15 of the year in which it is filed
20    unless the Commission enters an order on or before
21    December 15, after notice and hearing, that modifies such
22    calculation consistent with this Section. The Commission's
23    determinations of the prudence and reasonableness of the
24    costs incurred, and determination of such return on equity
25    calculation, for the applicable calendar year shall be
26    final upon entry of the Commission's order and shall not

 

 

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1    be subject to reopening, reexamination, or collateral
2    attack in any other Commission proceeding, case, docket,
3    order, rule, or regulation; however, nothing in this
4    paragraph (3) shall prohibit a party from petitioning the
5    Commission to rehear or appeal to the courts the order
6    under the provisions of this Act.
7    (e) Beginning on June 1, 2017 (the effective date of
8Public Act 99-906), a utility subject to the requirements of
9this Section may elect to defer, as a regulatory asset, up to
10the full amount of its expenditures incurred under this
11Section for each annual period, including, but not limited to,
12any expenditures incurred above the funding level set by
13subsection (f) of this Section for a given year. The total
14expenditures deferred as a regulatory asset in a given year
15shall be amortized and recovered over a period that is equal to
16the weighted average of the energy efficiency measure lives
17implemented for that year that are reflected in the regulatory
18asset. The unamortized balance shall be recognized as of
19December 31 for a given year. The utility shall also earn a
20return on the total of the unamortized balances of all of the
21energy efficiency regulatory assets, less any deferred taxes
22related to those unamortized balances, at an annual rate equal
23to the utility's weighted average cost of capital that
24includes, based on a year-end capital structure, the utility's
25actual cost of debt for the applicable calendar year and a cost
26of equity, which shall be calculated as the sum of the (i) the

 

 

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1average for the applicable calendar year of the monthly
2average yields of 30-year U.S. Treasury bonds published by the
3Board of Governors of the Federal Reserve System in its weekly
4H.15 Statistical Release or successor publication; and (ii)
5580 basis points, including a revenue conversion factor
6calculated to recover or refund all additional income taxes
7that may be payable or receivable as a result of that return.
8Capital investment costs shall be depreciated and recovered
9over their useful lives consistent with generally accepted
10accounting principles. The weighted average cost of capital
11shall be applied to the capital investment cost balance, less
12any accumulated depreciation and accumulated deferred income
13taxes, as of December 31 for a given year.
14    When an electric utility creates a regulatory asset under
15the provisions of this Section, the costs are recovered over a
16period during which customers also receive a benefit which is
17in the public interest. Accordingly, it is the intent of the
18General Assembly that an electric utility that elects to
19create a regulatory asset under the provisions of this Section
20shall recover all of the associated costs as set forth in this
21Section. After the Commission has approved the prudence and
22reasonableness of the costs that comprise the regulatory
23asset, the electric utility shall be permitted to recover all
24such costs, and the value and recoverability through rates of
25the associated regulatory asset shall not be limited, altered,
26impaired, or reduced.

 

 

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1    (f) Beginning in 2017, each electric utility shall file an
2energy efficiency plan with the Commission to meet the energy
3efficiency standards for the next applicable multi-year period
4beginning January 1 of the year following the filing,
5according to the schedule set forth in paragraphs (1) through
6(3) of this subsection (f). If a utility does not file such a
7plan on or before the applicable filing deadline for the plan,
8it shall face a penalty of $100,000 per day until the plan is
9filed.
10        (1) No later than 30 days after June 1, 2017 (the
11    effective date of Public Act 99-906), each electric
12    utility shall file a 4-year energy efficiency plan
13    commencing on January 1, 2018 that is designed to achieve
14    the cumulative persisting annual savings goals specified
15    in paragraphs (1) through (4) of subsection (b-5) of this
16    Section or in paragraphs (1) through (4) of subsection
17    (b-15) of this Section, as applicable, through
18    implementation of energy efficiency measures; however, the
19    goals may be reduced if the utility's expenditures are
20    limited pursuant to subsection (m) of this Section or, for
21    a utility that serves less than 3,000,000 retail
22    customers, if each of the following conditions are met:
23    (A) the plan's analysis and forecasts of the utility's
24    ability to acquire energy savings demonstrate that
25    achievement of such goals is not cost effective; and (B)
26    the amount of energy savings achieved by the utility as

 

 

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1    determined by the independent evaluator for the most
2    recent year for which savings have been evaluated
3    preceding the plan filing was less than the average annual
4    amount of savings required to achieve the goals for the
5    applicable 4-year plan period. Except as provided in
6    subsection (m) of this Section, annual increases in
7    cumulative persisting annual savings goals during the
8    applicable 4-year plan period shall not be reduced to
9    amounts that are less than the maximum amount of
10    cumulative persisting annual savings that is forecast to
11    be cost-effectively achievable during the 4-year plan
12    period. The Commission shall review any proposed goal
13    reduction as part of its review and approval of the
14    utility's proposed plan.
15        (2) No later than March 1, 2021, each electric utility
16    shall file a 4-year energy efficiency plan commencing on
17    January 1, 2022 that is designed to achieve the cumulative
18    persisting annual savings goals specified in paragraphs
19    (5) through (8) of subsection (b-5) of this Section or in
20    paragraphs (5) through (8) of subsection (b-15) of this
21    Section, as applicable, through implementation of energy
22    efficiency measures; however, the goals may be reduced if
23    the utility's expenditures are limited pursuant to
24    subsection (m) of this Section or, each of the following
25    conditions are met: (A) the plan's analysis and forecasts
26    of the utility's ability to acquire energy savings

 

 

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1    demonstrate that achievement of such goals is not cost
2    effective; and (B) the amount of energy savings achieved
3    by the utility as determined by the independent evaluator
4    for the most recent year for which savings have been
5    evaluated preceding the plan filing was less than the
6    average annual amount of savings required to achieve the
7    goals for the applicable 4-year plan period. Except as
8    provided in subsection (m) of this Section, annual
9    increases in cumulative persisting annual savings goals
10    during the applicable 4-year plan period shall not be
11    reduced to amounts that are less than the maximum amount
12    of cumulative persisting annual savings that is forecast
13    to be cost-effectively achievable during the 4-year plan
14    period. The Commission shall review any proposed goal
15    reduction as part of its review and approval of the
16    utility's proposed plan.
17        (3) No later than March 1, 2025, each electric utility
18    shall file a 5-year energy efficiency plan commencing on
19    January 1, 2026 that is designed to achieve the cumulative
20    persisting annual savings goals specified in paragraphs
21    (9) through (13) of subsection (b-5) of this Section or in
22    paragraphs (9) through (13) of subsection (b-15) of this
23    Section, as applicable, through implementation of energy
24    efficiency measures; however, the goals may be reduced if
25    the utility's expenditures are limited pursuant to
26    subsection (m) of this Section or, each of the following

 

 

SB2896- 439 -LRB102 17909 JWD 25989 b

1    conditions are met: (A) the plan's analysis and forecasts
2    of the utility's ability to acquire energy savings
3    demonstrate that achievement of such goals is not cost
4    effective; and (B) the amount of energy savings achieved
5    by the utility as determined by the independent evaluator
6    for the most recent year for which savings have been
7    evaluated preceding the plan filing was less than the
8    average annual amount of savings required to achieve the
9    goals for the applicable 5-year plan period. Except as
10    provided in subsection (m) of this Section, annual
11    increases in cumulative persisting annual savings goals
12    during the applicable 5-year plan period shall not be
13    reduced to amounts that are less than the maximum amount
14    of cumulative persisting annual savings that is forecast
15    to be cost-effectively achievable during the 5-year plan
16    period. The Commission shall review any proposed goal
17    reduction as part of its review and approval of the
18    utility's proposed plan.
19    Each utility's plan shall set forth the utility's
20proposals to meet the energy efficiency standards identified
21in subsection (b-5) or (b-15), as applicable and as such
22standards may have been modified under this subsection (f),
23taking into account the unique circumstances of the utility's
24service territory. For those plans commencing on January 1,
252018, the Commission shall seek public comment on the
26utility's plan and shall issue an order approving or

 

 

SB2896- 440 -LRB102 17909 JWD 25989 b

1disapproving each plan no later than 105 days after June 1,
22017 (the effective date of Public Act 99-906). For those
3plans commencing after December 31, 2021, the Commission shall
4seek public comment on the utility's plan and shall issue an
5order approving or disapproving each plan within 6 months
6after its submission. If the Commission disapproves a plan,
7the Commission shall, within 30 days, describe in detail the
8reasons for the disapproval and describe a path by which the
9utility may file a revised draft of the plan to address the
10Commission's concerns satisfactorily. If the utility does not
11refile with the Commission within 60 days, the utility shall
12be subject to penalties at a rate of $100,000 per day until the
13plan is filed. This process shall continue, and penalties
14shall accrue, until the utility has successfully filed a
15portfolio of energy efficiency and demand-response measures.
16Penalties shall be deposited into the Energy Efficiency Trust
17Fund.
18    (g) In submitting proposed plans and funding levels under
19subsection (f) of this Section to meet the savings goals
20identified in subsection (b-5) or (b-15) of this Section, as
21applicable, the utility shall:
22        (1) Demonstrate that its proposed energy efficiency
23    measures will achieve the applicable requirements that are
24    identified in subsection (b-5) or (b-15) of this Section,
25    as modified by subsection (f) of this Section.
26        (2) Present specific proposals to implement new

 

 

SB2896- 441 -LRB102 17909 JWD 25989 b

1    building and appliance standards that have been placed
2    into effect.
3        (3) Demonstrate that its overall portfolio of
4    measures, not including low-income programs described in
5    subsection (c) of this Section, is cost-effective using
6    the total resource cost test or complies with paragraphs
7    (1) through (3) of subsection (f) of this Section and
8    represents a diverse cross-section of opportunities for
9    customers of all rate classes, other than those customers
10    described in subsection (l) of this Section, to
11    participate in the programs. Individual measures need not
12    be cost effective.
13        (4) Present a third-party energy efficiency
14    implementation program subject to the following
15    requirements:
16            (A) beginning with the year commencing January 1,
17        2019, electric utilities that serve more than
18        3,000,000 retail customers in the State shall fund
19        third-party energy efficiency programs in an amount
20        that is no less than $25,000,000 per year, and
21        electric utilities that serve less than 3,000,000
22        retail customers but more than 500,000 retail
23        customers in the State shall fund third-party energy
24        efficiency programs in an amount that is no less than
25        $8,350,000 per year;
26            (B) during 2018, the utility shall conduct a

 

 

SB2896- 442 -LRB102 17909 JWD 25989 b

1        solicitation process for purposes of requesting
2        proposals from third-party vendors for those
3        third-party energy efficiency programs to be offered
4        during one or more of the years commencing January 1,
5        2019, January 1, 2020, and January 1, 2021; for those
6        multi-year plans commencing on January 1, 2022 and
7        January 1, 2026, the utility shall conduct a
8        solicitation process during 2021 and 2025,
9        respectively, for purposes of requesting proposals
10        from third-party vendors for those third-party energy
11        efficiency programs to be offered during one or more
12        years of the respective multi-year plan period; for
13        each solicitation process, the utility shall identify
14        the sector, technology, or geographical area for which
15        it is seeking requests for proposals;
16            (C) the utility shall propose the bidder
17        qualifications, performance measurement process, and
18        contract structure, which must include a performance
19        payment mechanism and general terms and conditions;
20        the proposed qualifications, process, and structure
21        shall be subject to Commission approval; and
22            (D) the utility shall retain an independent third
23        party to score the proposals received through the
24        solicitation process described in this paragraph (4),
25        rank them according to their cost per lifetime
26        kilowatt-hours saved, and assemble the portfolio of

 

 

SB2896- 443 -LRB102 17909 JWD 25989 b

1        third-party programs.
2        The electric utility shall recover all costs
3    associated with Commission-approved, third-party
4    administered programs regardless of the success of those
5    programs.
6        (4.5) Implement cost-effective demand-response
7    measures to reduce peak demand by 0.1% over the prior year
8    for eligible retail customers, as defined in Section
9    16-111.5 of this Act, and for customers that elect hourly
10    service from the utility pursuant to Section 16-107 of
11    this Act, provided those customers have not been declared
12    competitive. This requirement continues until December 31,
13    2026.
14        (5) Include a proposed or revised cost-recovery tariff
15    mechanism, as provided for under subsection (d) of this
16    Section, to fund the proposed energy efficiency and
17    demand-response measures and to ensure the recovery of the
18    prudently and reasonably incurred costs of
19    Commission-approved programs.
20        (6) Provide for an annual independent evaluation of
21    the performance of the cost-effectiveness of the utility's
22    portfolio of measures, as well as a full review of the
23    multi-year plan results of the broader net program impacts
24    and, to the extent practical, for adjustment of the
25    measures on a going-forward basis as a result of the
26    evaluations. The resources dedicated to evaluation shall

 

 

SB2896- 444 -LRB102 17909 JWD 25989 b

1    not exceed 3% of portfolio resources in any given year.
2        (7) For electric utilities that serve more than
3    3,000,000 retail customers in the State:
4            (A) Through December 31, 2025, provide for an
5        adjustment to the return on equity component of the
6        utility's weighted average cost of capital calculated
7        under subsection (d) of this Section:
8                (i) If the independent evaluator determines
9            that the utility achieved a cumulative persisting
10            annual savings that is less than the applicable
11            annual incremental goal, then the return on equity
12            component shall be reduced by a maximum of 200
13            basis points in the event that the utility
14            achieved no more than 75% of such goal. If the
15            utility achieved more than 75% of the applicable
16            annual incremental goal but less than 100% of such
17            goal, then the return on equity component shall be
18            reduced by 8 basis points for each percent by
19            which the utility failed to achieve the goal.
20                (ii) If the independent evaluator determines
21            that the utility achieved a cumulative persisting
22            annual savings that is more than the applicable
23            annual incremental goal, then the return on equity
24            component shall be increased by a maximum of 200
25            basis points in the event that the utility
26            achieved at least 125% of such goal. If the

 

 

SB2896- 445 -LRB102 17909 JWD 25989 b

1            utility achieved more than 100% of the applicable
2            annual incremental goal but less than 125% of such
3            goal, then the return on equity component shall be
4            increased by 8 basis points for each percent by
5            which the utility achieved above the goal. If the
6            applicable annual incremental goal was reduced
7            under paragraphs (1) or (2) of subsection (f) of
8            this Section, then the following adjustments shall
9            be made to the calculations described in this item
10            (ii):
11                    (aa) the calculation for determining
12                achievement that is at least 125% of the
13                applicable annual incremental goal shall use
14                the unreduced applicable annual incremental
15                goal to set the value; and
16                    (bb) the calculation for determining
17                achievement that is less than 125% but more
18                than 100% of the applicable annual incremental
19                goal shall use the reduced applicable annual
20                incremental goal to set the value for 100%
21                achievement of the goal and shall use the
22                unreduced goal to set the value for 125%
23                achievement. The 8 basis point value shall
24                also be modified, as necessary, so that the
25                200 basis points are evenly apportioned among
26                each percentage point value between 100% and

 

 

SB2896- 446 -LRB102 17909 JWD 25989 b

1                125% achievement.
2            (B) For the period January 1, 2026 through
3        December 31, 2030, provide for an adjustment to the
4        return on equity component of the utility's weighted
5        average cost of capital calculated under subsection
6        (d) of this Section:
7                (i) If the independent evaluator determines
8            that the utility achieved a cumulative persisting
9            annual savings that is less than the applicable
10            annual incremental goal, then the return on equity
11            component shall be reduced by a maximum of 200
12            basis points in the event that the utility
13            achieved no more than 66% of such goal. If the
14            utility achieved more than 66% of the applicable
15            annual incremental goal but less than 100% of such
16            goal, then the return on equity component shall be
17            reduced by 6 basis points for each percent by
18            which the utility failed to achieve the goal.
19                (ii) If the independent evaluator determines
20            that the utility achieved a cumulative persisting
21            annual savings that is more than the applicable
22            annual incremental goal, then the return on equity
23            component shall be increased by a maximum of 200
24            basis points in the event that the utility
25            achieved at least 134% of such goal. If the
26            utility achieved more than 100% of the applicable

 

 

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1            annual incremental goal but less than 134% of such
2            goal, then the return on equity component shall be
3            increased by 6 basis points for each percent by
4            which the utility achieved above the goal. If the
5            applicable annual incremental goal was reduced
6            under paragraph (3) of subsection (f) of this
7            Section, then the following adjustments shall be
8            made to the calculations described in this item
9            (ii):
10                    (aa) the calculation for determining
11                achievement that is at least 134% of the
12                applicable annual incremental goal shall use
13                the unreduced applicable annual incremental
14                goal to set the value; and
15                    (bb) the calculation for determining
16                achievement that is less than 134% but more
17                than 100% of the applicable annual incremental
18                goal shall use the reduced applicable annual
19                incremental goal to set the value for 100%
20                achievement of the goal and shall use the
21                unreduced goal to set the value for 134%
22                achievement. The 6 basis point value shall
23                also be modified, as necessary, so that the
24                200 basis points are evenly apportioned among
25                each percentage point value between 100% and
26                134% achievement.

 

 

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1        (7.5) For purposes of this Section, the term
2    "applicable annual incremental goal" means the difference
3    between the cumulative persisting annual savings goal for
4    the calendar year that is the subject of the independent
5    evaluator's determination and the cumulative persisting
6    annual savings goal for the immediately preceding calendar
7    year, as such goals are defined in subsections (b-5) and
8    (b-15) of this Section and as these goals may have been
9    modified as provided for under subsection (b-20) and
10    paragraphs (1) through (3) of subsection (f) of this
11    Section. Under subsections (b), (b-5), (b-10), and (b-15)
12    of this Section, a utility must first replace energy
13    savings from measures that have reached the end of their
14    measure lives and would otherwise have to be replaced to
15    meet the applicable savings goals identified in subsection
16    (b-5) or (b-15) of this Section before any progress
17    towards achievement of its applicable annual incremental
18    goal may be counted. Notwithstanding anything else set
19    forth in this Section, the difference between the actual
20    annual incremental savings achieved in any given year,
21    including the replacement of energy savings from measures
22    that have expired, and the applicable annual incremental
23    goal shall not affect adjustments to the return on equity
24    for subsequent calendar years under this subsection (g).
25        (8) For electric utilities that serve less than
26    3,000,000 retail customers but more than 500,000 retail

 

 

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1    customers in the State:
2            (A) Through December 31, 2025, the applicable
3        annual incremental goal shall be compared to the
4        annual incremental savings as determined by the
5        independent evaluator.
6                (i) The return on equity component shall be
7            reduced by 8 basis points for each percent by
8            which the utility did not achieve 84.4% of the
9            applicable annual incremental goal.
10                (ii) The return on equity component shall be
11            increased by 8 basis points for each percent by
12            which the utility exceeded 100% of the applicable
13            annual incremental goal.
14                (iii) The return on equity component shall not
15            be increased or decreased if the annual
16            incremental savings as determined by the
17            independent evaluator is greater than 84.4% of the
18            applicable annual incremental goal and less than
19            100% of the applicable annual incremental goal.
20                (iv) The return on equity component shall not
21            be increased or decreased by an amount greater
22            than 200 basis points pursuant to this
23            subparagraph (A).
24            (B) For the period of January 1, 2026 through
25        December 31, 2030, the applicable annual incremental
26        goal shall be compared to the annual incremental

 

 

SB2896- 450 -LRB102 17909 JWD 25989 b

1        savings as determined by the independent evaluator.
2                (i) The return on equity component shall be
3            reduced by 6 basis points for each percent by
4            which the utility did not achieve 100% of the
5            applicable annual incremental goal.
6                (ii) The return on equity component shall be
7            increased by 6 basis points for each percent by
8            which the utility exceeded 100% of the applicable
9            annual incremental goal.
10                (iii) The return on equity component shall not
11            be increased or decreased by an amount greater
12            than 200 basis points pursuant to this
13            subparagraph (B).
14            (C) If the applicable annual incremental goal was
15        reduced under paragraphs (1), (2) or (3) of subsection
16        (f) of this Section, then the following adjustments
17        shall be made to the calculations described in
18        subparagraphs (A) and (B) of this paragraph (8):
19                (i) The calculation for determining
20            achievement that is at least 125% or 134%, as
21            applicable, of the applicable annual incremental
22            goal shall use the unreduced applicable annual
23            incremental goal to set the value.
24                (ii) For the period through December 31, 2025,
25            the calculation for determining achievement that
26            is less than 125% but more than 100% of the

 

 

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1            applicable annual incremental goal shall use the
2            reduced applicable annual incremental goal to set
3            the value for 100% achievement of the goal and
4            shall use the unreduced goal to set the value for
5            125% achievement. The 8 basis point value shall
6            also be modified, as necessary, so that the 200
7            basis points are evenly apportioned among each
8            percentage point value between 100% and 125%
9            achievement.
10                (iii) For the period of January 1, 2026
11            through December 31, 2030, the calculation for
12            determining achievement that is less than 134% but
13            more than 100% of the applicable annual
14            incremental goal shall use the reduced applicable
15            annual incremental goal to set the value for 100%
16            achievement of the goal and shall use the
17            unreduced goal to set the value for 125%
18            achievement. The 6 basis point value shall also be
19            modified, as necessary, so that the 200 basis
20            points are evenly apportioned among each
21            percentage point value between 100% and 134%
22            achievement.
23        (9) The utility shall submit the energy savings data
24    to the independent evaluator no later than 30 days after
25    the close of the plan year. The independent evaluator
26    shall determine the cumulative persisting annual savings

 

 

SB2896- 452 -LRB102 17909 JWD 25989 b

1    for a given plan year no later than 120 days after the
2    close of the plan year. The utility shall submit an
3    informational filing to the Commission no later than 160
4    days after the close of the plan year that attaches the
5    independent evaluator's final report identifying the
6    cumulative persisting annual savings for the year and
7    calculates, under paragraph (7) or (8) of this subsection
8    (g), as applicable, any resulting change to the utility's
9    return on equity component of the weighted average cost of
10    capital applicable to the next plan year beginning with
11    the January monthly billing period and extending through
12    the December monthly billing period. However, if the
13    utility recovers the costs incurred under this Section
14    under paragraphs (2) and (3) of subsection (d) of this
15    Section, then the utility shall not be required to submit
16    such informational filing, and shall instead submit the
17    information that would otherwise be included in the
18    informational filing as part of its filing under paragraph
19    (3) of such subsection (d) that is due on or before June 1
20    of each year.
21        For those utilities that must submit the informational
22    filing, the Commission may, on its own motion or by
23    petition, initiate an investigation of such filing,
24    provided, however, that the utility's proposed return on
25    equity calculation shall be deemed the final, approved
26    calculation on December 15 of the year in which it is filed

 

 

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1    unless the Commission enters an order on or before
2    December 15, after notice and hearing, that modifies such
3    calculation consistent with this Section.
4        The adjustments to the return on equity component
5    described in paragraphs (7) and (8) of this subsection (g)
6    shall be applied as described in such paragraphs through a
7    separate tariff mechanism, which shall be filed by the
8    utility under subsections (f) and (g) of this Section.
9    (h) No more than 6% of energy efficiency and
10demand-response program revenue may be allocated for research,
11development, or pilot deployment of new equipment or measures.
12    (i) When practicable, electric utilities shall incorporate
13advanced metering infrastructure data into the planning,
14implementation, and evaluation of energy efficiency measures
15and programs, subject to the data privacy and confidentiality
16protections of applicable law.
17    (j) The independent evaluator shall follow the guidelines
18and use the savings set forth in Commission-approved energy
19efficiency policy manuals and technical reference manuals, as
20each may be updated from time to time. Until such time as
21measure life values for energy efficiency measures implemented
22for low-income households under subsection (c) of this Section
23are incorporated into such Commission-approved manuals, the
24low-income measures shall have the same measure life values
25that are established for same measures implemented in
26households that are not low-income households.

 

 

SB2896- 454 -LRB102 17909 JWD 25989 b

1    (k) Notwithstanding any provision of law to the contrary,
2an electric utility subject to the requirements of this
3Section may file a tariff cancelling an automatic adjustment
4clause tariff in effect under this Section or Section 8-103,
5which shall take effect no later than one business day after
6the date such tariff is filed. Thereafter, the utility shall
7be authorized to defer and recover its expenditures incurred
8under this Section through a new tariff authorized under
9subsection (d) of this Section or in the utility's next rate
10case under Article IX or Section 16-108.5 of this Act, with
11interest at an annual rate equal to the utility's weighted
12average cost of capital as approved by the Commission in such
13case. If the utility elects to file a new tariff under
14subsection (d) of this Section, the utility may file the
15tariff within 10 days after June 1, 2017 (the effective date of
16Public Act 99-906), and the cost inputs to such tariff shall be
17based on the projected costs to be incurred by the utility
18during the calendar year in which the new tariff is filed and
19that were not recovered under the tariff that was cancelled as
20provided for in this subsection. Such costs shall include
21those incurred or to be incurred by the utility under its
22multi-year plan approved under subsections (f) and (g) of this
23Section, including, but not limited to, projected capital
24investment costs and projected regulatory asset balances with
25correspondingly updated depreciation and amortization reserves
26and expense. The Commission shall, after notice and hearing,

 

 

SB2896- 455 -LRB102 17909 JWD 25989 b

1approve, or approve with modification, such tariff and cost
2inputs no later than 75 days after the utility filed the
3tariff, provided that such approval, or approval with
4modification, shall be consistent with the provisions of this
5Section to the extent they do not conflict with this
6subsection (k). The tariff approved by the Commission shall
7take effect no later than 5 days after the Commission enters
8its order approving the tariff.
9    No later than 60 days after the effective date of the
10tariff cancelling the utility's automatic adjustment clause
11tariff, the utility shall file a reconciliation that
12reconciles the moneys collected under its automatic adjustment
13clause tariff with the costs incurred during the period
14beginning June 1, 2016 and ending on the date that the electric
15utility's automatic adjustment clause tariff was cancelled. In
16the event the reconciliation reflects an under-collection, the
17utility shall recover the costs as specified in this
18subsection (k). If the reconciliation reflects an
19over-collection, the utility shall apply the amount of such
20over-collection as a one-time credit to retail customers'
21bills.
22    (l) For the calendar years covered by a multi-year plan
23commencing after December 31, 2017, subsections (a) through
24(j) of this Section do not apply to eligible large private
25energy customers that have chosen to opt out of multi-year
26plans consistent with this subsection.

 

 

SB2896- 456 -LRB102 17909 JWD 25989 b

1        (1) For purposes of this subsection, an "eligible
2    large private energy customer" is defined as any retail
3    customers, except for federal, State, municipal and other
4    public customers, of an electric utility that serves more
5    than 3,000,000 retail customers, except for federal,
6    State, municipal and other public customers, in the State
7    and whose total highest 30 minute demand was more than
8    10,000 kilowatts, or any retail customers of an electric
9    utility that serves less than 3,000,000 retail customers
10    but more than 500,000 retail customers in the State and
11    whose total highest 15 minute demand was more than 10,000
12    kilowatts. For purposes of this subsection (l), "retail
13    customer" has the meaning set forth in Section 16-102 of
14    this Act. A determination of whether this subsection is
15    applicable to a customer shall be made for each multi-year
16    plan beginning after December 31, 2017. The criteria for
17    determining whether this subsection (l) is applicable to a
18    retail customer shall be based on the 12 consecutive
19    billing periods prior to the start of the first year of
20    each such multi-year plan.
21        (2) The Commission shall prescribe the form for notice
22    required for opting out of energy efficiency programs. The
23    notice must be submitted to the retail utility 12 months
24    before the next energy efficiency planning cycle and shall
25    include all of the following:
26            (A) A statement indicating that the customer has

 

 

SB2896- 457 -LRB102 17909 JWD 25989 b

1        elected to opt out;
2            (B) The account number for the customer account to
3        which the opt out shall apply;
4            (C) The mailing address associated with the
5        customer account identified under subparagraph (B);
6            (D) An American Society of Heating, Refrigerating,
7        and Air-Conditioning Engineers (ASHRAE) level 2 or
8        higher audit report conducted by an independent third
9        party expert identifying cost-effective energy
10        efficiency project opportunities that could be
11        invested in over the next 10 years;
12            (E) A description of the customer's plans to
13        reallocate the funds toward internal energy efficiency
14        efforts identified in the subparagraph (D) report,
15        including but not limited to: (i) strategic energy
16        management or other programs, including descriptions
17        of targeted buildings, equipment and operations; (ii)
18        eligible energy efficiency measures; and (iii)
19        expected energy savings, itemized by technology; and
20            (F) The effective date of the opt out, which will
21        be the next January 1 following notice of the opt out.
22        (3) Upon receipt of a properly and timely noticed
23    request for opt out submitted by an eligible large private
24    energy customer, the retail utility shall grant the
25    request, file the request with the Commission and,
26    beginning January 1 of the following year, the opted out

 

 

SB2896- 458 -LRB102 17909 JWD 25989 b

1    customer shall no longer be assessed the costs of the plan
2    and shall be prohibited from participating in that
3    four-year plan cycle to give the retail utility the
4    certainty to design program plan proposals.
5        (4) Upon a customer's election to opt out under
6    paragraphs (1) and (2) of this subsection (l) and
7    commencing on the effective date of said opt out, the
8    account properly identified in the customer's notice under
9    paragraph (2) shall not be subject to any cost recovery
10    and shall not be eligible to participate in, or directly
11    benefit from, compliance with energy efficiency cumulative
12    persisting savings requirements under subsections (a)
13    through (j).
14        (5) A utility's cumulative persisting annual savings
15    targets will exclude any opted out load.
16        (6) The request to opt out is only valid for the
17    requested plan cycle. An eligible large private energy
18    customer must also request to opt out for future energy
19    plan cycles, otherwise the customer will be included in
20    the future energy plan cycle.
21    (m) Notwithstanding the requirements of this Section, as
22part of a proceeding to approve a multi-year plan under
23subsections (f) and (g) of this Section, the Commission shall
24reduce the amount of energy efficiency measures implemented
25for any single year, and whose costs are recovered under
26subsection (d) of this Section, by an amount necessary to

 

 

SB2896- 459 -LRB102 17909 JWD 25989 b

1limit the estimated average net increase due to the cost of the
2measures to no more than
3        (1) 3.5% for each of the 4 years beginning January 1,
4    2018,
5        (2) 3.75% for each of the 4 years beginning January 1,
6    2022, and
7        (3) 4% for each of the 5 years beginning January 1,
8    2026,
9of the average amount paid per kilowatthour by residential
10eligible retail customers during calendar year 2015. To
11determine the total amount that may be spent by an electric
12utility in any single year, the applicable percentage of the
13average amount paid per kilowatthour shall be multiplied by
14the total amount of energy delivered by such electric utility
15in the calendar year 2015, adjusted to reflect the proportion
16of the utility's load attributable to customers who have opted
17out of are exempt from subsections (a) through (j) of this
18Section under paragraph (1) of subsection (l) of this Section.
19For purposes of this subsection (m), the amount paid per
20kilowatthour includes, without limitation, estimated amounts
21paid for supply, transmission, distribution, surcharges, and
22add-on taxes. For purposes of this Section, "eligible retail
23customers" shall have the meaning set forth in Section
2416-111.5 of this Act. Once the Commission has approved a plan
25under subsections (f) and (g) of this Section, no subsequent
26rate impact determinations shall be made.

 

 

SB2896- 460 -LRB102 17909 JWD 25989 b

1(Source: P.A. 100-840, eff. 8-13-18; 101-81, eff. 7-12-19.)
 
2    (220 ILCS 5/8-103C new)
3    Sec. 8-103C. Demand response.
4    (a) The General Assembly finds that strengthening utility
5programs for demand response will lead to greater grid
6optimization, enhancement of rate design, less energy demand,
7reduced peak demand, and lower costs for ratepayers.
8    (b) No later than December 31, 2021, the Commission shall
9initiate a docket on strategies for expansion of demand
10response by utilities that serve more than 300,000 customers.
11Such docket shall explore at a minimum:
12        (1) Demand response programs for all customer classes.
13        (2) Utility investment in infrastructure to support
14    demand response.
15        (3) Rate design options, including but not limited to
16    time of use rates and critical peak pricing.
17        (4) Potential for peak load reductions.
18        (5) Greater utilization of devices such as smart
19    thermostats that will provide more efficiency gains.
20        (6) Customer education on opportunities for demand
21    response, pricing options and efficiency-inducing devices.
22        (7) Interaction between the docket findings and
23    Integrated Distribution Planning and Performance Based
24    Regulation, as set forth in this Act.
25        (8) Alignment between demand response programs and the

 

 

SB2896- 461 -LRB102 17909 JWD 25989 b

1    clean energy goals of the State.
2    (c) The Commission, as a result of the docket findings,
3shall have the authority to order the utilities to submit a
4demand response plan for consideration on a schedule to be
5determined by the Commission.
 
6    (220 ILCS 5/8-104.1 new)
7    Sec. 8-104.1. Gas utilities; annual savings goals.
8    (a) It is the policy of the State that gas utilities are
9required to use cost-effective energy efficiency to reduce
10delivery load. Requiring investment in cost-effective energy
11efficiency will reduce direct and indirect costs to consumers
12by decreasing environmental impacts and by reducing the amount
13of natural gas that needs to be purchased and avoiding or
14delaying the need for new transmission, distribution, storage
15and other related infrastructure. It serves the public
16interest to allow gas utilities to recover costs for
17reasonably and prudently incurred expenditures for energy
18efficiency measures.
19    (b) As used in this Section:
20    "Black, indigenous, and people of color" and "BIPOC" means
21people who are members of the groups described in
22subparagraphs (a) through (e) of paragraph (A) of subsection
23(1) of Section 2 of the Business Enterprise for Minorities,
24Women, and Persons with Disabilities Act.
25    "Cost-effective" means that the measures satisfy the total

 

 

SB2896- 462 -LRB102 17909 JWD 25989 b

1resource cost test that, for purposes of this Section, means a
2standard that is met if, for an investment in energy
3efficiency, the benefit-cost ratio is greater than one. The
4benefit-cost ratio is the ratio of the net present value of the
5total benefits of the measures to the net present value of the
6total costs as calculated over the lifetime of the measures.
7The total resource cost test compares the sum of avoided
8natural gas utility costs, representing the benefits that
9accrue to the natural gas system and the participant in the
10delivery of those efficiency measures and including avoided
11costs associated with the use of electricity or other fuels,
12avoided cost associated with reduced water consumption, and
13avoided costs associated with reduced operation and
14maintenance costs, as well as other quantifiable societal
15benefits, to the sum of all incremental costs of end-use
16measures (including both utility and participant
17contributions), plus costs to administer, deliver, and
18evaluate each demand-side measure, to quantify the net savings
19obtained by substituting demand-side measures for supply
20resources. In calculating avoided costs, reasonable estimates
21shall be included for financial costs likely to be imposed by
22future regulation of emissions of greenhouse gases. In
23discounting future societal costs and benefits for the purpose
24of calculating net present values, a societal discount rate
25based on actual, long-term Treasury bond yields shall be used.
26The low-income measures described in subsection (f) of this

 

 

SB2896- 463 -LRB102 17909 JWD 25989 b

1Section shall not be required to meet the total resource cost
2test.
3    "Cumulative persisting annual savings" means the total gas
4energy savings in a given year from measures installed in that
5year or in previous years, but no earlier than January 1, 2022,
6that are still operational and providing savings in that year
7because the measures have not yet reached the end of their
8useful lives.
9    "Energy efficiency" means measures that reduce the amount
10of energy required to achieve a given end use. "Energy
11efficiency" also includes measures that reduce the total Btus
12of electricity and natural gas needed to meet the end use or
13uses.
14    (c) This Section applies to all gas distribution utilities
15in the State for those multi-year plans that include energy
16efficiency programs commencing after December 31, 2022.
17    (d) Beginning in 2023, gas utilities subject to this
18Section shall achieve the following cumulative persisting
19annual savings goals, as compared to a deemed baseline
20equivalent to the utility's average annual therm throughput in
212016 through 2020 through the implementation of energy
22efficiency measures during the applicable year and in prior
23years, but no earlier than January 1, 2023:
24        (1) 1.2% cumulative persisting annual savings for the
25    year ending December 31, 2023;
26        (2) 2.1% cumulative persisting annual savings for the

 

 

SB2896- 464 -LRB102 17909 JWD 25989 b

1    year ending December 31, 2024;
2        (3) 3.0% cumulative persisting annual savings for the
3    year ending December 31, 2025;
4        (4) 3.9% cumulative persisting annual savings for the
5    year ending December 31, 2026;
6        (5) 4.8% cumulative persisting annual savings for the
7    year ending December 31, 2027;
8        (6) 5.7% cumulative persisting annual savings for the
9    year ending December 31, 2028;
10        (7) 6.6% cumulative persisting annual savings for the
11    year ending December 31, 2029;
12        (8) 7.4% cumulative persisting annual savings for the
13    year ending December 31, 2030;
14        (9) 8.2% cumulative persisting annual savings for the
15    year ending December 31, 2031;
16        (10) 9.0% cumulative persisting annual savings for the
17    year ending December 31, 2032;
18        (11) 9.8% cumulative persisting annual savings for the
19    year ending December 31, 2033;
20        (12) 10.6% cumulative persisting annual savings for
21    the year ending December 31, 2034;
22        (13) 11.4% cumulative persisting annual savings for
23    the year ending December 31, 2035;
24        (14) 12.1% cumulative persisting annual savings for
25    the year ending December 31, 2036; and
26        (15) 12.8% cumulative persisting annual savings for

 

 

SB2896- 465 -LRB102 17909 JWD 25989 b

1    the year ending December 31, 2037.
2    No later than December 31, 2025, the Illinois Commerce
3Commission shall establish additional cumulative persisting
4annual savings goals for the years 2037 through 2041. The
5Commission shall also establish additional cumulative
6persisting annual savings goals every 5 years thereafter to
7ensure utilities always have goals that extend at least 11
8years into the future. The cumulative persisting annual
9savings goals beyond the year 2035 shall increase by 0.6
10percentage points per year absent a Commission decision to
11initiate a proceeding to consider establishing goals that
12increase by more or less than that amount. Such a proceeding
13must be conducted in accordance with the procedures described
14in subsection (f) of this Section. If such a proceeding is
15initiated, the cumulative persisting annual savings goals
16established by the Commission through that proceeding shall
17reflect the Commission's best estimate of the maximum amount
18of additional gas savings that are forecast to be
19cost-effectively achievable unless such best estimates would
20result in goals that represent less than 0.4 percentage point
21annual increases in total cumulative persisting annual
22savings. The Commission may only establish goals that
23represent less than 0.4 percentage point annual increases in
24cumulative persisting annual savings if it can demonstrate,
25based on clear and convincing evidence, that 0.4 percentage
26point increases are not cost-effectively achievable.

 

 

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1    (e) If a gas utility jointly offers an energy efficiency
2measure or program with an electric utility under plans
3approved under this Section and Section 8-103B of this Act,
4the gas utility may continue offering the program, including
5the electric energy efficiency measures, if the electric
6utility discontinues funding the program. In that event, the
7energy-savings value associated with such other fuels shall be
8converted to gas energy savings on an equivalent Btu basis for
9the premises. However, the gas utility shall prioritize
10programs for low-income residential customers to the extent
11practicable. A gas utility may recover the costs of offering
12the gas energy efficiency measures under this subsection (e).
13For those energy efficiency measures or programs that save
14both gas and other fuels but are not jointly offered with an
15electric utility under plans approved under this Section and
16Section 8-103B, the gas utility may count savings of fuels
17other than gas toward the achievement of its annual savings
18goal, and the energy-savings value associated with such other
19fuels shall be converted to gas energy savings on an
20equivalent Btu basis at the premises. In no event shall more
21than 10% of each year's applicable annual total savings
22requirement as defined in paragraph (8) of subsection (j) of
23this Section be met through savings of fuels other than gas.
24    (f) Gas utilities are responsible for overseeing the
25design, development, and filing of energy efficiency plans
26with the Commission and may, as part of that implementation,

 

 

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1outsource various aspects of program development and
2implementation. A minimum of 10% of the utility's entire
3portfolio funding level for a given year shall be used to
4procure cost-effective energy efficiency measures from units
5of local government, municipal corporations, school districts,
6public housing, community college districts, and
7nonprofit-owned buildings provided that a minimum percentage
8of available funds shall be used to procure energy efficiency
9from public housing, which percentage shall be equal to public
10housing's share of public building energy consumption. The
11utilities shall also implement energy efficiency measures
12targeted at low-income single-family and multifamily
13households, which, as used in this Section, means households
14at or below 80% of area median income, and expenditures to
15implement the measures shall be no less than 25% of the
16utility's total efficiency portfolio budget. At least 70% of
17spending on programs targeted at low-income households shall
18go toward integrated whole building efficiency programs, as
19defined in subsection (g), or individual measures that reduce
20space heating needs through improvements to the building
21envelope, heating distribution systems, or heating system
22controls. In implementing these programs, utilities shall
23ensure that thermal insulating materials used in the building
24envelope do not contain any substance that is a Category 1
25respiratory sensitizer as defined by Appendix A to 29 CFR
261910.1200 (Health Hazard Criteria: A.4 Respiratory or Skin

 

 

SB2896- 468 -LRB102 17909 JWD 25989 b

1Sensitization) that was intentionally added or is present at
2greater than 0.1% (1000 ppm) by weight in the product.
3Programs targeted at low-income households, which address
4single-family and multifamily buildings shall be treated such
5that forecast savings to be achieved in each building type are
6approximately in proportional to the magnitude of
7cost-effective energy efficiency opportunities in these
8respective building types. Each gas utility shall assess
9opportunities to implement cost-effective energy efficiency
10measures and programs through a public-housing authority or
11authorities located in its service territory. If such
12opportunities are identified, the utility shall propose such
13measures and programs to address the opportunities.
14Expenditures to address such opportunities shall be credited
15toward the minimum procurement and expenditure requirements
16set forth in this subsection (f). Implementation of energy
17efficiency measures and programs targeted at low-income
18households shall be contracted, when it is practical, to
19independent third parties that have demonstrated capabilities
20to serve such households, with a preference for not-for-profit
21entities and government agencies that have existing
22relationships with or experience serving low-income
23communities in the State. Each gas utility shall develop and
24implement reporting procedures that address and assist in
25determining the amount of energy savings that can be applied
26to the low-income procurement and expenditure requirements set

 

 

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1forth in this subsection (f). Each gas utility shall also
2track the types and quantities or volumes of insulation and
3air sealing materials, and their associated energy saving
4benefits, installed in energy efficiency programs targeted at
5low-income single-family and multifamily households. Each gas
6utility shall implement a health and safety fund of a minimum
7of 0.5% of the utility's entire portfolio funding level for a
8given year, that shall be used for the purpose of making grants
9for technical assistance, construction, reconstruction,
10improvement, or repair of buildings to facilitate their
11participation in the energy efficiency programs targeted at
12low-income single-family and multifamily households. These
13funds may also be used for the purpose of making grants for
14technical assistance, construction, reconstruction,
15improvement, or repair of the following buildings to
16facilitate their participation in the energy efficiency
17programs created by this Section:
18        (1) buildings that are owned or operated by registered
19    501(c)(3) public charities; and
20        (2) day care centers, day care homes, or group day
21    care homes, as defined by 89 Ill. Adm. Code Part 406, 407,
22    or 408, respectively. The gas utilities shall participate
23    in a low-income energy efficiency accountability committee
24    ("the committee"), which will directly inform the design,
25    implementation, and evaluation of the low-income and
26    public-housing energy efficiency programs. The committee

 

 

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1    shall be composed of the electric utilities subject to the
2    requirements of Section 8-103B of this Act, the gas
3    utilities subject to the requirements of this Section, the
4    utilities' low-income energy efficiency implementation
5    contractors, nonprofit organizations, community action
6    agencies, advocacy groups, State and local governmental
7    agencies, public-housing organizations, and
8    representatives of community-based organizations,
9    especially those living in or working with environmental
10    justice communities and BIPOC communities. The committee
11    shall be composed of a statewide leadership committee and
12    2 geographically differentiated subcommittees: one for
13    stakeholders in northern Illinois and one for stakeholders
14    in central and southern Illinois. The subcommittees shall
15    meet together at least twice per year. There shall be a
16    statewide leadership committee led by and composed of
17    community-based organizations that are representative of
18    BIPOC and environmental justice communities and that
19    includes equitable representation from BIPOC communities.
20    The leadership committee shall be composed of an equal
21    number of representatives from the 2 subcommittees. The
22    subcommittees shall address specific programs and issues,
23    with the leadership committee convening targeted
24    workgroups as needed. The leadership committee may elect
25    to work with an independent facilitator to solicit and
26    organize feedback, recommendations and meeting

 

 

SB2896- 471 -LRB102 17909 JWD 25989 b

1    participation from a wide variety of community-based
2    stakeholders. If a facilitator is used, they shall be fair
3    and responsive to the needs of all stakeholders involved
4    in the committee. All committee meetings must be
5    accessible, with rotating locations if meetings are held
6    in-person, virtual participation options, and materials
7    and agendas circulated well in advance. There shall also
8    be opportunities for direct input by committee members
9    outside of committee meetings, such as via individual
10    meetings, surveys, emails and calls, to ensure robust
11    participation by stakeholders with limited capacity and
12    ability to attend committee meetings. Committee meetings
13    shall emphasize opportunities to bundle and coordinate
14    delivery of low-income energy efficiency with other
15    programs that serve low-income communities, such as Solar
16    for All and bill payment assistance programs. Meetings
17    shall include educational opportunities for stakeholders
18    to learn more about these additional offerings, and the
19    committee shall assist in figuring out the best methods
20    for coordinated delivery and implementation of offerings
21    when serving low-income communities. The committee shall
22    directly and equitably influence and inform utility
23    low-income and public-housing energy efficiency programs
24    and priorities. Participating utilities shall implement
25    recommendations from the committee whenever possible.
26    Participating utilities shall track and report how input

 

 

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1    from the committee has led to new approaches and changes
2    in their energy efficiency portfolios. This reporting
3    shall occur at committee meetings and in quarterly energy
4    efficiency reports to the Stakeholder Advisory Group and
5    Illinois Commerce Commission, and other relevant reporting
6    mechanisms. Participating utilities shall also report on
7    relevant equity data and metrics requested by the
8    committee, such as energy burden data, geographic, racial,
9    and other relevant demographic data on where programs are
10    being delivered and what populations programs are serving.
11    The Illinois Commerce Commission shall oversee and have
12    relevant staff participate in the committee. The committee
13    shall have a budget of 0.25% of each utility's entire
14    efficiency portfolio funding for a given year. The budget
15    shall be overseen by the Commission. The budget shall be
16    used to provide grants for community-based organizations
17    serving on the leadership committee, stipends for
18    community-based organizations participating in the
19    committee, grants for community-based organizations to do
20    energy efficiency outreach and education, and relevant
21    meeting needs as determined by the leadership committee.
22    The education and outreach shall include, but is not
23    limited to, basic energy efficiency education, information
24    about low-income energy efficiency programs, and
25    information on the committee's purpose, structure, and
26    activities.

 

 

SB2896- 473 -LRB102 17909 JWD 25989 b

1    (g) At least 50% of the entire efficiency program
2portfolio budget shall be spent on any combination of:
3        (1) heating energy savings from integrated,
4    residential or nonresidential, new or existing whole
5    building efficiency programs; and
6        (2) individual heating measures in residential or
7    nonresidential buildings, new or existing, that reduce the
8    amount of space heating needs through improvements to the
9    efficiency of building envelopes (including, but not
10    limited to, insulation measures, efficient windows and air
11    leakage reduction), improvements to systems for
12    distributing heat (including, but not limited to, duct
13    leakage reduction, duct insulation or pipe insulation) in
14    buildings, improvements to ventilation systems (including,
15    but not limited to heat recovery ventilation and demand
16    control ventilation measures) or improvements to controls
17    of heating equipment (including, but not limited to,
18    advanced thermostats). Spending on efficient furnaces,
19    efficient boilers, or other efficient heating equipment
20    measures outside of or separate from integrated whole
21    building efficiency programs is permitted within the
22    efficiency program portfolio, but does not count toward
23    the minimum spending requirement in this subsection (g).
24    Spending on integrated whole building efficiency programs
25    targeted to low-income customers, as well as spending on
26    individual building envelope, heating distribution system,

 

 

SB2896- 474 -LRB102 17909 JWD 25989 b

1    ventilation system and heating system control measures
2    installed in low-income homes does count toward this
3    requirement. The portion of portfolio spending on program
4    marketing, training of installers, audits of buildings,
5    inspections of work performed, and other administrative
6    and technical expenses that are clearly tied to promotion
7    and delivery of integrated whole building efficiency
8    programs or installation of individual building envelope,
9    heating distribution system, ventilation system or heating
10    system control measures shall count toward this
11    requirement. If this minimum requirement is not met, any
12    performance incentive earned under paragraph (7) of
13    subsection (j) should be reduced by the percentage point
14    level of shortfall in meeting this requirement; if the
15    utility is subject to a performance penalty, then the
16    magnitude of the penalty shall be increased by the
17    percentage point shortfall in meeting this requirement.
18        As used in this subsection (g), "integrated whole
19    building efficiency programs" means programs designed to
20    optimize the heating efficiency of buildings by
21    comprehensively and simultaneously addressing
22    cost-effective energy-savings opportunities associated
23    with heating equipment, heating distribution systems,
24    heating system controls, ventilation systems and building
25    envelopes; such programs may be targeted to existing
26    buildings or to construction of new buildings.

 

 

SB2896- 475 -LRB102 17909 JWD 25989 b

1    (h) Notwithstanding any other provision of law to the
2contrary, a utility providing approved energy efficiency
3measures in the State shall be permitted to recover all
4reasonable and prudently incurred costs of those measures from
5all distribution system customers, provided that nothing in
6this subsection (h) permits the double recovery of such costs
7from customers.
8    (i) Beginning in 2022, each gas utility shall file an
9energy efficiency plan with the Commission to meet the energy
10efficiency standards for the next applicable multi-year period
11beginning January 1 of the year following the filing,
12according to the schedule set forth in paragraphs (1) through
13(5) of this subsection (i). If a utility does not file such a
14plan on or before the applicable filing deadline for the plan,
15it shall face a penalty of $100,000 per day until the plan is
16filed.
17        (1) No later March 1, 2022, each gas utility shall
18    file a 3-year energy efficiency plan commencing on January
19    1, 2023 that is designed to achieve the cumulative
20    persisting annual savings goals specified in paragraphs
21    (1) through (3) of subsection (d) of this Section through
22    implementation of energy efficiency measures; however, the
23    goals may be reduced if the plan's analysis and forecasts
24    of the utility's ability to acquire energy savings
25    demonstrate beyond a reasonable doubt that achievement of
26    such goals is not cost-effective. Annual increases in

 

 

SB2896- 476 -LRB102 17909 JWD 25989 b

1    cumulative persisting annual savings goals during the
2    applicable 3-year plan period shall not be reduced to
3    amounts that are less than the maximum amount of
4    cumulative persisting annual savings that is forecast to
5    be cost-effectively achievable during the 3-year plan
6    period. The Commission shall review any proposed goal
7    reduction as part of its review and approval of the
8    utility's proposed plan.
9        (2) No later than March 1, 2025, each gas utility
10    shall file a 4-year energy efficiency plan commencing on
11    January 1, 2026 that is designed to achieve the cumulative
12    persisting annual savings goals specified in paragraphs
13    (4) through (7) of subsection (d) of this Section through
14    implementation of energy efficiency measures; however, the
15    goals may be reduced if each of the following conditions
16    are met:
17            (A) the plan's analysis and forecasts of the
18        utility's ability to acquire energy savings
19        demonstrate by clear and convincing evidence that
20        achievement of such goals is not cost-effective; and
21            (B) the amount of energy savings achieved by the
22        utility as determined by the independent evaluator for
23        the most recent year for which savings have been
24        evaluated preceding the plan filing was less than the
25        average annual amount of savings required to achieve
26        the goals for the applicable 4-year plan period.

 

 

SB2896- 477 -LRB102 17909 JWD 25989 b

1        Annual increases in cumulative persisting annual
2        savings goals during the applicable 4-year plan period
3        shall not be reduced to amounts that are less than the
4        maximum amount of cumulative persisting annual savings
5        that is forecast to be cost-effectively achievable
6        during the 4-year plan period. The Commission shall
7        review any proposed goal reduction as part of its
8        review and approval of the utility's proposed plan.
9        (3) No later than March 1, 2029, each gas utility
10    shall file a 4-year energy efficiency plan commencing on
11    January 1, 2030 that is designed to achieve the cumulative
12    persisting annual savings goals specified in paragraphs
13    (8) through (11) of subsection (d) of this Section through
14    implementation of energy efficiency measures; however, the
15    goals may be reduced if each of the following conditions
16    are met:
17            (A) the plan's analysis and forecasts of the
18        utility's ability to acquire energy savings
19        demonstrate by clear and convincing evidence that
20        achievement of such goals is not cost-effective; and
21            (B) the amount of energy savings achieved by the
22        utility as determined by the independent evaluator for
23        the most recent year for which savings have been
24        evaluated preceding the plan filing was less than the
25        average annual amount of savings required to achieve
26        the goals for the applicable 4-year plan period.

 

 

SB2896- 478 -LRB102 17909 JWD 25989 b

1        Annual increases in cumulative persisting annual
2        savings goals during the applicable 4-year plan period
3        shall not be reduced to amounts that are less than the
4        maximum amount of cumulative persisting annual savings
5        that is forecast to be cost-effectively achievable
6        during the 4-year plan period. The Commission shall
7        review any proposed goal reduction as part of its
8        review and approval of the utility's proposed plan.
9        (4) No later than March 1, beginning in 2033 and each
10    year thereafter, each gas utility shall file a 4-year
11    energy efficiency plan commencing on January 1, beginning
12    in 2034 and each 4-year period thereafter, that is
13    designed to achieve the cumulative persisting annual
14    savings goals specified in paragraphs (12) through (15) of
15    subsection (d), as well as goals for subsequent years that
16    are established by the Illinois Commerce Commission
17    pursuant to direction of subsection (d) of this Section,
18    through implementation of energy efficiency measures;
19    however, the goals may be reduced if each of the following
20    conditions are met:
21            (A) the plan's analysis and forecasts of the
22        utility's ability to acquire energy savings
23        demonstrate by clear and convincing evidence that
24        achievement of such goals is not cost-effective; and
25            (B) the amount of energy savings achieved by the
26        utility as determined by the independent evaluator for

 

 

SB2896- 479 -LRB102 17909 JWD 25989 b

1        the most recent year for which savings have been
2        evaluated preceding the plan filing was less than the
3        average annual amount of savings required to achieve
4        the goals for the applicable 4-year plan period.
5        Annual increases in cumulative persisting annual
6        savings goals during the applicable 4-year plan period
7        shall not be reduced to amounts that are less than the
8        maximum amount of cumulative persisting annual savings
9        that is forecast to be cost-effectively achievable
10        during the 4-year plan period. The Commission shall
11        review any proposed goal reduction as part of its
12        review and approval of the utility's proposed plan.
13        Each utility's plan shall set forth the utility's
14        proposals to meet the energy efficiency standards
15        identified in subsection (d). The Commission shall
16        seek public comment on the utility's plan and shall
17        issue an order approving or disapproving each plan
18        within 6 months after its submission. If the
19        Commission disapproves a plan, the Commission shall,
20        within 30 days, describe in detail the reasons for the
21        disapproval and describe a path by which the utility
22        may file a revised draft of the plan to address the
23        Commission's concerns satisfactorily. If the utility
24        does not refile with the Commission within 60 days,
25        the utility shall be subject to penalties at a rate of
26        $100,000 per day until the plan is filed. This process

 

 

SB2896- 480 -LRB102 17909 JWD 25989 b

1        shall continue, and penalties shall accrue, until the
2        utility has successfully filed a portfolio of energy
3        efficiency measures. Penalties shall be deposited into
4        the Energy Efficiency Trust Fund.
5    (j) In submitting proposed plans and funding levels under
6subsection (i) of this Section to meet the savings goals
7identified in subsection (d), the utility shall:
8        (1) Demonstrate that its proposed energy efficiency
9    measures will achieve the applicable requirements that are
10    identified in subsection (d) of this Section.
11        (2) Demonstrate consideration of program options for:
12            (A) advancing new building codes, appliance
13        standards, and municipal regulations governing
14        existing and new building efficiency improvements; and
15            (B) supporting efforts to improve compliance with
16        new building codes, appliance standards and municipal
17        regulations, as potentially cost-effective means of
18        acquiring energy savings to count toward savings
19        goals.
20        (3) Demonstrate that its overall portfolio of
21    measures, not including low-income programs described in
22    subsection (f) of this Section, is cost-effective using
23    the total resource cost test, complies with subsection (i)
24    of this Section and represents a diverse cross-section of
25    opportunities for customers of all rate classes, to
26    participate in the programs. Individual measures need not

 

 

SB2896- 481 -LRB102 17909 JWD 25989 b

1    be cost-effective.
2        (3.5) Demonstrate that the utility's plan integrates
3    the delivery of energy efficiency programs with electric
4    efficiency programs and other efforts to address bill
5    payment issues, including, but not limited to, LIHEAP and
6    the Percent Income Payment Plan, to the extent such
7    integration is practical and has the potential to enhance
8    customer engagement, minimize market confusion, or reduce
9    administrative costs.
10        (4) Present a third-party energy efficiency
11    implementation program subject to the following
12    requirements:
13            (A) Beginning with the year commencing January 1,
14        2024, gas utilities shall fund third-party energy
15        efficiency programs in an amount that is no less than
16        10% of total efficiency portfolio budgets per year.
17            (B) For the multi-year plans commencing on January
18        1, 2023, the utility shall conduct a solicitation
19        process during 2023 for purposes of requesting
20        proposals from third-party vendors for those
21        third-party energy efficiency programs to be offered
22        during one or more years of the last 2 years of the
23        2023 to 2025 plan period. For the solicitation
24        process, the utility shall identify the sector,
25        technology, or a geographic area for which it is
26        seeking requests for proposals. The solicitation

 

 

SB2896- 482 -LRB102 17909 JWD 25989 b

1        process must be for programs that fill gaps in the
2        utility's program portfolio or target business
3        sectors, building types, geographies or other specific
4        parts of its customer base with initiatives that would
5        be more effective at reaching these customer segments
6        than the utilities' programs filed in its energy
7        efficiency plans.
8            (C) For multi-year plans commencing on January 1,
9        2026, January 1, 2030, and every 4 years thereafter,
10        the utility shall conduct a solicitation process
11        during 2025, 2029, and every 4 years thereafter,
12        respectively, for purposes of requesting proposals
13        from third-party vendors for those third-party energy
14        efficiency programs to be offered during one or more
15        years of the respective multi-year plan period; for
16        each solicitation process, the utility shall identify
17        the sector, technology, or geographic area for which
18        it is seeking requests for proposals; the solicitation
19        process must be for programs that fill gaps in the
20        utility's program portfolio or target business
21        sectors, building types, geographies or other specific
22        parts of its customer base with initiatives that would
23        be more effective at reaching these customer segments
24        than the utilities' programs filed in its energy
25        efficiency plans.
26            (D) The utility shall propose the bidder

 

 

SB2896- 483 -LRB102 17909 JWD 25989 b

1        qualifications, performance measurement process, and
2        contract structure, which must include a performance
3        payment mechanism and general terms and conditions;
4        the proposed qualifications, process, and structure
5        shall be subject to Commission approval.
6            (E) The utility shall retain an independent third
7        party to score the proposals received through the
8        solicitation process described in this paragraph (4),
9        rank them according to their cost per lifetime
10        kilowatt hours saved, and assemble the portfolio of
11        third-party programs. The gas utility shall recover
12        all costs associated with Commission-approved,
13        third-party administered programs regardless of the
14        success of those programs.
15        (5) Include a proposed or revised cost-recovery
16    mechanism, as provided for under subsection (h) of this
17    Section, to fund the proposed energy efficiency measures
18    and to ensure the recovery of the prudently and reasonably
19    incurred costs of Commission-approved programs.
20        (6) Provide for an annual independent evaluation of
21    the performance of the cost-effectiveness of the utility's
22    portfolio of measures, as well as a full review of the
23    multi-year plan results of the broader net program impacts
24    and, to the extent practical, for adjustment of the
25    measures on a going-forward basis as a result of the
26    evaluations. The resources dedicated to evaluation shall

 

 

SB2896- 484 -LRB102 17909 JWD 25989 b

1    not exceed 3% of portfolio resources in any given year.
2        (7) (Reserved.)
3        (8) (Reserved.)
4        (9) A utility providing approved energy efficiency and
5    demand-response measures in the State shall be permitted
6    to recover costs of those measures through an automatic
7    adjustment clause tariff filed with and approved by the
8    Commission. The tariff shall be established outside the
9    context of a general rate case. Each year the Commission
10    shall initiate a review to reconcile any amounts collected
11    with the actual costs and to determine the required
12    adjustment to the annual tariff factor to match annual
13    expenditures.
14        (9.5) The utility must demonstrate how it will ensure
15    that program implementation contractors and energy
16    efficiency installation vendors will promote workforce
17    equity and quality jobs.
18        (9.6) Utilities shall collect data necessary to ensure
19    compliance with paragraph (9.5) no less than quarterly and
20    shall communicate progress toward compliance with
21    paragraph (9.5) to program implementation contractors and
22    energy efficiency installation vendors no less than
23    quarterly. When it seems unlikely that the criteria in
24    paragraph (9.5) will be met, utilities shall work with
25    relevant vendors, providing education, training, and other
26    resources needed to ensure compliance and, where

 

 

SB2896- 485 -LRB102 17909 JWD 25989 b

1    necessary, adjusting or terminating work with vendors that
2    cannot assist with compliance.
3        (10) A utility required to implement efficiency
4    programs under this Section shall report annually to the
5    Illinois Commerce Commission and the General Assembly on
6    how hiring, contracting, job training, and other practices
7    related to its energy efficiency programs enhance the
8    diversity of vendors working on such programs. These
9    reports must include data on vendor and employee
10    diversity, including data on the implementation of
11    paragraphs (9.5) and (9.6). If the utility is not meeting
12    the requirements of paragraphs (9.5) and (9.6), the
13    utility shall submit a plan to adjust their activities so
14    that they meet the requirements of paragraphs (9.5) and
15    (9.6) within the following year.
16    (k) No more than 6% of energy efficiency and
17demand-response program revenue may be allocated for research,
18development, or pilot deployment of new equipment or measures.
19    (l) When practical, gas utilities shall incorporate
20advanced metering infrastructure data into the planning,
21implementation, and evaluation of energy efficiency measures
22and programs, subject to the data privacy and confidentiality
23protections of applicable law.
24    (m) The independent evaluator shall follow the guidelines
25and use the savings set forth in Commission-approved energy
26efficiency policy manuals and technical reference manuals, as

 

 

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1each may be updated from time to time. Until measure life
2values for energy efficiency measures implemented for
3low-income households under subsection (f) of this Section are
4incorporated into such Commission-approved manuals, the
5low-income measures shall have the same measure life values
6that are established for same measures implemented in
7households that are not low-income households.
 
8    (220 ILCS 5/8-201.7 new)
9    Sec. 8-201.7. Prohibition on Deposits for Low-Income
10Residential Customers or Applicants.
11    (a) On and after the effective date of this amendatory Act
12of the 102nd General Assembly, no public utility shall as a
13condition for standard service require a low-income
14residential customer or applicant to provide a deposit as
15security against potential non-payment for service except when
16the utility has proof that the customer engaged in tampering
17of the public utility equipment during the previous 5 years.
18Within 60 days after the effective date of this amendatory Act
19of the 102nd General Assembly, a utility shall refund all
20deposits collected from low-income customers as security
21against potential nonpayment for standard service to such
22residential customers except when the utility has proof that
23the customer benefited from tampering. Proof that the customer
24for whom the deposit is being required engaged in tampering
25shall be the burden of the utility and the utility shall

 

 

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1provide the customer the opportunity to contest the finding
2that the customer engaged in tampering.
3    (b) As used in this Section:
4    "Low-income residential customer or applicant" means: (i)
5a member of a household at or below 80% of the latest median
6household income as reported by the United States Census
7Bureau for the most applicable community or county; (ii) a
8member of a household at or below 150% of the federal poverty
9level; (iii) a person who is eligible for the Illinois Low
10Income Home Energy Assistance Program (LIHEAP) as defined in
11the Energy Assistance Act; (iv) a person who is eligible to
12participate in the Percentage of Income Payment Plan (PIPP or
13PIP Plan) as defined in the Energy Assistance Act; or (v) a
14person who is eligible to receive Lifeline service as defined
15in the Universal Service Telephone Service Protection Law of
161985.
17    "Tampering" means any unauthorized alteration of utility
18equipment or facilities by which a benefit is achieved for
19which the utility is not compensated, including customer
20self-restoration of utility service.
 
21    (220 ILCS 5/8-201.8 new)
22    Sec. 8-201.8. Prohibition on Late Payment Fees for
23Low-Income Residential Customers or Applicants.
24    (a) Notwithstanding any other provision of this Act, as of
25the effective date of this amendatory Act of the 102nd General

 

 

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1Assembly, a utility shall not charge a low-income residential
2customer or applicant a fee, charge or penalty for late
3payment of any utility bill or invoice.
4    (b) As used in this Section, "low-income residential
5customer or applicant" means: (i) a member of a household at or
6below 80% of the latest median household income as reported by
7the United States Census Bureau for the most applicable
8community or county; (ii) a member of a household at or below
9150% of the federal poverty level; (iii) a person who is
10eligible for the Illinois Low Income Home Energy Assistance
11Program (LIHEAP) as defined in the Energy Assistance Act; (iv)
12a person who is eligible to participate in the Percentage of
13Income Payment Plan (PIPP or PIP Plan) as defined in the Energy
14Assistance Act; or (v) a person who is eligible to receive
15Lifeline service as defined in the Universal Service Telephone
16Service Protection Law of 1985.
17    
 
18    (220 ILCS 5/8-201.9 new)
19    Sec. 8-201.9. Prohibition on Credit Card Convenience Fees.
20    (a) No public utility shall assess any convenience fee,
21surcharge, or other fee to any customer who elects to pay for
22service using a credit card that the public utility would not
23assess to the customer if the customer paid by other available
24methods acceptable to the utility. The Commission may consider
25as an operating expense, for the purpose of determining

 

 

SB2896- 489 -LRB102 17909 JWD 25989 b

1whether a rate or other charge or classification is
2sufficient, costs incurred by a utility to process payments
3described in this Section so long as those costs are
4determined to be prudent, just, and reasonable.
5    (b) As used in this Section, "credit card" means an
6instrument or device, whether known as a credit card, bank
7card, charge card, debit card, automated teller machine card,
8secured credit card, smart card, electronic purse, prepaid
9card, affinity card, or by any other name, issued with or
10without fee by an issuer for the use of the holder to obtain
11credit, money, goods, services, or anything else of value.
 
12    (220 ILCS 5/8-201.10 new)
13    Sec. 8-201.10. Disconnection and Credit and Collections
14Reporting.
15    (a) The Commission shall require all gas, electric, water
16and sewer public utilities under its authority to submit an
17annual report by May 1, 2022 and every May 1 thereafter,
18reporting and making publicly available in executable,
19electronic spreadsheet format, by zip code, on the number of
20disconnections for nonpayment and reconnections that occurred
21in the immediately preceding calendar year.
22    (b) Each such public utility in its annual report shall
23report to the Commission and make publicly available in
24executable, electronic spreadsheet format the following
25information, by zip code, for the immediately preceding

 

 

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1calendar year:
2        (1) the number of customers, by customer class and
3    type of utility service provided, during each month;
4        (2) the number of customers, by customer class and
5    type of utility service, receiving disconnection notices
6    during each month;
7        (3) the number of customers, by customer class and
8    type of utility service, disconnected for nonpayment
9    during each month;
10        (4) the number of customers, by customer class and
11    type of utility service, reconnected because they have
12    paid in full or set up payment arrangements during each
13    month;
14        (5) the number of new deferred payment agreements, by
15    customer class and type of utility service, each month;
16        (6) the number of customers, by customer class and
17    type of utility service, taking service at the beginning
18    of the month under existing deferred payment arrangements;
19        (7) the number of customers, by customer class and
20    type of utility service, completing deferred payment
21    arrangements during the month;
22        (8) the number of payment agreements, by customer
23    class and type of utility service, that failed during each
24    month;
25        (9) the number of customers, by customer class and
26    type of utility service, renegotiating deferred payment

 

 

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1    arrangements during the month;
2        (10) the number of customers, by customer class and
3    type of utility service, assessed late payment fees or
4    charges during the month;
5        (11) the number of customers, by customer class and
6    type of utility service, taking service at the beginning
7    of the month under existing medical payment arrangements;
8        (12) the number of customers, by utility service,
9    completing medical payment arrangements during the month;
10        (13) the number of customers, by utility service,
11    enrolling in new medical payment arrangements during the
12    month;
13        (14) the number of customers, by utility service,
14    renegotiating medical payment arrangements plans during
15    the month;
16        (15) the number of customers, by customer class and
17    utility service, with required deposits with the company
18    at the beginning of the month;
19        (16) the number of customers, by customer class and
20    utility service, required to submit new deposits or
21    increased deposits during the month;
22        (17) the number of customers, by customer class and
23    utility service, whose required deposits were reduced in
24    part or forgone during the month;
25        (18) the number of customers, by customer class and
26    utility service, whose deposits were returned in full

 

 

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1    during the month;
2        (19) the number of customers, by customer class and
3    utility service, with past due amounts greater than 30
4    days past due at the beginning of the month and taking
5    service at the beginning of the month under existing
6    deferred payment arrangements;
7        (20) the dollar volume of past due accounts, by
8    customer class and utility service, for customers with
9    past due amounts greater than 30 days past due at the
10    beginning of the month and taking service at the beginning
11    of the month under existing deferred payment arrangements;
12        (21) the number of customers, by customer class and
13    utility service, with past due amounts greater than 30
14    days past due at the beginning of the month and not taking
15    service at the beginning of the month under existing
16    deferred payment arrangements; and
17        (22) the dollar volume of past due accounts, by
18    customer class and utility service, for customers with
19    past due amounts greater than 30 days past due at the
20    beginning of the month and not taking service at the
21    beginning of the month under existing deferred payment
22    arrangements.
23    (c) The Commission may specify the executable, electronic
24spreadsheet format that utilities must adhere to when
25submitting the information required by this Section.
26Notwithstanding the requirements of this Section, the

 

 

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1Commission may establish an online reporting system and
2require each public utility to report using the online
3reporting system instead of filing information in executable,
4electronic spreadsheet format. The Commission shall make each
5annual report submitted by each public utility publicly
6available on its website within 30 days of receipt.
7    (d) The Commission shall require all gas, electric, water
8and sewer public utilities under its authority to submit an
9annual report by May 1, 2022 and every May 1 thereafter,
10detailing the number of disconnections for nonpayment and
11reconnections that occurred in the immediately preceding
12calendar year.
13    (e) Each such public utility in its annual report shall
14include the following information for the immediately
15preceding calendar year:
16        (1) the number of customers, by customer class, during
17    each month;
18        (2) the number of customers, by customer class,
19    disconnected for nonpayment during each month;
20        (3) the number of customers, by customer class,
21    reconnected because they have paid in full or set up
22    payment arrangements during each month; and
23        (4) the number of customers, by customer class, who
24    have set up payment arrangements each month.
25    (f) The Commission shall make each annual report submitted
26by each public utility publicly available on its website

 

 

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1within 30 days of receipt.
 
2    (220 ILCS 5/8-201.11 new)
3    Sec. 8-201.11. Accelerated Repayment of Excess Deferred
4Income Tax.
5    (a) The General Assembly finds:
6        (1) That a portion of each utility's compensation from
7    ratepayers is attributable to reimbursement for federal
8    taxes paid by the utility.
9        (2) Due to the enactment of the 2017 Tax Cut and Jobs
10    Act, the federal income tax rate for corporations was
11    lowered, resulting in Excess Deferred Income Tax for
12    distribution utilities in the State that serve more than
13    100,000 customers.
14        (3) In proceedings before the Commission, it was
15    determined that the repayment period to ratepayers by the
16    utilities which serve more than 100,000 customers in this
17    State for this EDIT would be 39.5 years.
18        (4) The COVID-19 pandemic has harmed many customers of
19    all rate classes in the State, and resulted in the
20    Commission adopting a number of measures to provide relief
21    for customers.
22        (5) It would be in the interest of the State for the
23    repayment of the Excess Deferred Income Tax referenced in
24    Commission Dockets 19-0436, 19-0387, 20-0381 and 20-0393
25    to be paid back to ratepayers on a timetable greatly

 

 

SB2896- 495 -LRB102 17909 JWD 25989 b

1    accelerated from that set forth in the above-mentioned
2    dockets.
3    (b) Notwithstanding the Commission Orders in Dockets
419-0436, 19-0387, 20-0381 and 20-0383, the Excess Deferred
5Income Tax referenced in those dockets shall be fully refunded
6to ratepayers by the respective utilities no later than
7December 31, 2025.
8    (c) The Commission shall initiate a docket to provide for
9the refunding of these excess deferred income taxes to
10ratepayers of the utilities referenced in those dockets, and
11shall set forth any necessary provisions to accomplish the
12reimbursement on the schedule delineated in subsection (b),
13above.
 
14    (220 ILCS 5/8-201.12 new)
15    Sec. 8-201.12. Auditing the finances of nuclear power
16plants.
17    (a) The General Assembly finds and declares:
18        (1) Nuclear plants produce zero-carbon, baseload power
19    and thus offer value to the people of the State of Illinois
20    by furthering the State's goals to reduce greenhouse gas
21    emissions and reach 100% clean energy;
22        (2) Nuclear plants support communities through job
23    creation, economic investments, and property taxes paid to
24    local counties, which support schools, libraries, and fire
25    departments;

 

 

SB2896- 496 -LRB102 17909 JWD 25989 b

1        (3) In the near term, the closure of nuclear plants in
2    Illinois is likely to result in a generation gap that will
3    be filled by dirty energy, namely fossil fuels;
4        (4) As the State conducts an ongoing assessment of how
5    and over what period of time Illinois can meet its clean
6    energy goals, an understanding of the schedule of plant
7    closures is required;
8        (5) Announced closures of a large percentage of
9    Illinois' electric generation would have a substantial
10    impact on the State budget and electric reliability for
11    Illinois residents;
12        (6) Any financial support for nuclear plants should be
13    short-term and based on clearly demonstrated need;
14        (7) That need should be demonstrated in a transparent
15    and formulaic manner and should minimize costs to
16    ratepayers to the extent possible; and
17        (8) The Office of the Governor, the Illinois
18    Environmental Protection Agency, and the General Assembly
19    must be adequately informed in order to take any necessary
20    action to prevent or minimize serious economic and energy
21    disruption to critical State services.
22    The General Assembly therefore finds that it is necessary
23to audit the finances of nuclear power plants operating in
24Illinois on an annual basis, beginning on January 1, 2022 and
25occurring every year thereafter so long as such plants receive
26Zero Emission Credits.

 

 

SB2896- 497 -LRB102 17909 JWD 25989 b

1    (b) By January 31, 2022 the Illinois Environmental
2Protection Agency shall select an independent firm to conduct
3an in-depth analysis of each nuclear power plant's financial
4information. Within 90 days of selection, the firm shall
5conduct an analysis of the health of Illinois nuclear power
6plants and deliver a report to the Governor and the Illinois
7Environmental Protection Agency. The firm shall also develop
8and deliver a non-confidential summary, which redacts
9proprietary information, for the General Assembly. The report
10shall assess actual costs and revenues and attempt to quantify
11the range and distribution of possible outcomes (negative and
12positive) for the nuclear plants. The report shall make
13findings that include, but are not limited to, the following:
14        (1) The operating costs and risk of the plants,
15    measured against assumptions of market conditions in
16    capacity and energy markets;
17        (2) The amount of State support, if any, needed to
18    cover the operational and risk costs of the plants,
19    looking forward over the next five-year and ten-year
20    periods;
21        (3) Any known operating and risk cost differences
22    between the Illinois nuclear power plants and other
23    nuclear power plants located in the PJM footprint; and
24        (4) The overall financial health of Illinois nuclear
25    power plants, including any near-term growth or risk
26    potential, as well as any evaluation of the health of

 

 

SB2896- 498 -LRB102 17909 JWD 25989 b

1    individual nuclear power plants if some of the Illinois
2    nuclear fleet is decommissioned.
3    (c) The firm's analyses and conclusions in subsection (b)
4shall be based on:
5        (1) Revenues at each plant, which shall include, at a
6    minimum, the following information: (i) energy revenues,
7    including forward market energy prices and spot-market
8    energy prices, and (ii) capacity revenues, including
9    expected capacity revenues for each plant based on the
10    forecasted capacity price. Total revenue shall be
11    calculated as the sum of energy revenue, capacity revenue,
12    and ancillary revenue.
13        (2) Expenses at each plant, which shall include, at a
14    minimum, the following information: (i) operations and
15    maintenance (or O&M), including Site Non-Outage Production
16    Costs and Site Non-Outage Non-Production Costs, (ii)
17    overhead costs, including property tax, direct BSC,
18    nuclear corporate overhead-direct charge to site, nuclear
19    corporate overhead-Institute of Nuclear Power Operations
20    (INPO) allocated to site, and non-nuclear overhead, (iii)
21    outage costs, including O&M expenditures for unscheduled
22    outages, and indirect outage costs, (iv) capital
23    expenditures, including non-fuel capital expenditures and
24    fuel capital expenditures, and (v) spent fuel costs in the
25    form of the U.S. Department of Energy's spent nuclear fuel
26    disposal fee.

 

 

SB2896- 499 -LRB102 17909 JWD 25989 b

1        (3) Income tax, which shall estimate net income by
2    removing the capital expenditures from costs, replacing
3    them with capital depreciation and fuel amortization, and
4    calculating income tax as the product of the tax rate and
5    net income.
6        (4) Net cash flow, which shall be determined as the
7    difference between revenues and expenses in each year.
 
8    (220 ILCS 5/8-201.13 new)
9    Sec. 8-201.13. Customer data.
10    (a) The General Assembly finds:
11        (1) Utility customers in all rate classes are taking a
12    more active interest in their energy usage and how the
13    power they use is generated.
14        (2) As a result of advanced metering technology being
15    installed throughout Illinois, there is substantially more
16    data available than ever before.
17        (3) This data, if properly utilized, could lead to
18    substantial innovation in products and services available
19    to customers.
20        (4) At least one report has suggested that a
21    substantial number of Illinois electricity customers could
22    save money through time of use pricing programs that would
23    require utilization of customer data in their development.
24        (5) This innovation could lead to greater energy
25    efficiency, reduced emissions, and cost savings for

 

 

SB2896- 500 -LRB102 17909 JWD 25989 b

1    customers.
2        (6) While aggregated data may be helpful to providers
3    of energy services and programs, customer privacy must be
4    protected. Customers should have the ability to control
5    the dissemination of their individual data.
6    (b) No later than December 31, 2021, the Illinois Commerce
7Commission shall open a docket on customer data, to be
8concluded no later than June 30, 2022. The Commission process
9should include involvement from stakeholders, consumer
10advocates and the public, as well as experts in this field. At
11a minimum, the Commission process shall consider:
12        (1) the scope of the data currently collected or
13    capable of being collected through advanced metering and
14    other means;
15        (2) how data is currently collected stored and
16    disseminated, and to whom it is disseminated;
17        (3) customer rights associated with their data,
18    including access, opt-outs, and ability to share with
19    third parties;
20        (4) potential improvements that date collection can
21    bring to pricing methods, grid optimization, peak shaving,
22    energy efficiency and other policies consistent with the
23    goals of the State;
24        (5) potential third-parties with whom data could be
25    shared, and the purposes for sharing such data;
26        (6) consumer protections, including technology and

 

 

SB2896- 501 -LRB102 17909 JWD 25989 b

1    policy changes needed to ensure that customers control the
2    ability for individual data to be released;
3        (7) educational programs for consumers about data
4    collection and sharing practices;
5        (8) utility capabilities for different or expanded
6    methods of data collection, storage and dissemination, and
7    utility technology and personnel needed to facilitate
8    various options;
9        (9) methods for resolving resolving consumer
10    complaints about data collection practices; and
11        (10) data security practices and policies necessary to
12    ensure the confidentiality of consumer data and personal
13    information, including practices and policies necessary to
14    notify consumers of data breaches.
15    (c) At the conclusion of the process, the Commission
16shall:
17        (1) report recommendations to the General Assembly and
18    the Governor for suggested legislative changes, if any;
19    and
20        (2) identify and recommend other possible changes to
21    data collection and dissemination practices and policies
22    which do not require legislative approval.
23    (d) The Commission shall have the authority to require
24public utilities to submit plans to the Commission regarding
25data collection, data security, data storage, and data sharing
26practices.

 

 

SB2896- 502 -LRB102 17909 JWD 25989 b

1    (e) Nothing in this Section shall prohibit the Commission
2from exercising existing authority with respect to matters of
3data collection, including implementation of pilot or other
4programs authorized or created under this Act.
 
5    (220 ILCS 5/8-201.14 new)
6    Sec. 8-201.14. Right to self-generate electricity.
7    (a) As used in this Section:
8    "Electric cooperative" has the meaning set forth in
9Section 3.4 of the Electric Supplier Act.
10    "Municipal utility" means a public utility that is owned
11and operated by any political subdivision or municipal
12corporation of this State or owned by such an entity and
13operated by any lessee or any operating agent thereof.
14    "Public utility" has the definition set forth in Section
153-105 of this Act.
16    (b) Customers have the right to, and the Commission shall
17protect the rights of customers to, produce, consume, and
18store their own renewable energy without discriminatory
19repercussions from a public utility, electric cooperative, or
20municipal utility, regardless of whether that energy is
21produced via a system that is owned outright, leased, or
22financed through a behind-the-meter solar power-purchase
23agreement or other means. This includes customers' rights to:
24        (1) generate, consume, and export renewable energy and
25    reduce his or her use of electricity obtained from the

 

 

SB2896- 503 -LRB102 17909 JWD 25989 b

1    grid;
2        (2) use technology to store energy at his or her
3    residence;
4        (3) connect his or her electrical system that
5    generates renewable energy, stores energy, or any
6    combination thereof, with the electricity meter on the
7    customer's premises that is provided by a public utility,
8    electric cooperative, or municipal utility:
9            (A) in a timely manner;
10            (B) in accordance with requirements established by
11        the electric utility to ensure the safety of utility
12        workers; and
13            (C) after providing written notice to the electric
14        utility providing service in the service territory,
15        installing a nomenclature plate on the electrical
16        meter panel and meeting all applicable State and local
17        safety and electrical code requirements associated
18        with installing a parallel distributed generation
19        system; and
20        (4) receive fair credit for energy exported to the
21    grid.
22    (c) A public utility, electric cooperative, or municipal
23utility customer who produces, consumes, and stores his or her
24own renewable energy shall not face discriminatory rate
25design, fees, treatment, or excessive compliance requirements
26as provided by paragraph (3) of subsection (n) of Section

 

 

SB2896- 504 -LRB102 17909 JWD 25989 b

116-107.5.
2    (d) A public utility, electric cooperative, or municipal
3utility customer shall have a right to appeal any decision
4related to self-generation and storage that violates these
5rights to self-generation and non-discrimination pursuant to
6the provisions of this Section through a complaint process.
7    (e) The Illinois Commerce Commission shall adopt all rules
8necessary for the administration of this Section.
 
9    (220 ILCS 5/8-406)  (from Ch. 111 2/3, par. 8-406)
10    Sec. 8-406. Certificate of public convenience and
11necessity.
12    (a) No public utility not owning any city or village
13franchise nor engaged in performing any public service or in
14furnishing any product or commodity within this State as of
15July 1, 1921 and not possessing a certificate of public
16convenience and necessity from the Illinois Commerce
17Commission, the State Public Utilities Commission or the
18Public Utilities Commission, at the time this amendatory Act
19of 1985 goes into effect, shall transact any business in this
20State until it shall have obtained a certificate from the
21Commission that public convenience and necessity require the
22transaction of such business.
23    (b) No public utility shall begin the construction of any
24new plant, equipment, property or facility which is not in
25substitution of any existing plant, equipment, property or

 

 

SB2896- 505 -LRB102 17909 JWD 25989 b

1facility or any extension or alteration thereof or in addition
2thereto, unless and until it shall have obtained from the
3Commission a certificate that public convenience and necessity
4require such construction. Whenever after a hearing the
5Commission determines that any new construction or the
6transaction of any business by a public utility will promote
7the public convenience and is necessary thereto, it shall have
8the power to issue certificates of public convenience and
9necessity. The Commission shall determine that proposed
10construction will promote the public convenience and necessity
11only if the utility demonstrates: (1) that the proposed
12construction is necessary to provide adequate, reliable, and
13efficient service to its customers and is the least-cost means
14of satisfying the service needs of its customers or that the
15proposed construction will promote the development of an
16effectively competitive electricity market that operates
17efficiently, is equitable to all customers, and is the least
18cost means of satisfying those objectives; (2) that the
19utility is capable of efficiently managing and supervising the
20construction process and has taken sufficient action to ensure
21adequate and efficient construction and supervision thereof;
22and (3) that the utility is capable of financing the proposed
23construction without significant adverse financial
24consequences for the utility or its customers.
25    (c) After the effective date of this amendatory Act of
261987, no construction shall commence on any new nuclear power

 

 

SB2896- 506 -LRB102 17909 JWD 25989 b

1plant to be located within this State, and no certificate of
2public convenience and necessity or other authorization shall
3be issued therefor by the Commission, until the Director of
4the Illinois Environmental Protection Agency finds that the
5United States Government, through its authorized agency, has
6identified and approved a demonstrable technology or means for
7the disposal of high level nuclear waste, or until such
8construction has been specifically approved by a statute
9enacted by the General Assembly.
10    As used in this Section, "high level nuclear waste" means
11those aqueous wastes resulting from the operation of the first
12cycle of the solvent extraction system or equivalent and the
13concentrated wastes of the subsequent extraction cycles or
14equivalent in a facility for reprocessing irradiated reactor
15fuel and shall include spent fuel assemblies prior to fuel
16reprocessing.
17    (d) In making its determination, the Commission shall
18attach primary weight to the cost or cost savings to the
19customers of the utility. The Commission may consider any or
20all factors which will or may affect such cost or cost savings,
21including the public utility's engineering judgment regarding
22the materials used for construction.
23    (e) The Commission may issue a temporary certificate which
24shall remain in force not to exceed one year in cases of
25emergency, to assure maintenance of adequate service or to
26serve particular customers, without notice or hearing, pending

 

 

SB2896- 507 -LRB102 17909 JWD 25989 b

1the determination of an application for a certificate, and may
2by regulation exempt from the requirements of this Section
3temporary acts or operations for which the issuance of a
4certificate will not be required in the public interest.
5    A public utility shall not be required to obtain but may
6apply for and obtain a certificate of public convenience and
7necessity pursuant to this Section with respect to any matter
8as to which it has received the authorization or order of the
9Commission under the Electric Supplier Act, and any such
10authorization or order granted a public utility by the
11Commission under that Act shall as between public utilities be
12deemed to be, and shall have except as provided in that Act the
13same force and effect as, a certificate of public convenience
14and necessity issued pursuant to this Section.
15    No electric cooperative shall be made or shall become a
16party to or shall be entitled to be heard or to otherwise
17appear or participate in any proceeding initiated under this
18Section for authorization of power plant construction and as
19to matters as to which a remedy is available under The Electric
20Supplier Act.
21    (f) Such certificates may be altered or modified by the
22Commission, upon its own motion or upon application by the
23person or corporation affected. Unless exercised within a
24period of 2 years from the grant thereof authority conferred
25by a certificate of convenience and necessity issued by the
26Commission shall be null and void.

 

 

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1    No certificate of public convenience and necessity shall
2be construed as granting a monopoly or an exclusive privilege,
3immunity or franchise.
4    (g) A public utility that undertakes any of the actions
5described in items (1) through (3) of this subsection (g) or
6that has obtained approval pursuant to Section 8-406.1 of this
7Act shall not be required to comply with the requirements of
8this Section to the extent such requirements otherwise would
9apply. For purposes of this Section and Section 8-406.1 of
10this Act, "high voltage electric service line" means an
11electric line having a design voltage of 100,000 or more. For
12purposes of this subsection (g), a public utility may do any of
13the following:
14        (1) replace or upgrade any existing high voltage
15    electric service line and related facilities,
16    notwithstanding its length;
17        (2) relocate any existing high voltage electric
18    service line and related facilities, notwithstanding its
19    length, to accommodate construction or expansion of a
20    roadway or other transportation infrastructure; or
21        (3) construct a high voltage electric service line and
22    related facilities that is constructed solely to serve a
23    single customer's premises or to provide a generator
24    interconnection to the public utility's transmission
25    system and that will pass under or over the premises owned
26    by the customer or generator to be served or under or over

 

 

SB2896- 509 -LRB102 17909 JWD 25989 b

1    premises for which the customer or generator has secured
2    the necessary right of way.
3    (h) A public utility seeking to construct a high-voltage
4electric service line and related facilities (Project) must
5show that the utility has held a minimum of 2 pre-filing public
6meetings to receive public comment concerning the Project in
7each county where the Project is to be located, no earlier than
86 months prior to filing an application for a certificate of
9public convenience and necessity from the Commission. Notice
10of the public meeting shall be published in a newspaper of
11general circulation within the affected county once a week for
123 consecutive weeks, beginning no earlier than one month prior
13to the first public meeting. If the Project traverses 2
14contiguous counties and where in one county the transmission
15line mileage and number of landowners over whose property the
16proposed route traverses is one-fifth or less of the
17transmission line mileage and number of such landowners of the
18other county, then the utility may combine the 2 pre-filing
19meetings in the county with the greater transmission line
20mileage and affected landowners. All other requirements
21regarding pre-filing meetings shall apply in both counties.
22Notice of the public meeting, including a description of the
23Project, must be provided in writing to the clerk of each
24county where the Project is to be located. A representative of
25the Commission shall be invited to each pre-filing public
26meeting.

 

 

SB2896- 510 -LRB102 17909 JWD 25989 b

1    (i) For applications filed after the effective date of
2this amendatory Act of the 99th General Assembly, the
3Commission shall by registered mail notify each owner of
4record of land, as identified in the records of the relevant
5county tax assessor, included in the right-of-way over which
6the utility seeks in its application to construct a
7high-voltage electric line of the time and place scheduled for
8the initial hearing on the public utility's application. The
9utility shall reimburse the Commission for the cost of the
10postage and supplies incurred for mailing the notice.
11    (j) A certificate or approval under this Section shall not
12be modified or denied on the basis of the common law doctrine
13of first in the field if the plant, equipment, property, or
14facility is subject to a competitive process under the
15authority of the Federal Energy Regulatory Commission.
16(Source: P.A. 99-399, eff. 8-18-15.)
 
17    (220 ILCS 5/8-512 new)
18    Sec. 8-512. Renewable energy access plan.
19    (a) It is the policy of this State to promote
20cost-effective transmission system development that ensures
21reliability of the electric transmission system, lowers carbon
22emissions, minimizes long-term costs for consumers, and
23supports the electric policy goals of this State. The General
24Assembly finds that:
25        (1) Transmission planning, primarily for reliability

 

 

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1    purposes, but also for economic and public policy reasons
2    is conducted by regional transmission organizations in
3    which transmission-owning Illinois utilities and other
4    stakeholders are members.
5        (2) Order No. 1000 of the Federal Energy Regulatory
6    Commission requires regional transmission organizations to
7    plan for transmission system needs in light of State
8    public policies, and to accept input from states during
9    the transmission system planning processes.
10        (3) The State of Illinois does not currently have a
11    comprehensive power and environmental policy planning
12    process to identify transmission infrastructure needs that
13    can serve as a vital input into the regional and
14    inter-regional transmission organization planning
15    processes conducted under Order No. 1000 and other laws
16    and regulations.
17        (4) This State is an electricity generation and power
18    transmission hub, and can leverage that position to invest
19    in infrastructure that enables new and existing Illinois
20    generators to meet the public policy goals of the State of
21    Illinois and of interconnected states while
22    cost-effectively supporting tens of thousands of jobs in
23    the renewable energy sector in this State.
24        (5) The nation has a need to readily access this
25    State's low-cost, clean electric power, and this State
26    also desires access to clean energy resources in other

 

 

SB2896- 512 -LRB102 17909 JWD 25989 b

1    states to develop and support its low-carbon economy and
2    keep electricity prices low in Illinois and interconnected
3    states.
4        (6) Existing transmission infrastructure may constrain
5    the State's achievement of 100% renewable energy by 2050,
6    the accelerated adoption of electric vehicles in a just
7    and equitable way, and electrification of additional
8    sectors of the Illinois economy.
9        (7) Transmission system congestion within this State
10    and the regional transmission organizations serving this
11    State limits the ability of this State's existing and new
12    electric generation facilities that do not emit carbon
13    dioxide, including renewable energy resources and zero
14    emission facilities, to serve the public policy goals of
15    this State and other states, which constrains investment
16    in this State.
17        (8) Investment in infrastructure to support existing
18    and new electric generation facilities that do not emit
19    carbon dioxide, including renewable energy resources and
20    zero emission facilities, stimulates significant economic
21    development and job growth in this State, as well as
22    creates environmental and public health benefits in this
23    State.
24        (9) Creating a forward-looking plan for this State's
25    electric transmission infrastructure, as opposed to
26    relying on case-by-case development and repeated marginal

 

 

SB2896- 513 -LRB102 17909 JWD 25989 b

1    upgrades, will achieve a lower-cost system for Illinois'
2    electricity customers. A forward-looking plan can also
3    help integrate and achieve a comprehensive set of
4    objectives and multiple state, regional, and national
5    policy goals.
6        (10) Alternatives to overhead electric transmission
7    lines can achieve cost-effective resolution of system
8    impacts, and warrant investigation of the circumstances
9    under which those alternatives should be considered and
10    approved. The alternatives are likely to be beneficial as
11    investment in electric transmission infrastructure moves
12    forward.
13    (b) Consistent with the findings identified in subsection
14(a), the Commission shall open an investigation to develop and
15adopt a renewable energy access plan no later than December
1631, 2022. To assist and support the Commission in the
17development of the plan, the Commission shall retain the
18services of technical and policy experts with relevant fields
19of expertise, solicit technical and policy analysis from the
20public, and provide for a 120-day open public comment period
21after publication of a draft report, which shall be published
22no later than 90 days after the comment period ends. The plan
23shall, at a minimum, do the following:
24        (1) designate renewable energy access plan zones
25    throughout this State in areas in which renewable energy
26    resources and suitable land areas are sufficient for

 

 

SB2896- 514 -LRB102 17909 JWD 25989 b

1    developing generating capacity from renewable energy
2    technologies;
3        (2) develop a plan to achieve transmission capacity
4    necessary to deliver the electric output from renewable
5    energy technologies in the renewable energy access plan
6    zones to customers in Illinois and other states in a
7    manner that is most beneficial and cost-effective to
8    customers;
9        (3) use this State's position as an electricity
10    generation and power transmission hub to create new
11    investment in this State's renewable energy resources;
12        (4) consider programs, policies, and electric
13    transmission projects that can be adopted within this
14    State that promote the cost-effective delivery of power
15    from renewable energy resources interconnected to the bulk
16    electric system to meet the renewable portfolio standard
17    targets under subsection (c) of Section 1-75 of the
18    Illinois Power Agency Act;
19        (5) consider proposals to improve regional
20    transmission organizations' regional and interregional
21    system planning processes and an analysis of how those
22    proposals would improve reliability and cost-effective
23    delivery of electricity in Illinois and the region;
24        (6) make findings and policy recommendations based on
25    technical and policy analysis regarding locations of
26    renewable energy access plan zones and the transmission

 

 

SB2896- 515 -LRB102 17909 JWD 25989 b

1    system developments needed to cost-effectively achieve the
2    public policy goals identified herein; and
3        (7) present the Commission's conclusions and proposed
4    recommendations based on its analysis.
5    (c) No later than December 31, 2025, and every other year
6thereafter, the Commission shall open an investigation to
7develop and adopt an updated renewable energy access plan
8that, at a minimum, evaluates the implementation and
9effectiveness of the renewable energy access plan, recommends
10improvements to the renewable energy access plan, and provides
11changes to transmission capacity necessary to deliver electric
12output from the renewable energy access plan zones.
 
13    (220 ILCS 5/9-201)  (from Ch. 111 2/3, par. 9-201)
14    Sec. 9-201. (a) Unless the Commission otherwise orders,
15and except as otherwise provided in this Section, no change
16shall be made by any public utility in any rate or other charge
17or classification, or in any rule, regulation, practice or
18contract relating to or affecting any rate or other charge,
19classification or service, or in any privilege or facility,
20except after 45 days' notice to the Commission and to the
21public as herein provided. Such notice shall be given by
22filing with the Commission and keeping open for public
23inspection new schedules or supplements stating plainly the
24change or changes to be made in the schedule or schedules then
25in force, and the time when the change or changes will go into

 

 

SB2896- 516 -LRB102 17909 JWD 25989 b

1effect, and by publication in a newspaper of general
2circulation or such other notice to persons affected by such
3change as may be prescribed by rule of the Commission. The
4Commission, for good cause shown, may allow changes without
5requiring the 45 days' notice herein provided for, by an order
6specifying the changes so to be made and the time when they
7shall take effect and the manner in which they shall be filed
8and published.
9    When any change is proposed in any rate or other charge, or
10classification, or in any rule, regulation, practice, or
11contract relating to or affecting any rate or other charge,
12classification or service, or in any privilege or facility,
13such proposed change shall be plainly indicated on the new
14schedule filed with the Commission, by some character to be
15designated by the Commission, immediately preceding or
16following the item.
17    When any public utility providing water or sewer service
18proposes any change in any rate or other charge, or
19classification, or in any rule, regulation, practice, or
20contract relating to or affecting any rate or other charge,
21classification or service, or in any privilege or facility,
22such utility shall, in addition to the other notice
23requirements of this Act, provide notice of such change to all
24customers potentially affected by including a notice and
25description of such change, and of Commission procedures for
26intervention, in the first bill sent to each such customer

 

 

SB2896- 517 -LRB102 17909 JWD 25989 b

1after the filing of the proposed change.
2    For water or sewer utilities with greater than 15,000
3total customers, the following notice requirements are
4applicable, in addition to the other notice requirements of
5this Act:
6        (1) As a separate bill insert, an initial notice in
7    the first bill sent to all customers potentially affected
8    by the proposed change after the filing of the proposed
9    change shall include:
10            (A) the approximate date when the change or
11        changes shall go into effect assuming the Commission
12        utilizes the 11-month process as described in this
13        Section;
14            (B) a statement indicating that the estimated bill
15        impact may vary based on multiple factors, including,
16        but not limited to, meter size, usage volume, and the
17        fire protection district;
18            (C) the water or sewer utility's customer service
19        number or other number as may be appropriate where an
20        authorized agent of the water or sewer utility can
21        explain how the proposed increase might impact an
22        individual customer's bill;
23            (D) if the proposed change involves a change from
24        a flat to a volumetric rate, an explanation of
25        volumetric rate;
26            (E) a reference to the water or sewer utility's

 

 

SB2896- 518 -LRB102 17909 JWD 25989 b

1        website where customers can find tips on water
2        conservation; and
3            (F) for customers receiving both water and sewer
4        service from a utility and if the customer has an
5        option to install a separate meter for irrigation to
6        mitigate sewer charges, an explanation of the water
7        and sewer utility's and the customer's
8        responsibilities for installation of a separate meter
9        if such a change is approved.
10        (2) A second notice to all customers shall be included
11    on the first bill after the Commission suspends the
12    tariffs initiating the rate case.
13        (3) Final notice of such change shall be sent to all
14    customers potentially affected by the proposed change by
15    including information required under this paragraph (3)
16    with the first bill after the effective date of the rates
17    approved by the Final Order of the Commission in a rate
18    case. The notice shall include the following:
19            (A) the date when the change or changes went into
20        effect;
21            (B) the water or sewer utility's customer service
22        number or other number as may be appropriate where an
23        authorized agent of the water or sewer utility can
24        explain how the proposed increase might impact an
25        individual customer's bill;
26            (C) an explanation that usage shall now be charged

 

 

SB2896- 519 -LRB102 17909 JWD 25989 b

1        at a volumetric rate rather than a flat rate, if
2        applicable;
3            (D) a reference to the water or sewer utility's
4        website where the customer can find tips on water
5        conservation; and
6            (E) for customers receiving both water and sewer
7        service from a utility and if the customer has an
8        option to install a separate meter for irrigation to
9        mitigate sewer charges, an explanation of the water
10        and sewer utility's and the customer's
11        responsibilities for installation of a separate meter
12        if such a change is approved.
13    (b) Whenever there shall be filed with the Commission any
14schedule stating an individual or joint rate or other charge,
15classification, contract, practice, rule or regulation, the
16Commission shall have power, and it is hereby given authority,
17either upon complaint or upon its own initiative without
18complaint, at once, and if it so orders, without answer or
19other formal pleadings by the interested public utility or
20utilities, but upon reasonable notice, to enter upon a hearing
21concerning the propriety of such rate or other charge,
22classification, contract, practice, rule or regulation, and
23pending the hearing and decision thereon, such rate or other
24charge, classification, contract, practice, rule or regulation
25shall not go into effect. The period of suspension of such rate
26or other charge, classification, contract, practice, rule or

 

 

SB2896- 520 -LRB102 17909 JWD 25989 b

1regulation shall not extend more than 105 days beyond the time
2when such rate or other charge, classification, contract,
3practice, rule or regulation would otherwise go into effect
4unless the Commission, in its discretion, extends the period
5of suspension for a further period not exceeding 6 months.
6    All rates or other charges, classifications, contracts,
7practices, rules or regulations not so suspended shall, on the
8expiration of 45 days from the time of filing the same with the
9Commission, or of such lesser time as the Commission may
10grant, go into effect and be the established and effective
11rates or other charges, classifications, contracts, practices,
12rules and regulations, subject to the power of the Commission,
13after a hearing had on its own motion or upon complaint, as
14herein provided, to alter or modify the same.
15    Within 30 days after such changes have been authorized by
16the Commission, copies of the new or revised schedules shall
17be posted or filed in accordance with the terms of Section
189-103 of this Act, in such a manner that all changes shall be
19plainly indicated. The Commission shall incorporate into the
20period of suspension a review period of 4 business days during
21which the Commission may review and determine whether the new
22or revised schedules comply with the Commission's decision
23approving a change to the public utility's rates. Such review
24period shall not extend the suspension period by more than 2
25days. Absent notification to the contrary within the 4
26business day period, the new or revised schedules shall be

 

 

SB2896- 521 -LRB102 17909 JWD 25989 b

1deemed approved.
2    (c) If the Commission enters upon a hearing concerning the
3propriety of any proposed rate or other charge,
4classification, contract, practice, rule or regulation, the
5Commission shall establish the rates or other charges,
6classifications, contracts, practices, rules or regulations
7proposed, in whole or in part, or others in lieu thereof, which
8it shall find to be just and reasonable. In such hearing, the
9burden of proof to establish the justness and reasonableness
10of the proposed rates or other charges, classifications,
11contracts, practices, rules or regulations, in whole and in
12part, shall be upon the utility. The utility, the staff of the
13Commission, the Attorney General, or any party to a proceeding
14initiated under this Section who has been granted intervenor
15status and submitted a post-hearing brief must be given the
16opportunity to present oral argument, if requested no later
17than the date for filing exceptions, on the propriety of any
18proposed rate or other charge, classification, contract,
19practice, rule, or regulation. No rate or other charge,
20classification, contract, practice, rule or regulation shall
21be found just and reasonable unless it is consistent with
22Sections of this Article.
23    (d) Except where compliance with Section 8-401 of this Act
24is of urgent and immediate concern, no representative of a
25public utility may discuss with a commissioner, commissioner's
26assistant, or administrative law judge in a non-public setting

 

 

SB2896- 522 -LRB102 17909 JWD 25989 b

1a planned filing for a general rate increase. If a public
2utility makes a filing under this Section, then no substantive
3communication by any such person with a commissioner,
4commissioner's assistant, or administrative law judge
5concerning the filing is permitted until a notice of hearing
6has been issued. After the notice of hearing has been issued,
7the only communications by any such person with a
8commissioner, commissioner's assistant, or administrative law
9judge concerning the filing permitted are communications
10permitted under Section 10-103 of this Act. If any such
11communication does occur, then within 5 days of the docket
12being initiated all details relating to the communication
13shall be placed on the public record of the proceeding. The
14record shall include any materials, whether written, recorded,
15filmed, or graphic in nature, produced or reproduced on any
16media, used in connection with the communication. The record
17shall reflect the names of all persons who transmitted,
18received, or were otherwise involved in the communication, the
19duration of the communication, and whether the communication
20occurred in person or by other means. In the case of an oral
21communication, the record shall also reflect the location or
22locations of all persons involved in the communication and, if
23the communication occurred by telephone, the telephone numbers
24for the callers and recipients of the communication. A
25commissioner, commissioner's assistant, or administrative law
26judge who is involved in any such communication shall be

 

 

SB2896- 523 -LRB102 17909 JWD 25989 b

1recused from the affected proceeding. The Commission, or any
2commissioner or administrative law judge presiding over the
3proceeding shall, in the event of a violation of this Section,
4take action necessary to ensure that such violation does not
5prejudice any party or adversely affect the fairness of the
6proceedings including dismissing the affected proceeding.
7Nothing in this subsection (d) is intended to preclude
8otherwise allowable updates on issues that may be indirectly
9related to a general rate case filing because cost recovery
10for the underlying activity may be requested. Such updates may
11include, without limitation, issues related to outages and
12restoration, credit ratings, security issuances, reliability,
13Federal Energy Regulatory Commission matters, Federal
14Communications Commission matters, regional reliability
15organizations, consumer education, or labor matters, provided
16that such updates may not include cost recovery in a planned
17rate case.
18(Source: P.A. 100-840, eff. 8-13-18.)
 
19    (220 ILCS 5/9-220.3)
20    (Section scheduled to be repealed on December 31, 2023)
21    Sec. 9-220.3. Natural gas surcharges authorized.
22    (a) Tariff.
23        (1) Pursuant to Section 9-201 of this Act, a natural
24    gas utility serving more than 700,000 customers may file a
25    tariff for a surcharge which adjusts rates and charges to

 

 

SB2896- 524 -LRB102 17909 JWD 25989 b

1    provide for recovery of costs associated with investments
2    in qualifying infrastructure plant, independent of any
3    other matters related to the utility's revenue
4    requirement.
5        (2) Within 30 days after the effective date of this
6    amendatory Act of the 98th General Assembly, the
7    Commission shall adopt emergency rules to implement the
8    provisions of this amendatory Act of the 98th General
9    Assembly. The utility may file with the Commission tariffs
10    implementing the provisions of this amendatory Act of the
11    98th General Assembly after the effective date of the
12    emergency rules authorized by subsection (i).
13        (3) The Commission shall issue an order approving, or
14    approving with modification to ensure compliance with this
15    Section, the tariff no later than 120 days after such
16    filing of the tariffs filed pursuant to this Section. The
17    utility shall have 7 days following the date of service of
18    the order to notify the Commission in writing whether it
19    will accept any modifications so identified in the order
20    or whether it has elected not to proceed with the tariff.
21    If the order includes no modifications or if the utility
22    notifies the Commission that it will accept such
23    modifications, the tariff shall take effect on the first
24    day of the calendar year in which the Commission issues
25    the order, subject to petitions for rehearing and
26    appellate procedures. After the tariff takes effect, the

 

 

SB2896- 525 -LRB102 17909 JWD 25989 b

1    utility may, upon 10 days' notice to the Commission, file
2    to withdraw the tariff at any time, and the Commission
3    shall approve such filing without suspension or hearing,
4    subject to a final reconciliation as provided in
5    subsection (e) of this Section.
6        (4) When a natural gas utility withdraws the surcharge
7    tariff, the utility shall not recover any additional
8    charges through the surcharge approved pursuant to this
9    Section, subject to the resolution of the final
10    reconciliation pursuant to subsection (e) of this Section.
11    The utility's qualifying infrastructure investment net of
12    accumulated depreciation may be transferred to the natural
13    gas utility's rate base in the utility's next general rate
14    case. The utility's delivery base rates in effect upon
15    withdrawal of the surcharge tariff shall not be adjusted
16    at the time the surcharge tariff is withdrawn.
17        (5) A natural gas utility that is subject to its
18    delivery base rates being fixed at their current rates
19    pursuant to a Commission order entered in Docket No.
20    11-0046, notwithstanding the effective date of its tariff
21    authorized pursuant to this Section, shall reflect in a
22    tariff surcharge only those projects placed in service
23    after the fixed rate period of the merger agreement has
24    expired by its terms.
25    (b) For purposes of this Section, "qualifying
26infrastructure plant" includes only plant additions placed in

 

 

SB2896- 526 -LRB102 17909 JWD 25989 b

1service not reflected in the rate base used to establish the
2utility's delivery base rates. "Costs associated with
3investments in qualifying infrastructure plant" shall include
4a return on qualifying infrastructure plant and recovery of
5depreciation and amortization expense on qualifying
6infrastructure plant, net of the depreciation included in the
7utility's base rates on any plant retired in conjunction with
8the installation of the qualifying infrastructure plant.
9Collectively the "qualifying infrastructure plant" and "costs
10associated with investments in qualifying infrastructure
11plant" are referred to as the "qualifying infrastructure
12investment" and that are related to one or more of the
13following:
14        (1) the installation of facilities to retire and
15    replace underground natural gas facilities, including
16    facilities appurtenant to facilities constructed of those
17    materials such as meters, regulators, and services, and
18    that are constructed of cast iron, wrought iron, ductile
19    iron, unprotected coated steel, unprotected bare steel,
20    mechanically coupled steel, copper, Cellulose Acetate
21    Butyrate (CAB) plastic, pre-1973 DuPont Aldyl "A"
22    polyethylene, PVC, or other types of materials identified
23    by a State or federal governmental agency as being prone
24    to leakage;
25        (2) the relocation of meters from inside customers'
26    facilities to outside;

 

 

SB2896- 527 -LRB102 17909 JWD 25989 b

1        (3) the upgrading of the gas distribution system from
2    a low pressure to a medium pressure system, including
3    installation of high-pressure facilities to support the
4    upgrade;
5        (4) modernization investments by a combination
6    utility, as defined in subsection (b) of Section 16-108.5
7    of this Act, to install:
8            (A) advanced gas meters in connection with the
9        installation of advanced electric meters pursuant to
10        Sections 16-108.5 and 16-108.6 of this Act; and
11            (B) the communications hardware and software and
12        associated system software that creates a network
13        between advanced gas meters and utility business
14        systems and allows the collection and distribution of
15        gas-related information to customers and other parties
16        in addition to providing information to the utility
17        itself;
18        (5) replacing high-pressure transmission pipelines and
19    associated facilities identified as having a higher risk
20    of leakage or failure or installing or replacing
21    high-pressure transmission pipelines and associated
22    facilities to establish records and maximum allowable
23    operating pressures;
24        (6) replacing difficult to locate mains and service
25    pipes and associated facilities; and
26        (7) replacing or installing transmission and

 

 

SB2896- 528 -LRB102 17909 JWD 25989 b

1    distribution regulator stations, regulators, valves, and
2    associated facilities to establish over-pressure
3    protection.
4    With respect to the installation of the facilities
5identified in paragraph (1) of subsection (b) of this Section,
6the natural gas utility shall determine priorities for such
7installation with consideration of projects either: (i)
8integral to a general government public facilities improvement
9program or (ii) ranked in the highest risk categories in the
10utility's most recent Distribution Integrity Management Plan
11where removal or replacement is the remedial measure.
12    (c) Qualifying infrastructure investment, defined in
13subsection (b) of this Section, recoverable through a tariff
14authorized by subsection (a) of this Section, shall not
15include costs or expenses incurred in the ordinary course of
16business for the ongoing or routine operations of the utility,
17including, but not limited to:
18        (1) operating and maintenance costs; and
19        (2) costs of facilities that are revenue-producing,
20    which means facilities that are constructed or installed
21    for the purpose of serving new customers.
22    (d) Gas utility commitments. A natural gas utility that
23has in effect a natural gas surcharge tariff pursuant to this
24Section shall:
25        (1) recognize that the General Assembly identifies
26    improved public safety and reliability of natural gas

 

 

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1    facilities as the cornerstone upon which this Section is
2    designed, and qualifying projects should be encouraged,
3    selected, and prioritized based on these factors; and
4        (2) provide information to the Commission as requested
5    to demonstrate that (i) the projects included in the
6    tariff are indeed qualifying projects and (ii) the
7    projects are selected and prioritized taking into account
8    improved public safety and reliability.
9        (3) The amount of qualifying infrastructure investment
10    eligible for recovery under the tariff in the applicable
11    calendar year is limited to the lesser of (i) the actual
12    qualifying infrastructure plant placed in service in the
13    applicable calendar year and (ii) the difference by which
14    total plant additions in the applicable calendar year
15    exceed the baseline amount, and subject to the limitation
16    in subsection (g) of this Section. A natural gas utility
17    can recover the costs of qualifying infrastructure
18    investments through an approved surcharge tariff from the
19    beginning of each calendar year subject to the
20    reconciliation initiated under paragraph (2) of subsection
21    (e) of this Section, during which the Commission may make
22    adjustments to ensure that the limits defined in this
23    paragraph are not exceeded. Further, if total plant
24    additions in a calendar year do not exceed the baseline
25    amount in the applicable calendar year, the Commission,
26    during the reconciliation initiated under paragraph (2) of

 

 

SB2896- 530 -LRB102 17909 JWD 25989 b

1    subsection (e) of this Section for the applicable calendar
2    year, shall adjust the amount of qualifying infrastructure
3    investment eligible for recovery under the tariff to zero.
4        (4) For purposes of this Section, "baseline amount"
5    means an amount equal to the utility's average of total
6    depreciation expense, as reported on page 336, column (b)
7    of the utility's ILCC Form 21, for the calendar years 2006
8    through 2010.
9    (e) Review of investment.
10        (1) The amount of qualifying infrastructure investment
11    shall be shown on an Information Sheet supplemental to the
12    surcharge tariff and filed with the Commission monthly or
13    some other time period at the option of the utility. The
14    Information Sheet shall be accompanied by data showing the
15    calculation of the qualifying infrastructure investment
16    adjustment. Unless otherwise ordered by the Commission,
17    each qualifying infrastructure investment adjustment shown
18    on an Information Sheet shall become effective pursuant to
19    the utility's approved tariffs.
20        (2) For each calendar year in which a surcharge tariff
21    is in effect, the natural gas utility shall file a
22    petition with the Commission to initiate hearings to
23    reconcile amounts billed under each surcharge authorized
24    pursuant to this Section with the actual prudently
25    incurred costs recoverable under this tariff in the
26    preceding year. The petition filed by the natural gas

 

 

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1    utility shall include testimony and schedules that support
2    the accuracy and the prudence of the qualifying
3    infrastructure investment for the calendar year being
4    reconciled. The petition filed shall also include the
5    number of jobs attributable to the natural gas surcharge
6    tariff as required by rule. The review of the utility's
7    investment shall include identification and review of all
8    plant that was ranked within the highest risk categories
9    in that utility's most recent Distribution Integrity
10    Management Plan.
11    (f) The rate of return applied shall be the overall rate of
12return authorized by the Commission in the utility's last gas
13rate case.
14    (g) The cumulative amount of increases billed under the
15surcharge, since the utility's most recent delivery service
16rate order, shall not exceed an annual average 4% of the
17utility's delivery base rate revenues, but shall not exceed
185.5% in any given year. On the effective date of new delivery
19base rates, the surcharge shall be reduced to zero with
20respect to qualifying infrastructure investment that is
21transferred to the rate base used to establish the utility's
22delivery base rates, provided that the utility may continue to
23charge or refund any reconciliation adjustment determined
24pursuant to subsection (e) of this Section.
25    (h) If a gas utility obtains a surcharge tariff under this
26Section 9-220.3, then it and its affiliates are excused from

 

 

SB2896- 532 -LRB102 17909 JWD 25989 b

1the rate case filing requirements contained in Sections
29-220(h) and 9-220(h-1). In the event a natural gas utility,
3prior to the effective date of this amendatory Act of the 98th
4General Assembly, made a rate case filing that is still
5pending on the effective date of this amendatory Act of the
698th General Assembly, the natural gas utility may, at the
7time it files its surcharge tariff with the Commission, also
8file a notice with the Commission to withdraw its rate case
9filing. Any affiliate of such natural gas utility may also
10file to withdraw its rate case filing. Upon receipt of such
11notice, the Commission shall dismiss the rate case filing with
12prejudice and such tariffs and the record related thereto
13shall not be the subject of any further hearing,
14investigation, or proceeding of any kind related to rates for
15gas delivery services. Notwithstanding the foregoing, a
16natural gas utility shall not be permitted to withdraw a rate
17case filing for which a proposed order recommending a rate
18reduction is pending. A natural gas utility shall not be
19permitted to withdraw the gas delivery services tariffs that
20are the subject of Commission Docket Nos. 12-0511/12-0512
21(cons.). None of the costs incurred for the withdrawn rate
22case are recoverable from ratepayers.
23    (i) The Commission shall promulgate rules and regulations
24to carry out the provisions of this Section under the
25emergency rulemaking provisions set forth in Section 5-45 of
26the Illinois Administrative Procedure Act, and such emergency

 

 

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1rules shall be effective no later than 30 days after the
2effective date of this amendatory Act of the 98th General
3Assembly.
4    (j) This Section is repealed and tariffs authorized by
5this Section will terminate on December 31, 2021 December 31,
62023.
7(Source: P.A. 98-57, eff. 7-5-13.)
 
8    (220 ILCS 5/9-221)  (from Ch. 111 2/3, par. 9-221)
9    Sec. 9-221. Whenever a municipality pursuant to Section
108-11-2 or 8-11-2.7 of the Illinois Municipal Code, as
11heretofore and hereafter amended, imposes a tax on any public
12utility, such utility may charge its customers, other than
13customers who are certified business enterprises under
14paragraph (e) of Section 8-11-2 of the Illinois Municipal Code
15or are exempted from those taxes under paragraph (f) of that
16Section, to the extent of such exemption and during the period
17in which such exemption is in effect, in addition to any rate
18authorized by this Act, an additional charge equal to the sum
19of (1) an amount equal to such municipal tax, or any part
20thereof (2) 3% of such tax, or any part thereof, as the case
21may be, to cover costs of accounting, and (3) an amount equal
22to the increase in taxes and other payments to governmental
23bodies resulting from the amount of such additional charge.
24Such utility shall file with the Commission a true and correct
25copy of the municipal ordinance imposing such tax; and also

 

 

SB2896- 534 -LRB102 17909 JWD 25989 b

1shall file with the Commission a supplemental schedule
2applicable to such municipality which shall specify such
3additional charge and which shall become effective upon filing
4without further notice. Such additional charge shall be shown
5separately on the utility bill to each customer. The
6Commission shall have power to investigate whether or not such
7supplemental schedule correctly specifies such additional
8charge, but shall have no power to suspend such supplemental
9schedule. If the Commission finds, after a hearing, that such
10supplemental schedule does not correctly specify such
11additional charge, it shall by order require a refund to the
12appropriate customers of the excess, if any, with interest, in
13such manner as it shall deem just and reasonable, and in and by
14such order shall require the utility to file an amended
15supplemental schedule corresponding to the finding and order
16of the Commission.
17(Source: P.A. 87-895; 88-132.)
 
18    (220 ILCS 5/9-227)  (from Ch. 111 2/3, par. 9-227)
19    Sec. 9-227. Charitable contributions by public utilities.
20It shall not be proper for the Commission to consider as an
21operating expense, for the purpose of determining whether a
22rate or other charge or classification is sufficient,
23donations made by a public utility for the public welfare or
24for charitable scientific, religious or educational purposes,
25provided that such donations are reasonable in amount. In

 

 

SB2896- 535 -LRB102 17909 JWD 25989 b

1determining the reasonableness of such donations, the
2Commission may not establish, by rule, a presumption that any
3particular portion of an otherwise reasonable amount may not
4be considered as an operating expense. The Commission shall
5disallow be prohibited from disallowing by rule, as an
6operating expense, any portion of a reasonable donation for
7public welfare or charitable purposes.
8(Source: P.A. 85-122.)
 
9    (220 ILCS 5/9-229)
10    Sec. 9-229. Consideration of attorney and expert
11compensation as an expense and intervenor compensation fund.
12    (a) The Commission shall specifically assess the justness
13and reasonableness of any amount expended by a public utility
14to compensate attorneys or technical experts to prepare and
15litigate a general rate case filing. This issue shall be
16expressly addressed in the Commission's final order.
17    (b) The State of Illinois shall create a Consumer
18Intervenor Compensation Fund subject to the following:
19        (1) Legislative Intent. Provision of compensation for
20    Consumer Interest Representatives that intervene in
21    Illinois Commerce Commission proceedings will increase
22    public engagement, encourage additional transparency,
23    expand the information available to the Commission, and
24    improve decision-making.
25        (2) Definition. Consumer interest representative

 

 

SB2896- 536 -LRB102 17909 JWD 25989 b

1    means:
2            (A) a residential utility customer or group of
3        residential utility customers;
4            (B) representatives of not-for-profit groups or
5        organizations whose membership is limited to
6        residential utility customers;
7            (C) representatives of not-for-profit groups or
8        organizations whose membership includes Illinois
9        residents and that address the community, economic,
10        environmental, or social welfare of Illinois
11        residents; or
12            (D) not-for-profit organizations that are
13        authorized to represent the interests of residential
14        utility customers or small commercial utility
15        customers that receive utility service from a public
16        utility whose tariffs must be approved by the
17        Commission pursuant to their articles of incorporation
18        or bylaws.
19        (3) Eligibility for Compensation. A consumer interest
20    representative is eligible to receive compensation from
21    the consumer intervenor compensation fund if its
22    participation included lay or expert testimony or legal
23    briefing and argument concerning the expenses,
24    investments, rate design, rate impact, or other matters
25    affecting the pricing, rates, costs or other charges
26    associated with utility service, the Commission addresses

 

 

SB2896- 537 -LRB102 17909 JWD 25989 b

1    or adopts in whole or in part one or more factual
2    contentions, legal contentions, or policy or procedural
3    recommendations presented by the consumer interest
4    representative, the participant provided a significant
5    contribution to the record, and participation caused a
6    significant financial hardship to the participant.
7        (4) Consumer Intervenor Compensation Fund. Within 30
8    days after the effective date of this Act, each utility
9    that files a request for an increase in rates under
10    Article IX or Article XVI shall deposit an amount equal to
11    one half of the rate case attorney and expert expense
12    allowed by the Commission into the fund within 35 days of
13    the date of the Commission's final Order in the rate case
14    or 20 days after the denial of rehearing under Section
15    10-113 of this Act, whichever is later. The Consumer
16    Intervenor Compensation Fund shall be used to provide
17    payment to consumer interest representatives as described
18    in this Section.
19        (5)(A) Initial Funding of Consumer Intervenor
20    Compensation Fund. An electric public utility with
21    3,000,000 or more retail customers shall contribute
22    $450,000 to the Consumer Intervenor Compensation Fund
23    within 60 days after the effective date of this Act. A
24    combined electric and gas public utility serving fewer
25    than 3,000,000 but more than 500,000 retail customers
26    shall contribute $225,000 to the Consumer Intervenor

 

 

SB2896- 538 -LRB102 17909 JWD 25989 b

1    Compensation Fund within 60 days after the effective date
2    of this Act. A gas public utility with 1,500,000 or more
3    retail customers that is not a combined electric and gas
4    public utility shall contribute $225,000 to the Consumer
5    Intervenor Compensation Fund within 60 days after the
6    effective date of this Act. A gas public utility with
7    fewer than 1,500,000 retail customers but more than
8    300,000 retail customers that is not a combined electric
9    and gas public utility shall contribute $80,000 to the
10    Consumer Intervenor Compensation Fund within 60 days after
11    the effective date of this Act. A gas public utility with
12    fewer than 300,000 retail customers that is not a combined
13    electric and gas public utility shall contribute $20,000
14    to the Consumer Intervenor Compensation Fund within 60
15    days after the effective date of this Act. A combined
16    electric and gas public utility serving fewer than 500,000
17    retail customers shall contribute $20,000 to the Consumer
18    Intervenor Compensation Fund within 60 days after the
19    effective date of this Act. A water and/or sewer public
20    utility serving more than 100,000 retail customers shall
21    contribute $80,000, and a water and/or sewer public
22    utility serving fewer than 100,000 but more than 10,000
23    retail customers shall contribute $20,000.
24        (6)(A) Pre-Order Funding. Prior to the entry of a
25    Final Order in a docketed case, the Commission
26    Administrator shall provide a payment to a consumer

 

 

SB2896- 539 -LRB102 17909 JWD 25989 b

1    interest representative that demonstrates through a
2    verified application for funding that the consumer
3    interest representative's participation or intervention
4    without an award of fees or costs imposes a significant
5    financial hardship based on a schedule to be developed by
6    the Commission. The initial payment shall be no less than
7    $20,000 for a request for an increase in rates, and may be
8    up to $20,000 for other dockets, investigations,
9    rulemakings, or proceedings. The Administrator may require
10    verification of costs incurred, including statements of
11    hours spent, as a condition to paying the consumer
12    interest representative prior to the entry of a Final
13    Order in a docketed case.
14        (B) Post Order Funding. If the Commission addresses or
15    adopts in whole or in part one or more factual
16    contentions, legal contentions, or policy or procedural
17    recommendations presented by the consumer interest
18    representative, the participant provided a contribution to
19    the record, and participation caused a financial hardship
20    to the participant then the consumer interest
21    representative shall be allowed payment for some or all of
22    the consumer interest representative's reasonable
23    attorney's or advocate's fees, reasonable expert witness
24    fees, and other reasonable costs of preparation for and
25    participation in a hearing or proceeding. Expenses related
26    to travel or meals shall not be compensable. The

 

 

SB2896- 540 -LRB102 17909 JWD 25989 b

1    Administrator shall award compensation to maximize
2    intervenor participation.
3        (C) Request for Funding. The consumer interest
4    representative shall submit an itemized request for
5    compensation to the Consumer Intervenor Compensation Fund,
6    including the advocate's or attorney's reasonable fee
7    rate, the number of hours expended, reasonable expert and
8    expert witness fees, and other reasonable costs for the
9    preparation for and participation in the hearing and
10    briefing within 30 days of the Commission's final order
11    after denial or decision on rehearing, if any.
12        (7) Administration of the Fund.
13        (A) The Consumer Intervenor Compensation Fund is
14    created as a special fund in the State treasury. All
15    disbursements from the Consumer Intervenor Compensation
16    Fund shall be made only upon warrants of the Comptroller
17    drawn upon the Treasurer as custodian of the Fund upon
18    vouchers signed by the Executive Director of the
19    Commission or by the person or persons designated by the
20    Director for that purpose. The Comptroller is authorized
21    to draw the warrant upon vouchers so signed. The Treasurer
22    shall accept all warrants so signed and shall be released
23    from liability for all payments made on those warrants.
24    The Consumer Intervenor Compensation Fund shall be
25    administered by an Administrator that is a person or
26    entity that is independent of the Commission. The

 

 

SB2896- 541 -LRB102 17909 JWD 25989 b

1    administrator will be responsible for the prudent
2    management of the Consumer Intervenor Compensation Fund
3    and for recommendations for the award of consumer
4    intervenor compensation from the Consumer Intervenor
5    Compensation Fund. The Commission shall issue a request
6    for qualifications for a third-party program administrator
7    to administer the Consumer Intervenor Compensation Fund.
8    The third-party administrator shall be chosen through a
9    competitive bid process based on selection criteria and
10    requirements developed by the Commission. The Illinois
11    Procurement Code does not apply to the hiring or payment
12    of the Administrator. All Administrator costs may be paid
13    for using monies from the Consumer Intervenor Compensation
14    Fund, but the Program Administrator shall strive to
15    minimize costs in the implementation of the program. The
16    Consumer Intervenor Compensation Fund shall not be subject
17    to sweeps, administrative charges, or chargebacks,
18    including, but not limited to, those authorized under
19    Section 8h of the State Finance Act, that would in any way
20    result in the transfer of any funds from this Fund to any
21    other fund of this State or in having any such funds
22    utilized for any purpose other than the express purposes
23    set forth in this Section.
24        (B) The computation of compensation awarded from the
25    fund shall take into consideration the market rates paid
26    to persons of comparable training and experience who offer

 

 

SB2896- 542 -LRB102 17909 JWD 25989 b

1    similar services, but may not exceed the comparable market
2    rate for services paid by the public utility as part of its
3    rate case expense.
4        (C)(1) Recommendations on the award of compensation by
5    the administrator shall include consideration of whether
6    the Commission addressed or adopted in whole or in part
7    one or more factual contentions, legal contentions, or
8    policy or procedural recommendations presented by the
9    consumer interest representative; whether the participant
10    provided a to the record; and whether that participation
11    caused a financial hardship to the participant and the
12    payment of compensation is fair, just and reasonable.
13        (2) Recommendations on the award of compensation by
14    the administrator shall be submitted to the Commission for
15    approval. Unless the Commission initiates and
16    investigation within 45 days after the notice to the
17    Commission, the award of compensation shall be allowed 45
18    days after notice to the Commission. Such notice shall be
19    given by filing with the Commission on the Commission's
20    e-docket system, and keeping open for public inspection
21    the award for compensation proposed by the Administrator.
22    The Commission shall have power, and it is hereby given
23    authority, either upon complaint or upon its own
24    initiative without complaint, at once, and if it so
25    orders, without answer or other formal pleadings, but upon
26    reasonable notice, to enter upon a hearing concerning the

 

 

SB2896- 543 -LRB102 17909 JWD 25989 b

1    propriety of the award. The investigation shall not extend
2    more than 105 days after the Commission initiates the
3    investigation.
4    (c) The Commission may adopt rules to implement this
5Section.
6(Source: P.A. 96-33, eff. 7-10-09.)
 
7    (220 ILCS 5/9-241)  (from Ch. 111 2/3, par. 9-241)
8    Sec. 9-241. No public utility shall, as to rates or other
9charges, services, facilities or in other respect, make or
10grant any preference or advantage to any corporation or person
11or subject any corporation or person to any prejudice or
12disadvantage. No public utility shall establish or maintain
13any unreasonable difference as to rates or other charges,
14services, facilities, or in any other respect, either as
15between localities or as between classes of service.
16    However, nothing in this Section shall be construed as
17limiting the authority of the Commission to permit the
18establishment of economic development rates as incentives to
19economic development either in enterprise zones as designated
20by the State of Illinois or in other areas of a utility's
21service area. Such rates should be available to existing
22businesses which demonstrate an increase to existing load as
23well as new businesses which create new load for a utility so
24as to create a more balanced utilization of generating
25capacity. The Commission shall ensure that such rates are

 

 

SB2896- 544 -LRB102 17909 JWD 25989 b

1established at a level which provides a net benefit to
2customers within a public utility's service area.
3    The Commission shall require that public utilities provide
4low-income discount rates for customers whose income falls at
5or below 80% of area median income, and file tariffs to reflect
6said discounts with the discounts tiered and decreased as
7income increases. In its review of the tariffs, the Commission
8shall ensure recovery of any cost associated with the tariffs
9be reflected in the rates charged to all customer classes,
10with charges and credits under the tariff allocated and
11collected through existing volumetric charges for delivery
12services. The tariff may be established outside the context of
13a general rate case filing and shall specify the terms of any
14applicable audit. The Commission shall review and by order
15approve, or approve as modified, the proposed tariff within
16180 days after the date on which it is filed.
17    Upon approval of the tariff, the utility shall apply the
18appropriate credit or charge over a 12-month period beginning
19with the June billing period and ending with the May billing
20period, with the first such billing period beginning June
212022.
22    Eligibility for the low-income discount rates described in
23this subsection shall be established upon verification of a
24low-income customer's receipt of any means tested public
25benefit, or verification of eligibility for the low-income
26home energy assistance program. Said public benefits may

 

 

SB2896- 545 -LRB102 17909 JWD 25989 b

1include, but are not limited to, assistance from any
2government entity which provides cash, housing, food, or
3medical care, including, but not limited to, transitional
4assistance for needy families, supplemental security income,
5emergency assistance to elders, disabled, and children,
6supplemental nutrition assistance program, public housing,
7federally-subsidized or state-subsidized housing, the
8low-income home energy assistance program, veterans' benefits,
9and similar benefits. The Department of Human Services shall
10make available to distribution companies the eligibility
11guidelines for said public benefit programs.
12    Each distribution company shall conduct substantial
13outreach efforts to make said low-income discount available to
14eligible customers and shall report the Commission, at least
15annually, as to its outreach activities and results. Outreach
16may include establishing an automated program of matching
17customer accounts with lists of recipients of said means
18tested public benefit programs and based on the results of
19said matching program, to presumptively offer a low-income
20discount rate to eligible customers so identified; provided,
21however, that the distribution company, within 60 days of said
22presumptive enrollment, informs any such low-income customer
23of said presumptive enrollment and all rights and obligations
24of a customer under said program, including the right to
25withdraw from said program without penalty.
26    A residential customer eligible for low-income discount

 

 

SB2896- 546 -LRB102 17909 JWD 25989 b

1rates shall receive the service upon request and proof of
2eligibility. Each distribution company shall periodically
3notify all customers of the availability and method of
4obtaining low-income discount rates.
5    A utility shall file tariffs consistent with this
6subsection within 180 days of the enactment of this provision.
7The Commission shall promulgate rules and regulations
8requiring utility companies to produce information, in the
9form of a mailing, and other approved method of distribution,
10to their consumers, to inform them of available rebates,
11discounts, credits, and other cost-saving mechanisms that can
12help them lower their monthly utility bills, and send out such
13information semi-annually, unless otherwise provided by this
14chapter.
15    Prior to October 1, 1989, no public utility providing
16electrical or gas service shall consider the use of solar or
17other nonconventional renewable sources of energy by a
18customer as a basis for establishing higher rates or charges
19for any service or commodity sold to such customer; nor shall a
20public utility subject any customer utilizing such energy
21source or sources to any other prejudice or disadvantage on
22account of such use. No public utility shall without the
23consent of the Commission, charge or receive any greater
24compensation in the aggregate for a lesser commodity, product,
25or service than for a greater commodity, product or service of
26like character.

 

 

SB2896- 547 -LRB102 17909 JWD 25989 b

1    The Commission, in order to expedite the determination of
2rate questions, or to avoid unnecessary and unreasonable
3expense, or to avoid unjust or unreasonable discrimination
4between classes of customers, or, whenever in the judgment of
5the Commission public interest so requires, may, for rate
6making and accounting purposes, or either of them, consider
7one or more municipalities either with or without the adjacent
8or intervening rural territory as a regional unit where the
9same public utility serves such region under substantially
10similar conditions, and may within such region prescribe
11uniform rates for consumers or patrons of the same class.
12    Any public utility, with the consent and approval of the
13Commission, may as a basis for the determination of the
14charges made by it classify its service according to the
15amount used, the time when used, the purpose for which used,
16and other relevant factors.
17(Source: P.A. 91-357, eff. 7-29-99.)
 
18    (220 ILCS 5/16-107.5)
19    Sec. 16-107.5. Net electricity metering.
20    (a) The General Assembly Legislature finds and declares
21that a program to provide net electricity metering, as defined
22in this Section, for eligible customers can encourage private
23investment in renewable energy resources, stimulate economic
24growth, enhance the continued diversification of Illinois'
25energy resource mix, and protect the Illinois environment.

 

 

SB2896- 548 -LRB102 17909 JWD 25989 b

1Further, to achieve the goals of this Act that robust options
2for customer-site distributed generation continue to thrive in
3Illinois, the General Assembly finds that a predictable
4transition must be ensured for customers between full net
5metering at the retail electricity rate to the distribution
6generation rebate described in Section 16-107.6.
7    (b) As used in this Section, (i) "community renewable
8generation project" shall have the meaning set forth in
9Section 1-10 of the Illinois Power Agency Act; (ii) "eligible
10customer" means a retail customer that owns, hosts, or
11operates, including any third-party owned systems, a solar,
12wind, or other eligible renewable electrical generating
13facility with a rated alternating current capacity of not more
14than 5,000 2,000 kilowatts that is located on the customer's
15premises or customer's side of the billing meter and is
16intended primarily to offset the customer's own current or
17future electrical requirements; (iii) "electricity provider"
18means an electric utility or alternative retail electric
19supplier; (iv) "eligible renewable electrical generating
20facility" means a generator which may include the co-location
21of an energy storage system that is interconnected under rules
22adopted by the Commission and is powered by solar electric
23energy, wind, dedicated crops grown for electricity
24generation, agricultural residues, untreated and unadulterated
25wood waste, landscape trimmings, livestock manure, anaerobic
26digestion of livestock or food processing waste, fuel cells or

 

 

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1microturbines powered by renewable fuels, or hydroelectric
2energy; (v) "net electricity metering" (or "net metering")
3means the measurement, during the billing period applicable to
4an eligible customer, of the net amount of electricity
5supplied by an electricity provider to the customer's premises
6or provided to the electricity provider by the customer or
7subscriber; (vi) "subscriber" shall have the meaning as set
8forth in Section 1-10 of the Illinois Power Agency Act; and
9(vii) "subscription" shall have the meaning set forth in
10Section 1-10 of the Illinois Power Agency Act; (viii) "energy
11storage system" means commercially available technology that
12is capable of absorbing energy and storing it for a period of
13time for use at a later time including but not limited to
14electrochemical, thermal and electromechanical technologies
15and may be interconnected behind the customer's meter or
16interconnected behind its own meter; and (ix) "future
17electrical requirements" means a reasonable approximation of
18the annual load of two electric vehicles and, for non-electric
19heating customers, a reasonable approximation of the
20incremental electric load association with fuel switching. The
21approximations shall be applied to the appropriate net
22metering tariff, and do not need to be unique to each
23individual eligible customer. The utility shall submit these
24approximations to the Commission for review, modification, and
25approval.
26    (c) A net metering facility shall be equipped with

 

 

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1metering equipment that can measure the flow of electricity in
2both directions at the same rate.
3        (1) For eligible customers whose electric service has
4    not been declared competitive pursuant to Section 16-113
5    of this Act as of July 1, 2011 and whose electric delivery
6    service is provided and measured on a kilowatt-hour basis
7    and electric supply service is not provided based on
8    hourly pricing, this shall typically be accomplished
9    through use of a single, bi-directional meter. If the
10    eligible customer's existing electric revenue meter does
11    not meet this requirement, the electricity provider shall
12    arrange for the local electric utility or a meter service
13    provider to install and maintain a new revenue meter at
14    the electricity provider's expense, which may be the smart
15    meter described by subsection (b) of Section 16-108.5 of
16    this Act.
17        (2) For eligible customers whose electric service has
18    not been declared competitive pursuant to Section 16-113
19    of this Act as of July 1, 2011 and whose electric delivery
20    service is provided and measured on a kilowatt demand
21    basis and electric supply service is not provided based on
22    hourly pricing, this shall typically be accomplished
23    through use of a dual channel meter capable of measuring
24    the flow of electricity both into and out of the
25    customer's facility at the same rate and ratio. If such
26    customer's existing electric revenue meter does not meet

 

 

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1    this requirement, then the electricity provider shall
2    arrange for the local electric utility or a meter service
3    provider to install and maintain a new revenue meter at
4    the electricity provider's expense, which may be the smart
5    meter described by subsection (b) of Section 16-108.5 of
6    this Act.
7        (3) For all other eligible customers, until such time
8    as the local electric utility installs a smart meter, as
9    described by subsection (b) of Section 16-108.5 of this
10    Act, the electricity provider may arrange for the local
11    electric utility or a meter service provider to install
12    and maintain metering equipment capable of measuring the
13    flow of electricity both into and out of the customer's
14    facility at the same rate and ratio, typically through the
15    use of a dual channel meter. If the eligible customer's
16    existing electric revenue meter does not meet this
17    requirement, then the costs of installing such equipment
18    shall be paid for by the customer.
19    (d) An electricity provider shall measure and charge or
20credit for the net electricity supplied to eligible customers
21or provided by eligible customers whose electric service has
22not been declared competitive pursuant to Section 16-113 of
23this Act as of July 1, 2011 and whose electric delivery service
24is provided and measured on a kilowatt-hour basis and electric
25supply service is not provided based on hourly pricing in the
26following manner:

 

 

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1        (1) If the amount of electricity used by the customer
2    during the billing period exceeds the amount of
3    electricity produced by the customer, the electricity
4    provider shall charge the customer for the net electricity
5    supplied to and used by the customer as provided in
6    subsection (e-5) of this Section.
7        (2) If the amount of electricity produced by a
8    customer during the billing period exceeds the amount of
9    electricity used by the customer during that billing
10    period, the electricity provider supplying that customer
11    shall apply a 1:1 kilowatt-hour credit to a subsequent
12    bill for service to the customer for the net electricity
13    supplied to the electricity provider. The electricity
14    provider shall continue to carry over any excess
15    kilowatt-hour credits earned and apply those credits to
16    subsequent billing periods to offset any
17    customer-generator consumption in those billing periods
18    until all credits are used or until the end of the
19    annualized period.
20        (3) At the end of the year or annualized over the
21    period that service is supplied by means of net metering,
22    or in the event that the retail customer terminates
23    service with the electricity provider prior to the end of
24    the year or the annualized period, any remaining credits
25    in the customer's account shall expire.
26    (d-5) An electricity provider shall measure and charge or

 

 

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1credit for the net electricity supplied to eligible customers
2or provided by eligible customers whose electric service has
3not been declared competitive pursuant to Section 16-113 of
4this Act as of July 1, 2011 and whose electric delivery service
5is provided and measured on a kilowatt-hour basis and electric
6supply service is provided based on hourly pricing or time of
7use rates in the following manner:
8        (1) If the amount of electricity used by the customer
9    during any hourly period or time of use period exceeds the
10    amount of electricity produced by the customer, the
11    electricity provider shall charge the customer for the net
12    electricity supplied to and used by the customer according
13    to the terms of the contract or tariff to which the same
14    customer would be assigned to or be eligible for if the
15    customer was not a net metering customer.
16        (2) If the amount of electricity produced by a
17    customer during any hourly period or time of use period
18    exceeds the amount of electricity used by the customer
19    during that hourly period or time of use period, the
20    energy provider shall apply a credit for the net
21    kilowatt-hours produced in such period. The credit shall
22    consist of an energy credit and a delivery service credit.
23    The energy credit shall be valued at the same price per
24    kilowatt-hour as the electric service provider would
25    charge for kilowatt-hour energy sales during that same
26    hourly period or time of use period. The delivery credit

 

 

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1    shall be equal to the net kilowatt-hours produced in such
2    hourly period or time of use period times a credit that
3    reflects all kilowatt-hour based charges in the customer's
4    electric service rate, excluding energy charges.
5    (e) An electricity provider shall measure and charge or
6credit for the net electricity supplied to eligible customers
7whose electric service has not been declared competitive
8pursuant to Section 16-113 of this Act as of July 1, 2011 and
9whose electric delivery service is provided and measured on a
10kilowatt demand basis and electric supply service is not
11provided based on hourly pricing in the following manner:
12        (1) If the amount of electricity used by the customer
13    during the billing period exceeds the amount of
14    electricity produced by the customer, then the electricity
15    provider shall charge the customer for the net electricity
16    supplied to and used by the customer as provided in
17    subsection (e-5) of this Section. The customer shall
18    remain responsible for all taxes, fees, and utility
19    delivery charges that would otherwise be applicable to the
20    net amount of electricity used by the customer.
21        (2) If the amount of electricity produced by a
22    customer during the billing period exceeds the amount of
23    electricity used by the customer during that billing
24    period, then the electricity provider supplying that
25    customer shall apply a 1:1 kilowatt-hour credit that
26    reflects the kilowatt-hour based charges in the customer's

 

 

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1    electric service rate to a subsequent bill for service to
2    the customer for the net electricity supplied to the
3    electricity provider. The electricity provider shall
4    continue to carry over any excess kilowatt-hour credits
5    earned and apply those credits to subsequent billing
6    periods to offset any customer-generator consumption in
7    those billing periods until all credits are used or until
8    the end of the annualized period.
9        (3) At the end of the year or annualized over the
10    period that service is supplied by means of net metering,
11    or in the event that the retail customer terminates
12    service with the electricity provider prior to the end of
13    the year or the annualized period, any remaining credits
14    in the customer's account shall expire.
15    (e-5) An electricity provider shall provide electric
16service to eligible customers who utilize net metering at
17non-discriminatory rates that are identical, with respect to
18rate structure, retail rate components, and any monthly
19charges, to the rates that the customer would be charged if not
20a net metering customer. An electricity provider shall not
21charge net metering customers any fee or charge or require
22additional equipment, insurance, or any other requirements not
23specifically authorized by interconnection standards
24authorized by the Commission, unless the fee, charge, or other
25requirement would apply to other similarly situated customers
26who are not net metering customers. The customer will remain

 

 

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1responsible for all taxes, fees, and utility delivery charges
2that would otherwise be applicable to the net amount of
3electricity used by the customer. Subsections (c) through (e)
4of this Section shall not be construed to prevent an
5arms-length agreement between an electricity provider and an
6eligible customer that sets forth different prices, terms, and
7conditions for the provision of net metering service,
8including, but not limited to, the provision of the
9appropriate metering equipment for non-residential customers.
10    (f) Notwithstanding the requirements of subsections (c)
11through (e-5) of this Section, an electricity provider must
12require dual-channel metering for customers operating eligible
13renewable electrical generating facilities with a nameplate
14rating up to 2,000 kilowatts and to whom the provisions of
15neither subsection (d), (d-5), nor (e) of this Section apply.
16In such cases, electricity charges and credits shall be
17determined as follows:
18        (1) The electricity provider shall assess and the
19    customer remains responsible for all taxes, fees, and
20    utility delivery charges that would otherwise be
21    applicable to the gross amount of kilowatt-hours supplied
22    to the eligible customer by the electricity provider.
23        (2) Each month that service is supplied by means of
24    dual-channel metering, the electricity provider shall
25    compensate the eligible customer for any excess
26    kilowatt-hour credits at the electricity provider's

 

 

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1    avoided cost of electricity supply over the monthly period
2    or as otherwise specified by the terms of a power-purchase
3    agreement negotiated between the customer and electricity
4    provider.
5        (3) For all eligible net metering customers taking
6    service from an electricity provider under contracts or
7    tariffs employing hourly or time of use rates, any monthly
8    consumption of electricity shall be calculated according
9    to the terms of the contract or tariff to which the same
10    customer would be assigned to or be eligible for if the
11    customer was not a net metering customer. When those same
12    customer-generators are net generators during any discrete
13    hourly or time of use period, the net kilowatt-hours
14    produced shall be valued at the same price per
15    kilowatt-hour as the electric service provider would
16    charge for retail kilowatt-hour sales during that same
17    time of use period.
18    (g) For purposes of federal and State laws providing
19renewable energy credits or greenhouse gas credits, the
20eligible customer shall be treated as owning and having title
21to the renewable energy attributes, renewable energy credits,
22and greenhouse gas emission credits related to any electricity
23produced by the qualified generating unit. The electricity
24provider may not condition participation in a net metering
25program on the signing over of a customer's renewable energy
26credits; provided, however, this subsection (g) shall not be

 

 

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1construed to prevent an arms-length agreement between an
2electricity provider and an eligible customer that sets forth
3the ownership or title of the credits.
4    (h) Within 120 days after the effective date of this
5amendatory Act of the 95th General Assembly, the Commission
6shall establish standards for net metering and, if the
7Commission has not already acted on its own initiative,
8standards for the interconnection of eligible renewable
9generating equipment to the utility system. The
10interconnection standards shall address any procedural
11barriers, delays, and administrative costs associated with the
12interconnection of customer-generation while ensuring the
13safety and reliability of the units and the electric utility
14system. The Commission shall consider the Institute of
15Electrical and Electronics Engineers (IEEE) Standard 1547 and
16the issues of (i) reasonable and fair fees and costs, (ii)
17clear timelines for major milestones in the interconnection
18process, (iii) nondiscriminatory terms of agreement, and (iv)
19any best practices for interconnection of distributed
20generation.
21    (i) Within 90 days of the effective date of this
22amendatory Act of the 102nd General Assembly, the Commission
23shall: All electricity providers shall begin to offer net
24metering no later than April 1, 2008.
25        (1) establish an Interconnection Working Group. The
26    working group shall include representatives from electric

 

 

SB2896- 559 -LRB102 17909 JWD 25989 b

1    utilities, developers of renewable electric generating
2    facilities, other industries that regularly apply for
3    interconnection with the electric utilities,
4    representatives of distributed generation customers, the
5    Commission Staff and such other stakeholders with a
6    substantial interest in the topics addressed by the
7    working group. The working group shall address at least
8    the following issues:
9            (A) cost and best available technology for
10        interconnection and metering, including the
11        standardization and publication of standard costs;
12            (B) transparency, accuracy and use of the
13        distribution interconnection queue and hosting
14        capacity maps;
15            (C) distribution system upgrade cost avoidance
16        through use of advanced inverter functions;
17            (D) predictability of the queue management process
18        and enforcement of timelines;
19            (E) benefits and challenges associated with group
20        studies and cost sharing;
21            (F) minimum requirements for application to the
22        interconnection process and throughout the
23        interconnection process to avoid queue clogging
24        behavior;
25            (G) process and customer service for
26        interconnecting customers adopting distributed energy

 

 

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1        resources, including energy storage;
2            (H) options for metering distributed energy
3        resources, including energy storage;
4            (I) interconnection of new technologies, including
5        smart inverters and energy storage; and
6            (K) without limitation, such other technical,
7        policy, and tariff issues related to and affecting
8        interconnection performance and customer service, as
9        determined by the working group.
10        The Commission may create working group subcommittees
11    of the working group to focus on specific issues of
12    importance, as appropriate. The working group shall report
13    to the Commission on recommended improvements to
14    interconnection rules and tariffs and policies as
15    determined by the working group at least every 6 months.
16    Such reports shall include consensus recommendations of
17    the working group and, if applicable, additional
18    recommendations for which consensus was not reached. The
19    Commission shall use the report from the working group to
20    determine whether processes should be commenced to
21    formally codify or implement the recommendations;
22        (2) create or contract for an Ombudsman to resolve
23    disputes through non-binding arbitration. The Ombudsman
24    shall be paid in full or in part through fees levied on the
25    initiators of the dispute; and
26        (3) determine a single standardized cost for Level 1

 

 

SB2896- 561 -LRB102 17909 JWD 25989 b

1    interconnections that shall not exceed $200.
2    (j) An electricity provider shall provide net metering to
3eligible customers according to subsections (d), (d-5), and
4(e) until December 31, 2024 the load of its net metering
5customers equals 5% of the total peak demand supplied by that
6electricity provider during the previous year. After such time
7as the load of the electricity provider's net metering
8customers equals 5% of the total peak demand supplied by that
9electricity provider during the previous year, eligible
10customers that begin taking net metering shall only be
11eligible for netting of energy. An eligible customer according
12to subsections (d), (d-5), and (e) that registered for net
13metering before December 31, 2024 shall be allowed to stay
14under the tariff for the lifetime of the system. After
15December 31, 2024 any eligible customer that applies for net
16metering shall only be eligible for net metering as described
17in subsection (n).
18    (k) Each electricity provider shall maintain records and
19report annually to the Commission the total number of net
20metering customers served by the provider, as well as the
21type, capacity, and energy sources of the generating systems
22used by the net metering customers. Nothing in this Section
23shall limit the ability of an electricity provider to request
24the redaction of information deemed by the Commission to be
25confidential business information.
26        (l)(1) Notwithstanding the definition of "eligible

 

 

SB2896- 562 -LRB102 17909 JWD 25989 b

1    customer" in item (ii) of subsection (b) of this Section,
2    each electricity provider shall allow net metering as set
3    forth in this subsection (l) and for the following
4    projects, provided that only electric utilities shall
5    provide net metering for subparagraph (C) of this
6    paragraph (1):
7            (A) properties owned or leased by multiple
8        customers that contribute to the operation of an
9        eligible renewable electrical generating facility
10        through an ownership or leasehold interest of at least
11        200 watts in such facility, such as a community-owned
12        wind project, a community-owned biomass project, a
13        community-owned solar project, or a community methane
14        digester processing livestock waste from multiple
15        sources, provided that the facility is also located
16        within the utility's service territory;
17            (B) individual units, apartments, or properties
18        located in a single building that are owned or leased
19        by multiple customers and collectively served by a
20        common eligible renewable electrical generating
21        facility, such as an office or apartment building, a
22        shopping center or strip mall served by photovoltaic
23        panels on the roof; and
24            (C) subscriptions to community renewable
25        generation projects.
26        In addition, the nameplate capacity of the eligible

 

 

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1    renewable electric generating facility that serves the
2    demand of the properties, units, or apartments identified
3    in paragraphs (1) and (2) of this subsection (l) shall not
4    exceed 2,000 kilowatts in nameplate capacity in total. Any
5    eligible renewable electrical generating facility or
6    community renewable generation project that is powered by
7    photovoltaic electric energy and installed after the
8    effective date of this amendatory Act of the 99th General
9    Assembly must be installed by a qualified person in
10    compliance with the requirements of Section 16-128A of the
11    Public Utilities Act and any rules or regulations adopted
12    thereunder.
13        (2) Notwithstanding anything to the contrary and
14    regardless of whether a subscriber receives power and
15    energy service from the electric utility or an alternative
16    retail electric supplier, the electric utility an
17    electricity provider shall provide the monetary credits to
18    a subscriber's subsequent bill for the electricity
19    produced by community renewable generation projects the
20    projects described in paragraph (1) of this subsection
21    (l). The electric utility electricity provider shall
22    provide monetary credits to a subscriber's subsequent bill
23    at the utility's total price to compare subscriber's
24    energy supply rate on the subscriber's monthly bill equal
25    to the subscriber's share of the production of electricity
26    from the project, as determined by paragraph (3) of this

 

 

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1    subsection (l). For the purposes of this subsection,
2    "total price to compare" means the rate or rates published
3    by the Illinois Commerce Commission for energy supply for
4    eligible customers receiving supply service from the
5    electric utility, and includes energy, capacity,
6    transmission, and the purchased energy adjustment.
7    Notwithstanding anything to the contrary, customers on
8    payment plans or participating in budget billing programs
9    shall have credits applied on a monthly basis. Any
10    applicable credit or reduction in load obligation from the
11    production of the community renewable generating projects
12    receiving a credit under this subsection shall be credited
13    to the electric utility to offset the cost of providing
14    the credit. To the extent that the credit or load
15    obligation reduction does not completely offset the cost
16    of providing the credit to subscribers of community
17    renewable generation projects as described in this
18    subsection the electric utility may recover the remaining
19    costs through the process established in Section 16-111.8.
20        (3) If requested by the owner or operator of a
21    community renewable generating project, an electric
22    utility shall enter into a net crediting agreement with
23    the owner or operator to include a subscriber's
24    subscription fee on the subscriber's monthly electric bill
25    and provide the subscriber with a net credit equivalent to
26    the total bill credit value for that generation period

 

 

SB2896- 565 -LRB102 17909 JWD 25989 b

1    minus the subscription fee, provided the subscription fee
2    is structured as a fixed percentage of bill credit value.
3    The net crediting agreement shall set forth payment terms
4    from the electric utility to the owner or operator of the
5    community renewable generating project, and the electric
6    utility may charge a net crediting fee to the owner or
7    operator of a community renewable generating project that
8    may not exceed 1% of the bill credit value.
9        (4) (3) For the purposes of facilitating net metering,
10    the owner or operator of the eligible renewable electrical
11    generating facility or community renewable generation
12    project shall be responsible for determining the amount of
13    the credit that each customer or subscriber participating
14    in a project under this subsection (l) is to receive in the
15    following manner:
16            (A) The owner or operator shall, on a monthly
17        basis, provide to the electric utility the
18        kilowatthours of generation attributable to each of
19        the utility's retail customers and subscribers
20        participating in projects under this subsection (l) in
21        accordance with the customer's or subscriber's share
22        of the eligible renewable electric generating
23        facility's or community renewable generation project's
24        output of power and energy for such month. The owner or
25        operator shall electronically transmit such
26        calculations and associated documentation to the

 

 

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1        electric utility, in a format or method set forth in
2        the applicable tariff, on a monthly basis so that the
3        electric utility can reflect the monetary credits on
4        customers' and subscribers' electric utility bills.
5        The electric utility shall be permitted to revise its
6        tariffs to implement the provisions of this amendatory
7        Act of the 102nd 99th General Assembly. The owner or
8        operator shall separately provide the electric utility
9        with the documentation detailing the calculations
10        supporting the credit in the manner set forth in the
11        applicable tariff.
12            (B) For those participating customers in projects
13        described in subparagraphs (A) and (B) of this
14        paragraph (4) of subsection (l) and subscribers who
15        receive their energy supply from an alternative retail
16        electric supplier, the electric utility shall remit to
17        the applicable alternative retail electric supplier
18        the information provided under subparagraph (A) of
19        this paragraph (3) for such customers and subscribers
20        in a manner set forth in such alternative retail
21        electric supplier's net metering program, or as
22        otherwise agreed between the utility and the
23        alternative retail electric supplier. The alternative
24        retail electric supplier shall then submit to the
25        utility the amount of the charges for power and energy
26        to be applied to such customers and subscribers,

 

 

SB2896- 567 -LRB102 17909 JWD 25989 b

1        including the amount of the credit associated with net
2        metering.
3            (C) A participating customer or subscriber may
4        provide authorization as required by applicable law
5        that directs the electric utility to submit
6        information to the owner or operator of the eligible
7        renewable electrical generating facility or community
8        renewable generation project to which the customer or
9        subscriber has an ownership or leasehold interest or a
10        subscription. Such information shall be limited to the
11        components of the net metering credit calculated under
12        this subsection (l), including the bill credit rate,
13        total kilowatthours, and total monetary credit value
14        applied to the customer's or subscriber's bill for the
15        monthly billing period.
16    (l-5) Within 90 days after the effective date of this
17amendatory Act of the 102nd 99th General Assembly, each
18electric utility subject to this Section shall file a tariff
19or tariffs to implement the provisions of subsection (l) of
20this Section, which shall, consistent with the provisions of
21subsection (l), describe the terms and conditions under which
22owners or operators of qualifying properties, units, or
23apartments may participate in net metering. The Commission
24shall approve, or approve with modification, the tariff within
25120 days after the effective date of this amendatory Act of the
26102nd 99th General Assembly.

 

 

SB2896- 568 -LRB102 17909 JWD 25989 b

1    (m) Nothing in this Section shall affect the right of an
2electricity provider to continue to provide, or the right of a
3retail customer to continue to receive service pursuant to a
4contract for electric service between the electricity provider
5and the retail customer in accordance with the prices, terms,
6and conditions provided for in that contract. Either the
7electricity provider or the customer may require compliance
8with the prices, terms, and conditions of the contract.
9    (n) After December 31, 2024 At such time, if any, that the
10load of the electricity provider's net metering customers
11equals 5% of the total peak demand supplied by that
12electricity provider during the previous year, as specified in
13subsection (j) of this Section, the net metering services
14described in subsections (d), (d-5), and (e), (e-5), and (f)
15of this Section shall no longer be offered, except as to those
16retail customers that are receiving net metering service under
17these subsections at the time the net metering services under
18those subsections are no longer offered whom shall continue to
19receive net metering services described in subsections (d),
20(d-5), and (e) of this Section for lifetime of system,
21regardless of if those retail customers change electricity
22providers. The electricity utility is responsible for ensuring
23billing credits continue without lapse for the lifetime of
24systems, as required in subsection (o). Those retail customers
25that begin taking net metering service after the date that net
26metering services are no longer offered under such subsections

 

 

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1shall be subject to the provisions set forth in the following
2paragraphs (1) through (3) of this subsection (n):
3        (1) An electricity provider shall charge or credit for
4    the net electricity supplied to eligible customers or
5    provided by eligible customers whose electric supply
6    service is not provided based on hourly pricing in the
7    following manner:
8            (A) If the amount of electricity used by the
9        customer during the monthly billing period exceeds the
10        amount of electricity produced by the customer, then
11        the electricity provider shall charge the customer for
12        the net kilowatt-hour based electricity charges
13        reflected in the customer's electric service rate
14        supplied to and used by the customer as provided in
15        paragraph (3) of this subsection (n).
16            (B) If the amount of electricity produced by a
17        customer during the monthly billing period exceeds the
18        amount of electricity used by the customer during that
19        billing period, then the electricity provider
20        supplying that customer shall apply a monetary 1:1
21        kilowatt-hour energy credit equivalent to the kilowatt
22        hour supply charges to the customer's subsequent bill.
23        For the purposes of this subsection, "kilowatt-hour
24        supply charges" means the kilowatt-hour equivalent
25        values for energy, capacity, transmission, and the
26        purchased energy adjustment, if applicable.

 

 

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1        Notwithstanding anything to the contrary, customers on
2        payment plans or participating in budget billing
3        programs shall have credits applied on a monthly basis
4        that reflects the kilowatt-hour based energy charges
5        in the customer's electric service rate to a
6        subsequent bill for service to the customer for the
7        net electricity supplied to the electricity provider.
8        The electricity provider shall continue to carry over
9        any excess monetary kilowatt-hour energy credits
10        earned and apply those credits to subsequent billing
11        periods to offset any customer-generator consumption
12        in those billing periods until all credits are used or
13        until the end of the annualized period.
14            (C) (Blank). At the end of the year or annualized
15        over the period that service is supplied by means of
16        net metering, or in the event that the retail customer
17        terminates service with the electricity provider prior
18        to the end of the year or the annualized period, any
19        remaining credits in the customer's account shall
20        expire.
21        (2) An electricity provider shall charge or credit for
22    the net electricity supplied to eligible customers or
23    provided by eligible customers whose electric supply
24    service is provided based on hourly pricing in the
25    following manner:
26            (A) If the amount of electricity used by the

 

 

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1        customer during any hourly period exceeds the amount
2        of electricity produced by the customer, then the
3        electricity provider shall charge the customer for the
4        net electricity supplied to and used by the customer
5        as provided in paragraph (3) of this subsection (n).
6            (B) If the amount of electricity produced by a
7        customer during any hourly period exceeds the amount
8        of electricity used by the customer during that hourly
9        period, the energy provider shall calculate an energy
10        credit for the net kilowatt-hours produced in such
11        period, and shall apply that credit as a monetary
12        credit to the customer's subsequent bill. The value of
13        the energy credit shall be calculated using the same
14        price per kilowatt-hour as the electric service
15        provider would charge for kilowatt-hour energy sales
16        during that same hourly period, and shall also include
17        values for capacity, and transmission.
18        (3) An electricity provider shall provide electric
19    service to eligible customers who utilize net metering at
20    non-discriminatory rates that are identical, with respect
21    to rate structure, retail rate components, and any monthly
22    charges, to the rates that the customer would be charged
23    if not a net metering customer. An electricity provider
24    shall charge the customer for the net electricity supplied
25    to and used by the customer according to the terms of the
26    contract or tariff to which the same customer would be

 

 

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1    assigned or be eligible for if the customer was not a net
2    metering customer. An electricity provider shall not
3    charge net metering customers any fee or charge or require
4    additional equipment, insurance, or any other requirements
5    not specifically authorized by interconnection standards
6    authorized by the Commission, unless the fee, charge, or
7    other requirement would apply to other similarly situated
8    customers who are not net metering customers. The charge
9    or credit that the customer receives for net electricity
10    shall be at a rate equal to the customer's energy supply
11    rate. The customer remains responsible for the gross
12    amount of delivery services charges, supply-related
13    charges that are kilowatt based, and all taxes and fees
14    related to such charges. The customer also remains
15    responsible for all taxes and fees that would otherwise be
16    applicable to the net amount of electricity used by the
17    customer. Paragraphs (1) and (2) of this subsection (n)
18    shall not be construed to prevent an arms-length agreement
19    between an electricity provider and an eligible customer
20    that sets forth different prices, terms, and conditions
21    for the provision of net metering service, including, but
22    not limited to, the provision of the appropriate metering
23    equipment for non-residential customers. Nothing in this
24    paragraph (3) shall be interpreted to mandate that a
25    utility that is only required to provide delivery services
26    to a given customer must also sell electricity to such

 

 

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1    customer.
2    (o) Within 90 days after the effective date of this
3amendatory Act of the 102nd General Assembly, each electric
4utility subject to this Section and Section 16-107.5 shall
5file a tariff which shall, consistent with the provisions of
6this Section, propose the terms and conditions under which a
7customer may participate in net metering. The tariff shall
8also provide a streamlined and transparent bill crediting
9system for net metering to be managed by the electric
10utilities. The terms and conditions shall include, but are not
11limited to, that an electricity utility shall manage and
12maintain billing of net metering credits and charges
13regardless of if the eligible customer takes net metering
14under electricity utility or alternative retail electricity
15supplier. The electricity utility will process and approve all
16net metering applications, even if an eligible customer is
17served by an alternative retail electricity supplier; and the
18utility will forward application approval to the appropriate
19alternative retail electricity supplier. Eligibility for net
20metering shall remain with the owner of the utility billing
21address such that if a premise changes ownership the net
22metering eligibility transfers to the new owner. The
23electricity utility will manage net metering billing for
24eligible customers to ensure full crediting occurs on
25electricity bills, including but not limited to ensuring net
26metering crediting begins upon commercial operation date, net

 

 

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1metering billing transfers immediately if an eligible customer
2switches from an electricity utility to alternative retail
3electricity supplier or vice versa, and net metering billing
4transfers between ownership of a valid billing address. This
5includes transfer of all banked credits.
6(Source: P.A. 99-906, eff. 6-1-17.)
 
7    (220 ILCS 5/16-107.6)
8    Sec. 16-107.6. Distributed generation rebate.
9    (a) In this Section:
10    "Additive grid services" means the services, as determined
11by the Commission, that distributed generation provides the
12grid in addition to system-wide grid services. Additive grid
13services may include geographic, locational, geographic,
14time-based, and performance-based benefits, technological
15capabilities and present and future grid needs.
16    "Energy storage system" means commercially available
17technology that is capable of absorbing energy and storing it
18for a period of time for use at a later time including but not
19limited to electrochemical, thermal, and electromechanical
20technologies and may be interconnected behind the customer's
21meter or interconnected behind its own meter.
22    "Nameplate capacity" means the kilowatt-hour of rated AC
23capacity of the installed system.
24    "Smart inverter" means a device that converts direct
25current into alternating current and can autonomously

 

 

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1contribute to grid support during excursions from normal
2operating voltage and frequency conditions by providing each
3of the following: dynamic reactive and real power support,
4voltage and frequency ride-through, ramp rate controls, and
5communication systems with ability to accept external
6commands, and other functions from the electric utility.
7    "Subscriber" has the meaning set forth in Section 1-10 of
8the Illinois Power Agency Act.
9    "Subscription" has the meaning set forth in Section 1-10
10of the Illinois Power Agency Act.
11    "System-wide grid services" means the basic services a
12distributed generation project that installs a smart inverter
13provides to the grid for a minimum of 25 years. Those basic
14services are delineated in the definition of smart inverter
15above.
16    "Threshold date" means December 31, 2024 the date on which
17the load of an electricity provider's net metering customers
18equals 5% of the total peak demand supplied by that
19electricity provider during the previous year, as specified
20under subsection (j) of Section 16-107.5 of this Act.
21    (b) An electric utility that serves more than 200,000
22customers in the State shall file a petition with the
23Commission requesting approval of the utility's tariff to
24provide a rebate to the owner or operator of a retail customer
25who owns or operates distributed generation, including
26third-party owned systems, that meets the following criteria:

 

 

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1        (1) has a nameplate generating capacity no greater
2    than 5,000 2,000 kilowatts and is primarily used to offset
3    that customer's electricity load;
4        (2) is located on the customer's premises, for the
5    customer's own use, and not for commercial use or sales,
6    including, but not limited to, wholesale sales of electric
7    power and energy;
8        (3) is located in the electric utility's service
9    territory; and
10        (4) is interconnected under rules adopted by the
11    Commission by means of the inverter or smart inverter
12    required by this Section, as applicable.
13    For purposes of this Section, "distributed generation"
14shall satisfy the definition of distributed renewable energy
15generation device set forth in Section 1-10 of the Illinois
16Power Agency Act to the extent such definition is consistent
17with the requirements of this Section.
18    In addition, any new photovoltaic distributed generation
19that is installed after the effective date of this amendatory
20Act of the 99th General Assembly must be installed by a
21qualified person, as defined by subsection (i) of Section 1-56
22of the Illinois Power Agency Act.
23    The tariff shall include a base payment for system-wide
24grid services and an additional payment for additive grid
25services. The tariff shall provide that the base payment as
26outlined in (c) below is in exchange for system-wide grid

 

 

SB2896- 577 -LRB102 17909 JWD 25989 b

1services, and that the utility shall be permitted to send
2signals to utilize operate and control the smart inverter
3associated with the distributed generation that receives a
4base payment is the subject of the rebate for the purpose of
5preserving reliability during distribution system reliability
6events. The tariff and shall address the terms and conditions
7of the operation and the compensation associated with the
8operation. Nothing in this Section shall negate or supersede
9Institute of Electrical and Electronics Engineers
10interconnection requirements or standards or other similar
11standards or requirements. The tariff shall also provide for
12additive grid services additional uses of the smart inverter
13that shall be separately compensated from system-wide grid
14services. Such additive grid services and which may include,
15but are not limited to, voltage and VAR support, voltage watt,
16frequency watt, regulation, and other grid services. As part
17of the proceeding described in subsection (e) of this Section,
18the Commission shall review and determine whether smart
19inverters can provide any additive grid additional uses or
20services. If the Commission determines that an additive grid
21additional use or service would be beneficial, the Commission
22shall determine the terms and conditions of the operation of
23such additive grid service and shall approve the value of such
24additive grid service and how the use or service should be
25separately compensated.
26    (c) The proposed tariff authorized by subsection (b) of

 

 

SB2896- 578 -LRB102 17909 JWD 25989 b

1this Section shall include the following participation terms
2for and formulae to calculate the value of the rebates to be
3applied under this Section for distributed generation that
4satisfies the criteria set forth in subsection (b) of this
5Section:
6        (1) Until the utility files its tariff or tariffs to
7    place into effect the additional payment for additive grid
8    services as rebate values established by the Commission
9    under subsection (e) of this Section, the owner or
10    operator of distributed generation that services
11    non-residential customers that are taking service under a
12    net metering program offered by an electricity provider
13    under the terms of Section 16-107.5 of this Act may apply
14    for a rebate as provided for in this Section. The value of
15    the base payment rebate shall be $250 per kilowatt of
16    nameplate generating capacity, measured as nominal DC
17    power output, of a non-residential customer's distributed
18    generation. After the utility files a tariff or tariffs
19    making the additional payment for additive grid services
20    as established under subsection (e) of this Section,
21    non-residential customers may apply for a rebate in the
22    amount of the base payment as outlined in this Section and
23    may opt to apply for the additional payment for additive
24    grid services if the system chooses to provide such
25    services. To the extent the distributed generation system
26    also has a storage device as part of the system, and said

 

 

SB2896- 579 -LRB102 17909 JWD 25989 b

1    storage uses the same smart inverter as the distributed
2    generation, then the storage shall be separately
3    compensated at a base payment of $350 per kilowatt-hour of
4    nameplate capacity.
5        (2) After the threshold date and until December 31,
6    2029, the owner of distributed generation that, before the
7    threshold date, would have been eligible for net metering
8    under subsection (d), (d-5), or (e) of Section 16-107.5,
9    may apply for a rebate in the amount of the base payment
10    for system-wide grid services as provided for in this
11    Section. The value of the base payment shall be $350 per
12    kilowatt of nameplate generating capacity, measured as
13    nominal DC power output, of the distributed generation.
14    After the utility files a tariff or tariffs making the
15    additional payment for additive grid services as
16    established under subsection (e) of this Section, owners
17    or operators may apply for a rebate in the amount of the
18    base payment as outlined in this Section, and may opt to
19    apply for the additional payment for additive grid
20    services, if the system chooses to provide such services
21    To the extent the distributed generation system also has a
22    storage device as part of the system, and said storage
23    uses the same smart inverter as the distributed
24    generation, then the storage shall be separately
25    compensated at a base payment of $350 per kilowatt-hour of
26    nameplate capacity. After the utility's tariff or tariffs

 

 

SB2896- 580 -LRB102 17909 JWD 25989 b

1    setting the new rebate values established under subsection
2    (d) of this Section take effect, retail customers may, as
3    applicable, make the following elections:
4            (A) Residential customers that are taking service
5        under a net metering program offered by an electricity
6        provider under the terms of Section 16-107.5 of this
7        Act on the threshold date may elect to either continue
8        to take such service under the terms of such program as
9        in effect on such threshold date for the useful life of
10        the customer's eligible renewable electric generating
11        facility as defined in such Section, or file an
12        application to receive a rebate under the terms of
13        this Section, provided that such application must be
14        submitted within 6 months after the effective date of
15        the tariff approved under subsection (d) of this
16        Section. The value of the rebate shall be the amount
17        established by the Commission and reflected in the
18        utility's tariff pursuant to subsection (e) of this
19        Section.
20            (B) Non-residential customers that are taking
21        service under a net metering program offered by an
22        electricity provider under the terms of Section
23        16-107.5 of this Act on the threshold date may apply
24        for a rebate as provided for in this Section. The value
25        of the rebate shall be the amount established by the
26        Commission and reflected in the utility's tariff

 

 

SB2896- 581 -LRB102 17909 JWD 25989 b

1        pursuant to subsection (e) of this Section.
2        (3) Upon approval of a rebate application submitted
3    under this subsection (c), the retail customer shall no
4    longer be entitled to receive any delivery service credits
5    for the excess electricity generated by its facility and
6    shall be subject to the provisions of subsection (n) of
7    Section 16-107.5 of this Act.
8        (4) To be eligible for a rebate described in this
9    subsection (c), the owner or operator of the distributed
10    generation customers who begin taking service after the
11    effective date of this amendatory Act of the 99th General
12    Assembly under a net metering program offered by an
13    electricity provider under the terms of Section 16-107.5
14    of this Act must have a smart inverter installed and in
15    operation on the associated with the customer's
16    distributed generation.
17    (d) The Commission shall review the proposed tariff
18submitted under subsections (b) and (c) of this Section and
19may make changes to the tariff that are consistent with this
20Section and with the Commission's authority under Article IX
21of this Act, subject to notice and hearing. Following notice
22and hearing, the Commission shall issue an order approving, or
23approving with modification, such tariff no later than 240
24days after the utility files its tariff. Upon the effective
25date of this amendatory Act of the 102nd General Assembly, an
26electric utility shall file a petition with the Commission to

 

 

SB2896- 582 -LRB102 17909 JWD 25989 b

1amend and update any existing tariffs to comply with
2subsections (b) and (c).
3    (e) Upon the effective date of this amendatory Act of the
4102nd General Assembly, if When the total generating capacity
5of the electricity provider's net metering customers is equal
6to 3%, the Commission has not already opened an investigation,
7it shall open an investigation into a an annual process and
8formula for calculating the additional payment associated with
9additive grid services value of rebates for the retail
10customers described in subsections (b) and (f) of this Section
11that submit rebate applications after the threshold date for
12an electric utility that elected to file a tariff pursuant to
13this Section. The process for identifying additive grid
14services and the formula for calculating the additional
15payment for those additive grid services shall be updated
16every 5 years, and shall promote expansion of, and continuity
17in, the distributed generation competitive market. The value
18of the additional payment for additive grid services shall be
19set no more frequently than annually using the established
20process and formula established by the Commission. The
21investigation shall include diverse sets of stakeholders,
22calculations for valuing additive grid services distributed
23generation provides energy resource benefits to the grid based
24on best practices, and assessments of present and future
25technological capabilities of distributed generation energy
26resources. The value of such additional payments rebates shall

 

 

SB2896- 583 -LRB102 17909 JWD 25989 b

1reflect the value of the distributed generation to the
2distribution system at the location at which it is
3interconnected, taking into account the geographic,
4locational, time-based, and performance-based benefits, as
5well as technological capabilities and present and future grid
6needs. As such, different locations within the utility
7territory may have different additive grid services and
8associated additional payments. The investigation shall take a
9long-term look at the benefits and values of such additive
10grid services. No later than 60 10 days after the Commission
11enters its final order under this subsection (e), the utility
12shall file its updated tariff or tariffs in compliance with
13the order, and the Commission shall approve, or approve with
14modification, the tariff or tariffs within 90 45 days after
15the utility's filing. For those rebate applications filed
16after the threshold date but before the utility's tariff or
17tariffs filed pursuant to this subsection (e) take effect, the
18value of the rebate shall remain at the value established in
19subsection (c) of this Section until the tariff is approved.
20    (f) Notwithstanding any provision of this Act to the
21contrary, the owner, developer, or subscriber of a distributed
22generation facility that is a community renewable energy
23generation facility as defined in Section 1-75(c) of the
24Illinois Power Agency Act part of a net metering program
25provided under subsection (l) of Section 16-107.5 shall also
26be eligible to apply for the rebate described in this Section.

 

 

SB2896- 584 -LRB102 17909 JWD 25989 b

1The owner or operator of A subscriber to the generation
2facility may apply for a rebate in the amount of the
3subscriber's subscription only if the owner or operator, or
4previous owner or operator of the community renewable energy
5generation facility, developer, or previous subscriber to the
6same panel or panels has not already submitted an application,
7and, regardless of whether the subscriber is a residential or
8non-residential customer, may be allowed the amount identified
9in paragraph (1) of subsection (c) or in subsection (e) of this
10Section applicable to such customer on the date that the
11application is submitted. An application for a rebate for a
12portion of a project described in this subsection (f) may be
13submitted at or after the time that a related request for net
14metering is made.
15    (g) The owner of the distributed generation may apply for
16the tariff or tariffs approved under this Section at the time
17of execution of an interconnection agreement with the
18distribution utility and shall receive the value of the base
19payment and additional payment available at that time of
20execution of the interconnection agreement, provided the
21project reaches mechanical completion within 24 months of
22execution of the interconnection agreement. The utility shall
23issue the rebate no No later than 60 days after the project is
24energized utility receives an application for a rebate under
25its tariff approved under subsection (d) or (e) of this
26Section, the utility shall issue a rebate to the applicant

 

 

SB2896- 585 -LRB102 17909 JWD 25989 b

1under the terms of the tariff. In the event the application is
2incomplete or the utility is otherwise unable to calculate the
3payment based on the information provided by the owner, the
4utility shall issue the payment no later than 60 days after the
5application is complete or all requested information is
6received.
7    (h) An electric utility shall recover from its retail
8customers all of the costs of the rebates made under a tariff
9or tariffs placed into effect under this Section, including,
10but not limited to, the value of the rebates and all costs
11incurred by the utility to comply with and implement this
12Section, consistent with the following provisions:
13        (1) The utility shall defer the full amount of its
14    costs incurred under this Section as a regulatory asset.
15    The total costs deferred as a regulatory asset shall be
16    amortized over a 15-year period. The unamortized balance
17    shall be recognized as of December 31 for a given year. The
18    utility shall also earn a return on the total of the
19    unamortized balance of the regulatory assets, less any
20    deferred taxes related to the unamortized balance, at an
21    annual rate equal to the utility's weighted average cost
22    of capital that includes, based on a year-end capital
23    structure, the utility's actual cost of debt for the
24    applicable calendar year and a cost of equity, which shall
25    be calculated as the sum of (i) the average for the
26    applicable calendar year of the monthly average yields of

 

 

SB2896- 586 -LRB102 17909 JWD 25989 b

1    30-year U.S. Treasury bonds published by the Board of
2    Governors of the Federal Reserve System in its weekly H.15
3    Statistical Release or successor publication; and (ii) 580
4    basis points, including a revenue conversion factor
5    calculated to recover or refund all additional income
6    taxes that may be payable or receivable as a result of that
7    return.
8        When an electric utility creates a regulatory asset
9    under the provisions of this Section, the costs are
10    recovered over a period during which customers also
11    receive a benefit, which is in the public interest.
12    Accordingly, it is the intent of the General Assembly that
13    an electric utility that elects to create a regulatory
14    asset under the provisions of this Section shall recover
15    all of the associated costs, including, but not limited
16    to, its cost of capital as set forth in this Section. After
17    the Commission has approved the prudence and
18    reasonableness of the costs that comprise the regulatory
19    asset, the electric utility shall be permitted to recover
20    all such costs, and the value and recoverability through
21    rates of the associated regulatory asset shall not be
22    limited, altered, impaired, or reduced. To enable the
23    financing of the incremental capital expenditures,
24    including regulatory assets, for electric utilities that
25    serve less than 3,000,000 retail customers but more than
26    500,000 retail customers in the State, the utility's

 

 

SB2896- 587 -LRB102 17909 JWD 25989 b

1    actual year-end capital structure that includes a common
2    equity ratio, excluding goodwill, of up to and including
3    50% of the total capital structure shall be deemed
4    reasonable and used to set rates.
5        (2) The utility, at its election, may recover all of
6    the costs it incurs under this Section as part of a filing
7    for a general increase in rates under Article IX of this
8    Act, as part of an annual filing to update a
9    performance-based formula rate under subsection (d) of
10    Section 16-108.5 of this Act, or through an automatic
11    adjustment clause tariff, provided that nothing in this
12    paragraph (2) permits the double recovery of such costs
13    from customers. If the utility elects to recover the costs
14    it incurs under this Section through an automatic
15    adjustment clause tariff, the utility may file its
16    proposed tariff together with the tariff it files under
17    subsection (b) of this Section or at a later time. The
18    proposed tariff shall provide for an annual
19    reconciliation, less any deferred taxes related to the
20    reconciliation, with interest at an annual rate of return
21    equal to the utility's weighted average cost of capital as
22    calculated under paragraph (1) of this subsection (h),
23    including a revenue conversion factor calculated to
24    recover or refund all additional income taxes that may be
25    payable or receivable as a result of that return, of the
26    revenue requirement reflected in rates for each calendar

 

 

SB2896- 588 -LRB102 17909 JWD 25989 b

1    year, beginning with the calendar year in which the
2    utility files its automatic adjustment clause tariff under
3    this subsection (h), with what the revenue requirement
4    would have been had the actual cost information for the
5    applicable calendar year been available at the filing
6    date. The Commission shall review the proposed tariff and
7    may make changes to the tariff that are consistent with
8    this Section and with the Commission's authority under
9    Article IX of this Act, subject to notice and hearing.
10    Following notice and hearing, the Commission shall issue
11    an order approving, or approving with modification, such
12    tariff no later than 240 days after the utility files its
13    tariff.
14    (i) No later than 90 days after the Commission enters an
15order, or order on rehearing, whichever is later, approving an
16electric utility's proposed tariff under subsection (d) of
17this Section, the electric utility shall provide notice of the
18availability of rebates under this Section. Subsequent to the
19utility's notice, any entity that offers in the State, for
20sale or lease, distributed generation and estimates the dollar
21saving attributable to such distributed generation shall
22provide estimates based on both delivery service credits and
23the rebates available under this Section.
24(Source: P.A. 99-906, eff. 6-1-17.)
 
25    (220 ILCS 5/16-108)

 

 

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1    Sec. 16-108. Recovery of costs associated with the
2provision of delivery and other services.
3    (a) An electric utility shall file a delivery services
4tariff with the Commission at least 210 days prior to the date
5that it is required to begin offering such services pursuant
6to this Act. An electric utility shall provide the components
7of delivery services that are subject to the jurisdiction of
8the Federal Energy Regulatory Commission at the same prices,
9terms and conditions set forth in its applicable tariff as
10approved or allowed into effect by that Commission. The
11Commission shall otherwise have the authority pursuant to
12Article IX to review, approve, and modify the prices, terms
13and conditions of those components of delivery services not
14subject to the jurisdiction of the Federal Energy Regulatory
15Commission, including the authority to determine the extent to
16which such delivery services should be offered on an unbundled
17basis. In making any such determination the Commission shall
18consider, at a minimum, the effect of additional unbundling on
19(i) the objective of just and reasonable rates, (ii) electric
20utility employees, and (iii) the development of competitive
21markets for electric energy services in Illinois.
22    (b) The Commission shall enter an order approving, or
23approving as modified, the delivery services tariff no later
24than 30 days prior to the date on which the electric utility
25must commence offering such services. The Commission may
26subsequently modify such tariff pursuant to this Act.

 

 

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1    (c) The electric utility's tariffs shall define the
2classes of its customers for purposes of delivery services
3charges. Delivery services shall be priced and made available
4to all retail customers electing delivery services in each
5such class on a nondiscriminatory basis regardless of whether
6the retail customer chooses the electric utility, an affiliate
7of the electric utility, or another entity as its supplier of
8electric power and energy. Charges for delivery services shall
9be cost based, and shall allow the electric utility to recover
10the costs of providing delivery services through its charges
11to its delivery service customers that use the facilities and
12services associated with such costs. Such costs shall include
13the costs of owning, operating and maintaining transmission
14and distribution facilities. The Commission shall also be
15authorized to consider whether, and if so to what extent, the
16following costs are appropriately included in the electric
17utility's delivery services rates: (i) the costs of that
18portion of generation facilities used for the production and
19absorption of reactive power in order that retail customers
20located in the electric utility's service area can receive
21electric power and energy from suppliers other than the
22electric utility, and (ii) the costs associated with the use
23and redispatch of generation facilities to mitigate
24constraints on the transmission or distribution system in
25order that retail customers located in the electric utility's
26service area can receive electric power and energy from

 

 

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1suppliers other than the electric utility. Nothing in this
2subsection shall be construed as directing the Commission to
3allocate any of the costs described in (i) or (ii) that are
4found to be appropriately included in the electric utility's
5delivery services rates to any particular customer group or
6geographic area in setting delivery services rates.
7    (d) The Commission shall establish charges, terms and
8conditions for delivery services that are just and reasonable
9and shall take into account customer impacts when establishing
10such charges. In establishing charges, terms and conditions
11for delivery services, the Commission shall take into account
12voltage level differences. A retail customer shall have the
13option to request to purchase electric service at any delivery
14service voltage reasonably and technically feasible from the
15electric facilities serving that customer's premises provided
16that there are no significant adverse impacts upon system
17reliability or system efficiency. A retail customer shall also
18have the option to request to purchase electric service at any
19point of delivery that is reasonably and technically feasible
20provided that there are no significant adverse impacts on
21system reliability or efficiency. Such requests shall not be
22unreasonably denied.
23    (e) Electric utilities shall recover the costs of
24installing, operating or maintaining facilities for the
25particular benefit of one or more delivery services customers,
26including without limitation any costs incurred in complying

 

 

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1with a customer's request to be served at a different voltage
2level, directly from the retail customer or customers for
3whose benefit the costs were incurred, to the extent such
4costs are not recovered through the charges referred to in
5subsections (c) and (d) of this Section.
6    (f) An electric utility shall be entitled but not required
7to implement transition charges in conjunction with the
8offering of delivery services pursuant to Section 16-104. If
9an electric utility implements transition charges, it shall
10implement such charges for all delivery services customers and
11for all customers described in subsection (h), but shall not
12implement transition charges for power and energy that a
13retail customer takes from cogeneration or self-generation
14facilities located on that retail customer's premises, if such
15facilities meet the following criteria:
16        (i) the cogeneration or self-generation facilities
17    serve a single retail customer and are located on that
18    retail customer's premises (for purposes of this
19    subparagraph and subparagraph (ii), an industrial or
20    manufacturing retail customer and a third party contractor
21    that is served by such industrial or manufacturing
22    customer through such retail customer's own electrical
23    distribution facilities under the circumstances described
24    in subsection (vi) of the definition of "alternative
25    retail electric supplier" set forth in Section 16-102,
26    shall be considered a single retail customer);

 

 

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1        (ii) the cogeneration or self-generation facilities
2    either (A) are sized pursuant to generally accepted
3    engineering standards for the retail customer's electrical
4    load at that premises (taking into account standby or
5    other reliability considerations related to that retail
6    customer's operations at that site) or (B) if the facility
7    is a cogeneration facility located on the retail
8    customer's premises, the retail customer is the thermal
9    host for that facility and the facility has been designed
10    to meet that retail customer's thermal energy requirements
11    resulting in electrical output beyond that retail
12    customer's electrical demand at that premises, comply with
13    the operating and efficiency standards applicable to
14    "qualifying facilities" specified in title 18 Code of
15    Federal Regulations Section 292.205 as in effect on the
16    effective date of this amendatory Act of 1999;
17        (iii) the retail customer on whose premises the
18    facilities are located either has an exclusive right to
19    receive, and corresponding obligation to pay for, all of
20    the electrical capacity of the facility, or in the case of
21    a cogeneration facility that has been designed to meet the
22    retail customer's thermal energy requirements at that
23    premises, an identified amount of the electrical capacity
24    of the facility, over a minimum 5-year period; and
25        (iv) if the cogeneration facility is sized for the
26    retail customer's thermal load at that premises but

 

 

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1    exceeds the electrical load, any sales of excess power or
2    energy are made only at wholesale, are subject to the
3    jurisdiction of the Federal Energy Regulatory Commission,
4    and are not for the purpose of circumventing the
5    provisions of this subsection (f).
6If a generation facility located at a retail customer's
7premises does not meet the above criteria, an electric utility
8implementing transition charges shall implement a transition
9charge until December 31, 2006 for any power and energy taken
10by such retail customer from such facility as if such power and
11energy had been delivered by the electric utility. Provided,
12however, that an industrial retail customer that is taking
13power from a generation facility that does not meet the above
14criteria but that is located on such customer's premises will
15not be subject to a transition charge for the power and energy
16taken by such retail customer from such generation facility if
17the facility does not serve any other retail customer and
18either was installed on behalf of the customer and for its own
19use prior to January 1, 1997, or is both predominantly fueled
20by byproducts of such customer's manufacturing process at such
21premises and sells or offers an average of 300 megawatts or
22more of electricity produced from such generation facility
23into the wholesale market. Such charges shall be calculated as
24provided in Section 16-102, and shall be collected on each
25kilowatt-hour delivered under a delivery services tariff to a
26retail customer from the date the customer first takes

 

 

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1delivery services until December 31, 2006 except as provided
2in subsection (h) of this Section. Provided, however, that an
3electric utility, other than an electric utility providing
4service to at least 1,000,000 customers in this State on
5January 1, 1999, shall be entitled to petition for entry of an
6order by the Commission authorizing the electric utility to
7implement transition charges for an additional period ending
8no later than December 31, 2008. The electric utility shall
9file its petition with supporting evidence no earlier than 16
10months, and no later than 12 months, prior to December 31,
112006. The Commission shall hold a hearing on the electric
12utility's petition and shall enter its order no later than 8
13months after the petition is filed. The Commission shall
14determine whether and to what extent the electric utility
15shall be authorized to implement transition charges for an
16additional period. The Commission may authorize the electric
17utility to implement transition charges for some or all of the
18additional period, and shall determine the mitigation factors
19to be used in implementing such transition charges; provided,
20that the Commission shall not authorize mitigation factors
21less than 110% of those in effect during the 12 months ended
22December 31, 2006. In making its determination, the Commission
23shall consider the following factors: the necessity to
24implement transition charges for an additional period in order
25to maintain the financial integrity of the electric utility;
26the prudence of the electric utility's actions in reducing its

 

 

SB2896- 596 -LRB102 17909 JWD 25989 b

1costs since the effective date of this amendatory Act of 1997;
2the ability of the electric utility to provide safe, adequate
3and reliable service to retail customers in its service area;
4and the impact on competition of allowing the electric utility
5to implement transition charges for the additional period.
6    (g) The electric utility shall file tariffs that establish
7the transition charges to be paid by each class of customers to
8the electric utility in conjunction with the provision of
9delivery services. The electric utility's tariffs shall define
10the classes of its customers for purposes of calculating
11transition charges. The electric utility's tariffs shall
12provide for the calculation of transition charges on a
13customer-specific basis for any retail customer whose average
14monthly maximum electrical demand on the electric utility's
15system during the 6 months with the customer's highest monthly
16maximum electrical demands equals or exceeds 3.0 megawatts for
17electric utilities having more than 1,000,000 customers, and
18for other electric utilities for any customer that has an
19average monthly maximum electrical demand on the electric
20utility's system of one megawatt or more, and (A) for which
21there exists data on the customer's usage during the 3 years
22preceding the date that the customer became eligible to take
23delivery services, or (B) for which there does not exist data
24on the customer's usage during the 3 years preceding the date
25that the customer became eligible to take delivery services,
26if in the electric utility's reasonable judgment there exists

 

 

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1comparable usage information or a sufficient basis to develop
2such information, and further provided that the electric
3utility can require customers for which an individual
4calculation is made to sign contracts that set forth the
5transition charges to be paid by the customer to the electric
6utility pursuant to the tariff.
7    (h) An electric utility shall also be entitled to file
8tariffs that allow it to collect transition charges from
9retail customers in the electric utility's service area that
10do not take delivery services but that take electric power or
11energy from an alternative retail electric supplier or from an
12electric utility other than the electric utility in whose
13service area the customer is located. Such charges shall be
14calculated, in accordance with the definition of transition
15charges in Section 16-102, for the period of time that the
16customer would be obligated to pay transition charges if it
17were taking delivery services, except that no deduction for
18delivery services revenues shall be made in such calculation,
19and usage data from the customer's class shall be used where
20historical usage data is not available for the individual
21customer. The customer shall be obligated to pay such charges
22on a lump sum basis on or before the date on which the customer
23commences to take service from the alternative retail electric
24supplier or other electric utility, provided, that the
25electric utility in whose service area the customer is located
26shall offer the customer the option of signing a contract

 

 

SB2896- 598 -LRB102 17909 JWD 25989 b

1pursuant to which the customer pays such charges ratably over
2the period in which the charges would otherwise have applied.
3    (i) An electric utility shall be entitled to add to the
4bills of delivery services customers charges pursuant to
5Sections 9-221, 9-222 (except as provided in Section 9-222.1),
6and Section 16-114 of this Act, Section 5-5 of the Electricity
7Infrastructure Maintenance Fee Law, Section 6-5 of the
8Renewable Energy, Energy Efficiency, and Coal Resources
9Development Law of 1997, and Section 13 of the Energy
10Assistance Act.
11    (j) If a retail customer that obtains electric power and
12energy from cogeneration or self-generation facilities
13installed for its own use on or before January 1, 1997,
14subsequently takes service from an alternative retail electric
15supplier or an electric utility other than the electric
16utility in whose service area the customer is located for any
17portion of the customer's electric power and energy
18requirements formerly obtained from those facilities
19(including that amount purchased from the utility in lieu of
20such generation and not as standby power purchases, under a
21cogeneration displacement tariff in effect as of the effective
22date of this amendatory Act of 1997), the transition charges
23otherwise applicable pursuant to subsections (f), (g), or (h)
24of this Section shall not be applicable in any year to that
25portion of the customer's electric power and energy
26requirements formerly obtained from those facilities,

 

 

SB2896- 599 -LRB102 17909 JWD 25989 b

1provided, that for purposes of this subsection (j), such
2portion shall not exceed the average number of kilowatt-hours
3per year obtained from the cogeneration or self-generation
4facilities during the 3 years prior to the date on which the
5customer became eligible for delivery services, except as
6provided in subsection (f) of Section 16-110.
7    (k) The electric utility shall be entitled to recover
8through tariffed charges all of the costs associated with the
9purchase of zero emission credits from zero emission
10facilities to meet the requirements of subsection (d-5) of
11Section 1-75 of the Illinois Power Agency Act. Such costs
12shall include the costs of procuring the zero emission
13credits, as well as the reasonable costs that the utility
14incurs as part of the procurement processes and to implement
15and comply with plans and processes approved by the Commission
16under such subsection (d-5). The costs shall be allocated
17across all retail customers through a single, uniform cents
18per kilowatt-hour charge applicable to all retail customers,
19which shall appear as a separate line item on each customer's
20bill. Beginning June 1, 2017, the electric utility shall be
21entitled to recover through tariffed charges all of the costs
22associated with the purchase of renewable energy resources to
23meet the renewable energy resource standards of subsection (c)
24of Section 1-75 of the Illinois Power Agency Act, under
25procurement plans as approved in accordance with that Section
26and Section 16-111.5 of this Act. Such costs shall include the

 

 

SB2896- 600 -LRB102 17909 JWD 25989 b

1costs of procuring the renewable energy resources, as well as
2the reasonable costs that the utility incurs as part of the
3procurement processes and to implement and comply with plans
4and processes approved by the Commission under such Sections.
5The costs associated with the purchase of renewable energy
6resources shall be allocated across all retail customers in
7proportion to the amount of renewable energy resources the
8utility procures for such customers through a single, uniform
9cents per kilowatt-hour charge applicable to such retail
10customers, which shall appear as a separate line item on each
11such customer's bill.
12    Notwithstanding whether the Commission has approved the
13initial long-term renewable resources procurement plan as of
14June 1, 2017, an electric utility shall place new tariffed
15charges into effect beginning with the June 2017 monthly
16billing period, to the extent practicable, to begin recovering
17the costs of procuring renewable energy resources, as those
18charges are calculated under the limitations described in
19subparagraph (E) of paragraph (1) of subsection (c) of Section
201-75 of the Illinois Power Agency Act. Notwithstanding the
21date on which the utility places such new tariffed charges
22into effect, the utility shall be permitted to collect the
23charges under such tariff as if the tariff had been in effect
24beginning with the first day of the June 2017 monthly billing
25period. For the delivery years commencing June 1, 2017, June
261, 2018, and June 1, 2019, June 1, 2020, June 1, 2021, and June

 

 

SB2896- 601 -LRB102 17909 JWD 25989 b

11, 2022, the electric utility shall deposit into a separate
2interest bearing account of a financial institution the monies
3collected under the tariffed charges. Any interest earned
4shall be credited back to retail customers under the
5reconciliation proceeding provided for in this subsection (k),
6provided that the electric utility shall first be reimbursed
7from the interest for the administrative costs that it incurs
8to administer and manage the account. Any taxes due on the
9funds in the account, or interest earned on it, will be paid
10from the account or, if insufficient monies are available in
11the account, from the monies collected under the tariffed
12charges to recover the costs of procuring renewable energy
13resources. Monies deposited in the account shall be subject to
14the review, reconciliation, and true-up process described in
15this subsection (k) that is applicable to the funds collected
16and costs incurred for the procurement of renewable energy
17resources.
18    The electric utility shall be entitled to recover all of
19the costs identified in this subsection (k) through automatic
20adjustment clause tariffs applicable to all of the utility's
21retail customers that allow the electric utility to adjust its
22tariffed charges consistent with this subsection (k). The
23determination as to whether any excess funds were collected
24during a given delivery year for the purchase of renewable
25energy resources, and the crediting of any excess funds back
26to retail customers, shall not be made until after the close of

 

 

SB2896- 602 -LRB102 17909 JWD 25989 b

1the delivery year, which will ensure that the maximum amount
2of funds is available to implement the approved long-term
3renewable resources procurement plan during a given delivery
4year. The amount of excess funds credited back to retail
5customers shall be reduced by an amount equal to the payment
6obligations required by any contracts entered into by an
7electric utility under described in Sections 1-56(b) and
81-75(c) of the Illinois Power Agency Act, even if such
9payments have not yet been made. The electric utility's
10collections under such automatic adjustment clause tariffs to
11recover the costs of renewable energy resources and zero
12emission credits from zero emission facilities shall be
13subject to separate annual review, reconciliation, and true-up
14against actual costs by the Commission under a procedure that
15shall be specified in the electric utility's automatic
16adjustment clause tariffs and that shall be approved by the
17Commission in connection with its approval of such tariffs.
18The procedure shall provide that any difference between the
19electric utility's collections under the automatic adjustment
20charges for an annual period and the electric utility's actual
21costs of renewable energy resources and zero emission credits
22from zero emission facilities for that same annual period
23shall be refunded to or collected from, as applicable, the
24electric utility's retail customers in subsequent periods.
25    Nothing in this subsection (k) is intended to affect,
26limit, or change the right of the electric utility to recover

 

 

SB2896- 603 -LRB102 17909 JWD 25989 b

1the costs associated with the procurement of renewable energy
2resources for periods commencing before, on, or after June 1,
32017, as otherwise provided in the Illinois Power Agency Act.
4    Notwithstanding anything to the contrary, the Commission
5shall not conduct an annual review, reconciliation, and
6true-up associated with renewable energy resources'
7collections and costs for the delivery years commencing June
81, 2017, June 1, 2018, June 1, 2019, and June 1, 2020, June 1,
92021, and June 1, 2022, and shall instead conduct a single
10review, reconciliation, and true-up associated with renewable
11energy resources' collections and costs for the 6-year 4-year
12period beginning June 1, 2017 and ending May 31, 2023 2021,
13provided that the review, reconciliation, and true-up shall
14not be initiated until after August 31, 2023 2021. During the
156-year 4-year period, the utility shall be permitted to
16collect and retain funds under this subsection (k) and to
17purchase renewable energy resources under an approved
18long-term renewable resources procurement plan using those
19funds regardless of the delivery year in which the funds were
20collected during the 6-year 4-year period.
21    If the amount of funds collected during the delivery year
22commencing June 1, 2017, exceeds the costs incurred during
23that delivery year, then up to half of this excess amount, as
24calculated on June 1, 2018, may be used to fund the programs
25under subsection (b) of Section 1-56 of the Illinois Power
26Agency Act in the same proportion the programs are funded

 

 

SB2896- 604 -LRB102 17909 JWD 25989 b

1under that subsection (b). However, any amount identified
2under this subsection (k) to fund programs under subsection
3(b) of Section 1-56 of the Illinois Power Agency Act shall be
4reduced if it exceeds the funding shortfall. For purposes of
5this Section, "funding shortfall" means the difference between
6$200,000,000 and the amount appropriated by the General
7Assembly to the Illinois Power Agency Renewable Energy
8Resources Fund during the period that commences on the
9effective date of this amendatory act of the 99th General
10Assembly and ends on August 1, 2018.
11    If the amount of funds collected during the delivery year
12commencing June 1, 2018, exceeds the costs incurred during
13that delivery year, then up to half of this excess amount, as
14calculated on June 1, 2019, may be used to fund the programs
15under subsection (b) of Section 1-56 of the Illinois Power
16Agency Act in the same proportion the programs are funded
17under that subsection (b). However, any amount identified
18under this subsection (k) to fund programs under subsection
19(b) of Section 1-56 of the Illinois Power Agency Act shall be
20reduced if it exceeds the funding shortfall.
21    If the amount of funds collected during the delivery year
22commencing June 1, 2019, exceeds the costs incurred during
23that delivery year, then up to half of this excess amount, as
24calculated on June 1, 2020, may be used to fund the programs
25under subsection (b) of Section 1-56 of the Illinois Power
26Agency Act in the same proportion the programs are funded

 

 

SB2896- 605 -LRB102 17909 JWD 25989 b

1under that subsection (b). However, any amount identified
2under this subsection (k) to fund programs under subsection
3(b) of Section 1-56 of the Illinois Power Agency Act shall be
4reduced if it exceeds the funding shortfall.
5    The funding available under this subsection (k), if any,
6for the programs described under subsection (b) of Section
71-56 of the Illinois Power Agency Act shall not reduce the
8amount of funding for the programs described in subparagraph
9(O) of paragraph (1) of subsection (c) of Section 1-75 of the
10Illinois Power Agency Act. If funding is available under this
11subsection (k) for programs described under subsection (b) of
12Section 1-56 of the Illinois Power Agency Act, then the
13long-term renewable resources plan shall provide for the
14Agency to procure contracts in an amount that does not exceed
15the funding, and the contracts approved by the Commission
16shall be executed by the applicable utility or utilities.
17    (l) A utility that has terminated any contract executed
18under subsection (d-5) of Section 1-75 of the Illinois Power
19Agency Act shall be entitled to recover any remaining balance
20associated with the purchase of zero emission credits prior to
21such termination, and such utility shall also apply a credit
22to its retail customer bills in the event of any
23over-collection.
24        (m)(1) An electric utility that recovers its costs of
25    procuring zero emission credits from zero emission
26    facilities through a cents-per-kilowatthour charge under

 

 

SB2896- 606 -LRB102 17909 JWD 25989 b

1    to subsection (k) of this Section shall be subject to the
2    requirements of this subsection (m). Notwithstanding
3    anything to the contrary, such electric utility shall,
4    beginning on April 30, 2018, and each April 30 thereafter
5    until April 30, 2026, calculate whether any reduction must
6    be applied to such cents-per-kilowatthour charge that is
7    paid by retail customers of the electric utility that are
8    exempt from subsections (a) through (j) of Section 8-103B
9    of this Act under subsection (l) of Section 8-103B. Such
10    charge shall be reduced for such customers for the next
11    delivery year commencing on June 1 based on the amount
12    necessary, if any, to limit the annual estimated average
13    net increase for the prior calendar year due to the future
14    energy investment costs to no more than 1.3% of 5.98 cents
15    per kilowatt-hour, which is the average amount paid per
16    kilowatthour for electric service during the year ending
17    December 31, 2015 by Illinois industrial retail customers,
18    as reported to the Edison Electric Institute.
19        The calculations required by this subsection (m) shall
20    be made only once for each year, and no subsequent rate
21    impact determinations shall be made.
22        (2) For purposes of this Section, "future energy
23    investment costs" shall be calculated by subtracting the
24    cents-per-kilowatthour charge identified in subparagraph
25    (A) of this paragraph (2) from the sum of the
26    cents-per-kilowatthour charges identified in subparagraph

 

 

SB2896- 607 -LRB102 17909 JWD 25989 b

1    (B) of this paragraph (2):
2            (A) The cents-per-kilowatthour charge identified
3        in the electric utility's tariff placed into effect
4        under Section 8-103 of the Public Utilities Act that,
5        on December 1, 2016, was applicable to those retail
6        customers that are exempt from subsections (a) through
7        (j) of Section 8-103B of this Act under subsection (l)
8        of Section 8-103B.
9            (B) The sum of the following
10        cents-per-kilowatthour charges applicable to those
11        retail customers that are exempt from subsections (a)
12        through (j) of Section 8-103B of this Act under
13        subsection (l) of Section 8-103B, provided that if one
14        or more of the following charges has been in effect and
15        applied to such customers for more than one calendar
16        year, then each charge shall be equal to the average of
17        the charges applied over a period that commences with
18        the calendar year ending December 31, 2017 and ends
19        with the most recently completed calendar year prior
20        to the calculation required by this subsection (m):
21                (i) the cents-per-kilowatthour charge to
22            recover the costs incurred by the utility under
23            subsection (d-5) of Section 1-75 of the Illinois
24            Power Agency Act, adjusted for any reductions
25            required under this subsection (m); and
26                (ii) the cents-per-kilowatthour charge to

 

 

SB2896- 608 -LRB102 17909 JWD 25989 b

1            recover the costs incurred by the utility under
2            Section 16-107.6 of the Public Utilities Act.
3            If no charge was applied for a given calendar year
4        under item (i) or (ii) of this subparagraph (B), then
5        the value of the charge for that year shall be zero.
6        (3) If a reduction is required by the calculation
7    performed under this subsection (m), then the amount of
8    the reduction shall be multiplied by the number of years
9    reflected in the averages calculated under subparagraph
10    (B) of paragraph (2) of this subsection (m). Such
11    reduction shall be applied to the cents-per-kilowatthour
12    charge that is applicable to those retail customers that
13    are exempt from subsections (a) through (j) of Section
14    8-103B of this Act under subsection (l) of Section 8-103B
15    beginning with the next delivery year commencing after the
16    date of the calculation required by this subsection (m).
17        (4) The electric utility shall file a notice with the
18    Commission on May 1 of 2018 and each May 1 thereafter until
19    May 1, 2026 containing the reduction, if any, which must
20    be applied for the delivery year which begins in the year
21    of the filing. The notice shall contain the calculations
22    made pursuant to this Section. By October 1 of each year
23    beginning in 2018, each electric utility shall notify the
24    Commission if it appears, based on an estimate of the
25    calculation required in this subsection (m), that a
26    reduction will be required in the next year.

 

 

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1(Source: P.A. 99-906, eff. 6-1-17.)
 
2    (220 ILCS 5/16-108.5)
3    Sec. 16-108.5. Infrastructure investment and
4modernization; regulatory reform.
5    (a) (Blank).
6    (b) For purposes of this Section, "participating utility"
7means an electric utility or a combination utility serving
8more than 1,000,000 customers in Illinois that voluntarily
9elects and commits to undertake (i) the infrastructure
10investment program consisting of the commitments and
11obligations described in this subsection (b) and (ii) the
12customer assistance program consisting of the commitments and
13obligations described in subsection (b-10) of this Section,
14notwithstanding any other provisions of this Act and without
15obtaining any approvals from the Commission or any other
16agency other than as set forth in this Section, regardless of
17whether any such approval would otherwise be required.
18"Combination utility" means a utility that, as of January 1,
192011, provided electric service to at least one million retail
20customers in Illinois and gas service to at least 500,000
21retail customers in Illinois. A participating utility shall
22recover the expenditures made under the infrastructure
23investment program through the ratemaking process, including,
24but not limited to, the performance-based formula rate and
25process set forth in this Section.

 

 

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1    During the infrastructure investment program's peak
2program year, a participating utility other than a combination
3utility shall create 2,000 full-time equivalent jobs in
4Illinois, and a participating utility that is a combination
5utility shall create 450 full-time equivalent jobs in Illinois
6related to the provision of electric service. These jobs shall
7include direct jobs, contractor positions, and induced jobs,
8but shall not include any portion of a job commitment, not
9specifically contingent on an amendatory Act of the 97th
10General Assembly becoming law, between a participating utility
11and a labor union that existed on December 30, 2011 (the
12effective date of Public Act 97-646) and that has not yet been
13fulfilled. A portion of the full-time equivalent jobs created
14by each participating utility shall include incremental
15personnel hired subsequent to December 30, 2011 (the effective
16date of Public Act 97-646). For purposes of this Section,
17"peak program year" means the consecutive 12-month period with
18the highest number of full-time equivalent jobs that occurs
19between the beginning of investment year 2 and the end of
20investment year 4.
21    A participating utility shall meet one of the following
22commitments, as applicable:
23        (1) Beginning no later than 180 days after a
24    participating utility other than a combination utility
25    files a performance-based formula rate tariff pursuant to
26    subsection (c) of this Section, or, beginning no later

 

 

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1    than January 1, 2012 if such utility files such
2    performance-based formula rate tariff within 14 days of
3    October 26, 2011 (the effective date of Public Act
4    97-616), the participating utility shall, except as
5    provided in subsection (b-5):
6            (A) over a 5-year period, invest an estimated
7        $1,300,000,000 in electric system upgrades,
8        modernization projects, and training facilities,
9        including, but not limited to:
10                (i) distribution infrastructure improvements
11            totaling an estimated $1,000,000,000, including
12            underground residential distribution cable
13            injection and replacement and mainline cable
14            system refurbishment and replacement projects;
15                (ii) training facility construction or upgrade
16            projects totaling an estimated $10,000,000,
17            provided that, at a minimum, one such facility
18            shall be located in a municipality having a
19            population of more than 2 million residents and
20            one such facility shall be located in a
21            municipality having a population of more than
22            150,000 residents but fewer than 170,000
23            residents; any such new facility located in a
24            municipality having a population of more than 2
25            million residents must be designed for the purpose
26            of obtaining, and the owner of the facility shall

 

 

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1            apply for, certification under the United States
2            Green Building Council's Leadership in Energy
3            Efficiency Design Green Building Rating System;
4                (iii) wood pole inspection, treatment, and
5            replacement programs;
6                (iv) an estimated $200,000,000 for reducing
7            the susceptibility of certain circuits to
8            storm-related damage, including, but not limited
9            to, high winds, thunderstorms, and ice storms;
10            improvements may include, but are not limited to,
11            overhead to underground conversion and other
12            engineered outcomes for circuits; the
13            participating utility shall prioritize the
14            selection of circuits based on each circuit's
15            historical susceptibility to storm-related damage
16            and the ability to provide the greatest customer
17            benefit upon completion of the improvements; to be
18            eligible for improvement, the participating
19            utility's ability to maintain proper tree
20            clearances surrounding the overhead circuit must
21            not have been impeded by third parties; and
22            (B) over a 10-year period, invest an estimated
23        $1,300,000,000 to upgrade and modernize its
24        transmission and distribution infrastructure and in
25        Smart Grid electric system upgrades, including, but
26        not limited to:

 

 

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1                (i) additional smart meters;
2                (ii) distribution automation;
3                (iii) associated cyber secure data
4            communication network; and
5                (iv) substation micro-processor relay
6            upgrades.
7        (2) Beginning no later than 180 days after a
8    participating utility that is a combination utility files
9    a performance-based formula rate tariff pursuant to
10    subsection (c) of this Section, or, beginning no later
11    than January 1, 2012 if such utility files such
12    performance-based formula rate tariff within 14 days of
13    October 26, 2011 (the effective date of Public Act
14    97-616), the participating utility shall, except as
15    provided in subsection (b-5):
16            (A) over a 10-year period, invest an estimated
17        $265,000,000 in electric system upgrades,
18        modernization projects, and training facilities,
19        including, but not limited to:
20                (i) distribution infrastructure improvements
21            totaling an estimated $245,000,000, which may
22            include bulk supply substations, transformers,
23            reconductoring, and rebuilding overhead
24            distribution and sub-transmission lines,
25            underground residential distribution cable
26            injection and replacement and mainline cable

 

 

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1            system refurbishment and replacement projects;
2                (ii) training facility construction or upgrade
3            projects totaling an estimated $1,000,000; any
4            such new facility must be designed for the purpose
5            of obtaining, and the owner of the facility shall
6            apply for, certification under the United States
7            Green Building Council's Leadership in Energy
8            Efficiency Design Green Building Rating System;
9            and
10                (iii) wood pole inspection, treatment, and
11            replacement programs; and
12            (B) over a 10-year period, invest an estimated
13        $360,000,000 to upgrade and modernize its transmission
14        and distribution infrastructure and in Smart Grid
15        electric system upgrades, including, but not limited
16        to:
17                (i) additional smart meters;
18                (ii) distribution automation;
19                (iii) associated cyber secure data
20            communication network; and
21                (iv) substation micro-processor relay
22            upgrades.
23    For purposes of this Section, "Smart Grid electric system
24upgrades" shall have the meaning set forth in subsection (a)
25of Section 16-108.6 of this Act.
26    The investments in the infrastructure investment program

 

 

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1described in this subsection (b) shall be incremental to the
2participating utility's annual capital investment program, as
3defined by, for purposes of this subsection (b), the
4participating utility's average capital spend for calendar
5years 2008, 2009, and 2010 as reported in the applicable
6Federal Energy Regulatory Commission (FERC) Form 1; provided
7that where one or more utilities have merged, the average
8capital spend shall be determined using the aggregate of the
9merged utilities' capital spend reported in FERC Form 1 for
10the years 2008, 2009, and 2010. A participating utility may
11add reasonable construction ramp-up and ramp-down time to the
12investment periods specified in this subsection (b). For each
13such investment period, the ramp-up and ramp-down time shall
14not exceed a total of 6 months.
15    Within 60 days after filing a tariff under subsection (c)
16of this Section, a participating utility shall submit to the
17Commission its plan, including scope, schedule, and staffing,
18for satisfying its infrastructure investment program
19commitments pursuant to this subsection (b). The submitted
20plan shall include a schedule and staffing plan for the next
21calendar year. The plan shall also include a plan for the
22creation, operation, and administration of a Smart Grid test
23bed as described in subsection (c) of Section 16-108.8. The
24plan need not allocate the work equally over the respective
25periods, but should allocate material increments throughout
26such periods commensurate with the work to be undertaken. No

 

 

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1later than April 1 of each subsequent year, the utility shall
2submit to the Commission a report that includes any updates to
3the plan, a schedule for the next calendar year, the
4expenditures made for the prior calendar year and
5cumulatively, and the number of full-time equivalent jobs
6created for the prior calendar year and cumulatively. If the
7utility is materially deficient in satisfying a schedule or
8staffing plan, then the report must also include a corrective
9action plan to address the deficiency. The fact that the plan,
10implementation of the plan, or a schedule changes shall not
11imply the imprudence or unreasonableness of the infrastructure
12investment program, plan, or schedule. Further, no later than
1345 days following the last day of the first, second, and third
14quarters of each year of the plan, a participating utility
15shall submit to the Commission a verified quarterly report for
16the prior quarter that includes (i) the total number of
17full-time equivalent jobs created during the prior quarter,
18(ii) the total number of employees as of the last day of the
19prior quarter, (iii) the total number of full-time equivalent
20hours in each job classification or job title, (iv) the total
21number of incremental employees and contractors in support of
22the investments undertaken pursuant to this subsection (b) for
23the prior quarter, and (v) any other information that the
24Commission may require by rule.
25    With respect to the participating utility's peak job
26commitment, if, after considering the utility's corrective

 

 

SB2896- 617 -LRB102 17909 JWD 25989 b

1action plan and compliance thereunder, the Commission enters
2an order finding, after notice and hearing, that a
3participating utility did not satisfy its peak job commitment
4described in this subsection (b) for reasons that are
5reasonably within its control, then the Commission shall also
6determine, after consideration of the evidence, including, but
7not limited to, evidence submitted by the Department of
8Commerce and Economic Opportunity and the utility, the
9deficiency in the number of full-time equivalent jobs during
10the peak program year due to such failure. The Commission
11shall notify the Department of any proceeding that is
12initiated pursuant to this paragraph. For each full-time
13equivalent job deficiency during the peak program year that
14the Commission finds as set forth in this paragraph, the
15participating utility shall, within 30 days after the entry of
16the Commission's order, pay $6,000 to a fund for training
17grants administered under Section 605-800 of the Department of
18Commerce and Economic Opportunity Law, which shall not be a
19recoverable expense.
20    With respect to the participating utility's investment
21amount commitments, if, after considering the utility's
22corrective action plan and compliance thereunder, the
23Commission enters an order finding, after notice and hearing,
24that a participating utility is not satisfying its investment
25amount commitments described in this subsection (b), then the
26utility shall no longer be eligible to annually update the

 

 

SB2896- 618 -LRB102 17909 JWD 25989 b

1performance-based formula rate tariff pursuant to subsection
2(d) of this Section. In such event, the then current rates
3shall remain in effect until such time as new rates are set
4pursuant to Article IX of this Act, subject to retroactive
5adjustment, with interest, to reconcile rates charged with
6actual costs.
7    If the Commission finds that a participating utility is no
8longer eligible to update the performance-based formula rate
9tariff pursuant to subsection (d) of this Section, or the
10performance-based formula rate is otherwise terminated, then
11the participating utility's voluntary commitments and
12obligations under this subsection (b) shall immediately
13terminate, except for the utility's obligation to pay an
14amount already owed to the fund for training grants pursuant
15to a Commission order.
16    In meeting the obligations of this subsection (b), to the
17extent feasible and consistent with State and federal law, the
18investments under the infrastructure investment program should
19provide employment opportunities for all segments of the
20population and workforce, including minority-owned and
21female-owned business enterprises, and shall not, consistent
22with State and federal law, discriminate based on race or
23socioeconomic status.
24    (b-5) Nothing in this Section shall prohibit the
25Commission from investigating the prudence and reasonableness
26of the expenditures made under the infrastructure investment

 

 

SB2896- 619 -LRB102 17909 JWD 25989 b

1program during the annual review required by subsection (d) of
2this Section and shall, as part of such investigation,
3determine whether the utility's actual costs under the program
4are prudent and reasonable. The fact that a participating
5utility invests more than the minimum amounts specified in
6subsection (b) of this Section or its plan shall not imply
7imprudence or unreasonableness.
8    If the participating utility finds that it is implementing
9its plan for satisfying the infrastructure investment program
10commitments described in subsection (b) of this Section at a
11cost below the estimated amounts specified in subsection (b)
12of this Section, then the utility may file a petition with the
13Commission requesting that it be permitted to satisfy its
14commitments by spending less than the estimated amounts
15specified in subsection (b) of this Section. The Commission
16shall, after notice and hearing, enter its order approving, or
17approving as modified, or denying each such petition within
18150 days after the filing of the petition.
19    In no event, absent General Assembly approval, shall the
20capital investment costs incurred by a participating utility
21other than a combination utility in satisfying its
22infrastructure investment program commitments described in
23subsection (b) of this Section exceed $3,000,000,000 or, for a
24participating utility that is a combination utility,
25$720,000,000. If the participating utility's updated cost
26estimates for satisfying its infrastructure investment program

 

 

SB2896- 620 -LRB102 17909 JWD 25989 b

1commitments described in subsection (b) of this Section exceed
2the limitation imposed by this subsection (b-5), then it shall
3submit a report to the Commission that identifies the
4increased costs and explains the reason or reasons for the
5increased costs no later than the year in which the utility
6estimates it will exceed the limitation. The Commission shall
7review the report and shall, within 90 days after the
8participating utility files the report, report to the General
9Assembly its findings regarding the participating utility's
10report. If the General Assembly does not amend the limitation
11imposed by this subsection (b-5), then the utility may modify
12its plan so as not to exceed the limitation imposed by this
13subsection (b-5) and may propose corresponding changes to the
14metrics established pursuant to subparagraphs (5) through (8)
15of subsection (f) of this Section, and the Commission may
16modify the metrics and incremental savings goals established
17pursuant to subsection (f) of this Section accordingly.
18    (b-10) All participating utilities shall make
19contributions for an energy low-income and support program in
20accordance with this subsection. Beginning no later than 180
21days after a participating utility files a performance-based
22formula rate tariff pursuant to subsection (c) of this
23Section, or beginning no later than January 1, 2012 if such
24utility files such performance-based formula rate tariff
25within 14 days of December 30, 2011 (the effective date of
26Public Act 97-646), and without obtaining any approvals from

 

 

SB2896- 621 -LRB102 17909 JWD 25989 b

1the Commission or any other agency other than as set forth in
2this Section, regardless of whether any such approval would
3otherwise be required, a participating utility other than a
4combination utility shall pay $23,500,000 $10,000,000 per year
5for 5 years and a participating utility that is a combination
6utility shall pay $1,000,000 per year for 10 years to the
7energy low-income and support program, which is intended to
8fund customer assistance programs with the primary purpose
9being avoidance of imminent disconnection. Such programs may
10include:
11        (1) a residential hardship program that may partner
12    with community-based organizations, including senior
13    citizen organizations, and provides grants to low-income
14    residential customers, including low-income senior
15    citizens, who demonstrate a hardship;
16        (2) a program that provides grants and other bill
17    payment concessions to veterans with disabilities who
18    demonstrate a hardship and members of the armed services
19    or reserve forces of the United States or members of the
20    Illinois National Guard who are on active duty pursuant to
21    an executive order of the President of the United States,
22    an act of the Congress of the United States, or an order of
23    the Governor and who demonstrate a hardship;
24        (3) a budget assistance program that provides tools
25    and education to low-income senior citizens to assist them
26    with obtaining information regarding energy usage and

 

 

SB2896- 622 -LRB102 17909 JWD 25989 b

1    effective means of managing energy costs;
2        (4) a non-residential special hardship program that
3    provides grants to non-residential customers such as small
4    businesses and non-profit organizations that demonstrate a
5    hardship, including those providing services to senior
6    citizen and low-income customers; and
7        (5) a performance-based assistance program that
8    provides grants to encourage residential customers to make
9    on-time payments by matching a portion of the customer's
10    payments or providing credits towards arrearages.
11    The payments made by a participating utility pursuant to
12this subsection (b-10) shall not be a recoverable expense. A
13participating utility may elect to fund either new or existing
14customer assistance programs, including, but not limited to,
15those that are administered by the utility.
16    Programs that use funds that are provided by a
17participating utility to reduce utility bills may be
18implemented through tariffs that are filed with and reviewed
19by the Commission. If a utility elects to file tariffs with the
20Commission to implement all or a portion of the programs,
21those tariffs shall, regardless of the date actually filed, be
22deemed accepted and approved, and shall become effective on
23December 30, 2011 (the effective date of Public Act 97-646).
24The participating utilities whose customers benefit from the
25funds that are disbursed as contemplated in this Section shall
26file annual reports documenting the disbursement of those

 

 

SB2896- 623 -LRB102 17909 JWD 25989 b

1funds with the Commission. The Commission has the authority to
2audit disbursement of the funds to ensure they were disbursed
3consistently with this Section.
4    If the Commission finds that a participating utility is no
5longer eligible to update the performance-based formula rate
6tariff pursuant to subsection (d) of this Section, or the
7performance-based formula rate is otherwise terminated, then
8the participating utility's voluntary commitments and
9obligations under this subsection (b-10) shall immediately
10terminate.
11    (c) A participating utility may elect to recover its
12delivery services costs through a performance-based formula
13rate approved by the Commission, which shall specify the cost
14components that form the basis of the rate charged to
15customers with sufficient specificity to operate in a
16standardized manner and be updated annually with transparent
17information that reflects the utility's actual costs to be
18recovered during the applicable rate year, which is the period
19beginning with the first billing day of January and extending
20through the last billing day of the following December. In the
21event the utility recovers a portion of its costs through
22automatic adjustment clause tariffs on October 26, 2011 (the
23effective date of Public Act 97-616), the utility may elect to
24continue to recover these costs through such tariffs, but then
25these costs shall not be recovered through the
26performance-based formula rate. In the event the participating

 

 

SB2896- 624 -LRB102 17909 JWD 25989 b

1utility, prior to December 30, 2011 (the effective date of
2Public Act 97-646), filed electric delivery services tariffs
3with the Commission pursuant to Section 9-201 of this Act that
4are related to the recovery of its electric delivery services
5costs that are still pending on December 30, 2011 (the
6effective date of Public Act 97-646), the participating
7utility shall, at the time it files its performance-based
8formula rate tariff with the Commission, also file a notice of
9withdrawal with the Commission to withdraw the electric
10delivery services tariffs previously filed pursuant to Section
119-201 of this Act. Upon receipt of such notice, the Commission
12shall dismiss with prejudice any docket that had been
13initiated to investigate the electric delivery services
14tariffs filed pursuant to Section 9-201 of this Act, and such
15tariffs and the record related thereto shall not be the
16subject of any further hearing, investigation, or proceeding
17of any kind related to rates for electric delivery services.
18    The performance-based formula rate shall be implemented
19through a tariff filed with the Commission consistent with the
20provisions of this subsection (c) that shall be applicable to
21all delivery services customers. The Commission shall initiate
22and conduct an investigation of the tariff in a manner
23consistent with the provisions of this subsection (c) and the
24provisions of Article IX of this Act to the extent they do not
25conflict with this subsection (c). Except in the case where
26the Commission finds, after notice and hearing, that a

 

 

SB2896- 625 -LRB102 17909 JWD 25989 b

1participating utility is not satisfying its investment amount
2commitments under subsection (b) of this Section, the
3performance-based formula rate shall remain in effect at the
4discretion of the utility. The performance-based formula rate
5approved by the Commission shall do the following:
6        (1) Provide for the recovery of the utility's actual
7    costs of delivery services that are prudently incurred and
8    reasonable in amount consistent with Commission practice
9    and law. The sole fact that a cost differs from that
10    incurred in a prior calendar year or that an investment is
11    different from that made in a prior calendar year shall
12    not imply the imprudence or unreasonableness of that cost
13    or investment.
14        (2) Reflect the utility's actual year-end capital
15    structure for the applicable calendar year, excluding
16    goodwill, subject to a determination of prudence and
17    reasonableness consistent with Commission practice and
18    law. To enable the financing of the incremental capital
19    expenditures, including regulatory assets, for electric
20    utilities that serve less than 3,000,000 retail customers
21    but more than 500,000 retail customers in the State, a
22    participating electric utility's actual year-end capital
23    structure that includes a common equity ratio, excluding
24    goodwill, of up to and including 50% of the total capital
25    structure shall be deemed reasonable and used to set
26    rates.

 

 

SB2896- 626 -LRB102 17909 JWD 25989 b

1        (3) Include a cost of equity, which shall be
2    calculated as the sum of the following:
3            (A) the average for the applicable calendar year
4        of the monthly average yields of 30-year U.S. Treasury
5        bonds published by the Board of Governors of the
6        Federal Reserve System in its weekly H.15 Statistical
7        Release or successor publication; and
8            (B) 580 basis points.
9        At such time as the Board of Governors of the Federal
10    Reserve System ceases to include the monthly average
11    yields of 30-year U.S. Treasury bonds in its weekly H.15
12    Statistical Release or successor publication, the monthly
13    average yields of the U.S. Treasury bonds then having the
14    longest duration published by the Board of Governors in
15    its weekly H.15 Statistical Release or successor
16    publication shall instead be used for purposes of this
17    paragraph (3).
18        (4) Permit and set forth protocols, subject to a
19    determination of prudence and reasonableness consistent
20    with Commission practice and law, for the following:
21            (A) recovery of incentive compensation expense
22        that is based on the achievement of operational
23        metrics, including metrics related to budget controls,
24        outage duration and frequency, safety, customer
25        service, efficiency and productivity, and
26        environmental compliance. Incentive compensation

 

 

SB2896- 627 -LRB102 17909 JWD 25989 b

1        expense that is based on net income or an affiliate's
2        earnings per share shall not be recoverable under the
3        performance-based formula rate;
4            (B) recovery of pension and other post-employment
5        benefits expense, provided that such costs are
6        supported by an actuarial study;
7            (C) recovery of severance costs, provided that if
8        the amount is over $3,700,000 for a participating
9        utility that is a combination utility or $10,000,000
10        for a participating utility that serves more than 3
11        million retail customers, then the full amount shall
12        be amortized consistent with subparagraph (F) of this
13        paragraph (4);
14            (D) investment return at a rate equal to the
15        utility's weighted average cost of long-term debt, on
16        the pension assets as, and in the amount, reported in
17        Account 186 (or in such other Account or Accounts as
18        such asset may subsequently be recorded) of the
19        utility's most recently filed FERC Form 1, net of
20        deferred tax benefits;
21            (E) recovery of the expenses related to the
22        Commission proceeding under this subsection (c) to
23        approve this performance-based formula rate and
24        initial rates or to subsequent proceedings related to
25        the formula, provided that the recovery shall be
26        amortized over a 3-year period; recovery of expenses

 

 

SB2896- 628 -LRB102 17909 JWD 25989 b

1        related to the annual Commission proceedings under
2        subsection (d) of this Section to review the inputs to
3        the performance-based formula rate shall be expensed
4        and recovered through the performance-based formula
5        rate;
6            (F) amortization over a 5-year period of the full
7        amount of each charge or credit that exceeds
8        $3,700,000 for a participating utility that is a
9        combination utility or $10,000,000 for a participating
10        utility that serves more than 3 million retail
11        customers in the applicable calendar year and that
12        relates to a workforce reduction program's severance
13        costs, changes in accounting rules, changes in law,
14        compliance with any Commission-initiated audit, or a
15        single storm or other similar expense, provided that
16        any unamortized balance shall be reflected in rate
17        base. For purposes of this subparagraph (F), changes
18        in law includes any enactment, repeal, or amendment in
19        a law, ordinance, rule, regulation, interpretation,
20        permit, license, consent, or order, including those
21        relating to taxes, accounting, or to environmental
22        matters, or in the interpretation or application
23        thereof by any governmental authority occurring after
24        October 26, 2011 (the effective date of Public Act
25        97-616);
26            (G) recovery of existing regulatory assets over

 

 

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1        the periods previously authorized by the Commission;
2            (H) historical weather normalized billing
3        determinants; and
4            (I) allocation methods for common costs.
5        (5) Provide that if the participating utility's earned
6    rate of return on common equity related to the provision
7    of delivery services for the prior rate year (calculated
8    using costs and capital structure approved by the
9    Commission as provided in subparagraph (2) of this
10    subsection (c), consistent with this Section, in
11    accordance with Commission rules and orders, including,
12    but not limited to, adjustments for goodwill, and after
13    any Commission-ordered disallowances and taxes) is more
14    than 50 basis points higher than the rate of return on
15    common equity calculated pursuant to paragraph (3) of this
16    subsection (c) (after adjusting for any penalties to the
17    rate of return on common equity applied pursuant to the
18    performance metrics provision of subsection (f) of this
19    Section), then the participating utility shall apply a
20    credit through the performance-based formula rate that
21    reflects an amount equal to the value of that portion of
22    the earned rate of return on common equity that is more
23    than 50 basis points higher than the rate of return on
24    common equity calculated pursuant to paragraph (3) of this
25    subsection (c) (after adjusting for any penalties to the
26    rate of return on common equity applied pursuant to the

 

 

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1    performance metrics provision of subsection (f) of this
2    Section) for the prior rate year, adjusted for taxes. If
3    the participating utility's earned rate of return on
4    common equity related to the provision of delivery
5    services for the prior rate year (calculated using costs
6    and capital structure approved by the Commission as
7    provided in subparagraph (2) of this subsection (c),
8    consistent with this Section, in accordance with
9    Commission rules and orders, including, but not limited
10    to, adjustments for goodwill, and after any
11    Commission-ordered disallowances and taxes) is more than
12    50 basis points less than the return on common equity
13    calculated pursuant to paragraph (3) of this subsection
14    (c) (after adjusting for any penalties to the rate of
15    return on common equity applied pursuant to the
16    performance metrics provision of subsection (f) of this
17    Section), then the participating utility shall apply a
18    charge through the performance-based formula rate that
19    reflects an amount equal to the value of that portion of
20    the earned rate of return on common equity that is more
21    than 50 basis points less than the rate of return on common
22    equity calculated pursuant to paragraph (3) of this
23    subsection (c) (after adjusting for any penalties to the
24    rate of return on common equity applied pursuant to the
25    performance metrics provision of subsection (f) of this
26    Section) for the prior rate year, adjusted for taxes.

 

 

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1        (6) Provide for an annual reconciliation, as described
2    in subsection (d) of this Section, with interest, of the
3    revenue requirement reflected in rates for each calendar
4    year, beginning with the calendar year in which the
5    utility files its performance-based formula rate tariff
6    pursuant to subsection (c) of this Section, with what the
7    revenue requirement would have been had the actual cost
8    information for the applicable calendar year been
9    available at the filing date.
10    The utility shall file, together with its tariff, final
11data based on its most recently filed FERC Form 1, plus
12projected plant additions and correspondingly updated
13depreciation reserve and expense for the calendar year in
14which the tariff and data are filed, that shall populate the
15performance-based formula rate and set the initial delivery
16services rates under the formula. For purposes of this
17Section, "FERC Form 1" means the Annual Report of Major
18Electric Utilities, Licensees and Others that electric
19utilities are required to file with the Federal Energy
20Regulatory Commission under the Federal Power Act, Sections 3,
214(a), 304 and 209, modified as necessary to be consistent with
2283 Ill. Admin. Code Part 415 as of May 1, 2011. Nothing in this
23Section is intended to allow costs that are not otherwise
24recoverable to be recoverable by virtue of inclusion in FERC
25Form 1.
26    After the utility files its proposed performance-based

 

 

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1formula rate structure and protocols and initial rates, the
2Commission shall initiate a docket to review the filing. The
3Commission shall enter an order approving, or approving as
4modified, the performance-based formula rate, including the
5initial rates, as just and reasonable within 270 days after
6the date on which the tariff was filed, or, if the tariff is
7filed within 14 days after October 26, 2011 (the effective
8date of Public Act 97-616), then by May 31, 2012. Such review
9shall be based on the same evidentiary standards, including,
10but not limited to, those concerning the prudence and
11reasonableness of the costs incurred by the utility, the
12Commission applies in a hearing to review a filing for a
13general increase in rates under Article IX of this Act. The
14initial rates shall take effect within 30 days after the
15Commission's order approving the performance-based formula
16rate tariff.
17    Until such time as the Commission approves a different
18rate design and cost allocation pursuant to subsection (e) of
19this Section, rate design and cost allocation across customer
20classes shall be consistent with the Commission's most recent
21order regarding the participating utility's request for a
22general increase in its delivery services rates.
23    Subsequent changes to the performance-based formula rate
24structure or protocols shall be made as set forth in Section
259-201 of this Act, but nothing in this subsection (c) is
26intended to limit the Commission's authority under Article IX

 

 

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1and other provisions of this Act to initiate an investigation
2of a participating utility's performance-based formula rate
3tariff, provided that any such changes shall be consistent
4with paragraphs (1) through (6) of this subsection (c). Any
5change ordered by the Commission shall be made at the same time
6new rates take effect following the Commission's next order
7pursuant to subsection (d) of this Section, provided that the
8new rates take effect no less than 30 days after the date on
9which the Commission issues an order adopting the change.
10    A participating utility that files a tariff pursuant to
11this subsection (c) must submit a one-time $200,000 filing fee
12at the time the Chief Clerk of the Commission accepts the
13filing, which shall be a recoverable expense.
14    In the event the performance-based formula rate is
15terminated, the then current rates shall remain in effect
16until such time as new rates are set pursuant to Article IX of
17this Act, subject to retroactive rate adjustment, with
18interest, to reconcile rates charged with actual costs. At
19such time that the performance-based formula rate is
20terminated, the participating utility's voluntary commitments
21and obligations under subsection (b) of this Section shall
22immediately terminate, except for the utility's obligation to
23pay an amount already owed to the fund for training grants
24pursuant to a Commission order issued under subsection (b) of
25this Section.
26    (d) Subsequent to the Commission's issuance of an order

 

 

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1approving the utility's performance-based formula rate
2structure and protocols, and initial rates under subsection
3(c) of this Section, the utility shall file, on or before May 1
4of each year, with the Chief Clerk of the Commission its
5updated cost inputs to the performance-based formula rate for
6the applicable rate year and the corresponding new charges.
7Each such filing shall conform to the following requirements
8and include the following information:
9        (1) The inputs to the performance-based formula rate
10    for the applicable rate year shall be based on final
11    historical data reflected in the utility's most recently
12    filed annual FERC Form 1 plus projected plant additions
13    and correspondingly updated depreciation reserve and
14    expense for the calendar year in which the inputs are
15    filed. The filing shall also include a reconciliation of
16    the revenue requirement that was in effect for the prior
17    rate year (as set by the cost inputs for the prior rate
18    year) with the actual revenue requirement for the prior
19    rate year (determined using a year-end rate base) that
20    uses amounts reflected in the applicable FERC Form 1 that
21    reports the actual costs for the prior rate year. Any
22    over-collection or under-collection indicated by such
23    reconciliation shall be reflected as a credit against, or
24    recovered as an additional charge to, respectively, with
25    interest calculated at a rate equal to the utility's
26    weighted average cost of capital approved by the

 

 

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1    Commission for the prior rate year, the charges for the
2    applicable rate year. Provided, however, that the first
3    such reconciliation shall be for the calendar year in
4    which the utility files its performance-based formula rate
5    tariff pursuant to subsection (c) of this Section and
6    shall reconcile (i) the revenue requirement or
7    requirements established by the rate order or orders in
8    effect from time to time during such calendar year
9    (weighted, as applicable) with (ii) the revenue
10    requirement determined using a year-end rate base for that
11    calendar year calculated pursuant to the performance-based
12    formula rate using (A) actual costs for that year as
13    reflected in the applicable FERC Form 1, and (B) for the
14    first such reconciliation only, the cost of equity, which
15    shall be calculated as the sum of 590 basis points plus the
16    average for the applicable calendar year of the monthly
17    average yields of 30-year U.S. Treasury bonds published by
18    the Board of Governors of the Federal Reserve System in
19    its weekly H.15 Statistical Release or successor
20    publication. The first such reconciliation is not intended
21    to provide for the recovery of costs previously excluded
22    from rates based on a prior Commission order finding of
23    imprudence or unreasonableness. Each reconciliation shall
24    be certified by the participating utility in the same
25    manner that FERC Form 1 is certified. The filing shall
26    also include the charge or credit, if any, resulting from

 

 

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1    the calculation required by paragraph (6) of subsection
2    (c) of this Section.
3        Notwithstanding anything that may be to the contrary,
4    the intent of the reconciliation is to ultimately
5    reconcile the revenue requirement reflected in rates for
6    each calendar year, beginning with the calendar year in
7    which the utility files its performance-based formula rate
8    tariff pursuant to subsection (c) of this Section, with
9    what the revenue requirement determined using a year-end
10    rate base for the applicable calendar year would have been
11    had the actual cost information for the applicable
12    calendar year been available at the filing date.
13        (2) The new charges shall take effect beginning on the
14    first billing day of the following January billing period
15    and remain in effect through the last billing day of the
16    next December billing period regardless of whether the
17    Commission enters upon a hearing pursuant to this
18    subsection (d).
19        (3) The filing shall include relevant and necessary
20    data and documentation for the applicable rate year that
21    is consistent with the Commission's rules applicable to a
22    filing for a general increase in rates or any rules
23    adopted by the Commission to implement this Section.
24    Normalization adjustments shall not be required.
25    Notwithstanding any other provision of this Section or Act
26    or any rule or other requirement adopted by the

 

 

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1    Commission, a participating utility that is a combination
2    utility with more than one rate zone shall not be required
3    to file a separate set of such data and documentation for
4    each rate zone and may combine such data and documentation
5    into a single set of schedules.
6    Within 45 days after the utility files its annual update
7of cost inputs to the performance-based formula rate, the
8Commission shall have the authority, either upon complaint or
9its own initiative, but with reasonable notice, to enter upon
10a hearing concerning the prudence and reasonableness of the
11costs incurred by the utility to be recovered during the
12applicable rate year that are reflected in the inputs to the
13performance-based formula rate derived from the utility's FERC
14Form 1. During the course of the hearing, each objection shall
15be stated with particularity and evidence provided in support
16thereof, after which the utility shall have the opportunity to
17rebut the evidence. Discovery shall be allowed consistent with
18the Commission's Rules of Practice, which Rules shall be
19enforced by the Commission or the assigned administrative law
20judge. The Commission shall apply the same evidentiary
21standards, including, but not limited to, those concerning the
22prudence and reasonableness of the costs incurred by the
23utility, in the hearing as it would apply in a hearing to
24review a filing for a general increase in rates under Article
25IX of this Act. The Commission shall not, however, have the
26authority in a proceeding under this subsection (d) to

 

 

SB2896- 638 -LRB102 17909 JWD 25989 b

1consider or order any changes to the structure or protocols of
2the performance-based formula rate approved pursuant to
3subsection (c) of this Section. In a proceeding under this
4subsection (d), the Commission shall enter its order no later
5than the earlier of 240 days after the utility's filing of its
6annual update of cost inputs to the performance-based formula
7rate or December 31. The Commission's determinations of the
8prudence and reasonableness of the costs incurred for the
9applicable calendar year shall be final upon entry of the
10Commission's order and shall not be subject to reopening,
11reexamination, or collateral attack in any other Commission
12proceeding, case, docket, order, rule or regulation, provided,
13however, that nothing in this subsection (d) shall prohibit a
14party from petitioning the Commission to rehear or appeal to
15the courts the order pursuant to the provisions of this Act.
16    In the event the Commission does not, either upon
17complaint or its own initiative, enter upon a hearing within
1845 days after the utility files the annual update of cost
19inputs to its performance-based formula rate, then the costs
20incurred for the applicable calendar year shall be deemed
21prudent and reasonable, and the filed charges shall not be
22subject to reopening, reexamination, or collateral attack in
23any other proceeding, case, docket, order, rule, or
24regulation.
25    A participating utility's first filing of the updated cost
26inputs, and any Commission investigation of such inputs

 

 

SB2896- 639 -LRB102 17909 JWD 25989 b

1pursuant to this subsection (d) shall proceed notwithstanding
2the fact that the Commission's investigation under subsection
3(c) of this Section is still pending and notwithstanding any
4other law, order, rule, or Commission practice to the
5contrary.
6    (e) Nothing in subsections (c) or (d) of this Section
7shall prohibit the Commission from investigating, or a
8participating utility from filing, revenue-neutral tariff
9changes related to rate design of a performance-based formula
10rate that has been placed into effect for the utility.
11Following approval of a participating utility's
12performance-based formula rate tariff pursuant to subsection
13(c) of this Section, the utility shall make a filing with the
14Commission within one year after the effective date of the
15performance-based formula rate tariff that proposes changes to
16the tariff to incorporate the findings of any final rate
17design orders of the Commission applicable to the
18participating utility and entered subsequent to the
19Commission's approval of the tariff. The Commission shall,
20after notice and hearing, enter its order approving, or
21approving with modification, the proposed changes to the
22performance-based formula rate tariff within 240 days after
23the utility's filing. Following such approval, the utility
24shall make a filing with the Commission during each subsequent
253-year period that either proposes revenue-neutral tariff
26changes or re-files the existing tariffs without change, which

 

 

SB2896- 640 -LRB102 17909 JWD 25989 b

1shall present the Commission with an opportunity to suspend
2the tariffs and consider revenue-neutral tariff changes
3related to rate design.
4    (f) Within 30 days after the filing of a tariff pursuant to
5subsection (c) of this Section, each participating utility
6shall develop and file with the Commission multi-year metrics
7designed to achieve, ratably (i.e., in equal segments) over a
810-year period, improvement over baseline performance values
9as follows:
10        (1) Twenty percent improvement in the System Average
11    Interruption Frequency Index, using a baseline of the
12    average of the data from 2001 through 2010.
13        (2) Fifteen percent improvement in the system Customer
14    Average Interruption Duration Index, using a baseline of
15    the average of the data from 2001 through 2010.
16        (3) For a participating utility other than a
17    combination utility, 20% improvement in the System Average
18    Interruption Frequency Index for its Southern Region,
19    using a baseline of the average of the data from 2001
20    through 2010. For purposes of this paragraph (3), Southern
21    Region shall have the meaning set forth in the
22    participating utility's most recent report filed pursuant
23    to Section 16-125 of this Act.
24        (3.5) For a participating utility other than a
25    combination utility, 20% improvement in the System Average
26    Interruption Frequency Index for its Northeastern Region,

 

 

SB2896- 641 -LRB102 17909 JWD 25989 b

1    using a baseline of the average of the data from 2001
2    through 2010. For purposes of this paragraph (3.5),
3    Northeastern Region shall have the meaning set forth in
4    the participating utility's most recent report filed
5    pursuant to Section 16-125 of this Act.
6        (4) Seventy-five percent improvement in the total
7    number of customers who exceed the service reliability
8    targets as set forth in subparagraphs (A) through (C) of
9    paragraph (4) of subsection (b) of 83 Ill. Admin. Code
10    Part 411.140 as of May 1, 2011, using 2010 as the baseline
11    year.
12        (5) Reduction in issuance of estimated electric bills:
13    90% improvement for a participating utility other than a
14    combination utility, and 56% improvement for a
15    participating utility that is a combination utility, using
16    a baseline of the average number of estimated bills for
17    the years 2008 through 2010.
18        (6) Consumption on inactive meters: 90% improvement
19    for a participating utility other than a combination
20    utility, and 56% improvement for a participating utility
21    that is a combination utility, using a baseline of the
22    average unbilled kilowatthours for the years 2009 and
23    2010.
24        (7) Unaccounted for energy: 50% improvement for a
25    participating utility other than a combination utility
26    using a baseline of the non-technical line loss

 

 

SB2896- 642 -LRB102 17909 JWD 25989 b

1    unaccounted for energy kilowatthours for the year 2009.
2        (8) Uncollectible expense: reduce uncollectible
3    expense by at least $30,000,000 for a participating
4    utility other than a combination utility and by at least
5    $3,500,000 for a participating utility that is a
6    combination utility, using a baseline of the average
7    uncollectible expense for the years 2008 through 2010.
8        (9) Opportunities for minority-owned and female-owned
9    business enterprises: design a performance metric
10    regarding the creation of opportunities for minority-owned
11    and female-owned business enterprises consistent with
12    State and federal law using a base performance value of
13    the percentage of the participating utility's capital
14    expenditures that were paid to minority-owned and
15    female-owned business enterprises in 2010.
16    The definitions set forth in 83 Ill. Admin. Code Part
17411.20 as of May 1, 2011 shall be used for purposes of
18calculating performance under paragraphs (1) through (3.5) of
19this subsection (f), provided, however, that the participating
20utility may exclude up to 9 extreme weather event days from
21such calculation for each year, and provided further that the
22participating utility shall exclude 9 extreme weather event
23days when calculating each year of the baseline period to the
24extent that there are 9 such days in a given year of the
25baseline period. For purposes of this Section, an extreme
26weather event day is a 24-hour calendar day (beginning at

 

 

SB2896- 643 -LRB102 17909 JWD 25989 b

112:00 a.m. and ending at 11:59 p.m.) during which any weather
2event (e.g., storm, tornado) caused interruptions for 10,000
3or more of the participating utility's customers for 3 hours
4or more. If there are more than 9 extreme weather event days in
5a year, then the utility may choose no more than 9 extreme
6weather event days to exclude, provided that the same extreme
7weather event days are excluded from each of the calculations
8performed under paragraphs (1) through (3.5) of this
9subsection (f).
10    The metrics shall include incremental performance goals
11for each year of the 10-year period, which shall be designed to
12demonstrate that the utility is on track to achieve the
13performance goal in each category at the end of the 10-year
14period. The utility shall elect when the 10-year period shall
15commence for the metrics set forth in subparagraphs (1)
16through (4) and (9) of this subsection (f), provided that it
17begins no later than 14 months following the date on which the
18utility begins investing pursuant to subsection (b) of this
19Section, and when the 10-year period shall commence for the
20metrics set forth in subparagraphs (5) through (8) of this
21subsection (f), provided that it begins no later than 14
22months following the date on which the Commission enters its
23order approving the utility's Advanced Metering Infrastructure
24Deployment Plan pursuant to subsection (c) of Section 16-108.6
25of this Act.
26    The metrics and performance goals set forth in

 

 

SB2896- 644 -LRB102 17909 JWD 25989 b

1subparagraphs (5) through (8) of this subsection (f) are based
2on the assumptions that the participating utility may fully
3implement the technology described in subsection (b) of this
4Section, including utilizing the full functionality of such
5technology and that there is no requirement for personal
6on-site notification. If the utility is unable to meet the
7metrics and performance goals set forth in subparagraphs (5)
8through (8) of this subsection (f) for such reasons, and the
9Commission so finds after notice and hearing, then the utility
10shall be excused from compliance, but only to the limited
11extent achievement of the affected metrics and performance
12goals was hindered by the less than full implementation.
13    (f-5) The financial penalties applicable to the metrics
14described in subparagraphs (1) through (8) of subsection (f)
15of this Section, as applicable, shall be applied through an
16adjustment to the participating utility's return on equity of
17no more than a total of 30 basis points in each of the first 3
18years, of no more than a total of 34 basis points in each of
19the 3 years thereafter, and of no more than a total of 38 basis
20points in each of the 4 years thereafter, as follows:
21        (1) With respect to each of the incremental annual
22    performance goals established pursuant to paragraph (1) of
23    subsection (f) of this Section,
24            (A) for each year that a participating utility
25        other than a combination utility does not achieve the
26        annual goal, the participating utility's return on

 

 

SB2896- 645 -LRB102 17909 JWD 25989 b

1        equity shall be reduced as follows: during years 1
2        through 3, by 5 basis points; during years 4 through 6,
3        by 6 basis points; and during years 7 through 10, by 7
4        basis points; and
5            (B) for each year that a participating utility
6        that is a combination utility does not achieve the
7        annual goal, the participating utility's return on
8        equity shall be reduced as follows: during years 1
9        through 3, by 10 basis points; during years 4 through
10        6, by 12 basis points; and during years 7 through 10,
11        by 14 basis points.
12        (2) With respect to each of the incremental annual
13    performance goals established pursuant to paragraph (2) of
14    subsection (f) of this Section, for each year that the
15    participating utility does not achieve each such goal, the
16    participating utility's return on equity shall be reduced
17    as follows: during years 1 through 3, by 5 basis points;
18    during years 4 through 6, by 6 basis points; and during
19    years 7 through 10, by 7 basis points.
20        (3) With respect to each of the incremental annual
21    performance goals established pursuant to paragraphs (3)
22    and (3.5) of subsection (f) of this Section, for each year
23    that a participating utility other than a combination
24    utility does not achieve both such goals, the
25    participating utility's return on equity shall be reduced
26    as follows: during years 1 through 3, by 5 basis points;

 

 

SB2896- 646 -LRB102 17909 JWD 25989 b

1    during years 4 through 6, by 6 basis points; and during
2    years 7 through 10, by 7 basis points.
3        (4) With respect to each of the incremental annual
4    performance goals established pursuant to paragraph (4) of
5    subsection (f) of this Section, for each year that the
6    participating utility does not achieve each such goal, the
7    participating utility's return on equity shall be reduced
8    as follows: during years 1 through 3, by 5 basis points;
9    during years 4 through 6, by 6 basis points; and during
10    years 7 through 10, by 7 basis points.
11        (5) With respect to each of the incremental annual
12    performance goals established pursuant to subparagraph (5)
13    of subsection (f) of this Section, for each year that the
14    participating utility does not achieve at least 95% of
15    each such goal, the participating utility's return on
16    equity shall be reduced by 5 basis points for each such
17    unachieved goal.
18        (6) With respect to each of the incremental annual
19    performance goals established pursuant to paragraphs (6),
20    (7), and (8) of subsection (f) of this Section, as
21    applicable, which together measure non-operational
22    customer savings and benefits relating to the
23    implementation of the Advanced Metering Infrastructure
24    Deployment Plan, as defined in Section 16-108.6 of this
25    Act, the performance under each such goal shall be
26    calculated in terms of the percentage of the goal

 

 

SB2896- 647 -LRB102 17909 JWD 25989 b

1    achieved. The percentage of goal achieved for each of the
2    goals shall be aggregated, and an average percentage value
3    calculated, for each year of the 10-year period. If the
4    utility does not achieve an average percentage value in a
5    given year of at least 95%, the participating utility's
6    return on equity shall be reduced by 5 basis points.
7    The financial penalties shall be applied as described in
8this subsection (f-5) for the 12-month period in which the
9deficiency occurred through a separate tariff mechanism, which
10shall be filed by the utility together with its metrics. In the
11event the formula rate tariff established pursuant to
12subsection (c) of this Section terminates, the utility's
13obligations under subsection (f) of this Section and this
14subsection (f-5) shall also terminate, provided, however, that
15the tariff mechanism established pursuant to subsection (f) of
16this Section and this subsection (f-5) shall remain in effect
17until any penalties due and owing at the time of such
18termination are applied.
19    The Commission shall, after notice and hearing, enter an
20order within 120 days after the metrics are filed approving,
21or approving with modification, a participating utility's
22tariff or mechanism to satisfy the metrics set forth in
23subsection (f) of this Section. On June 1 of each subsequent
24year, each participating utility shall file a report with the
25Commission that includes, among other things, a description of
26how the participating utility performed under each metric and

 

 

SB2896- 648 -LRB102 17909 JWD 25989 b

1an identification of any extraordinary events that adversely
2impacted the utility's performance. Whenever a participating
3utility does not satisfy the metrics required pursuant to
4subsection (f) of this Section, the Commission shall, after
5notice and hearing, enter an order approving financial
6penalties in accordance with this subsection (f-5). The
7Commission-approved financial penalties shall be applied
8beginning with the next rate year. Nothing in this Section
9shall authorize the Commission to reduce or otherwise obviate
10the imposition of financial penalties for failing to achieve
11one or more of the metrics established pursuant to
12subparagraph (1) through (4) of subsection (f) of this
13Section.
14    (g) On or before July 31, 2014, each participating utility
15shall file a report with the Commission that sets forth the
16average annual increase in the average amount paid per
17kilowatthour for residential eligible retail customers,
18exclusive of the effects of energy efficiency programs,
19comparing the 12-month period ending May 31, 2012; the
2012-month period ending May 31, 2013; and the 12-month period
21ending May 31, 2014. For a participating utility that is a
22combination utility with more than one rate zone, the weighted
23average aggregate increase shall be provided. The report shall
24be filed together with a statement from an independent auditor
25attesting to the accuracy of the report. The cost of the
26independent auditor shall be borne by the participating

 

 

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1utility and shall not be a recoverable expense. "The average
2amount paid per kilowatthour" shall be based on the
3participating utility's tariffed rates actually in effect and
4shall not be calculated using any hypothetical rate or
5adjustments to actual charges (other than as specified for
6energy efficiency) as an input.
7    In the event that the average annual increase exceeds 2.5%
8as calculated pursuant to this subsection (g), then Sections
916-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act, other
10than this subsection, shall be inoperative as they relate to
11the utility and its service area as of the date of the report
12due to be submitted pursuant to this subsection and the
13utility shall no longer be eligible to annually update the
14performance-based formula rate tariff pursuant to subsection
15(d) of this Section. In such event, the then current rates
16shall remain in effect until such time as new rates are set
17pursuant to Article IX of this Act, subject to retroactive
18adjustment, with interest, to reconcile rates charged with
19actual costs, and the participating utility's voluntary
20commitments and obligations under subsection (b) of this
21Section shall immediately terminate, except for the utility's
22obligation to pay an amount already owed to the fund for
23training grants pursuant to a Commission order issued under
24subsection (b) of this Section.
25    In the event that the average annual increase is 2.5% or
26less as calculated pursuant to this subsection (g), then the

 

 

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1performance-based formula rate shall remain in effect as set
2forth in this Section.
3    For purposes of this Section, the amount per kilowatthour
4means the total amount paid for electric service expressed on
5a per kilowatthour basis, and the total amount paid for
6electric service includes without limitation amounts paid for
7supply, transmission, distribution, surcharges, and add-on
8taxes exclusive of any increases in taxes or new taxes imposed
9after October 26, 2011 (the effective date of Public Act
1097-616). For purposes of this Section, "eligible retail
11customers" shall have the meaning set forth in Section
1216-111.5 of this Act.
13    The fact that this Section becomes inoperative as set
14forth in this subsection shall not be construed to mean that
15the Commission may reexamine or otherwise reopen prudence or
16reasonableness determinations already made.
17    (h) By December 31, 2017, the Commission shall prepare and
18file with the General Assembly a report on the infrastructure
19program and the performance-based formula rate. The report
20shall include the change in the average amount per
21kilowatthour paid by residential customers between June 1,
222011 and May 31, 2017. If the change in the total average rate
23paid exceeds 2.5% compounded annually, the Commission shall
24include in the report an analysis that shows the portion of the
25change due to the delivery services component and the portion
26of the change due to the supply component of the rate. The

 

 

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1report shall include separate sections for each participating
2utility.
3    Sections 16-108.5, 16-108.6, 16-108.7, and 16-108.8 of
4this Act, other than this subsection (h), are inoperative
5after December 31, 2021 2022 for every participating utility,
6after which time a participating utility shall no longer be
7eligible to annually update the performance-based formula rate
8tariff pursuant to subsection (d) of this Section. At such
9time, the then current rates shall remain in effect until such
10time as new rates are set pursuant to Article IX of this Act,
11subject to retroactive adjustment, with interest, to reconcile
12rates charged with actual costs.
13    The fact that this Section becomes inoperative as set
14forth in this subsection shall not be construed to mean that
15the Commission may reexamine or otherwise reopen prudence or
16reasonableness determinations already made.
17    (i) While a participating utility may use, develop, and
18maintain broadband systems and the delivery of broadband
19services, voice-over-internet-protocol services,
20telecommunications services, and cable and video programming
21services for use in providing delivery services and Smart Grid
22functionality or application to its retail customers,
23including, but not limited to, the installation,
24implementation and maintenance of Smart Grid electric system
25upgrades as defined in Section 16-108.6 of this Act, a
26participating utility is prohibited from offering to its

 

 

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1retail customers broadband services or the delivery of
2broadband services, voice-over-internet-protocol services,
3telecommunications services, or cable or video programming
4services, unless they are part of a service directly related
5to delivery services or Smart Grid functionality or
6applications as defined in Section 16-108.6 of this Act, and
7from recovering the costs of such offerings from retail
8customers.
9    (j) Nothing in this Section is intended to legislatively
10overturn the opinion issued in Commonwealth Edison Co. v. Ill.
11Commerce Comm'n, Nos. 2-08-0959, 2-08-1037, 2-08-1137,
121-08-3008, 1-08-3030, 1-08-3054, 1-08-3313 cons. (Ill. App.
13Ct. 2d Dist. Sept. 30, 2010). Public Act 97-616 shall not be
14construed as creating a contract between the General Assembly
15and the participating utility, and shall not establish a
16property right in the participating utility.
17    (k) The changes made in subsections (c) and (d) of this
18Section by Public Act 98-15 are intended to be a restatement
19and clarification of existing law, and intended to give
20binding effect to the provisions of House Resolution 1157
21adopted by the House of Representatives of the 97th General
22Assembly and Senate Resolution 821 adopted by the Senate of
23the 97th General Assembly that are reflected in paragraph (3)
24of this subsection. In addition, Public Act 98-15 preempts and
25supersedes any final Commission orders entered in Docket Nos.
2611-0721, 12-0001, 12-0293, and 12-0321 to the extent

 

 

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1inconsistent with the amendatory language added to subsections
2(c) and (d).
3        (1) No earlier than 5 business days after May 22, 2013
4    (the effective date of Public Act 98-15), each
5    participating utility shall file any tariff changes
6    necessary to implement the amendatory language set forth
7    in subsections (c) and (d) of this Section by Public Act
8    98-15 and a revised revenue requirement under the
9    participating utility's performance-based formula rate.
10    The Commission shall enter a final order approving such
11    tariff changes and revised revenue requirement within 21
12    days after the participating utility's filing.
13        (2) Notwithstanding anything that may be to the
14    contrary, a participating utility may file a tariff to
15    retroactively recover its previously unrecovered actual
16    costs of delivery service that are no longer subject to
17    recovery through a reconciliation adjustment under
18    subsection (d) of this Section. This retroactive recovery
19    shall include any derivative adjustments resulting from
20    the changes to subsections (c) and (d) of this Section by
21    Public Act 98-15. Such tariff shall allow the utility to
22    assess, on current customer bills over a period of 12
23    monthly billing periods, a charge or credit related to
24    those unrecovered costs with interest at the utility's
25    weighted average cost of capital during the period in
26    which those costs were unrecovered. A participating

 

 

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1    utility may file a tariff that implements a retroactive
2    charge or credit as described in this paragraph for
3    amounts not otherwise included in the tariff filing
4    provided for in paragraph (1) of this subsection (k). The
5    Commission shall enter a final order approving such tariff
6    within 21 days after the participating utility's filing.
7        (3) The tariff changes described in paragraphs (1) and
8    (2) of this subsection (k) shall relate only to, and be
9    consistent with, the following provisions of Public Act
10    98-15: paragraph (2) of subsection (c) regarding year-end
11    capital structure, subparagraph (D) of paragraph (4) of
12    subsection (c) regarding pension assets, and subsection
13    (d) regarding the reconciliation components related to
14    year-end rate base and interest calculated at a rate equal
15    to the utility's weighted average cost of capital.
16        (4) Nothing in this subsection is intended to effect a
17    dismissal of or otherwise affect an appeal from any final
18    Commission orders entered in Docket Nos. 11-0721, 12-0001,
19    12-0293, and 12-0321 other than to the extent of the
20    amendatory language contained in subsections (c) and (d)
21    of this Section of Public Act 98-15.
22    (l) Each participating utility shall be deemed to have
23been in full compliance with all requirements of subsection
24(b) of this Section, subsection (c) of this Section, Section
2516-108.6 of this Act, and all Commission orders entered
26pursuant to Sections 16-108.5 and 16-108.6 of this Act, up to

 

 

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1and including May 22, 2013 (the effective date of Public Act
298-15). The Commission shall not undertake any investigation
3of such compliance and no penalty shall be assessed or adverse
4action taken against a participating utility for noncompliance
5with Commission orders associated with subsection (b) of this
6Section, subsection (c) of this Section, and Section 16-108.6
7of this Act prior to such date. Each participating utility
8other than a combination utility shall be permitted, without
9penalty, a period of 12 months after such effective date to
10take actions required to ensure its infrastructure investment
11program is in compliance with subsection (b) of this Section
12and with Section 16-108.6 of this Act. Provided further, the
13following subparagraphs shall apply to a participating utility
14other than a combination utility:
15        (A) if the Commission has initiated a proceeding
16    pursuant to subsection (e) of Section 16-108.6 of this Act
17    that is pending as of May 22, 2013 (the effective date of
18    Public Act 98-15), then the order entered in such
19    proceeding shall, after notice and hearing, accelerate the
20    commencement of the meter deployment schedule approved in
21    the final Commission order on rehearing entered in Docket
22    No. 12-0298;
23        (B) if the Commission has entered an order pursuant to
24    subsection (e) of Section 16-108.6 of this Act prior to
25    May 22, 2013 (the effective date of Public Act 98-15) that
26    does not accelerate the commencement of the meter

 

 

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1    deployment schedule approved in the final Commission order
2    on rehearing entered in Docket No. 12-0298, then the
3    utility shall file with the Commission, within 45 days
4    after such effective date, a plan for accelerating the
5    commencement of the utility's meter deployment schedule
6    approved in the final Commission order on rehearing
7    entered in Docket No. 12-0298; the Commission shall reopen
8    the proceeding in which it entered its order pursuant to
9    subsection (e) of Section 16-108.6 of this Act and shall,
10    after notice and hearing, enter an amendatory order that
11    approves or approves as modified such accelerated plan
12    within 90 days after the utility's filing; or
13        (C) if the Commission has not initiated a proceeding
14    pursuant to subsection (e) of Section 16-108.6 of this Act
15    prior to May 22, 2013 (the effective date of Public Act
16    98-15), then the utility shall file with the Commission,
17    within 45 days after such effective date, a plan for
18    accelerating the commencement of the utility's meter
19    deployment schedule approved in the final Commission order
20    on rehearing entered in Docket No. 12-0298 and the
21    Commission shall, after notice and hearing, approve or
22    approve as modified such plan within 90 days after the
23    utility's filing.
24    Any schedule for meter deployment approved by the
25Commission pursuant to this subsection (l) shall take into
26consideration procurement times for meters and other equipment

 

 

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1and operational issues. Nothing in Public Act 98-15 shall
2shorten or extend the end dates for the 5-year or 10-year
3periods set forth in subsection (b) of this Section or Section
416-108.6 of this Act. Nothing in this subsection is intended
5to address whether a participating utility has, or has not,
6satisfied any or all of the metrics and performance goals
7established pursuant to subsection (f) of this Section.
8    (m) The provisions of Public Act 98-15 are severable under
9Section 1.31 of the Statute on Statutes.
10(Source: P.A. 99-143, eff. 7-27-15; 99-642, eff. 7-28-16;
1199-906, eff. 6-1-17; 100-840, eff. 8-13-18.)
 
12    (220 ILCS 5/16-108.17 new)
13    Sec. 16-108.17. Distribution system planning.
14    (a) It is the policy of the State of Illinois to promote
15cost-effective distribution system planning that minimizes
16long-term costs for Illinois customers and supports the
17achievement of State carbon reduction and clean energy policy
18goals.
19    The General Assembly makes the following findings:
20        (1) Investment in infrastructure to support existing
21    and new distributed energy resources creates significant
22    economic development, environmental and public health
23    benefits in the State of Illinois.
24        (2) Distribution system planning is an important tool
25    for the Commission, electric utilities, and stakeholders

 

 

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1    to identify and support opportunities to maintain and
2    enhance the safety, security, reliability, and resilience
3    of the electricity grid, at fair and reasonable costs,
4    consistent with the State's clean energy policies.
5        (3) A distribution system planning process can
6    minimize distribution system costs to consumers while
7    advancing other Illinois clean energy policy goals by
8    supporting integration of distributed energy resources and
9    the procurement of non-wires alternatives to capital
10    investments.
11        (4) The planning process should maximize the sharing
12    of information, minimize overlap with existing filing
13    requirements to ensure robust stakeholder participation,
14    and recognize the responsibility of the utility to manage
15    the grid in a safe, reliable manner.
16    (b) Terms used in this Section shall have the same
17meanings as defined in Sections 16-102 and 16-107.6.
18    (c) An electric utility serving more than 100,000
19customers on January 1, 2009 shall prepare a distribution
20system investment plan that meets the requirements of this
21Section, and shall file said plan with the Commission no later
22than July 1, 2022.
23    (d) The distribution system investment plan shall be
24designed to:
25        (1) optimize utilization of electricity grid assets
26    and resources to minimize total system costs;

 

 

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1        (2) enable greater customer engagement, empowerment,
2    and options for energy services;
3        (3) move toward the creation of efficient,
4    cost-effective, accessible grid platforms for new
5    products, new services, and opportunities for adoption of
6    new distributed technologies;
7        (4) bring the benefits of grid modernization and the
8    deployment of distributed energy resources to all
9    communities, including economically disadvantaged
10    communities throughout Illinois;
11        (5) reduce grid congestion to facilitate availability
12    and development of distributed energy resources;
13        (6) provide for the analysis of the cost-effectiveness
14    of proposed system improvements;
15        (7) to the maximum extent possible, achieve or support
16    the achievement of reduction of greenhouse gas emissions;
17    and
18        (8) support existing Illinois policy goals promoting
19    the long-term growth of energy efficiency, demand response
20    and investments in renewable energy resources.
21    (e) The distribution investment system plan shall provide,
22at a minimum, the following information:
23        (1) Distribution system planning processes. A
24    description of the utility's distribution system planning
25    process, including:
26            (A) the overview of the process, including

 

 

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1        frequency and duration of the process, roles and
2        responsibilities of individuals and organizations
3        involved;
4            (B) a summary of the meetings with stakeholders
5        conducted prior to filing of the plan with the
6        Commission. Such meetings shall number at least two,
7        and should be held at times and in places to maximize,
8        to the extent possible, stakeholder and public
9        participation, including representatives of
10        environmental justice and low-income communities. The
11        summary shall include at a minimum, the participants
12        in meetings, the material covered in the meetings, and
13        a summary of questions asked and answers provided;
14            (C) a description of other internal planning
15        processes; and
16            (D) the description of any alignment with other
17        external planning processes, such as those required by
18        a regional transmission operator.
19        (2) Baseline distribution system data. A discussion
20    detailing the current operating conditions for the
21    distribution system, including a detailed description,
22    with supporting data, of system conditions, including
23    asset age and useful life, ratings, loadings and other
24    characteristics, as well as:
25            (A) distribution system annual line loss
26        percentage for the prior year (average of 12 monthly

 

 

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1        loss percentages);
2            (B) the maximum hourly coincident load (kw) for
3        the distribution system as measured at the interface
4        between the transmission and distribution system;
5            (C) total distribution substation capacity in kVA;
6            (D) total distribution transformer capacity in
7        kVA;
8            (E) total miles of overhead distribution wire;
9            (F) total miles of underground distribution wire;
10            (G) a list of all high-voltage and low-voltage
11        substations, or circuits, along with the following for
12        each substation: nameplate rating; firm capacity (or
13        maximum desired peak demand given contingency or
14        redundancies desired); maximum historic peak demand,
15        including specific days and hours of the days peak
16        load was experienced; average annual peak load growth
17        over the previous 5 years; forecast annual peak load
18        growth over the next 10 years; types of monitoring and
19        control capabilities, or planned additions of such; a
20        summary of existing system visibility and measurement
21        (feeder-level and time) interval and planned
22        visibility improvements; including information on
23        percentage of the system with each level of visibility
24        (such as maximum and minimum, daytime and nighttime,
25        monthly and daily reads, automated or manual); and
26        number of customer meters with advanced metering

 

 

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1        infrastructure/smart meters and those without, planned
2        advanced metering infrastructure investments, and
3        overview of functionality available; and
4            (H) discussion of how IEEE Std. 1547-2018 impacts
5        distribution system planning considerations
6        (including, but not limited to, opportunities and
7        constraints related to interoperability).
8        (3) Financial data:
9            (A) historical distribution system spending for
10        the past five years, in each of the following
11        categories: age-related replacements and asset
12        renewal; system expansion or upgrades for capacity;
13        and system expansion or upgrades for reliability and
14        power quality; and
15            (B) projected distribution system spending for ten
16        years into the future for the categories listed in
17        paragraph (1) of this subsection (e), itemizing any
18        non-traditional distribution projects, including:
19        planned distribution capital projects, cost drivers
20        for the project, and summary of anticipated changes in
21        historic spending; and any available cost-benefit
22        analysis in which the company evaluated a
23        non-traditional distribution system solution to either
24        a capital or operating upgrade or replacement.
25        (4) Distributed energy resources deployment.
26            (A) Discussion of how the impacts of the utility's

 

 

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1        energy efficiency programs are factored into load
2        forecasts at the substation or circuit level.
3            (B) Discussion of how other distributed energy
4        resources are factored into load forecasts and any
5        expected changes in load forecasting methodology.
6            (C) Total costs spent on distributed energy
7        resource generation installation in the prior year.
8            (D) Total charges to installers for distributed
9        energy resource generation installation in the prior
10        year.
11            (E) Total nameplate kw of distributed energy
12        resource generation systems that completed
13        interconnection to the system in the prior year.
14            (F) Total number of distributed energy resource
15        generation systems that completed interconnection to
16        the system in the prior year.
17            (G) Current distributed energy resource deployment
18        by type, size, and geographic dispersion.
19            (H) Information on geographic areas of existing or
20        forecast low, moderate and high distributed energy
21        resource penetration.
22            (I) List of geographic areas with existing or
23        forecast abnormal voltage or frequency issues that may
24        benefit from advanced inverter technology.
25        (5) Hosting capacity and interconnection requirements.
26    A hosting capacity analysis, made available to the public

 

 

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1    on the Illinois Commerce Commission's website with mapping
2    and GIS capability, with detail at the block level, that
3    includes a detailed and current analysis of how much
4    capacity is available on each substation circuit, and node
5    for integrating new distributed energy resources as
6    allowed by thermal ratings, protection system limits,
7    power quality standards, and safety standards. The
8    analysis must also include:
9            (A) circuit level maps and downloadable data sets
10        for public use;
11            (B) an assessment of the impact of utility
12        investments over the next five years; and
13            (C) a narrative describing how the hosting
14        capacity analysis advances customer-sited distributed
15        energy resources (including PV and electric storage
16        systems), and how the identification of
17        interconnection points on the distribution system will
18        support the continued development of distributed
19        generation resources.
20        (6) Scenario analysis and forecasting. The plan shall
21    include load forecasts over the next ten years at the
22    substation and circuit level using dynamic load
23    forecasting, utilizing multiple scenarios and
24    probabilistic planning. In particular, the plan shall
25    include the following:
26            (A) Definitions and a discussion of the

 

 

SB2896- 665 -LRB102 17909 JWD 25989 b

1    development of base-case, medium and high scenarios of
2    distributed energy resource deployment. Scenarios shall
3    reflect a reasonable mix of individual distributed energy
4    resource adoption and aggregated or bundled distributed
5    energy resource service types and shall include the
6    projected load forecast impacts of distributed energy
7    resource investments, including investments in energy
8    efficiency and demand response. The scenario analysis
9    shall include information on the methodologies used to
10    develop the low, medium and high scenarios, including the
11    distributed energy resource adoption rates, geographic
12    deployment assumptions, expected distributed energy
13    resource load profiles, and any other relevant assumptions
14    factored into the scenario discussion.
15            (B) A discussion of the processes and tools
16    necessary to accommodate the specified levels of
17    distributed energy resource adoption, including an
18    analysis of the sufficiency of existing tools. Provide a
19    discussion of the system impacts that may arise from
20    increased distributed energy resource adoption, potential
21    barriers to distributed energy resource integration, and
22    the system upgrades necessary to accommodate the
23    distributed energy resource at the listed penetration
24    levels.
25            (C) A discussion of how present and projected
26    reductions in the demand for energy may result from

 

 

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1    measures to improve energy efficiency in the industrial,
2    commercial, residential, and energy producing sectors of
3    the utility service territory.
4            (D) Information on anticipated impacts from FERC
5    Order 841, and a discussion of potential impacts from the
6    related FERC Docket No. RM18-9-000.
7            (E) Discussion of how the distribution system
8    planning is consistent with Commission orders regarding
9    the procurement of renewable resources as discussed in
10    Section 16-111.5, energy efficiency plans as discussed in
11    Section 8-103B, distributed generation rebates as
12    discussed in Section 16-107.6, and any other order
13    affecting the goals described in subsection (d) of this
14    Section.
15        (7) Non-wires alternatives analysis:
16            (A) Detailed discussion of all distribution system
17        projects in the coming ten years that are anticipated
18        to have a total cost of greater than $5,000,000. For
19        these projects, provide an analysis of the viability,
20        price, and long-term value of non-wires alternatives
21        (including increased local energy efficiency beyond
22        what will occur through system-wide programs), demand
23        response, distributed generation, and storage. Such
24        analysis must include consideration of the benefits of
25        distributed energy resources beyond meeting local
26        reliability needs (for example, avoided energy costs,

 

 

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1        avoided system capacity costs, avoided transmission
2        costs, and reduced exposure to future environmental
3        regulations).
4            (B) Identification of the project types that would
5        benefit from non-traditional solutions (for example,
6        load relief or reliability).
7            (C) Timelines needed to consider alternatives to
8        any project types that would benefit from
9        non-traditional solutions (including time for any
10        requests for proposals, response, review, contracting
11        and implementation).
12            (D) The cost threshold of any project type that
13        would need to be met to have a non-traditional
14        solution reviewed.
15        (8) Proposed distribution system investments. The plan
16    shall identify proposed investments, including the reason
17    for investment, projected costs, scope of work,
18    prioritization, sequencing of investments, and
19    explanations of how planned investments will support the
20    goals described in subsection (d) of this Section.
21        (9) Cybersecurity. The Plan shall include a high-level
22    summary of the utility's planning process for addressing
23    cyber and physical security risks. As part of the summary,
24    the qualifying retail utility is not required to report
25    any confidential, proprietary or other information in the
26    plan that could in any way compromise or decrease the

 

 

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1    utility's ability to prevent, mitigate, or recover from
2    potential system disruptions caused by physical events or
3    cyberattacks.
4    (f) Within 45 days after the filing of the distribution
5system investment plan, the Commission shall, with reasonable
6notice, open an investigation to consider whether the plan
7meets the objectives of and contains the information required
8by this Section. The Commission shall approve, approve with
9modifications, or reject the plan within 270 days from the
10date of filing. The Commission may approve the plan if it finds
11that the plan will achieve the goals described in subsection
12(d) of this Section and contains the information described in
13subsection (e) of this Section. Proceedings under this Section
14shall proceed according to the rules provided by Article IX of
15this Act. Information contained in the approved plan shall be
16considered part of the record in any Commission proceeding
17under Section 16-107.6 of this Act, provided that a final
18order has not been entered prior to the initial filing date
19referenced in subsection (c).
20    (g) Plan updates: the utility shall file an update to the
21plan on June 1, 2024, and every 24 months thereafter. This
22update shall describe the distribution system investments made
23during the prior plan period, the investments planned to be
24made in the following 24 months, and updates to the
25information required by subsection (e) of this Section. Within
2635 days after the utility files its report, the Commission

 

 

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1shall, upon its own initiative, open an investigation
2regarding the utility's plan update to ensure that the
3objectives described in subsection (d) of this Section are
4being achieved. If the Commission finds, after notice and
5hearing, that the utility's plan is materially deficient, the
6Commission shall issue an order requiring the utility to
7devise a corrective action plan, subject to Commission
8approval, to bring the plan into compliance with the goals of
9this Section. The Commission's order shall be entered within
10270 days after the utility files its annual report.
11    (h) The plan is designed to provide information to the
12Commission, stakeholders and the public concerning the
13distribution grid, and should provide a guide for future
14utility investment in the distribution grid. Therefore, the
15contents of a plan filed under this Section shall be available
16for evidence in Commission proceedings. However, omission from
17an approved plan shall not render any future utility
18expenditure to be considered unreasonable or imprudent. The
19Commission may, upon sufficient evidence, allow expenditures
20that were not part of any particular distribution plan.
 
21    (220 ILCS 5/16-108.18 new)
22    Sec. 16-108.18. Independent audit.
23    (a) Prior to the filing of the initial distribution system
24investment plan described in Section 16-108.17, an independent
25audit of the current state of the grid, and of the expenditures

 

 

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1made since 2011, will need to be made.
2    The General Assembly makes the following findings:
3        (1) Pursuant to the Energy Infrastructure
4    Modernization Act and subsequent clarifying legislation,
5    utilities in this State that serve over 100,000 customers
6    have made substantial investments to the grid and to
7    advanced metering infrastructure.
8        (2) It is necessary to understand the benefits to the
9    grid and to customers from these expenditures.
10        (3) Before a distribution system investment plan is
11    filed under Section 16-108.17, it is necessary to
12    understand the current condition of the distribution grid.
13        (4) It is also necessary for utilities, the
14    Commission, and stakeholders to have an independent set of
15    data to establish the baseline for future distribution
16    grid spending.
17        (5) The Commission has authority and jurisdiction for
18    the requirements of this Section under Section 8-102.
19    (b) Terms used in this Section shall have the same meaning
20as in Sections 16-102, 16-107.6 and 16-108.
21    (c) Within 30 days after the adoption of this Act, the
22Commission shall order an audit of each public utility serving
23over 100,000 customers in the State examining the following:
24        (1) An assessment of the distribution grid, as
25    described in paragraph (3) of subsection (a), with the
26    exception that the data referenced in paragraph (3) of

 

 

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1    subsection (a) shall be for the preceding 10 years. The
2    Commission shall have the authority to require additional
3    items which it deems necessary.
4        (2) An analysis of the utility's capital projects in
5    the preceding ten years, with respect to the value of such
6    spending for grid optimization and customer value, such
7    projects to include advanced meter installation and
8    related programs.
9        (3) An analysis of the utility management of the
10    distribution grid, including initiatives to optimize
11    reliability and efficiency of the grid, other than through
12    capital spending.
13        (4) An analysis of the utility's existing policies,
14    including their performance in implementation, concerning
15    the planning and execution of grid projects.
16        (5) Creation of a data baseline to inform the
17    beginning of the distribution planning process described
18    in Section 16-108.17.
19        (6) Identification of any deficiencies in data which
20    may impact the distribution planning process.
21    (d) The audit described above should be reflected in a
22report delivered to the Commission, describing the information
23specified above, and any recommendations for the distribution
24planning process. Such report is to be delivered no later than
25180 days after the Commission Order. It is understood that any
26public report may not contain items that are confidential or

 

 

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1proprietary.
2    (e) The costs of this audit shall be borne by the
3respective utilities, such costs not to exceed $250,000 for
4each utility. Such costs are not deemed to be a recoverable
5expense.
6    (f) The Commission shall have the authority to retain the
7services of the auditor to assist with the distribution
8planning process, as well as in docketed proceedings. Such
9expenses for these activities are to be compensated by the
10Commission.
 
11    (220 ILCS 5/16-108.19 new)
12    Sec. 16-108.19. Division of Integrated Distribution
13Planning.
14    (a) The Commission shall establish the Division of
15Integrated Distribution Planning within the Bureau of Public
16Utilities. The Division shall be staffed by no less than 13
17professionals, including 4 engineers, 1 rate analyst, 2
18accountants, 1 policy analyst, 1 utility research and analysis
19analyst, 1 cybersecurity analyst, 1 information technology
20specialist, and 2 lawyers to review and evaluate distribution
21system investment plans, updates to distribution system
22investment plans, audits, and other duties as assigned by the
23Chief of the Public Utilities Bureau.
24    (b) The Division of Integrated Distribution Planning shall
25be established by July 1, 2022.
 

 

 

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1    (220 ILCS 5/16-108.20 new)
2    Sec. 16-108.20. Performance incentive mechanisms.
3    (a) Findings and Purpose. The General Assembly finds:
4        (1) That improving the alignment of utility customer
5    and company interests is critical to ensuring the expected
6    rapid growth of distributed energy resources, electric
7    vehicles, and other new technologies that substantially
8    change the makeup of the grid is done in efficiently and
9    transparently.
10        (2) There is urgency around addressing increasing
11    threats from climate change and assisting communities that
12    have borne disproportionate impacts from climate change,
13    including air pollution, greenhouse gas emissions, and
14    energy burdens. Addressing this problem requires changes
15    to the business model under which utilities in Illinois
16    have traditionally functioned.
17        (3) Providing targeted incentives to support change
18    through a new performance-based structure to enhance
19    ratemaking is intended to enable alignment of utility,
20    customer, community, and environmental goals.
21        (4) Though Illinois has taken some measures to move
22    utilities to performance-based ratemaking through the
23    establishment of performance incentives and a
24    performance-based formula rate under the Energy
25    Infrastructure Modernization Act, these measures have not

 

 

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1    been transformative in urgently moving electric utilities
2    toward the State's ambitious clean energy policy goals:
3    protecting a healthy environment and climate, improving
4    public health, and creating quality jobs and statewide
5    economic opportunities, including wealth building,
6    especially in economically disadvantaged communities and
7    communities of color.
8        (5) These measures were not developed through a
9    process which sought to understand first what needed to be
10    measured and then worked to ensure that the measures and
11    penalties associated with the measures would help drive
12    the sought-after behavior by the utilities.
13        (6) These measures have resulted in excess utility
14    spending and profits without meaningful improvements in
15    customer experience, rates, or equity.
16        (7) Discussions of performance incentive mechanisms
17    must always take into account the affordability of
18    customer rates and bills.
19        (8) The General Assembly therefore directs the
20    Illinois Commerce Commission to develop performance
21    incentive mechanisms for electric utilities with more than
22    300,000 customers to further specified goals and
23    objectives.
24    (b) Definitions. As used in this Section:
25    "Commission" means the Illinois Commerce Commission.
26    "Demand response" means measures that decrease peak

 

 

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1electricity demand or shift demand from peak to off-peak
2periods.
3    "Distributed energy resources" or "DER" means a wide range
4of technologies that are located on the customer side of the
5customer's electric meter and can provide value to the
6distribution system, including, but not limited to,
7distributed generation, energy storage, electric vehicles, and
8demand response technologies.
9    "Economically disadvantaged communities" means areas of
10one or more census tracts where average household income does
11not exceed 80% of area median income.
12    "Environmental justice communities" means the definition
13of that term as used and as may be updated in the Long-Term
14Renewable Resources Procurement Plan by the Illinois Power
15Agency and its Program Administrator in the Illinois Solar for
16All Program.
17    "Performance incentive mechanism" or "PIM" means an
18instrument by which utility performance is incentivized, which
19could include a monetary reward or penalty.
20    "Performance Metric" means a manner of measurement for a
21particular utility activity.
22        (c) Objectives. Performance incentive mechanisms
23should be designed to accomplish the following objectives:
24        (1) maintain and improve service reliability and
25    safety;
26        (2) enable least cost interconnection to enable

 

 

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1    decarbonize utility systems at a pace that meets or
2    exceeds the State's climate goals;
3        (3) choose the most cost-effective expenditures for
4    assets or services, whether self-supplied by the utility
5    or through third-party contracting, to deliver
6    high-quality service to customers at least cost and
7    eliminate utility preference for rate base investments
8    that increase profits;
9        (4) maintain the affordability of electric delivery
10    and supply services;
11        (5) achieve high-quality customer service, affordable
12    and a variety of rate options, including demand response,
13    time of use rates for delivery and supply, real-time
14    pricing rates for supply, comprehensive and predictable
15    net metering, utilize the benefits of grid modernization
16    and clean energy for ratepayers;
17        (6) address the particular burdens faced by consumers
18    in environmental justice and economically disadvantaged
19    communities, including shareholder, consumer, and publicly
20    funded bill payment assistance and credit and collection
21    policies; and
22        (7) maintain and grow a diverse workforce, diverse
23    supplier procurement base and, for relevant programs,
24    diverse approved-vendor pools.
25    (d) Performance incentive mechanisms.
26        (1) The Commission may establish performance incentive

 

 

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1    mechanisms in order to better tie utility revenues to
2    performance and customer benefits, accelerate progress on
3    Illinois energy and other goals, and hold utilities
4    publicly accountable. The Commission shall develop
5    metrics, which are observable and measurable indicators of
6    system or utility performance, in order to create
7    performance incentive mechanisms independent of its rate
8    making function. Specifically, the Commission may
9    establish tracking metrics, to be used for measuring and
10    reporting utility performance.
11            (A) Tracking metrics, if adopted, shall entail a
12        description of the metric, a calculation method, a
13        data collection method, and measure achievement of at
14        least one of the outcomes set forth in paragraph (2) of
15        this subsection.
16            (B) The Commission may adopt tracking metrics that
17        are supported by stakeholder consensus.
18            (C) The Commission shall first identify the
19        tracking metrics that are already in place and then
20        make a determination of their effectiveness with
21        respect to the program goals described in this
22        section.
23            (D) The tracking metric shall include a
24        description of the metric, a calculation method, a
25        data collection method, annual binding performance
26        targets, and may include monetary incentives (rewards

 

 

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1        or penalties or both, depending on the metric) for
2        utilities' achievement of or failure to achieve their
3        performance targets. For metrics where progressive
4        improvement is desirable, performance targets shall
5        increase annually and shall require utilities to
6        perform beyond business as usual, as determined by
7        baseline tracking data and high-confidence
8        projections. Increases to a target shall be considered
9        in light of other metrics, cost-effectiveness, and
10        other factors the Commission deems appropriate.
11            (E) Metrics shall include one year of tracking
12        data collected in a consistent manner, verifiable by
13        an independent evaluator in order to establish a
14        baseline and measure outcomes and actual results
15        against projections where possible.
16        (2) Outcomes of Metrics. The Commission may approve
17    tracking and performance metrics that encourage
18    cost-effective, equitable utility achievement of the
19    following outcomes:
20            (A) Affordability. Achieve affordable customer
21        energy costs and utility bills, with particular
22        emphasis on keeping lower-income households' bills
23        within a manageable portion of their income.
24            (B) Pollution Reduction. Minimize emissions of
25        greenhouse gases and pollutants that harm human
26        health, particularly in environmental justice and

 

 

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1        economically disadvantaged communities, through
2        minimizing total emissions, including by accelerating
3        electrification of transportation, buildings and
4        industries where such electrification results in net
5        reductions, across all fuels and over the life of
6        electrification measures, of greenhouse gases and
7        other pollutants, taking into consideration the fuel
8        mix used to produce electricity at the relevant hour
9        and the effect of accelerating electrification on
10        electricity supply prices and peak demand.
11            (C) Flexibility. Enhance the grid's ability to
12        incorporate increased deployment of nondispatchable
13        resources; improve the predictability and
14        cost-effectiveness of interconnection processes;
15        improve load balancing; and offer a variety of rate
16        plans to suit consumer consumption patterns to lower
17        consumer bills for electricity delivery and supply.
18            (D) Reliability. Meet high standards of overall
19        and locational reliability, including the standards
20        and processes described in Section 16-125 of this Act.
21            (E) Customer Experience. Cost-effectively deliver
22        customer service quality, customer engagement, and
23        customer access to utility system information
24        according to consumer demand and interest.
25            (F) Equity. Maximize and prioritize the low-income
26        assistance and allocation of grid planning benefits to

 

 

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1        environmental justice and economically disadvantaged
2        customers and communities. Sustain a diverse
3        workforce, supplier procurement base and, for relevant
4        programs, approved vendor pools.
5            (G) Cost-effectiveness. Ensure rates reflect cost
6        savings attributable to grid modernization and
7        integration of distributed energy resources and
8        identify circumstances that allow the utility to
9        reduce expenditures by deferring or forgoing
10        traditional grid investments that would otherwise be
11        required and increase customer charges.
12        It is the intent of the General Assembly that these
13    outcomes shall guide the development of metrics even as
14    the grid, along with its associated technologies and
15    policies, evolves. It is also the intent of the General
16    Assembly that the limitation of total costs to customers
17    and the promotion of ethical and transparent practices by
18    utilities, as well as the role that flexible load and
19    distributed energy resources can play in advancing the
20    outcomes, are objectives in the establishment of metrics.
21        (3) Performance incentives. The Commission shall
22    determine whether and to what extent each performance
23    metric shall offer a reward, penalty, or both to a
24    utility. For metrics where a reward is offered, and that
25    reward is a cash payment, the reward shall be calculated
26    as a percentage of net benefits from the outcome, net of

 

 

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1    costs to customers.
2            (A) The Commission shall develop a methodology to
3        calculate net benefits that includes the cost to
4        consumers, societal costs, and benefits. In
5        determining the appropriate level of a reward or
6        penalty, the Commission shall consider: the extent to
7        which the result is included in the utility's
8        obligation to serve, whether the amount is likely to
9        encourage the utility to achieve the performance
10        target in the least cost manner; the value of benefits
11        to customers, the grid, and the environment from
12        achievement of the performance target, including in
13        particular benefits to environmental justice and
14        economically disadvantaged communities; the effect on
15        customer bill affordability; the effect on the
16        utility's revenue requirement; the effect on whether
17        the utility's earnings remain just and reasonable and
18        not in excess of a reasonable return on equity; and
19        other such factors that the Commission deems
20        appropriate.
21            (B) The consideration of these factors shall
22        result in an incentive level that ensures benefits
23        exceed costs for customers. In determining the
24        specific rewards or penalties, the Commission shall
25        give weight to the following goals: (i) affordability,
26        (ii) cost-effectiveness, (iii) pollution reduction,

 

 

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1        (iv) rate flexibility, (v) customer experience, (vi)
2        reliability, and (vii) equity.
3            (C) It is the intent of the General Assembly that
4        over time the utility's return on equity remains just
5        and reasonable and that the return on equity embedded
6        in base rates and surcharges shall be progressively
7        reduced while the opportunity to grow earnings as a
8        result of achieving performance targets shall be
9        progressively increased as the Commission establishes
10        new performance metrics.
11    (e) Initial Metrics.
12        (1) The Commission shall initiate a 6-month workshop
13    process no later than March 1, 2022 for the purpose of
14    informing the enactment of metrics. The workshop shall be
15    facilitated by Staff of the Illinois Commerce Commission
16    and shall be organized and facilitated in a manner that
17    encourages representation from diverse stakeholders,
18    ensuring equitable opportunities for participation,
19    without requiring formal intervention or representation by
20    an attorney. Following the workshop, the Commission shall
21    establish initial tracking and performance metrics in a
22    docketed proceeding that shall be filed by the electric
23    utility by September 2, 2022. The proceeding shall
24    conclude, and the Commission shall issue an order in the
25    matter, no later than December 1, 2023.
26        (2) The Commission shall approve metrics consistent

 

 

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1    with this Section, and it shall establish calculations and
2    goals for the tracking metrics and calculations, targets,
3    and incentives for the tracking metrics set forth in this
4    Section. Initial Performance Metrics shall include at a
5    minimum, but not limited to, the following: (A) system
6    Average Interruption Frequency Index; (B) customer Average
7    Interruption Duration Index; and (C) peak load reductions
8    enabled by demand response programs.
9    (f) Future Metrics. The Commission shall establish new
10tracking and performance metrics in future Annual Performance
11Evaluation proceedings to further measure achievement of the
12outcomes, goals, and requirements of this Section. The
13Commission shall also evaluate metrics that were established
14in prior Annual Performance Evaluation proceedings under the
15procedures set forth in subsection (g) to determine if
16adjustments are required to improve the likelihood of the
17outcomes described in paragraph (2) of subsection (d). For
18metrics that were established in prior Annual Performance
19Evaluation proceedings and that the Commission elects to
20continue, the design of these metrics, including the goals of
21tracking metrics and the targets and incentive levels and
22structures of performance metrics, may be adjusted pursuant to
23the requirements in this Section. The Commission may also
24phase out tracking and performance metrics that were
25established in prior Annual Performance Evaluation proceedings
26if these metrics no longer meet the requirements of this

 

 

SB2896- 684 -LRB102 17909 JWD 25989 b

1Section or if they are rendered obsolete by the changing needs
2and technology of an evolving grid. Additionally, performance
3metrics that no longer require an incentive to create improved
4utility performance may become tracking metrics. In service of
5the outcomes set forth in paragraph (2) of subsection (d), it
6is the intent of the General Assembly that the Commission in
7future Annual Performance Evaluation proceedings establish the
8tracking metrics and performance metrics set forth in
9subparagraph (A) and subparagraph (B) of paragraph (3) of
10subsection (d) of this Section when these metrics would be
11compliant with the requirements set forth in this Section.
12    (g) Annual Performance Evaluation. On June 1 of each year
13following the order establishing the performance metrics, the
14Commission shall open an Annual Performance Evaluation
15proceeding to evaluate the utilities' performance on their
16metric targets during the delivery year just completed and
17accordingly determine rewards or penalties or both to be
18reflected in rates in the following calendar year.
19        (1) Utility Reporting. On April 1 of each year, prior
20    to the Annual Performance Evaluation proceeding, each
21    participating utility shall file a Performance Evaluation
22    Report with the Commission that includes a description of
23    and all data supporting how the participating utility
24    performed under each tracking and performance metric and
25    an identification of any extraordinary events that
26    adversely impacted the utility's performance. The

 

 

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1    Performance Evaluation Report shall be verified by an
2    independent evaluator as set out in paragraph (3) of this
3    subsection (g) and shall include both a report made to the
4    Commission and a short, public-facing scorecard that makes
5    this information publicly accessible and easily
6    understandable. The Commission shall post each scorecard
7    upon receipt on the Commission's web page in an easily
8    accessible location. The format of the report and the
9    scorecard shall be developed by the Commission, be
10    consistent across utilities, and shall include, but not be
11    limited to:
12            (A) a list of metrics to which the utility is
13        subject;
14            (B) the previous delivery year's calculation
15        methods and performance on metrics if applicable;
16            (C) the current delivery year's calculation
17        methods and a detailed description of the effect of
18        any differences;
19            (D) the current-year goals for tracking metrics
20        and current-year targets for performance metrics;
21            (E) the current year's performance on metrics
22        targets; and
23            (F) a summary of the investments and programs
24        undertaken in order to achieve those metrics targets;
25        and within 30 days after the Commission's Order in the
26        utility's Annual Performance Evaluation and Adjustment

 

 

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1        filing, the utility shall update the public scorecard
2        with any changes required by the Commission and the
3        revised scorecard shall be posted on the Commission's
4        website.
5        (2) Public Workshops. Upon the filing of each
6    Performance Evaluation Report, but no later than May 7
7    each year, the Commission shall initiate a four-month
8    workshop process. The workshops shall be facilitated by
9    Staff of the Illinois Commerce Commission and shall be
10    organized and facilitated in a manner that encourages
11    representation from diverse stakeholders, ensuring
12    equitable opportunities for participation, without
13    requiring formal intervention or representation by an
14    attorney. During these workshops, each electric utility
15    shall publicly present its performance on tracking and
16    performance metrics following the requirements set forth
17    in paragraph (1) of this subsection (g). The electric
18    utility shall also explain how it has holistically
19    considered the plans, programs, tariffs and policies in
20    order to achieve its metric targets. Members of the public
21    shall have the opportunity to request additional relevant
22    information and submit comment and feedback to the
23    Commission. A summary of that feedback shall be provided
24    in an exhibit submitted by Staff of the Illinois Commerce
25    Commission in the Annual Performance Evaluation.
26        (3) Independent Evaluation. The Commission shall

 

 

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1    provide for an annual independent evaluation of the
2    electric utility's performance on metrics, and the cost of
3    the independent evaluation shall be treated as a cost of
4    service. The independent evaluator shall review the
5    utility's assumptions, baselines, targets, calculation
6    methodologies, and other relevant information, especially
7    ensuring that the utility's data for establishing
8    baselines matches actual performance, and shall provide a
9    Report to the Commission no later than May 1 describing
10    the results. The independent evaluator shall present this
11    Report as evidence as a nonparty participant in each
12    Annual Performance Evaluation. The independent evaluator
13    shall be hired by the Commission through a competitive
14    bidding process. The Commission shall post the Report on
15    its website no fewer than 5 business days before the first
16    Public Workshop described in subsection (2) of this
17    subsection (g), and shall consider the Report of the
18    independent evaluator in determining the utility's
19    achievement of performance targets. Discrepancies between
20    the utility's assumptions, baselines, targets, or
21    calculations and those of the independent evaluator shall
22    be closely scrutinized by the Commission and may be the
23    bases for rejecting the utility's conclusion about its
24    performance. If the Commission finds that the utility's
25    reported data for any metric or metrics significantly
26    deviates from the data reported by the independent

 

 

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1    evaluator, then the Commission shall order the utility to
2    revise its data collection and calculation process within
3    60 days, with specifications where appropriate, and no
4    performance incentive shall be allowed.
5        (4) Performance Adjustment. The Commission shall,
6    after notice and hearing in the Annual Performance
7    Evaluation proceeding, enter an order approving the
8    utility's performance adjustment based on its achievement
9    of or failure to achieve its performance targets no later
10    than December 31 each year. The Commission-approved
11    penalties or rewards shall be itemized and the annual cost
12    to consumers or to the utility shall be reported. The
13    penalties or rewards shall be collected or credited
14    beginning with the next calendar year.
15        (5) Revisions to Metrics. Tracking and performance
16    metrics, along with their associated goals, targets, and
17    incentives, may be changed as part of the Annual
18    Performance Evaluation. In addition, the Commission may
19    open a separate investigation into whether the metric
20    should be continued, modified, or discontinued, and
21    whether the methodology, including assumptions and
22    calculations used to measure or quantify progress toward
23    goals and targets in the Annual Performance Evaluation
24    should be continued, modified, or discontinued, at the
25    request of an intervening party.
 

 

 

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1    (220 ILCS 5/16-108.21 new)
2    Sec. 16-108.21. Energy storage program.
3    (a) Findings. The Illinois General Assembly hereby finds
4and declares that:
5        (1) Energy storage systems provide opportunities to:
6            (A) reduce costs to ratepayers directly or
7        indirectly by avoiding or deferring the need for
8        investment in new generation and for upgrades to
9        systems for the transmission and distribution of
10        electricity;
11            (B) reduce the use of fossil fuels for meeting
12        demand during peak load periods;
13            (C) provide ancillary services such as frequency
14        response, load following, and voltage support;
15            (D) assist electric utilities with integrating
16        sources of renewable energy into the grid for the
17        transmission and distribution of electricity, and with
18        maintaining grid stability;
19            (E) support diversification of energy resources;
20            (F) enhance the resilience and reliability of the
21        electric grid; and
22            (G) reduce greenhouse gas emissions and other air
23        pollutants resulting from power generation, thereby
24        minimizing public health impacts that result from
25        power generation.
26        (2) There are significant barriers to obtaining the

 

 

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1    benefits of energy storage systems, including inadequate
2    valuation of the services that energy storage can provide
3    to the grid and the public.
4        (3) It is in the public interest to:
5            (A) develop a robust competitive market for
6        existing and new providers of energy storage systems
7        in order to leverage Illinois' position as a leader in
8        advanced energy and to capture the potential for
9        economic development;
10            (B) implement targets and programs to achieve
11        deployment of energy storage systems; and
12            (C) modernize distributed energy resource programs
13        and interconnection standards to lower costs and
14        efficiently deploy energy storage systems in order to
15        increase economic development and job creation within
16        the State's clean energy economy.
17    (b) Definitions. As used in this Section:
18    "Deployment" means the installation of energy storage
19systems through a variety of mechanisms, including utility
20procurement, customer installation, or other processes.
21    "Electric utility" has the meaning as provided in Section
2216-102.
23    "Energy storage peak standard" means a percentage of
24annual retail electricity sales during peak hours that an
25electric utility must derive from electricity discharged from
26eligible energy storage systems.

 

 

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1    "Energy storage system" means a technology that is capable
2of absorbing zero-carbon energy, storing it for a period of
3time, and redelivering that energy after it has been stored in
4order to provide direct or indirect benefits to the broader
5electricity system. "Energy storage system" includes, but is
6not limited to, electrochemical, thermal, and
7electromechanical technologies.
8    "Non-wires alternatives solicitation" means a utility
9solicitation for third-party-owned or utility-owned
10distributed energy resources that uses non-traditional
11solutions to defer or replace planned investment on the
12distribution or transmission system.
13    "Total peak demand" means the highest hourly electricity
14demand for an electric utility in a given year, measured in
15megawatts, from all of the electric utility's customers of
16distribution service.
17    (c) Energy storage proceeding.
18        (1) The Commission, in consultation with the Illinois
19    Power Agency, shall initiate a proceeding to examine
20    specific programs, mechanisms, and policies that could
21    support the deployment of energy storage systems. The
22    Illinois Commerce Commission shall engage a broad group of
23    Illinois stakeholders, including electric utilities, the
24    energy storage industry, the renewable energy industry,
25    and others to inform the proceeding.
26        (2) The proceeding must, at minimum:

 

 

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1            (A) Develop a framework to identify and measure
2        the potential costs, benefits, that deployment of
3        energy storage could produce, as well as barriers to
4        realizing such benefits, including, but not limited
5        to:
6                (i) avoided cost and deferred investments in
7            generation, transmission, and distribution
8            facilities;
9                (ii) reduced ancillary services costs;
10                (iii) reduced transmission and distribution
11            congestion;
12                (iv) lower peak power costs and reduced
13            capacity costs;
14                (v) reduced costs for emergency power supplies
15            during outages;
16                (vi) reduced curtailment of renewable energy
17            generators;
18                (vii) reduced greenhouse gas emissions and
19            other criteria air pollutants;
20                (viii) increased grid hosting capacity of
21            renewable energy generators that produce energy on
22            an intermittent basis;
23                (ix) increased reliability and resilience of
24            the electric grid;
25                (x) increased resource diversification; and
26                (xi) increased economic development.

 

 

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1            (B) Analyze and estimate:
2                (i) the impact on the system's ability to
3            integrate renewable resources;
4                (ii) the benefits of addition of storage at
5            specific locations, such as at existing peaking
6            units or locations on the grid close to large load
7            centers;
8                (iii) the impact on grid reliability and power
9            quality; and
10                (iv) the effect on retail electric rates and
11            supply rates over the useful life of a given
12            energy storage system.
13            (C) Evaluate and identify cost-effective policies
14        and programs to support the deployment of energy
15        storage systems, including, but not limited to:
16                (i) incentive programs;
17                (ii) energy storage peak standards;
18                (iii) non-wires alternative solicitation;
19                (iv) peak demand reduction programs for
20            behind-the-meter storage for all customer classes;
21                (v) value of distributed energy resources
22            programs;
23                (vi) tax incentives;
24                (vii) time-varying rates;
25                (viii) updating of interconnection processes
26            and metering standards;and

 

 

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1                (ix) procurement by the Illinois Power Agency
2            of energy storage resources.
3        (3) The Commission shall, no later than May 31, 2022,
4    submit to the General Assembly and the Governor any
5    recommendations for additional legislative, regulatory or
6    executive actions based on the findings of the proceeding.
7        (4) At the conclusion of the proceeding required under
8    subsection (c), the Commission shall consider and
9    recommend to the Governor and General Assembly energy
10    storage deployment targets, if any, for each electric
11    utility that serves more than 200,000 customers to be
12    achieved by December 31, 2032, including recommended
13    interim targets.
14        (5) In setting recommendations for energy storage
15    deployment targets, the Commission shall:
16            (A) take into account the costs and benefits of
17        procuring energy storage according to the framework
18        developed in the proceeding under subsection (c); and
19            (B) consider establishing specific sub-categories
20        of deployment of systems by point of interconnection
21        or application in addition to any requirement for
22        behind the meter storage.
 
23    (220 ILCS 5/16-108.22 new)
24    Sec. 16-108.22. Nuclear plant assistance.
25    (a) The General Assembly finds:

 

 

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1        (1)It is in the interest of the State to support large
2    employers who bring needed jobs, tax base and ancillary
3    benefits to our State.
4        (2)The nuclear power generation facilities located in
5    Illinois provide the benefits listed in subsection (a) of
6    Section 8-201.12, as well as provide energy with zero
7    carbon emissions.
8        (3)The clean energy attributes of the nuclear
9    generation facilities support the State in its efforts to
10    achieve 100% clean energy.
11        (4)The State currently invests in various forms of
12    clean energy including, but not limited to, renewable
13    energy, energy efficiency, low-emission vehicles, among
14    others.
15        In addition to the economic benefits described in
16    subsection (a) of Section 8-201.12, nuclear plants provide
17    clean energy, which helps to avoid many health related
18    negative impacts.
19    (b) Beginning with calendar year 2021, and concluding with
20calendar year 2025, the State shall incentivize the retention
21of workers at the Byron and Dresden nuclear generation
22facilities by compensating their parent corporation as
23follows:
24        (1) For Byron, an amount equal to the sum of $1 per
25    megawatt hour of nameplate capacity for each of the 5
26    years as set forth in this subsection (b).

 

 

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1        (2) For Dresden, an amount equal to the sum of $3.50
2    per megawatt hour of nameplate capacity for each of the 5
3    years as set forth in this subsection (b).
4        (3) Initial payments shall occur on or before
5    September 1, 2021, and in each subsequent year, on or
6    before July 1.
7        (4) Payment in any given calendar year is conditioned
8    upon a determination of need from an independent audit of
9    the parent corporation, as set forth in Section 16-108.18.
10    (c) If the result of the independent audit shows that the
11operation of the nuclear facility in question is not in need of
12the level of assistance set forth in paragraphs (1) and (2) of
13subsection (b) to have a positive net present value, then the
14amount of assistance shall be reduced to the level of
15assistance necessary.
16    (d) In the event of reduction in assistance in any given
17year, the difference in the actual amount of funds provided
18and the funds contemplated in paragraphs (1) and (2) of
19subsection (b) shall be deposited in the Greenhouse Gas
20Emissions Reinvestment Fund, as described in paragraph (4) of
21subsection (c) of Section 9.18 of the Illinois Environmental
22Protection Act.
23    (e) In exchange for acceptance of the assistance described
24in this Section, the owner of the nuclear generation
25facilities shall agree to keep the plants in operation through
26the period ending December 31, 2025.

 

 

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1    (f) If the owner of a nuclear generation facility that has
2received assistance under this chapter retires the plant in
3violation of subsection (e), the owner shall reimburse the
4State for any funds received up to the date of retirement,
5unless the Commission has determined that the owner of the
6nuclear generation facility made a good faith effort to sell
7the facility to another entity prior to its retirement and
8that the owner did not refuse a reasonable offer to purchase
9the facility or the commission determines that, if a
10reasonable offer was received, the sale was not completed for
11a reason beyond the reasonable control of the public utility.
12    (g) In determining whether the nuclear generation facility
13owner made a good faith effort to sell the facility under this
14Section the Commission shall consider:
15        (1) whether the owner provided sufficient time prior
16    to the facility's retirement for potential purchasers to
17    evaluate purchasing the facility;
18        (2) whether the owner used reasonable efforts to make
19    potential purchasers aware of the opportunity to purchase
20    the facility;
21        (3) whether the owner reasonably evaluated any offers
22    received for the purchase of the facility; and
23        (4) any other factor deemed appropriate by the
24    Commission.
25    (h) In determining whether an offer to purchase a nuclear
26generation facility under this Section was reasonable the

 

 

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1Commission shall consider whether accepting the offer to
2purchase the facility would have been in the public interest.
3    (i) The assistance described in this Section shall be
4provided to subsequent owners of the facilities, subject to
5the same audit requirements as described in paragraph (4) of
6subsection (g).
 
7    (220 ILCS 5/16-111.5)
8    Sec. 16-111.5. Provisions relating to procurement.
9    (a) An electric utility that on December 31, 2005 served
10at least 100,000 customers in Illinois shall procure power and
11energy for its eligible retail customers in accordance with
12the applicable provisions set forth in Section 1-75 of the
13Illinois Power Agency Act and this Section. Beginning with the
14delivery year commencing on June 1, 2017, such electric
15utility shall also procure zero emission credits from zero
16emission facilities in accordance with the applicable
17provisions set forth in Section 1-75 of the Illinois Power
18Agency Act, and, for years beginning on or after June 1, 2017,
19the utility shall procure renewable energy resources in
20accordance with the applicable provisions set forth in Section
211-75 of the Illinois Power Agency Act and this Section. A small
22multi-jurisdictional electric utility that on December 31,
232005 served less than 100,000 customers in Illinois may elect
24to procure power and energy for all or a portion of its
25eligible Illinois retail customers in accordance with the

 

 

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1applicable provisions set forth in this Section and Section
21-75 of the Illinois Power Agency Act. This Section shall not
3apply to a small multi-jurisdictional utility until such time
4as a small multi-jurisdictional utility requests the Illinois
5Power Agency to prepare a procurement plan for its eligible
6retail customers. "Eligible retail customers" for the purposes
7of this Section means those retail customers that purchase
8power and energy from the electric utility under fixed-price
9bundled service tariffs, other than those retail customers
10whose service is declared or deemed competitive under Section
1116-113 and those other customer groups specified in this
12Section, including self-generating customers, customers
13electing hourly pricing, or those customers who are otherwise
14ineligible for fixed-price bundled tariff service. For those
15customers that are excluded from the procurement plan's
16electric supply service requirements, and the utility shall
17procure any supply requirements, including capacity, ancillary
18services, and hourly priced energy, in the applicable markets
19as needed to serve those customers, provided that the utility
20may include in its procurement plan load requirements for the
21load that is associated with those retail customers whose
22service has been declared or deemed competitive pursuant to
23Section 16-113 of this Act to the extent that those customers
24are purchasing power and energy during one of the transition
25periods identified in subsection (b) of Section 16-113 of this
26Act.

 

 

SB2896- 700 -LRB102 17909 JWD 25989 b

1    (b) A procurement plan shall be prepared for each electric
2utility consistent with the applicable requirements of the
3Illinois Power Agency Act and this Section. For purposes of
4this Section, Illinois electric utilities that are affiliated
5by virtue of a common parent company are considered to be a
6single electric utility. Small multi-jurisdictional utilities
7may request a procurement plan for a portion of or all of its
8Illinois load. Each procurement plan shall analyze the
9projected balance of supply and demand for those retail
10customers to be included in the plan's electric supply service
11requirements over a 5-year period, with the first planning
12year beginning on June 1 of the year following the year in
13which the plan is filed. The plan shall specifically identify
14the wholesale products to be procured following plan approval,
15and shall follow all the requirements set forth in the Public
16Utilities Act and all applicable State and federal laws,
17statutes, rules, or regulations, as well as Commission orders.
18Nothing in this Section precludes consideration of contracts
19longer than 5 years and related forecast data. Unless
20specified otherwise in this Section, in the procurement plan
21or in the implementing tariff, any procurement occurring in
22accordance with this plan shall be competitively bid through a
23request for proposals process. Approval and implementation of
24the procurement plan shall be subject to review and approval
25by the Commission according to the provisions set forth in
26this Section. A procurement plan shall include each of the

 

 

SB2896- 701 -LRB102 17909 JWD 25989 b

1following components:
2        (1) Hourly load analysis. This analysis shall include:
3            (i) multi-year historical analysis of hourly
4        loads;
5            (ii) switching trends and competitive retail
6        market analysis;
7            (iii) known or projected changes to future loads;
8        and
9            (iv) growth forecasts by customer class.
10        (2) Analysis of the impact of any demand side and
11    renewable energy initiatives. This analysis shall include:
12            (i) the impact of demand response programs and
13        energy efficiency programs, both current and
14        projected; for small multi-jurisdictional utilities,
15        the impact of demand response and energy efficiency
16        programs approved pursuant to Section 8-408 of this
17        Act, both current and projected; and
18            (ii) supply side needs that are projected to be
19        offset by purchases of renewable energy resources, if
20        any.
21        (3) A plan for meeting the expected load requirements
22    that will not be met through preexisting contracts. This
23    plan shall include:
24            (i) definitions of the different Illinois retail
25        customer classes for which supply is being purchased;
26            (ii) the proposed mix of demand-response products

 

 

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1        for which contracts will be executed during the next
2        year. For small multi-jurisdictional electric
3        utilities that on December 31, 2005 served fewer than
4        100,000 customers in Illinois, these shall be defined
5        as demand-response products offered in an energy
6        efficiency plan approved pursuant to Section 8-408 of
7        this Act. The cost-effective demand-response measures
8        shall be procured whenever the cost is lower than
9        procuring comparable capacity products, provided that
10        such products shall:
11                (A) be procured by a demand-response provider
12            from those retail customers included in the plan's
13            electric supply service requirements;
14                (B) at least satisfy the demand-response
15            requirements of the regional transmission
16            organization market in which the utility's service
17            territory is located, including, but not limited
18            to, any applicable capacity or dispatch
19            requirements;
20                (C) provide for customers' participation in
21            the stream of benefits produced by the
22            demand-response products;
23                (D) provide for reimbursement by the
24            demand-response provider of the utility for any
25            costs incurred as a result of the failure of the
26            supplier of such products to perform its

 

 

SB2896- 703 -LRB102 17909 JWD 25989 b

1            obligations thereunder; and
2                (E) meet the same credit requirements as apply
3            to suppliers of capacity, in the applicable
4            regional transmission organization market;
5            (iii) monthly forecasted system supply
6        requirements, including expected minimum, maximum, and
7        average values for the planning period;
8            (iv) the proposed mix and selection of standard
9        wholesale products for which contracts will be
10        executed during the next year, separately or in
11        combination, to meet that portion of its load
12        requirements not met through pre-existing contracts,
13        including but not limited to monthly 5 x 16 peak period
14        block energy, monthly off-peak wrap energy, monthly 7
15        x 24 energy, annual 5 x 16 energy, annual off-peak wrap
16        energy, annual 7 x 24 energy, monthly capacity, annual
17        capacity, peak load capacity obligations, capacity
18        purchase plan, and ancillary services;
19            (v) proposed term structures for each wholesale
20        product type included in the proposed procurement plan
21        portfolio of products; and
22            (vi) an assessment of the price risk, load
23        uncertainty, and other factors that are associated
24        with the proposed procurement plan; this assessment,
25        to the extent possible, shall include an analysis of
26        the following factors: contract terms, time frames for

 

 

SB2896- 704 -LRB102 17909 JWD 25989 b

1        securing products or services, fuel costs, weather
2        patterns, transmission costs, market conditions, and
3        the governmental regulatory environment; the proposed
4        procurement plan shall also identify alternatives for
5        those portfolio measures that are identified as having
6        significant price risk.
7        (4) Proposed procedures for balancing loads. The
8    procurement plan shall include, for load requirements
9    included in the procurement plan, the process for (i)
10    hourly balancing of supply and demand and (ii) the
11    criteria for portfolio re-balancing in the event of
12    significant shifts in load.
13        (5) Long-Term Renewable Resources Procurement Plan.
14    The Agency shall prepare a long-term renewable resources
15    procurement plan for the procurement of renewable energy
16    credits under Sections 1-56 and 1-75 of the Illinois Power
17    Agency Act for delivery beginning in the 2017 delivery
18    year.
19            (i) The initial long-term renewable resources
20        procurement plan and all subsequent revisions shall be
21        subject to review and approval by the Commission. For
22        the purposes of this Section, "delivery year" has the
23        same meaning as in Section 1-10 of the Illinois Power
24        Agency Act. For purposes of this Section, "Agency"
25        shall mean the Illinois Power Agency.
26            (ii) The long-term renewable resources planning

 

 

SB2896- 705 -LRB102 17909 JWD 25989 b

1        process shall be conducted as follows:
2                (A) Electric utilities shall provide a range
3            of load forecasts to the Illinois Power Agency
4            within 45 days of the Agency's request for
5            forecasts, which request shall specify the length
6            and conditions for the forecasts including, but
7            not limited to, the quantity of distributed
8            generation expected to be interconnected for each
9            year.
10                (B) The Agency shall publish for comment the
11            initial long-term renewable resources procurement
12            plan no later than 120 days after the effective
13            date of this amendatory Act of the 99th General
14            Assembly and shall review, and may revise, the
15            plan at least every 2 years thereafter. To the
16            extent practicable, the Agency shall review and
17            propose any revisions to the long-term renewable
18            energy resources procurement plan in conjunction
19            with the Agency's other planning and approval
20            processes conducted under this Section. The
21            initial long-term renewable resources procurement
22            plan shall:
23                    (aa) Identify the procurement programs and
24                competitive procurement events consistent with
25                the applicable requirements of the Illinois
26                Power Agency Act and shall be designed to

 

 

SB2896- 706 -LRB102 17909 JWD 25989 b

1                achieve the goals set forth in subsection (c)
2                of Section 1-75 of that Act.
3                    (bb) Include a schedule for procurements
4                for renewable energy credits from
5                utility-scale wind projects, utility-scale
6                solar projects, and brownfield site
7                photovoltaic projects consistent with
8                subparagraph (G) of paragraph (1) of
9                subsection (c) of Section 1-75 of the Illinois
10                Power Agency Act.
11                    (cc) Identify the process whereby the
12                Agency will submit to the Commission for
13                review and approval the proposed contracts to
14                implement the programs required by such plan.
15                Copies of the initial long-term renewable
16            resources procurement plan and all subsequent
17            revisions shall be posted and made publicly
18            available on the Agency's and Commission's
19            websites, and copies shall also be provided to
20            each affected electric utility. An affected
21            utility and other interested parties shall have 45
22            days following the date of posting to provide
23            comment to the Agency on the initial long-term
24            renewable resources procurement plan and all
25            subsequent revisions. All comments submitted to
26            the Agency shall be specific, supported by data or

 

 

SB2896- 707 -LRB102 17909 JWD 25989 b

1            other detailed analyses, and, if objecting to all
2            or a portion of the procurement plan, accompanied
3            by specific alternative wording or proposals. All
4            comments shall be posted on the Agency's and
5            Commission's websites. During this 45-day comment
6            period, the Agency shall hold at least one public
7            hearing within each utility's service area that is
8            subject to the requirements of this paragraph (5)
9            for the purpose of receiving public comment.
10            Within 21 days following the end of the 45-day
11            review period, the Agency may revise the long-term
12            renewable resources procurement plan based on the
13            comments received and shall file the plan with the
14            Commission for review and approval.
15                (C) Within 14 days after the filing of the
16            initial long-term renewable resources procurement
17            plan or any subsequent revisions, any person
18            objecting to the plan may file an objection with
19            the Commission. Within 21 days after the filing of
20            the plan, the Commission shall determine whether a
21            hearing is necessary. The Commission shall enter
22            its order confirming or modifying the initial
23            long-term renewable resources procurement plan or
24            any subsequent revisions within 120 days after the
25            filing of the plan by the Illinois Power Agency.
26                (D) The Commission shall approve the initial

 

 

SB2896- 708 -LRB102 17909 JWD 25989 b

1            long-term renewable resources procurement plan and
2            any subsequent revisions, including expressly the
3            forecast used in the plan and taking into account
4            that funding will be limited to the amount of
5            revenues actually collected by the utilities, if
6            the Commission determines that the plan will
7            reasonably and prudently accomplish the
8            requirements of Section 1-56 and subsection (c) of
9            Section 1-75 of the Illinois Power Agency Act. The
10            Commission shall also approve the process for the
11            submission, review, and approval of the proposed
12            contracts to procure renewable energy credits or
13            implement the programs authorized by the
14            Commission pursuant to a long-term renewable
15            resources procurement plan approved under this
16            Section.
17            (iii) The Agency or third parties contracted by
18        the Agency shall implement all programs authorized by
19        the Commission in an approved long-term renewable
20        resources procurement plan without further review and
21        approval by the Commission. Any disputes regarding
22        implementation of the programs authorized in the Plan
23        shall be resolved in an expedited manner by the
24        Commission. Third parties shall not begin implementing
25        any programs or receive any payment under this Section
26        until the Commission has approved the contract or

 

 

SB2896- 709 -LRB102 17909 JWD 25989 b

1        contracts under the process authorized by the
2        Commission in item (D) of subparagraph (ii) of
3        paragraph (5) of this subsection (b) and the third
4        party and the Agency or utility, as applicable, have
5        executed the contract. For those renewable energy
6        credits subject to procurement through a competitive
7        bid process under the plan or under the initial
8        forward procurements for wind and solar resources
9        described in subparagraph (G) of paragraph (1) of
10        subsection (c) of Section 1-75 of the Illinois Power
11        Agency Act, the Agency shall follow the procurement
12        process specified in the provisions relating to
13        electricity procurement in subsections (e) through (i)
14        of this Section.
15            (iv) An electric utility shall recover its costs
16        associated with the procurement of renewable energy
17        credits under this Section through an automatic
18        adjustment clause tariff under subsection (k) of
19        Section 16-108 of this Act. A utility shall not be
20        required to advance any payment or pay any amounts
21        under this Section that exceed the actual amount of
22        revenues collected by the utility under paragraph (6)
23        of subsection (c) of Section 1-75 of the Illinois
24        Power Agency Act and subsection (k) of Section 16-108
25        of this Act, and contracts executed under this Section
26        shall expressly incorporate this limitation.

 

 

SB2896- 710 -LRB102 17909 JWD 25989 b

1            (v) For the public interest, safety, and welfare,
2        the Agency and the Commission may adopt rules to carry
3        out the provisions of this Section on an emergency
4        basis immediately following the effective date of this
5        amendatory Act of the 99th General Assembly.
6            (vi) On or before July 1 of each year, the
7        Commission shall hold an informal hearing for the
8        purpose of receiving comments on the prior year's
9        procurement process and any recommendations for
10        change.
11    (c) The procurement process set forth in Section 1-75 of
12the Illinois Power Agency Act and subsection (e) of this
13Section shall be administered by a procurement administrator
14and monitored by a procurement monitor.
15        (1) The procurement administrator shall:
16            (i) design the final procurement process in
17        accordance with Section 1-75 of the Illinois Power
18        Agency Act and subsection (e) of this Section
19        following Commission approval of the procurement plan;
20            (ii) develop benchmarks in accordance with
21        subsection (e)(3) to be used to evaluate bids; these
22        benchmarks shall be submitted to the Commission for
23        review and approval on a confidential basis prior to
24        the procurement event;
25            (iii) serve as the interface between the electric
26        utility and suppliers;

 

 

SB2896- 711 -LRB102 17909 JWD 25989 b

1            (iv) manage the bidder pre-qualification and
2        registration process;
3            (v) obtain the electric utilities' agreement to
4        the final form of all supply contracts and credit
5        collateral agreements;
6            (vi) administer the request for proposals process;
7            (vii) have the discretion to negotiate to
8        determine whether bidders are willing to lower the
9        price of bids that meet the benchmarks approved by the
10        Commission; any post-bid negotiations with bidders
11        shall be limited to price only and shall be completed
12        within 24 hours after opening the sealed bids and
13        shall be conducted in a fair and unbiased manner; in
14        conducting the negotiations, there shall be no
15        disclosure of any information derived from proposals
16        submitted by competing bidders; if information is
17        disclosed to any bidder, it shall be provided to all
18        competing bidders;
19            (viii) maintain confidentiality of supplier and
20        bidding information in a manner consistent with all
21        applicable laws, rules, regulations, and tariffs;
22            (ix) submit a confidential report to the
23        Commission recommending acceptance or rejection of
24        bids;
25            (x) notify the utility of contract counterparties
26        and contract specifics; and

 

 

SB2896- 712 -LRB102 17909 JWD 25989 b

1            (xi) administer related contingency procurement
2        events.
3        (2) The procurement monitor, who shall be retained by
4    the Commission, shall:
5            (i) monitor interactions among the procurement
6        administrator, suppliers, and utility;
7            (ii) monitor and report to the Commission on the
8        progress of the procurement process;
9            (iii) provide an independent confidential report
10        to the Commission regarding the results of the
11        procurement event;
12            (iv) assess compliance with the procurement plans
13        approved by the Commission for each utility that on
14        December 31, 2005 provided electric service to at
15        least 100,000 customers in Illinois and for each small
16        multi-jurisdictional utility that on December 31, 2005
17        served less than 100,000 customers in Illinois;
18            (v) preserve the confidentiality of supplier and
19        bidding information in a manner consistent with all
20        applicable laws, rules, regulations, and tariffs;
21            (vi) provide expert advice to the Commission and
22        consult with the procurement administrator regarding
23        issues related to procurement process design, rules,
24        protocols, and policy-related matters; and
25            (vii) consult with the procurement administrator
26        regarding the development and use of benchmark

 

 

SB2896- 713 -LRB102 17909 JWD 25989 b

1        criteria, standard form contracts, credit policies,
2        and bid documents.
3    (d) Except as provided in subsection (j), the planning
4process shall be conducted as follows:
5        (1) Beginning in 2008, each Illinois utility procuring
6    power pursuant to this Section shall annually provide a
7    range of load forecasts to the Illinois Power Agency by
8    July 15 of each year, or such other date as may be required
9    by the Commission or Agency. The load forecasts shall
10    cover the 5-year procurement planning period for the next
11    procurement plan and shall include hourly data
12    representing a high-load, low-load, and expected-load
13    scenario for the load of those retail customers included
14    in the plan's electric supply service requirements. The
15    utility shall provide supporting data and assumptions for
16    each of the scenarios.
17        (2) Beginning in 2008, the Illinois Power Agency shall
18    prepare a procurement plan by August 15th of each year, or
19    such other date as may be required by the Commission. The
20    procurement plan shall identify the portfolio of
21    demand-response and power and energy products to be
22    procured. Cost-effective demand-response measures shall be
23    procured as set forth in item (iii) of subsection (b) of
24    this Section. Copies of the procurement plan shall be
25    posted and made publicly available on the Agency's and
26    Commission's websites, and copies shall also be provided

 

 

SB2896- 714 -LRB102 17909 JWD 25989 b

1    to each affected electric utility. An affected utility
2    shall have 30 days following the date of posting to
3    provide comment to the Agency on the procurement plan.
4    Other interested entities also may comment on the
5    procurement plan. All comments submitted to the Agency
6    shall be specific, supported by data or other detailed
7    analyses, and, if objecting to all or a portion of the
8    procurement plan, accompanied by specific alternative
9    wording or proposals. All comments shall be posted on the
10    Agency's and Commission's websites. During this 30-day
11    comment period, the Agency shall hold at least one public
12    hearing within each utility's service area for the purpose
13    of receiving public comment on the procurement plan.
14    Within 14 days following the end of the 30-day review
15    period, the Agency shall revise the procurement plan as
16    necessary based on the comments received and file the
17    procurement plan with the Commission and post the
18    procurement plan on the websites.
19        (3) Within 5 days after the filing of the procurement
20    plan, any person objecting to the procurement plan shall
21    file an objection with the Commission. Within 10 days
22    after the filing, the Commission shall determine whether a
23    hearing is necessary. The Commission shall enter its order
24    confirming or modifying the procurement plan within 90
25    days after the filing of the procurement plan by the
26    Illinois Power Agency.

 

 

SB2896- 715 -LRB102 17909 JWD 25989 b

1        (4) The Commission shall approve the procurement plan,
2    including expressly the forecast used in the procurement
3    plan, if the Commission determines that it will ensure
4    adequate, reliable, affordable, efficient, and
5    environmentally sustainable electric service at the lowest
6    total cost over time, taking into account any benefits of
7    price stability.
8    (e) The procurement process shall include each of the
9following components:
10        (1) Solicitation, pre-qualification, and registration
11    of bidders. The procurement administrator shall
12    disseminate information to potential bidders to promote a
13    procurement event, notify potential bidders that the
14    procurement administrator may enter into a post-bid price
15    negotiation with bidders that meet the applicable
16    benchmarks, provide supply requirements, and otherwise
17    explain the competitive procurement process. In addition
18    to such other publication as the procurement administrator
19    determines is appropriate, this information shall be
20    posted on the Illinois Power Agency's and the Commission's
21    websites. The procurement administrator shall also
22    administer the prequalification process, including
23    evaluation of credit worthiness, compliance with
24    procurement rules, and agreement to the standard form
25    contract developed pursuant to paragraph (2) of this
26    subsection (e). The procurement administrator shall then

 

 

SB2896- 716 -LRB102 17909 JWD 25989 b

1    identify and register bidders to participate in the
2    procurement event.
3        (2) Standard contract forms and credit terms and
4    instruments. The procurement administrator, in
5    consultation with the utilities, the Commission, and other
6    interested parties and subject to Commission oversight,
7    shall develop and provide standard contract forms for the
8    supplier contracts that meet generally accepted industry
9    practices. Standard credit terms and instruments that meet
10    generally accepted industry practices shall be similarly
11    developed. The procurement administrator shall make
12    available to the Commission all written comments it
13    receives on the contract forms, credit terms, or
14    instruments. If the procurement administrator cannot reach
15    agreement with the applicable electric utility as to the
16    contract terms and conditions, the procurement
17    administrator must notify the Commission of any disputed
18    terms and the Commission shall resolve the dispute. The
19    terms of the contracts shall not be subject to negotiation
20    by winning bidders, and the bidders must agree to the
21    terms of the contract in advance so that winning bids are
22    selected solely on the basis of price.
23        (3) Establishment of a market-based price benchmark.
24    As part of the development of the procurement process, the
25    procurement administrator, in consultation with the
26    Commission staff, Agency staff, and the procurement

 

 

SB2896- 717 -LRB102 17909 JWD 25989 b

1    monitor, shall establish benchmarks for evaluating the
2    final prices in the contracts for each of the products
3    that will be procured through the procurement process. The
4    benchmarks shall be based on price data for similar
5    products for the same delivery period and same delivery
6    hub, or other delivery hubs after adjusting for that
7    difference. The price benchmarks may also be adjusted to
8    take into account differences between the information
9    reflected in the underlying data sources and the specific
10    products and procurement process being used to procure
11    power for the Illinois utilities. The benchmarks shall be
12    confidential but shall be provided to, and will be subject
13    to Commission review and approval, prior to a procurement
14    event.
15        (4) Request for proposals competitive procurement
16    process. The procurement administrator shall design and
17    issue a request for proposals to supply electricity in
18    accordance with each utility's procurement plan, as
19    approved by the Commission. The request for proposals
20    shall set forth a procedure for sealed, binding commitment
21    bidding with pay-as-bid settlement, and provision for
22    selection of bids on the basis of price.
23        (5) A plan for implementing contingencies in the event
24    of supplier default or failure of the procurement process
25    to fully meet the expected load requirement due to
26    insufficient supplier participation, Commission rejection

 

 

SB2896- 718 -LRB102 17909 JWD 25989 b

1    of results, or any other cause.
2            (i) Event of supplier default: In the event of
3        supplier default, the utility shall review the
4        contract of the defaulting supplier to determine if
5        the amount of supply is 200 megawatts or greater, and
6        if there are more than 60 days remaining of the
7        contract term. If both of these conditions are met,
8        and the default results in termination of the
9        contract, the utility shall immediately notify the
10        Illinois Power Agency that a request for proposals
11        must be issued to procure replacement power, and the
12        procurement administrator shall run an additional
13        procurement event. If the contracted supply of the
14        defaulting supplier is less than 200 megawatts or
15        there are less than 60 days remaining of the contract
16        term, the utility shall procure power and energy from
17        the applicable regional transmission organization
18        market, including ancillary services, capacity, and
19        day-ahead or real time energy, or both, for the
20        duration of the contract term to replace the
21        contracted supply; provided, however, that if a needed
22        product is not available through the regional
23        transmission organization market it shall be purchased
24        from the wholesale market.
25            (ii) Failure of the procurement process to fully
26        meet the expected load requirement: If the procurement

 

 

SB2896- 719 -LRB102 17909 JWD 25989 b

1        process fails to fully meet the expected load
2        requirement due to insufficient supplier participation
3        or due to a Commission rejection of the procurement
4        results, the procurement administrator, the
5        procurement monitor, and the Commission staff shall
6        meet within 10 days to analyze potential causes of low
7        supplier interest or causes for the Commission
8        decision. If changes are identified that would likely
9        result in increased supplier participation, or that
10        would address concerns causing the Commission to
11        reject the results of the prior procurement event, the
12        procurement administrator may implement those changes
13        and rerun the request for proposals process according
14        to a schedule determined by those parties and
15        consistent with Section 1-75 of the Illinois Power
16        Agency Act and this subsection. In any event, a new
17        request for proposals process shall be implemented by
18        the procurement administrator within 90 days after the
19        determination that the procurement process has failed
20        to fully meet the expected load requirement.
21            (iii) In all cases where there is insufficient
22        supply provided under contracts awarded through the
23        procurement process to fully meet the electric
24        utility's load requirement, the utility shall meet the
25        load requirement by procuring power and energy from
26        the applicable regional transmission organization

 

 

SB2896- 720 -LRB102 17909 JWD 25989 b

1        market, including ancillary services, capacity, and
2        day-ahead or real time energy, or both; provided,
3        however, that if a needed product is not available
4        through the regional transmission organization market
5        it shall be purchased from the wholesale market.
6        (6) The procurement process described in this
7    subsection is exempt from the requirements of the Illinois
8    Procurement Code, pursuant to Section 20-10 of that Code.
9    (f) Within 2 business days after opening the sealed bids,
10the procurement administrator shall submit a confidential
11report to the Commission. The report shall contain the results
12of the bidding for each of the products along with the
13procurement administrator's recommendation for the acceptance
14and rejection of bids based on the price benchmark criteria
15and other factors observed in the process. The procurement
16monitor also shall submit a confidential report to the
17Commission within 2 business days after opening the sealed
18bids. The report shall contain the procurement monitor's
19assessment of bidder behavior in the process as well as an
20assessment of the procurement administrator's compliance with
21the procurement process and rules. The Commission shall review
22the confidential reports submitted by the procurement
23administrator and procurement monitor, and shall accept or
24reject the recommendations of the procurement administrator
25within 2 business days after receipt of the reports.
26    (g) Within 3 business days after the Commission decision

 

 

SB2896- 721 -LRB102 17909 JWD 25989 b

1approving the results of a procurement event, the utility
2shall enter into binding contractual arrangements with the
3winning suppliers using the standard form contracts; except
4that the utility shall not be required either directly or
5indirectly to execute the contracts if a tariff that is
6consistent with subsection (l) of this Section has not been
7approved and placed into effect for that utility.
8    (h) The names of the successful bidders and the load
9weighted average of the winning bid prices for each contract
10type and for each contract term shall be made available to the
11public at the time of Commission approval of a procurement
12event. The Commission, the procurement monitor, the
13procurement administrator, the Illinois Power Agency, and all
14participants in the procurement process shall maintain the
15confidentiality of all other supplier and bidding information
16in a manner consistent with all applicable laws, rules,
17regulations, and tariffs. Confidential information, including
18the confidential reports submitted by the procurement
19administrator and procurement monitor pursuant to subsection
20(f) of this Section, shall not be made publicly available and
21shall not be discoverable by any party in any proceeding,
22absent a compelling demonstration of need, nor shall those
23reports be admissible in any proceeding other than one for law
24enforcement purposes.
25    (i) Within 2 business days after a Commission decision
26approving the results of a procurement event or such other

 

 

SB2896- 722 -LRB102 17909 JWD 25989 b

1date as may be required by the Commission from time to time,
2the utility shall file for informational purposes with the
3Commission its actual or estimated retail supply charges, as
4applicable, by customer supply group reflecting the costs
5associated with the procurement and computed in accordance
6with the tariffs filed pursuant to subsection (l) of this
7Section and approved by the Commission.
8    (j) Within 60 days following August 28, 2007 (the
9effective date of Public Act 95-481), each electric utility
10that on December 31, 2005 provided electric service to at
11least 100,000 customers in Illinois shall prepare and file
12with the Commission an initial procurement plan, which shall
13conform in all material respects to the requirements of the
14procurement plan set forth in subsection (b); provided,
15however, that the Illinois Power Agency Act shall not apply to
16the initial procurement plan prepared pursuant to this
17subsection. The initial procurement plan shall identify the
18portfolio of power and energy products to be procured and
19delivered for the period June 2008 through May 2009, and shall
20identify the proposed procurement administrator, who shall
21have the same experience and expertise as is required of a
22procurement administrator hired pursuant to Section 1-75 of
23the Illinois Power Agency Act. Copies of the procurement plan
24shall be posted and made publicly available on the
25Commission's website. The initial procurement plan may include
26contracts for renewable resources that extend beyond May 2009.

 

 

SB2896- 723 -LRB102 17909 JWD 25989 b

1        (i) Within 14 days following filing of the initial
2    procurement plan, any person may file a detailed objection
3    with the Commission contesting the procurement plan
4    submitted by the electric utility. All objections to the
5    electric utility's plan shall be specific, supported by
6    data or other detailed analyses. The electric utility may
7    file a response to any objections to its procurement plan
8    within 7 days after the date objections are due to be
9    filed. Within 7 days after the date the utility's response
10    is due, the Commission shall determine whether a hearing
11    is necessary. If it determines that a hearing is
12    necessary, it shall require the hearing to be completed
13    and issue an order on the procurement plan within 60 days
14    after the filing of the procurement plan by the electric
15    utility.
16        (ii) The order shall approve or modify the procurement
17    plan, approve an independent procurement administrator,
18    and approve or modify the electric utility's tariffs that
19    are proposed with the initial procurement plan. The
20    Commission shall approve the procurement plan if the
21    Commission determines that it will ensure adequate,
22    reliable, affordable, efficient, and environmentally
23    sustainable electric service at the lowest total cost over
24    time, taking into account any benefits of price stability.
25    (k) (Blank).
26    (k-5) (Blank).

 

 

SB2896- 724 -LRB102 17909 JWD 25989 b

1    (l) An electric utility shall recover its costs incurred
2under this Section, including, but not limited to, the costs
3of procuring power and energy demand-response resources under
4this Section. The utility shall file with the initial
5procurement plan its proposed tariffs through which its costs
6of procuring power that are incurred pursuant to a
7Commission-approved procurement plan and those other costs
8identified in this subsection (l), will be recovered. The
9tariffs shall include a formula rate or charge designed to
10pass through both the costs incurred by the utility in
11procuring a supply of electric power and energy for the
12applicable customer classes with no mark-up or return on the
13price paid by the utility for that supply, plus any just and
14reasonable costs that the utility incurs in arranging and
15providing for the supply of electric power and energy. The
16formula rate or charge shall also contain provisions that
17ensure that its application does not result in over or under
18recovery due to changes in customer usage and demand patterns,
19and that provide for the correction, on at least an annual
20basis, of any accounting errors that may occur. A utility
21shall recover through the tariff all reasonable costs incurred
22to implement or comply with any procurement plan that is
23developed and put into effect pursuant to Section 1-75 of the
24Illinois Power Agency Act and this Section, including any fees
25assessed by the Illinois Power Agency, costs associated with
26load balancing, and contingency plan costs. The electric

 

 

SB2896- 725 -LRB102 17909 JWD 25989 b

1utility shall also recover its full costs of procuring
2electric supply for which it contracted before the effective
3date of this Section in conjunction with the provision of full
4requirements service under fixed-price bundled service tariffs
5subsequent to December 31, 2006. All such costs shall be
6deemed to have been prudently incurred. The pass-through
7tariffs that are filed and approved pursuant to this Section
8shall not be subject to review under, or in any way limited by,
9Section 16-111(i) of this Act. All of the costs incurred by the
10electric utility associated with the purchase of zero emission
11credits in accordance with subsection (d-5) of Section 1-75 of
12the Illinois Power Agency Act and, beginning June 1, 2017, all
13of the costs incurred by the electric utility associated with
14the purchase of renewable energy resources in accordance with
15Sections 1-56 and 1-75 of the Illinois Power Agency Act, shall
16be recovered through the electric utility's tariffed charges
17applicable to all of its retail customers, as specified in
18subsection (k) of Section 16-108 of this Act, and shall not be
19recovered through the electric utility's tariffed charges for
20electric power and energy supply to its eligible retail
21customers.
22    (m) The Commission has the authority to adopt rules to
23carry out the provisions of this Section. For the public
24interest, safety, and welfare, the Commission also has
25authority to adopt rules to carry out the provisions of this
26Section on an emergency basis immediately following August 28,

 

 

SB2896- 726 -LRB102 17909 JWD 25989 b

12007 (the effective date of Public Act 95-481).
2    (n) Notwithstanding any other provision of this Act, any
3affiliated electric utilities that submit a single procurement
4plan covering their combined needs may procure for those
5combined needs in conjunction with that plan, and may enter
6jointly into power supply contracts, purchases, and other
7procurement arrangements, and allocate capacity and energy and
8cost responsibility therefor among themselves in proportion to
9their requirements.
10    (o) On or before June 1 of each year, the Commission shall
11hold an informal hearing for the purpose of receiving comments
12on the prior year's procurement process and any
13recommendations for change.
14    (p) An electric utility subject to this Section may
15propose to invest, lease, own, or operate an electric
16generation facility as part of its procurement plan, provided
17the utility demonstrates that such facility is the least-cost
18option to provide electric service to those retail customers
19included in the plan's electric supply service requirements.
20If the facility is shown to be the least-cost option and is
21included in a procurement plan prepared in accordance with
22Section 1-75 of the Illinois Power Agency Act and this
23Section, then the electric utility shall make a filing
24pursuant to Section 8-406 of this Act, and may request of the
25Commission any statutory relief required thereunder. If the
26Commission grants all of the necessary approvals for the

 

 

SB2896- 727 -LRB102 17909 JWD 25989 b

1proposed facility, such supply shall thereafter be considered
2as a pre-existing contract under subsection (b) of this
3Section. The Commission shall in any order approving a
4proposal under this subsection specify how the utility will
5recover the prudently incurred costs of investing in, leasing,
6owning, or operating such generation facility through just and
7reasonable rates charged to those retail customers included in
8the plan's electric supply service requirements. Cost recovery
9for facilities included in the utility's procurement plan
10pursuant to this subsection shall not be subject to review
11under or in any way limited by the provisions of Section
1216-111(i) of this Act. Nothing in this Section is intended to
13prohibit a utility from filing for a fuel adjustment clause as
14is otherwise permitted under Section 9-220 of this Act.
15    (q) If the Illinois Power Agency filed with the
16Commission, under Section 16-111.5 of this Act, its proposed
17procurement plan for the period commencing June 1, 2017, and
18the Commission has not yet entered its final order approving
19the plan on or before the effective date of this amendatory Act
20of the 99th General Assembly, then the Illinois Power Agency
21shall file a notice of withdrawal with the Commission, after
22the effective date of this amendatory Act of the 99th General
23Assembly, to withdraw the proposed procurement of renewable
24energy resources to be approved under the plan, other than the
25procurement of renewable energy credits from distributed
26renewable energy generation devices using funds previously

 

 

SB2896- 728 -LRB102 17909 JWD 25989 b

1collected from electric utilities' retail customers that take
2service pursuant to electric utilities' hourly pricing tariff
3or tariffs and, for an electric utility that serves less than
4100,000 retail customers in the State, other than the
5procurement of renewable energy credits from distributed
6renewable energy generation devices. Upon receipt of the
7notice, the Commission shall enter an order that approves the
8withdrawal of the proposed procurement of renewable energy
9resources from the plan. The initially proposed procurement of
10renewable energy resources shall not be approved or be the
11subject of any further hearing, investigation, proceeding, or
12order of any kind.
13    (r) For the procurement of standard wholesale products,
14the names of the successful bidders and the load weighted
15average of the winning bid prices for each contract type and
16for each contract term shall be made available to the public at
17the time of Commission approval of a procurement event. For
18procurements conducted to meet the requirements of Section
191-56(b) or Section 1-75(c) of the Illinois Power Agency Act
20governed by the provisions of this Section, the address and
21nameplate capacity of the new renewable energy generating
22facility proposed by a winning bidder shall also be made
23available to the public at the time of Commission approval of a
24procurement event, along with the business address and contact
25information for any winning bidder. An estimate or
26approximation of the nameplate capacity of the new renewable

 

 

SB2896- 729 -LRB102 17909 JWD 25989 b

1energy generating facility may be disclosed if necessary to
2protect the confidentiality of individual bid prices.
3    The Commission, the procurement monitor, the procurement
4administrator, the Illinois Power Agency, and all participants
5in the procurement process shall maintain the confidentiality
6of all other supplier and bidding information in a manner
7consistent with all applicable laws, rules, regulations, and
8tariffs. Confidential information, including the confidential
9reports submitted by the procurement administrator and
10procurement monitor pursuant to subsection (f) of this
11Section, shall not be made publicly available and shall not be
12discoverable by any party in any proceeding, absent a
13compelling demonstration of need, nor shall those reports be
14admissible in any proceeding other than one for law
15enforcement purposes.
16    This amendatory Act of the 99th General Assembly preempts
17and supersedes any order entered by the Commission that
18approved the Illinois Power Agency's procurement plan for the
19period commencing June 1, 2017, to the extent it is
20inconsistent with the provisions of this amendatory Act of the
2199th General Assembly. To the extent any previously entered
22order approved the procurement of renewable energy resources,
23the portion of that order approving the procurement shall be
24void, other than the procurement of renewable energy credits
25from distributed renewable energy generation devices using
26funds previously collected from electric utilities' retail

 

 

SB2896- 730 -LRB102 17909 JWD 25989 b

1customers that take service under electric utilities' hourly
2pricing tariff or tariffs and, for an electric utility that
3serves less than 100,000 retail customers in the State, other
4than the procurement of renewable energy credits for
5distributed renewable energy generation devices.
6(Source: P.A. 99-906, eff. 6-1-17.)
 
7    (220 ILCS 5/16-111.8)
8    Sec. 16-111.8. Automatic adjustment clause tariff;
9uncollectibles.
10    (a) An electric utility shall be permitted, at its
11election, to recover through an automatic adjustment clause
12tariff the incremental difference between its actual
13uncollectible amount as set forth in Account 904 in the
14utility's most recent annual FERC Form 1 and the uncollectible
15amount included in the utility's rates for the period reported
16in such annual FERC Form 1. The Commission may, in a proceeding
17to review a general rate case filed subsequent to the
18effective date of the tariff established under this Section,
19prospectively switch from using the actual uncollectible
20amount set forth in Account 904 to using net write-offs in such
21tariff, but only if net write-offs are also used to determine
22the utility's uncollectible amount in rates. In the event the
23Commission requires such a change, it shall be made effective
24at the beginning of the first full calendar year after the new
25rates approved in such proceeding are first placed in effect

 

 

SB2896- 731 -LRB102 17909 JWD 25989 b

1and an adjustment shall be made, if necessary, to ensure the
2change does not result in double-recovery or unrecovered
3uncollectible amounts for any year. For purposes of this
4Section, "uncollectible amount" means the expense set forth in
5Account 904 of the utility's FERC Form 1 or cost of net
6write-offs as appropriate. In the event the utility's rates
7change during the period of time reported in its most recent
8annual FERC Form 1, the uncollectible amount included in the
9utility's rates during such period of time for purposes of
10this Section will be a weighted average, based on revenues
11earned during such period by the utility under each set of
12rates, of the uncollectible amount included in the utility's
13rates at the beginning of such period and at the end of such
14period. This difference may either be a charge or a credit to
15customers depending on whether the uncollectible amount is
16more or less than the uncollectible amount then included in
17the utility's rates.
18    (b) The tariff may be established outside the context of a
19general rate case filing and shall specify the terms of any
20applicable audit. The Commission shall review and by order
21approve, or approve as modified, the proposed tariff within
22180 days after the date on which it is filed. Charges and
23credits under the tariff shall be allocated to the appropriate
24customer class or classes. In addition, customers who purchase
25their electric supply from an alternative retail electric
26supplier shall not be charged by the utility for uncollectible

 

 

SB2896- 732 -LRB102 17909 JWD 25989 b

1amounts associated with electric supply provided by the
2utility to the utility's customers, provided that nothing in
3this Section is intended to affect or alter the rights and
4obligations imposed pursuant to Section 16-118 of this Act and
5any Commission order issued thereunder. Upon approval of the
6tariff, the utility shall, based on the 2008 FERC Form 1, apply
7the appropriate credit or charge based on the full year 2008
8amounts for the remainder of the 2010 calendar year. Starting
9with the 2009 FERC Form 1 reporting period and each subsequent
10period, the utility shall apply the appropriate credit or
11charge over a 12-month period beginning with the June billing
12period and ending with the May billing period, with the first
13such billing period beginning June 2010.
14    (c) The approved tariff shall provide that the utility
15shall file a petition with the Commission annually, no later
16than August 31st, seeking initiation of an annual review to
17reconcile all amounts collected with the actual uncollectible
18amount in the prior period. As part of its review, the
19Commission shall verify that the utility collects no more and
20no less than its actual uncollectible amount in each
21applicable FERC Form 1 reporting period, and that the utility
22has demonstrated actions to make its rates more affordable,
23minimize disconnections, and preserve the availability of
24utility services to all customers, consistent with item (viii)
25of subsection (d) of Section 1-102. The Commission shall
26review the prudence and reasonableness of the utility's

 

 

SB2896- 733 -LRB102 17909 JWD 25989 b

1actions to pursue minimization and collection of
2uncollectibles and preserve the availability of utility
3services to all customers, which shall include, at a minimum,
4the 6 enumerated criteria set forth in this Section. The
5Commission shall determine any required adjustments and may
6include suggestions for prospective changes in current
7practices. Nothing in this Section or the implementing tariffs
8shall affect or alter the electric utility's existing
9obligation to pursue collection of uncollectibles or the
10electric utility's right to disconnect service. A utility that
11has in effect a tariff authorized by this Section shall pursue
12minimization of and collection of uncollectibles through the
13following activities, including, but not limited to:
14        (1) contacting the customers in an effort to obtain
15    payment;
16        (2) providing delinquent customers with information
17    about possible options, including payment plans and
18    assistance programs, and how to reach agencies and
19    community-based organizations that provide assistance;
20        (3) specific action to limit disconnections in zip
21    code areas that would otherwise be disproportionately
22    impacted by the utility's credit and collection policies;
23        (4) community outreach in areas demonstrating higher
24    than average arrearages to help inform customers about
25    available assistance programs;
26        (5) providing bill payment assistance funds in an

 

 

SB2896- 734 -LRB102 17909 JWD 25989 b

1    amount that equals 50% of its total uncollectibles for
2    calendar year 2019, the funding of which shall be
3    recovered through the automatic adjustment clause that is
4    the subject of this subsection;
5        (6) demonstrating that the bill payment assistance
6    funds reduced the number of disconnections in the
7    reconciliation year;
8        (7) the offering of a Commission-approved discount
9    rate tariff pursuant to Section 9-241, tiered by income
10    level, for customers whose income falls at or below 80% of
11    area median income; and
12        (8) an arrearage reduction program for low income
13    discount rate customers that eliminates customer
14    arrearages in ratable proportion for each month that plan
15    participants timely pay their utility bill.
16        (1) identifying customers with late payments;
17        (2) contacting the customers in an effort to obtain
18    payment;
19        (3) providing delinquent customers with information
20    about possible options, including payment plans and
21    assistance programs;
22        (4) serving disconnection notices;
23        (5) implementing disconnections based on the level of
24    uncollectibles; and
25        (6) pursuing collection activities based on the level
26    of uncollectibles.

 

 

SB2896- 735 -LRB102 17909 JWD 25989 b

1    (d) Nothing in this Section shall be construed to require
2a utility to immediately disconnect service for nonpayment.
3(Source: P.A. 96-33, eff. 7-10-09; 96-1000, eff. 7-2-10.)
 
4    (220 ILCS 5/16-115)
5    Sec. 16-115. Certification of alternative retail electric
6suppliers.
7    (a) Any alternative retail electric supplier must obtain a
8certificate of service authority from the Commission in
9accordance with this Section before serving any retail
10customer or other user located in this State. An alternative
11retail electric supplier may request, and the Commission may
12grant, a certificate of service authority for the entire State
13or for a specified geographic area of the State. A license
14granted pursuant to this Section is not property and the grant
15of a license to an entity does not create a property interest
16in the license.
17    (b) An alternative retail electric supplier seeking a
18certificate of service authority shall file with the
19Commission a verified application containing information
20showing that the applicant meets the requirements of this
21Section. The alternative retail electric supplier shall
22publish notice of its application in the official State
23newspaper within 10 days following the date of its filing. No
24later than 45 days after the application is properly filed
25with the Commission, and such notice is published, the

 

 

SB2896- 736 -LRB102 17909 JWD 25989 b

1Commission shall issue its order granting or denying the
2application.
3    (c) An application for a certificate of service authority
4shall identify the area or areas in which the applicant
5intends to offer service and the types of services it intends
6to offer. Applicants that seek to serve residential or small
7commercial retail customers within a geographic area that is
8smaller than an electric utility's service area shall submit
9evidence demonstrating that the designation of this smaller
10area does not violate Section 16-115A. An applicant that seeks
11to serve residential or small commercial retail customers may
12state in its application for certification any limitations
13that will be imposed on the number of customers or maximum load
14to be served.
15    (d) The Commission shall grant the application for a
16certificate of service authority if it makes the findings set
17forth in this subsection based on the verified application and
18such other information as the applicant may submit:
19        (1) That the applicant possesses sufficient technical,
20    financial and managerial resources and abilities to
21    provide the service for which it seeks a certificate of
22    service authority. In determining the level of technical,
23    financial and managerial resources and abilities which the
24    applicant must demonstrate, the Commission shall consider
25    (i) the characteristics, including the size and financial
26    sophistication, of the customers that the applicant seeks

 

 

SB2896- 737 -LRB102 17909 JWD 25989 b

1    to serve, and (ii) whether the applicant seeks to provide
2    electric power and energy using property, plant and
3    equipment which it owns, controls or operates;
4        (2) That the applicant will comply with all applicable
5    federal, State, regional and industry rules, policies,
6    practices and procedures for the use, operation, and
7    maintenance of the safety, integrity and reliability, of
8    the interconnected electric transmission system;
9        (3) That the applicant will only provide service to
10    retail customers in an electric utility's service area
11    that are eligible to take delivery services under this
12    Act;
13        (4) That the applicant will comply with such
14    informational or reporting requirements as the Commission
15    may by rule establish and provide the information required
16    by Section 16-112. Any data related to contracts for the
17    purchase and sale of electric power and energy shall be
18    made available for review by the Staff of the Commission
19    on a confidential and proprietary basis and only to the
20    extent and for the purposes which the Commission
21    determines are reasonably necessary in order to carry out
22    the purposes of this Act;
23        (5) That the applicant will procure renewable energy
24    resources in accordance with Section 16-115D of this Act,
25    and will source electricity from clean coal facilities, as
26    defined in Section 1-10 of the Illinois Power Agency Act,

 

 

SB2896- 738 -LRB102 17909 JWD 25989 b

1    in amounts at least equal to the percentages set forth in
2    subsections (c) and (d) of Section 1-75 of the Illinois
3    Power Agency Act. For purposes of this Section:
4            (i) (blank);
5            (ii) (blank);
6            (iii) the required sourcing of electricity
7        generated by clean coal facilities, other than the
8        initial clean coal facility, shall be limited to the
9        amount of electricity that can be procured or sourced
10        at a price at or below the benchmarks approved by the
11        Commission each year in accordance with item (1) of
12        subsection (c) and items (1) and (5) of subsection (d)
13        of Section 1-75 of the Illinois Power Agency Act;
14            (iv) all alternative retail electric suppliers
15        shall execute a sourcing agreement to source
16        electricity from the initial clean coal facility, on
17        the terms set forth in paragraphs (3) and (4) of
18        subsection (d) of Section 1-75 of the Illinois Power
19        Agency Act, except that in lieu of the requirements in
20        subparagraphs (A)(v), (B)(i), (C)(v), and (C)(vi) of
21        paragraph (3) of that subsection (d), the applicant
22        shall execute one or more of the following:
23                (1) if the sourcing agreement is a power
24            purchase agreement, a contract with the initial
25            clean coal facility to purchase in each hour an
26            amount of electricity equal to all clean coal

 

 

SB2896- 739 -LRB102 17909 JWD 25989 b

1            energy made available from the initial clean coal
2            facility during such hour, which the utilities are
3            not required to procure under the terms of
4            subsection (d) of Section 1-75 of the Illinois
5            Power Agency Act, multiplied by a fraction, the
6            numerator of which is the alternative retail
7            electric supplier's retail market sales of
8            electricity (expressed in kilowatthours sold) in
9            the State during the prior calendar month and the
10            denominator of which is the total sales of
11            electricity (expressed in kilowatthours sold) in
12            the State by alternative retail electric suppliers
13            during such prior month that are subject to the
14            requirements of this paragraph (5) of subsection
15            (d) of this Section and subsection (d) of Section
16            1-75 of the Illinois Power Agency Act plus the
17            total sales of electricity (expressed in
18            kilowatthours sold) by utilities outside of their
19            service areas during such prior month, pursuant to
20            subsection (c) of Section 16-116 of this Act; or
21                (2) if the sourcing agreement is a contract
22            for differences, a contract with the initial clean
23            coal facility in each hour with respect to an
24            amount of electricity equal to all clean coal
25            energy made available from the initial clean coal
26            facility during such hour, which the utilities are

 

 

SB2896- 740 -LRB102 17909 JWD 25989 b

1            not required to procure under the terms of
2            subsection (d) of Section 1-75 of the Illinois
3            Power Agency Act, multiplied by a fraction, the
4            numerator of which is the alternative retail
5            electric supplier's retail market sales of
6            electricity (expressed in kilowatthours sold) in
7            the State during the prior calendar month and the
8            denominator of which is the total sales of
9            electricity (expressed in kilowatthours sold) in
10            the State by alternative retail electric suppliers
11            during such prior month that are subject to the
12            requirements of this paragraph (5) of subsection
13            (d) of this Section and subsection (d) of Section
14            1-75 of the Illinois Power Agency Act plus the
15            total sales of electricity (expressed in
16            kilowatthours sold) by utilities outside of their
17            service areas during such prior month, pursuant to
18            subsection (c) of Section 16-116 of this Act;
19            (v) if, in any year after the first year of
20        commercial operation, the owner of the clean coal
21        facility fails to demonstrate to the Commission that
22        the initial clean coal facility captured and
23        sequestered at least 50% of the total carbon emissions
24        that the facility would otherwise emit or that
25        sequestration of emissions from prior years has
26        failed, resulting in the release of carbon into the

 

 

SB2896- 741 -LRB102 17909 JWD 25989 b

1        atmosphere, the owner of the facility must offset
2        excess emissions. Any such carbon offsets must be
3        permanent, additional, verifiable, real, located
4        within the State of Illinois, and legally and
5        practicably enforceable. The costs of any such offsets
6        that are not recoverable shall not exceed $15 million
7        in any given year. No costs of any such purchases of
8        carbon offsets may be recovered from an alternative
9        retail electric supplier or its customers. All carbon
10        offsets purchased for this purpose and any carbon
11        emission credits associated with sequestration of
12        carbon from the facility must be permanently retired.
13        The initial clean coal facility shall not forfeit its
14        designation as a clean coal facility if the facility
15        fails to fully comply with the applicable carbon
16        sequestration requirements in any given year, provided
17        the requisite offsets are purchased. However, the
18        Attorney General, on behalf of the People of the State
19        of Illinois, may specifically enforce the facility's
20        sequestration requirement and the other terms of this
21        contract provision. Compliance with the sequestration
22        requirements and offset purchase requirements that
23        apply to the initial clean coal facility shall be
24        reviewed annually by an independent expert retained by
25        the owner of the initial clean coal facility, with the
26        advance written approval of the Attorney General;

 

 

SB2896- 742 -LRB102 17909 JWD 25989 b

1            (vi) The Commission shall, after notice and
2        hearing, revoke the certification of any alternative
3        retail electric supplier that fails to execute a
4        sourcing agreement with the initial clean coal
5        facility as required by item (5) of subsection (d) of
6        this Section. The sourcing agreements with this
7        initial clean coal facility shall be subject to both
8        approval of the initial clean coal facility by the
9        General Assembly and satisfaction of the requirements
10        of item (4) of subsection (d) of Section 1-75 of the
11        Illinois Power Agency Act, and shall be executed
12        within 90 days after any such approval by the General
13        Assembly. The Commission shall not accept an
14        application for certification from an alternative
15        retail electric supplier that has lost certification
16        under this subsection (d), or any corporate affiliate
17        thereof, for at least one year from the date of
18        revocation;
19        (6) With respect to an applicant that seeks to serve
20    residential or small commercial retail customers, that the
21    area to be served by the applicant and any limitations it
22    proposes on the number of customers or maximum amount of
23    load to be served meet the provisions of Section 16-115A,
24    provided, that the Commission can extend the time for
25    considering such a certificate request by up to 90 days,
26    and can schedule hearings on such a request;

 

 

SB2896- 743 -LRB102 17909 JWD 25989 b

1        (7) That the applicant meets the requirements of
2    subsection (a) of Section 16-128;
3        (8) That the applicant discloses whether the applicant
4    is the subject of any lawsuit filed in a court of law or
5    formal complaint filed with a regulatory agency alleging
6    fraud, deception, or unfair marketing practices or other
7    similar allegations and, if the applicant is the subject
8    of such lawsuit or formal complaint, the applicant shall
9    identify the name, case number, and jurisdiction of each
10    lawsuit or complaint. For the purpose of this item (8),
11    "formal complaint" includes only those complaints that
12    seek a binding determination from a State or federal
13    regulatory body;
14        (9) That the applicant shall continue to comply with
15    requirements for certification stated in this Section;
16        (10) That the applicant shall execute and maintain a
17    license or permit bond issued by a qualifying surety or
18    insurance company authorized to transact business in the
19    State of Illinois in favor of the People of the State of
20    Illinois. The amount of the bond shall equal $30,000 if
21    the applicant seeks to serve only nonresidential retail
22    customers with maximum electrical demands of one megawatt
23    or more, $150,000 if the applicant seeks to serve only
24    non-residential retail customers with annual electrical
25    consumption greater than 15,000 kWh, or $500,000 if the
26    applicant seeks to serve all eligible customers.

 

 

SB2896- 744 -LRB102 17909 JWD 25989 b

1    Applicants shall be required to submit an additional
2    $500,000 bond if the applicant intends to market to
3    residential customers using in-person solicitations. The
4    bond shall be conditioned upon the full and faithful
5    performance of all duties and obligations of the applicant
6    as an alternative retail electric supplier and shall be
7    valid for a period of not less than one year. The cost of
8    the bond shall be paid by the applicant. The applicant
9    shall file a copy of this bond, with a notarized
10    verification page from the issuer, as part of its
11    application for certification under 83 Ill. Adm. Code 451;
12    and
13        (11) That the applicant will comply with all other
14    applicable laws and regulations.
15    (d-3) The Commission may deny with prejudice an
16application in which the applicant fails to provide the
17Commission with information sufficient for the Commission to
18grant the application.
19    (d-5) (Blank).
20    (e) A retail customer that owns a cogeneration or
21self-generation facility and that seeks certification only to
22provide electric power and energy from such facility to retail
23customers at separate locations which customers are both (i)
24owned by, or a subsidiary or other corporate affiliate of,
25such applicant and (ii) eligible for delivery services, shall
26be granted a certificate of service authority upon filing an

 

 

SB2896- 745 -LRB102 17909 JWD 25989 b

1application and notifying the Commission that it has entered
2into an agreement with the relevant electric utilities
3pursuant to Section 16-118. Provided, however, that if the
4retail customer owning such cogeneration or self-generation
5facility would not be charged a transition charge due to the
6exemption provided under subsection (f) of Section 16-108
7prior to the certification, and the retail customers at
8separate locations are taking delivery services in conjunction
9with purchasing power and energy from the facility, the retail
10customer on whose premises the facility is located shall not
11thereafter be required to pay transition charges on the power
12and energy that such retail customer takes from the facility.
13    (f) The Commission shall have the authority to promulgate
14rules and regulations to carry out the provisions of this
15Section. On or before May 1, 1999, the Commission shall adopt a
16rule or rules applicable to the certification of those
17alternative retail electric suppliers that seek to serve only
18nonresidential retail customers with maximum electrical
19demands of one megawatt or more which shall provide for (i)
20expedited and streamlined procedures for certification of such
21alternative retail electric suppliers and (ii) specific
22criteria which, if met by any such alternative retail electric
23supplier, shall constitute the demonstration of technical,
24financial and managerial resources and abilities to provide
25service required by subsection (d) (1) of this Section, such
26as a requirement to post a bond or letter of credit, from a

 

 

SB2896- 746 -LRB102 17909 JWD 25989 b

1responsible surety or financial institution, of sufficient
2size for the nature and scope of the services to be provided;
3demonstration of adequate insurance for the scope and nature
4of the services to be provided; and experience in providing
5similar services in other jurisdictions.
6    (g) An alternative retail electric supplier may seek
7confidential treatment for the following information by filing
8an affidavit with the Commission so long as the affidavit
9meets the requirements in this subsection (g):
10        (1) the total annual kilowatt-hours delivered and sold
11    by an alternative retail electric supplier to retail
12    customers within each utility service territory and the
13    total annual kilowatt-hours delivered and sold by an
14    alternative retail electric supplier to retail customers
15    in all utility service territories in the preceding
16    calendar year as required by 83 Ill. Adm. Code 451.770;
17        (2) the total peak demand supplied by an alternative
18    retail electric supplier during the previous year in each
19    utility service territory as required by 83 Ill. Adm. Code
20    465.40;
21        (3) a good faith estimate of the amount an alternative
22    retail electric supplier expects to be obliged to pay the
23    utility under single billing tariffs during the next 12
24    months and the amount of any bond or letter of credit used
25    to demonstrate an alternative retail electric supplier's
26    credit worthiness to provide single billing services

 

 

SB2896- 747 -LRB102 17909 JWD 25989 b

1    pursuant to 83 Ill. Adm. Code 451.510(a) and (b).
2    The affidavit must be filed contemporaneously with the
3information for which confidential treatment is sought and
4must clearly state that the affiant seeks confidential
5treatment pursuant to this subsection (g) and the information
6for which confidential treatment is sought must be clearly
7identified on the confidential version of the document filed
8with the Commission. The affidavit must be accompanied by a
9"confidential" and a "public" version of the document or
10documents containing the information for which confidential
11treatment is sought.
12    If the alternative retail electric supplier has met the
13affidavit requirements of this subsection (g), then the
14Commission shall afford confidential treatment to the
15information identified in the affidavit for a period of 2
16years after the date the affidavit is received by the
17Commission.
18    Nothing in this subsection (g) prevents an alternative
19retail electric supplier from filing a petition with the
20Commission seeking confidential treatment for information
21beyond that identified in this subsection (g) or for
22information contained in other reports or documents filed with
23the Commission.
24    Nothing in this subsection (g) prevents the Commission, on
25its own motion, or any party from filing a formal petition with
26the Commission seeking to reconsider the conferring of

 

 

SB2896- 748 -LRB102 17909 JWD 25989 b

1confidential status on an item of information afforded
2confidential treatment pursuant to this subsection (g).
3    The Commission, on its own motion, may at any time
4initiate a docketed proceeding to investigate the continued
5applicability of this subsection (g) to the information
6contained in items (i), (ii), and (iii) of this subsection
7(g). If, at the end of such investigation, the Commission
8determines that a particular item of information should no
9longer be eligible for the affidavit-based process outlined in
10this subsection (g), the Commission may enter an order to
11remove that item from the list of items eligible for the
12process set forth in this subsection (g). Notwithstanding any
13such order, in the event the Commission makes such a
14determination, nothing in this subsection (g) prevents an
15alternative retail electric supplier desiring confidential
16treatment for such information from filing a formal petition
17with the Commission seeking confidential treatment for such
18information.
19(Source: P.A. 101-590, eff. 1-1-20.)
 
20    (220 ILCS 5/16-115C)
21    Sec. 16-115C. Licensure of agents, brokers, and
22consultants engaged in the procurement or sale of retail
23electricity supply for third parties.
24    (a) The purpose of this Section is to adopt licensing and
25code of conduct rules in a competitive retail electricity

 

 

SB2896- 749 -LRB102 17909 JWD 25989 b

1market to protect Illinois consumers from unfair or deceptive
2acts or practices and to provide persons acting as agents,
3brokers, and consultants engaged in the procurement or sale of
4retail electricity supply for third parties with notice of the
5illegality of those acts or practices.
6    (a-5) All third-party sales representatives engaged in the
7marketing of retail electricity supply must, prior to the
8customer signing a contract, disclose that they are not
9employed by the electric utility operating in the applicable
10service territory.
11    (b) For purposes of this Section, "agents, brokers, and
12consultants engaged in the procurement or sale of retail
13electricity supply for third parties" means any person or
14entity that attempts to procure on behalf of or sell retail
15electric service to an electric customer in the State.
16"Agents, brokers, and consultants engaged in the procurement
17or sale of retail electricity supply for third parties" does
18not include the Illinois Power Agency or any of its employees,
19any entity licensed as an alternative retail electric supplier
20pursuant to 83 Ill. Adm. Code 451 offering retail electric
21service on its own behalf, any person acting exclusively on
22behalf of a single alternative retail electric supplier on
23condition that exclusivity is disclosed to any third party
24contracted in such agent capacity, any person acting
25exclusively on behalf of a retail electric supplier on
26condition that exclusivity is disclosed to any third party

 

 

SB2896- 750 -LRB102 17909 JWD 25989 b

1contracted in such agent capacity, any person or entity
2representing a municipal power agency, as defined in Section
311-119.1-3 of the Illinois Municipal Code, or any person or
4entity that is attempting to procure on behalf of or sell
5retail electric service to a third party that has aggregate
6billing demand of all of its affiliated electric service
7accounts in Illinois of greater than 1,500 kW.
8    (c) No person or entity shall act as an agent, broker, or
9consultant engaged in the procurement or sale of retail
10electricity supply for third parties unless that person or
11entity is licensed by the Commission under this Section or is
12offering services on their own behalf under 83 Ill. Adm. Code
13451. A license granted pursuant to this Section is not
14property and the grant of a license to an entity does not
15create a property interest in the license.
16    (d) The Commission shall create requirements for licensure
17as an agent, broker, or consultant engaged in the procurement
18or sale of retail electricity supply for third parties, which
19shall include all of the following criteria:
20        (1) Technical competence.
21        (2) Managerial competence.
22        (3) Financial responsibility, including the posting of
23    an appropriate performance bond.
24        (4) Annual reporting requirements.
25    (e) Any person or entity required to be licensed under
26this Section must:

 

 

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1        (1) disclose in plain language in writing to all
2    persons it solicits (i) before July 1, 2011, the total
3    anticipated remuneration to be paid to it by any third
4    party over the period of the proposed underlying customer
5    contract and (ii) on or after July 1, 2011, the total price
6    per kilowatt-hour, and the total anticipated cost,
7    inclusive of all fees or commissions received by the
8    licensee, to be paid by the customer over the period of the
9    proposed underlying customer contract;
10        (2) disclose, if applicable, to all customers, prior
11    to the customer signing a contract, the fact that they
12    will be receiving compensation from the supplier;
13        (3) not hold itself out as independent or unaffiliated
14    with any supplier, or both, or use words reasonably
15    calculated to give that impression, unless the person
16    offering service under this Section has no contractual
17    relationship with any retail electricity supplier or its
18    affiliates regarding retail electric service in Illinois;
19        (4) not utilize false, misleading, materially
20    inaccurate, defamatory, or otherwise deceptive language or
21    materials in the soliciting or providing of its services;
22        (5) maintain copies of all marketing materials
23    disseminated to third parties for a period of not less
24    than 3 years;
25        (6) not present electricity pricing information in a
26    manner that favors one supplier over another, unless a

 

 

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1    valid pricing comparison is made utilizing all relevant
2    costs and terms; and
3        (7) comply with the requirements of Sections 2EE, 2FF,
4    2GG, and 2HH of the Consumer Fraud and Deceptive Business
5    Practices Act.
6    (f) Any person or entity licensed under this Section shall
7file with the Commission all of the following information no
8later than March of each year:
9        (1) A verified report detailing any and all
10    contractual relationships that it has with certified
11    electricity suppliers in the State regarding retail
12    electric service in Illinois.
13        (2) A verified report detailing the distribution of
14    its customers with the various certified electricity
15    suppliers in Illinois during the prior calendar year. A
16    report under this Section shall not be required to contain
17    customer-identifying information.
18        A public redacted version of the verified report may
19    be submitted to the Commission along with a proprietary
20    version. The public redacted version may redact from the
21    verified report the name or names of every certified
22    electricity supplier contained in the report to protect
23    against disclosure of competitively sensitive market share
24    information. The information shall be afforded proprietary
25    treatment for 2 years after the date of the filing of the
26    verified report.

 

 

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1        (3) A verified statement of any changes to the
2    original licensure qualifications and notice of continuing
3    compliance with all requirements.
4    (g) The Commission shall have jurisdiction over
5disciplinary proceedings and complaints, including on the
6Commission's own motion, for violations of this Section. The
7findings of a violation of this Section by the Commission
8shall result in discipline on a progressive disciplinary
9scale. For a first violation, the Commission may, in its
10discretion, suspend the license of the person or entity so
11disciplined for a period of no less than one month. For a
12second violation within a 5-year period, the Commission shall
13suspend the license of for the person or entity so disciplined
14for a period of not less than 6 months. For a third or
15subsequent violation within a 5-year period, the Commission
16shall suspend the license of the disciplined person for a
17period of not less than 2 years. Notwithstanding the minimum
18progressive suspensions, the Commission shall have authority,
19in its discretion, to impose whatever disciplinary measures it
20deems appropriate for any violation, including but not limited
21to terminating the license of the person or entity.
22    (h) This Section shall not apply to a retail customer that
23operates or manages either directly or indirectly any
24facilities, equipment, or property used or contemplated to be
25used to distribute electric power or energy if that retail
26customer is a political subdivision or public institution of

 

 

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1higher education of this State, or any corporation, company,
2limited liability company, association, joint-stock company or
3association, firm, partnership, or individual, or their
4lessees, trusts, or receivers appointed by any court
5whatsoever that are owned or controlled by the political
6subdivision, public institution of higher education, or
7operated by any of its lessees or operating agents.
8(Source: P.A. 95-679, eff. 10-11-07; 96-1385, eff. 7-29-10.)
 
9    (220 ILCS 5/19-110)
10    Sec. 19-110. Certification of alternative gas suppliers.
11    (a) The provisions of this Section shall apply only to
12alternative gas suppliers serving or seeking to serve
13residential or small commercial customers and only to the
14extent such alternative gas suppliers provide services to
15residential or small commercial customers.
16    (b) An alternative gas supplier must obtain a certificate
17of service authority from the Commission in accordance with
18this Section before serving any customer or other user located
19in this State. An alternative gas supplier may request, and
20the Commission may grant, a certificate of service authority
21for the entire State or for a specified geographic area of the
22State. An alternative gas supplier may request, and the
23Commission may grant, a certificate of service authority for
24the entire State or for a specified geographic area of the
25State. A license granted pursuant to this Section is not

 

 

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1property and the grant of a license to an entity does not
2create a property interest in the license. A person,
3corporation, or other entity acting as an alternative gas
4supplier on the effective date of this amendatory Act of the
592nd General Assembly shall have 180 days from the effective
6date of this amendatory Act of the 92nd General Assembly to
7comply with the requirements of this Section in order to
8continue to operate as an alternative gas supplier.
9    (c) An alternative gas supplier seeking a certificate of
10service authority shall file with the Commission a verified
11application containing information showing that the applicant
12meets the requirements of this Section. The alternative gas
13supplier shall publish notice of its application in the
14official State newspaper within 10 days following the date of
15its filing. No later than 45 days after the application is
16properly filed with the Commission, and such notice is
17published, the Commission shall issue its order granting or
18denying the application.
19    (d) An application for a certificate of service authority
20shall identify the area or areas in which the applicant
21intends to offer service and the types of services it intends
22to offer. Applicants that seek to serve residential or small
23commercial customers within a geographic area that is smaller
24than a gas utility's service area shall submit evidence
25demonstrating that the designation of this smaller area does
26not violate Section 19-115. An applicant may state in its

 

 

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1application for certification any limitations that will be
2imposed on the number of customers or maximum load to be
3served. The applicant shall submit as part of its application
4a statement indicating:
5        (1) Whether the applicant has been denied a natural
6    gas supplier license in any state in the United States.
7        (2) Whether the applicant has had a natural gas
8    supplier license suspended or revoked by any state in the
9    United States.
10        (3) Where, if any, other natural gas supplier license
11    applications are pending in the United States.
12        (4) Whether the applicant is the subject of any
13    lawsuits filed in a court of law or formal complaints
14    filed with a regulatory agency alleging fraud, deception
15    or unfair marketing practices, or other similar
16    allegations, identifying the name, case number, and
17    jurisdiction of each such lawsuit or complaint.
18    For the purposes of this subsection (d), formal complaints
19include only those complaints that seek a binding
20determination from a state or federal regulatory body.
21    (e) The Commission shall grant the application for a
22certificate of service authority if it makes the findings set
23forth in this subsection based on the verified application and
24such other information as the applicant may submit.
25        (1) That the applicant possesses sufficient technical,
26    financial, and managerial resources and abilities to

 

 

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1    provide the service for which it seeks a certificate of
2    service authority. In determining the level of technical,
3    financial, and managerial resources and abilities which
4    the applicant must demonstrate, the Commission shall
5    consider:
6            (A) the characteristics, including the size and
7        financial sophistication of the customers that the
8        applicant seeks to serve;
9            (B) whether the applicant seeks to provide gas
10        using property, plant, and equipment that it owns,
11        controls, or operates; and
12            (C) the applicant's commitment of resources to the
13        management of sales and marketing staff, through
14        affirmative managerial policies, independent audits,
15        technology, hands-on field monitoring and training,
16        and, in the case of applicants who will have sales
17        personnel or sales agents within the State of
18        Illinois, the applicant's managerial presence within
19        the State.
20        (2) That the applicant will comply with all applicable
21    federal, State, regional, and industry rules, policies,
22    practices, and procedures for the use, operation, and
23    maintenance of the safety, integrity, and reliability of
24    the gas transmission system.
25        (3) That the applicant will comply with such
26    informational or reporting requirements as the Commission

 

 

SB2896- 758 -LRB102 17909 JWD 25989 b

1    may by rule establish.
2        (4) That the area to be served by the applicant and any
3    limitations it proposes on the number of customers or
4    maximum amount of load to be served meet the provisions of
5    Section 19-115, provided, that if the applicant seeks to
6    serve an area smaller than the service area of a gas
7    utility or proposes other limitations on the number of
8    customers or maximum amount of load to be served, the
9    Commission can extend the time for considering such a
10    certificate request by up to 90 days, and can schedule
11    hearings on such a request.
12        (5) That the applicant shall continue to comply with
13    requirements for certification stated in this Section.
14        (6) That the applicant shall execute and maintain a
15    license or permit bond issued by a qualifying surety or
16    insurance company authorized to transact business in the
17    State of Illinois in favor of the People of the State of
18    Illinois. The amount of the bond shall equal $150,000 if
19    the applicant seeks to serve only nonresidential retail
20    customers or $500,000 if the applicant seeks to serve all
21    eligible customers. Applicants shall be required to submit
22    an additional $500,000 bond if the applicant intends to
23    market to residential customers using in-person
24    solicitations. The bond shall be conditioned upon the full
25    and faithful performance of all duties and obligations of
26    the applicant as an alternative retail gas supplier and

 

 

SB2896- 759 -LRB102 17909 JWD 25989 b

1    shall be valid for a period of not less than one year. The
2    cost of the bond shall be paid by the applicant. The
3    applicant shall file a copy of this bond, with a notarized
4    verification page from the issuer, as part of its
5    application for certification under 83 Ill. Adm. Code 551.
6        (7) That the applicant will comply with all other
7    applicable laws and rules.
8    (e-5) The Commission may deny with prejudice an
9application in which the applicant fails to provide the
10Commission with information sufficient for the Commission to
11grant the application.
12    (f) The Commission can extend the time for considering
13such a certificate request by up to 90 days, and can schedule
14hearings on such a request if:
15        (1) a party to the application proceeding has formally
16    requested that the Commission hold hearings in a pleading
17    that alleges that one or more of the allegations or
18    certifications in the application is false or misleading;
19    or
20        (2) other facts or circumstances exist that will
21    necessitate additional time or evidence in order to
22    determine whether a certificate should be issued.
23    (g) The Commission shall have the authority to promulgate
24rules to carry out the provisions of this Section. Within 30
25days after the effective date of this amendatory Act of the
2692nd General Assembly, the Commission shall adopt an emergency

 

 

SB2896- 760 -LRB102 17909 JWD 25989 b

1rule or rules applicable to the certification of those gas
2suppliers that seek to serve residential customers. Within 180
3days of the effective date of this amendatory Act of the 92nd
4General Assembly, the Commission shall adopt rules that
5specify criteria which, if met by any such alternative gas
6supplier, shall constitute the demonstration of technical,
7financial, and managerial resources and abilities to provide
8service required by item (1) of subsection (e) of this
9Section, such as a requirement to post a bond or letter of
10credit, from a responsible surety or financial institution, of
11sufficient size for the nature and scope of the services to be
12provided, demonstration of adequate insurance for the scope
13and nature of the services to be provided, and experience in
14providing similar services in other jurisdictions.
15    (h) The Commission may deny with prejudice any application
16that repeatedly fails to include the attachments,
17documentation, and affidavits required by the application form
18or that repeatedly fails to provide any other information
19required by this Section.
20    (i) An alternative gas supplier may seek confidential
21treatment for the reporting to the Commission of its total
22annual dekatherms delivered and sold by it to residential and
23small commercial customers by utility service territory during
24the preceding year via the filing of an affidavit with the
25Commission so long as the affidavit meets the requirements of
26this subsection (i). The affidavit must be filed

 

 

SB2896- 761 -LRB102 17909 JWD 25989 b

1contemporaneously with the information for which confidential
2treatment is sought and must clearly state that the affiant
3seeks confidential treatment pursuant to this subsection (i)
4and the information for which confidential treatment is sought
5must be clearly identified on the confidential version of the
6document filed with the Commission. The affidavit must be
7accompanied by both a "confidential" and a "public" version of
8the document or documents containing the information for which
9confidential treatment is sought.
10    If the alternative gas supplier has met the affidavit
11requirements of this subsection (i), then the Commission shall
12afford confidential treatment to the information identified in
13the affidavit for a period of 2 years after the date the
14affidavit is received by the Commission.
15    Nothing in this subsection (i) prevents an alternative gas
16supplier from filing a petition with the Commission seeking
17confidential treatment for information beyond that identified
18in this subsection (i) or for information contained in other
19reports or documents filed with the Commission.
20    Nothing in this subsection (i) prevents the Commission, on
21its own motion, or any party from filing a formal petition with
22the Commission seeking to reconsider the conferring of
23confidential status pursuant to this subsection (i).
24    The Commission, on its own motion, may at any time
25initiate a docketed proceeding to investigate the continued
26applicability of this affidavit-based process for seeking

 

 

SB2896- 762 -LRB102 17909 JWD 25989 b

1confidential treatment. If, at the end of such investigation,
2the Commission determines that this affidavit-based process
3for seeking confidential treatment for the information is no
4longer necessary, the Commission may enter an order to that
5effect. Notwithstanding any such order, in the event the
6Commission makes such a determination, nothing in this
7subsection (i) prevents an alternative gas supplier desiring
8confidential treatment for such information from filing a
9formal petition with the Commission seeking confidential
10treatment for such information.
11(Source: P.A. 101-590, eff. 1-1-20.)
 
12    (220 ILCS 5/19-145)
13    Sec. 19-145. Automatic adjustment clause tariff;
14uncollectibles.
15    (a) A gas utility shall be permitted, at its election, to
16recover through an automatic adjustment clause tariff the
17incremental difference between its actual uncollectible amount
18as set forth in Account 904 in the utility's most recent annual
19Form 21 ILCC and the uncollectible amount included in the
20utility's rates for the period reported in such annual Form 21
21ILCC. The Commission may, in a proceeding to review a general
22rate case filed subsequent to the effective date of the tariff
23established under this Section, prospectively switch, from
24using the actual uncollectible amount set forth in Account 904
25to using net write-offs in such tariff, but only if net

 

 

SB2896- 763 -LRB102 17909 JWD 25989 b

1write-offs are also used to determine the utility's
2uncollectible amount in rates. In the event the Commission
3requires such a change, it shall be made effective at the
4beginning of the first full calendar year after the new rates
5approved in such proceeding are first placed in effect and an
6adjustment shall be made, if necessary, to ensure the change
7does not result in double-recovery or unrecovered
8uncollectible amounts for any year. For purposes of this
9Section, "uncollectible amount" means the expense set forth in
10Account 904 of the utility's Form 21 ILCC or cost of net
11write-offs as appropriate. In the event the utility's rates
12change during the period of time reported in its most recent
13annual Form 21 ILCC, the uncollectible amount included in the
14utility's rates during such period of time for purposes of
15this Section will be a weighted average, based on revenues
16earned during such period by the utility under each set of
17rates, of the uncollectible amount included in the utility's
18rates at the beginning of such period and at the end of such
19period. This difference may either be a charge or a credit to
20customers depending on whether the uncollectible amount is
21more or less than the uncollectible amount then included in
22the utility's rates.
23    (b) The tariff may be established outside the context of a
24general rate case filing, and shall specify the terms of any
25applicable audit. The Commission shall review and by order
26approve, or approve as modified, the proposed tariff within

 

 

SB2896- 764 -LRB102 17909 JWD 25989 b

1180 days after the date on which it is filed. Charges and
2credits under the tariff shall be allocated to the appropriate
3customer class or classes. In addition, customers who do not
4purchase their gas supply from a gas utility shall not be
5charged by the utility for uncollectible amounts associated
6with gas supply provided by the utility to the utility's
7customers. Upon approval of the tariff, the utility shall,
8based on the 2008 Form 21 ILCC, apply the appropriate credit or
9charge based on the full year 2008 amounts for the remainder of
10the 2010 calendar year. Starting with the 2009 Form 21 ILCC
11reporting period and each subsequent period, the utility shall
12apply the appropriate credit or charge over a 12-month period
13beginning with the June billing period and ending with the May
14billing period, with the first such billing period beginning
15June 2010.
16    (c) The approved tariff shall provide that the utility
17shall file a petition with the Commission annually, no later
18than August 31st, seeking initiation of an annual review to
19reconcile all amounts collected with the actual uncollectible
20amount in the prior period. As part of its review, the
21Commission shall verify that the utility collects no more and
22no less than its actual uncollectible amount in each
23applicable Form 21 ILCC reporting period, and that the utility
24has demonstrated actions to make its rates more affordable,
25minimize disconnections, and therefore preserve the
26availability of utility services to all customers, consistent

 

 

SB2896- 765 -LRB102 17909 JWD 25989 b

1with item (viii) of subsection (d) of Section 1-102. The
2Commission shall review the prudence and reasonableness of the
3utility's actions to pursue minimization and collection of
4uncollectibles and preserve the availability of utility
5services to all customers, which shall include, at a minimum,
6the 6 enumerated criteria set forth in this Section. The
7Commission shall determine any required adjustments and may
8include suggestions for prospective changes in current
9practices. Nothing in this Section or the implementing tariffs
10shall affect or alter the gas utility's existing obligation to
11pursue collection of uncollectibles or the gas utility's right
12to disconnect service. A utility that has in effect a tariff
13authorized by this Section shall pursue minimization of and
14collection of uncollectibles through the following activities,
15including but not limited to:
16        (1) contacting the customers in an effort to obtain
17    payment;
18        (2) providing delinquent customers with information
19    about possible options, including payment plans and
20    assistance programs, and how to reach agencies and
21    community-based organizations that provide assistance;
22        (3) specific action to limit disconnections in zip
23    code areas that would otherwise be disproportionately
24    impacted by the utility's credit and collection policies;
25        (4) community outreach in areas demonstrating higher
26    than average arrearages to help inform customers about

 

 

SB2896- 766 -LRB102 17909 JWD 25989 b

1    available assistance programs;
2        (5) providing bill payment assistance funds in an
3    amount that equals 50% of its total uncollectibles for
4    calendar year 2019, the funding of which shall be
5    recovered through the automatic adjustment clause that is
6    the subject of this subsection;
7        (6) demonstrating that the bill payment assistance
8    funds reduced the number of disconnections in the
9    reconciliation year;
10        (7) the offering of a Commission-approved discount
11    rate tariff pursuant to Section 9-241, tiered by income
12    level, for customers whose income falls at or below 80% of
13    area median income; and
14        (8) an arrearage reduction program for low income
15    discount rate customers that eliminates customer
16    arrearages in ratable proportion for each month that plan
17    participants timely pay their utility bill.
18        (1) identifying customers with late payments;
19        (2) contacting the customers in an effort to obtain
20    payment;
21        (3) providing delinquent customers with information
22    about possible options, including payment plans and
23    assistance programs;
24        (4) serving disconnection notices;
25        (5) implementing disconnections based on the level of
26    uncollectibles; and

 

 

SB2896- 767 -LRB102 17909 JWD 25989 b

1        (6) pursuing collection activities based on the level
2    of uncollectibles.
3    (d) Nothing in this Section shall be construed to require
4a utility to immediately disconnect service for nonpayment.
5(Source: P.A. 96-33, eff. 7-10-09.)
 
6    Section 30-41. The Citizens Utility Board Act is amended
7by changing Sections 3, 5, and 13 as follows:
 
8    (220 ILCS 10/3)  (from Ch. 111 2/3, par. 903)
9    Sec. 3. Definitions. As used in this Act:
10     "Affiliated organization" means any Illinois nonprofit
11organization that has a formal association with the
12corporation, as demonstrated by such factors such as use of
13the corporation name or receipt of a gift, grant or donation
14from the corporation.
15    (1)"Board" means the board of directors of the
16corporation.
17    (2)"Campaign contribution" means a gift, subscription,
18loan, advance or deposit of money or anything of value, made
19for the purpose of electing a candidate to the board; or a
20contract, a promise or agreement, express or implied, whether
21or not legally enforceable, to make any campaign contribution;
22but does not include the value of services provided without
23compensation by individuals who volunteer a portion or all of
24their time on behalf of a candidate or political committee, or

 

 

SB2896- 768 -LRB102 17909 JWD 25989 b

1the use of real or personal property and the cost of
2invitations, food and beverages, voluntarily provided by an
3individual to a candidate in rendering voluntary personal
4services on the individual's residential premises for
5candidate-related activities if the cumulative value of the
6activities to the individual on behalf of any candidate does
7not exceed $100 for any election.
8    (3)"Campaign expenditures" means a purchase, payment
9distribution, loan, advance, deposit or gift of money or
10anything of value, made for the purpose of electing a
11candidate to the board; or a contract, promise, or agreement,
12express or implied, whether or not legally enforceable, to
13make any campaign expenditure; but does not include the use of
14real or personal property and the cost of invitations, food
15and beverages, voluntarily provided by an individual to a
16candidate in rendering voluntary personal services on the
17individual's residential premises for candidate-related
18activities if the cumulative value of the activities by the
19individual on behalf of any candidate does not exceed $100 for
20any election.
21    (4)"Class A utility" means any gas, electric or water
22public utility with annual total gross operating revenues of
23$2.5 million or more or any telephone public utility with
24annual total gross operating revenues of $1,600,000 or more on
25the effective date of this Act.
26    (5)"Corporation" means the citizens utility board.

 

 

SB2896- 769 -LRB102 17909 JWD 25989 b

1    (6)"Director" means any member of the board.
2    (7)"District" means a corporation district, the boundaries
3of which are congruent with the boundaries of the
4Congressional districts in the State.
5    (8)"Immediate family" of a person means the person's
6spouse and legal dependents.
7    (9)"Member" means any person who satisfies the
8requirements for membership under Section 4.
9    (10)"Periodic customer billing" means a demand for payment
10for utility services by a public utility to a residential
11utility consumer on a monthly or other regular basis.
12    (11)"Political committee" means any committee, club,
13association or other group of persons which make campaign
14expenditures or receive campaign contributions during the year
15before an election of the board.
16    (12)"Public utility" means any person who owns, operates,
17manages or controls any plant or equipment or any part of a
18plant or equipment, within the State, for the conveyance of
19telephone messages or for the production, transmission,
20delivery or furnishing of heat, light, water or power either
21directly or indirectly to or for the public. "Public utility"
22includes any person engaged in the transmission or delivery of
23natural gas for compensation within this State by means of
24pipes or mains. "Public utility" does not include a
25cooperative association organized for the purpose of
26furnishing telephone service to its members only. "Public

 

 

SB2896- 770 -LRB102 17909 JWD 25989 b

1utility" does not include electric cooperatives as defined in
2Section 3-119 of the Public Utilities Act. However, "public
3utility" does not include either public utilities that are
4owned and operated by a political subdivision, public
5institution of higher education or municipal corporation of
6this State or public utilities that are owned by such
7political subdivision, public institution of higher education,
8or municipal corporation and operated by any of its lessees or
9operating agents.
10    (13)"Utility consumer" means any individual or entity,
11which is not governmental or a public utility, which is
12located in this State and which is furnished with a utility
13service by a public utility.
14    (14)"Utility service" means electricity, natural gas,
15water and telephone service supplied by a public utility.
16(Source: P.A. 91-357, eff. 7-29-99.)
 
17    (220 ILCS 10/5)  (from Ch. 111 2/3, par. 905)
18    Sec. 5. Powers and duties.
19    (1) The corporation shall:
20        (a) Represent and protect the interests of the
21    residential utility consumers of this State. All actions
22    by the corporation under this Act shall be directed toward
23    such duty; provided that the corporation may also give due
24    consideration to the interests of business in the State.
25        (b) Inform, in so far as possible, all utility

 

 

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1    consumers about the corporation, including the procedure
2    for obtaining membership in the corporation.
3    (2) The corporation shall have all the powers necessary or
4convenient for the effective representation and protection of
5the interest of utility consumers and to implement this Act,
6including the following powers in addition to all other powers
7granted by this Act.
8        (a) To make, amend and repeal bylaws and rules for the
9    regulation of its affairs and the conduct of its business;
10    to adopt an official seal and alter it at pleasure; to
11    maintain an office; to sue and be sued in its own name,
12    plead and be impleaded; and to make and execute contracts
13    and other instruments necessary or convenient to the
14    exercise of the powers of the corporation.
15        (b) To employ such agents, employees and special
16    advisors as it finds necessary and to fix their
17    compensation.
18        (c) To solicit and accept gifts, loans, including
19    loans made by the Illinois Commerce Commission from funds
20    appropriated for that purpose by law, or other aid in
21    order to support activities concerning the interests of
22    utility consumers. Except as provided in Section 5.1, the
23    corporation may not accept gifts, loans or other aid from
24    any public utility or from any director, employee or agent
25    or member of the immediate family of a director, employee
26    or agent of any public utility, or from any foundation or

 

 

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1    nonprofit organization established by or affiliated with a
2    public utility and, after the first election the
3    corporation, may not accept from any individual, private
4    corporation, association or partnership in any single year
5    a total of more than $1,000 in gifts. Under this
6    paragraph, "aid" does not mean payment of membership dues.
7        (d) To intervene as a party or otherwise participate
8    on behalf of utility consumers in any proceeding which
9    affects the interest of utility consumers.
10        (e) To represent the interests of utility consumers
11    before the Illinois Commerce Commission, the Federal
12    Energy Regulatory Commission, the Federal Communications
13    Commission, the courts, and other public bodies, except
14    that no director, employee or agent of the corporation may
15    engage in lobbying without first complying with any
16    applicable statute, administrative rule or other
17    regulation relating to lobbying.
18        (f) To establish annual dues which shall be set at a
19    level that provides sufficient funding for the corporation
20    to effectively perform its powers and duties, and is
21    affordable for as many utility consumers as is possible.
22        (g) To implement solicitation for corporation funding
23    and membership.
24        (h) To seek tax exempt status under State and federal
25    law, including 501(c)(3) status under the United States
26    Internal Revenue Code.

 

 

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1        (i) To provide information and advice to utility
2    consumers on any matter with respect to utility service,
3    including but not limited to information and advice on
4    benefits and methods of energy conservation.
5    (3) The powers, duties, rights and privileges conferred or
6imposed upon the corporation by this Act may not be
7transferred.
8    (4) The corporation shall refrain from interfering with
9collective bargaining rights of any employees of a public
10utility.
11(Source: P.A. 91-50, eff. 6-30-99.)
 
12    (220 ILCS 10/13)  (from Ch. 111 2/3, par. 913)
13    Sec. 13. Public records. Statements filed with the
14corporation shall be available for public inspection at the
15office of the corporation during reasonable hours of the day.
16With regard to the records described in this Section, a
17corporation and any affiliated organizations are considered
18public bodies subject to the provisions of the Freedom of
19Information Act. Such records may be copied. The corporation
20may charge a reasonable fee for the cost of such copies.
21(Source: P.A. 83-945.)
 
22    Section 30-45. The Energy Assistance Act is amended by
23changing Sections 6, 13, and 18 and by adding Section 20 as
24follows:
 

 

 

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1    (305 ILCS 20/6)  (from Ch. 111 2/3, par. 1406)
2    Sec. 6. Eligibility, Conditions of Participation, and
3Energy Assistance.
4    (a) Any person who is a resident of the State of Illinois
5and whose household income is not greater than an amount
6determined annually by the Department, in consultation with
7the Policy Advisory Council, may apply for assistance pursuant
8to this Act in accordance with regulations promulgated by the
9Department. In setting the annual eligibility level, the
10Department shall consider the amount of available funding and
11may not set a limit higher than 150% of the federal nonfarm
12poverty level as established by the federal Office of
13Management and Budget or 60% of the State median income for the
14current State fiscal year as established by the U.S.
15Department of Health and Human Services; except that for the
16period from the effective date of this amendatory Act of the
17101st General Assembly through June 30, 2021, the Department
18may establish limits not higher than 200% of that poverty
19level. The Department, in consultation with the Policy
20Advisory Council, may adjust the percentage of poverty level
21annually in accordance with federal guidelines and based on
22funding availability.
23    (b) Applicants who qualify for assistance pursuant to
24subsection (a) of this Section shall, subject to appropriation
25from the General Assembly and subject to availability of funds

 

 

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1to the Department, receive energy assistance as provided by
2this Act. The Department, upon receipt of monies authorized
3pursuant to this Act for energy assistance, shall commit funds
4for each qualified applicant in an amount determined by the
5Department. In determining the amounts of assistance to be
6provided to or on behalf of a qualified applicant, the
7Department shall ensure that the highest amounts of assistance
8go to households with the greatest energy costs in relation to
9household income. The Department shall include factors such as
10energy costs, household size, household income, and region of
11the State when determining individual household benefits. In
12setting assistance levels, the Department shall attempt to
13provide assistance to approximately the same number of
14households who participated in the 1991 Residential Energy
15Assistance Partnership Program. Such assistance levels shall
16be adjusted annually on the basis of funding availability and
17energy costs. In promulgating rules for the administration of
18this Section the Department shall assure that a minimum of 1/3
19of funds available for benefits to eligible households with
20the lowest incomes and that elderly households, households
21with children under the age of 6 years old, and households with
22persons with disabilities are offered a priority application
23period.
24    (c) If the applicant is not a customer of record of an
25energy provider for energy services or an applicant for such
26service, such applicant shall receive a direct energy

 

 

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1assistance payment in an amount established by the Department
2for all such applicants under this Act; provided, however,
3that such an applicant must have rental expenses for housing
4greater than 30% of household income.
5    (c-1) This subsection shall apply only in cases where: (1)
6the applicant is not a customer of record of an energy provider
7because energy services are provided by the owner of the unit
8as a portion of the rent; (2) the applicant resides in housing
9subsidized or developed with funds provided under the Rental
10Housing Support Program Act or under a similar locally funded
11rent subsidy program, or is the voucher holder who resides in a
12rental unit within the State of Illinois and whose monthly
13rent is subsidized by the tenant-based Housing Choice Voucher
14Program under Section 8 of the U.S. Housing Act of 1937; and
15(3) the rental expenses for housing are no more than 30% of
16household income. In such cases, the household may apply for
17an energy assistance payment under this Act and the owner of
18the housing unit shall cooperate with the applicant by
19providing documentation of the energy costs for that unit. Any
20compensation paid to the energy provider who supplied energy
21services to the household shall be paid on behalf of the owner
22of the housing unit providing energy services to the
23household. The Department shall report annually to the General
24Assembly on the number of households receiving energy
25assistance under this subsection and the cost of such
26assistance. The provisions of this subsection (c-1), other

 

 

SB2896- 777 -LRB102 17909 JWD 25989 b

1than this sentence, are inoperative after August 31, 2012.
2    (d) If the applicant is a customer of an energy provider,
3such applicant shall receive energy assistance in an amount
4established by the Department for all such applicants under
5this Act, such amount to be paid by the Department to the
6energy provider supplying winter energy service to such
7applicant. Such applicant shall:
8        (i) make all reasonable efforts to apply to any other
9    appropriate source of public energy assistance; and
10        (ii) sign a waiver permitting the Department to
11    receive income information from any public or private
12    agency providing income or energy assistance and from any
13    employer, whether public or private.
14    (e) Any qualified applicant pursuant to this Section may
15receive or have paid on such applicant's behalf an emergency
16assistance payment to enable such applicant to obtain access
17to winter energy services. Any such payments shall be made in
18accordance with regulations of the Department.
19    (f) The Department may, if sufficient funds are available,
20provide additional benefits to certain qualified applicants:
21        (i) for the reduction of past due amounts owed to
22    energy providers; and
23        (ii) to assist the household in responding to
24    excessively high summer temperatures or energy costs.
25    Households containing elderly members, children, a person
26    with a disability, or a person with a medical need for

 

 

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1    conditioned air shall receive priority for receipt of such
2    benefits.
3(Source: P.A. 101-636, eff. 6-10-20.)
 
4    (305 ILCS 20/13)
5    (Section scheduled to be repealed on January 1, 2025)
6    Sec. 13. Supplemental Low-Income Energy Assistance Fund.
7    (a) The Supplemental Low-Income Energy Assistance Fund is
8hereby created as a special fund in the State Treasury. The
9Supplemental Low-Income Energy Assistance Fund is authorized
10to receive moneys from voluntary donations from individuals,
11foundations, corporations, and other sources, moneys received
12pursuant to Section 17, and, by statutory deposit, the moneys
13collected pursuant to this Section. The Fund is also
14authorized to receive voluntary donations from individuals,
15foundations, corporations, and other sources. Subject to
16appropriation, the Department shall use moneys from the
17Supplemental Low-Income Energy Assistance Fund for payments to
18electric or gas public utilities, municipal electric or gas
19utilities, and electric cooperatives on behalf of their
20customers who are participants in the program authorized by
21Sections 4 and 18 of this Act, for the provision of
22weatherization services and for administration of the
23Supplemental Low-Income Energy Assistance Fund. All other
24deposits, except for the Energy Assistance Charge in
25subsection (b), are not subject to the percentage restrictions

 

 

SB2896- 779 -LRB102 17909 JWD 25989 b

1related to administrative and weatherization expenses provided
2in this subsection. The yearly expenditures for weatherization
3may not exceed 10% of the amount collected during the year
4pursuant to this Section, except when unspent funds from the
5Supplemental Low-Income Energy Assistance Fund are reallocated
6from a previous year; any unspent balance of the 10%
7weatherization allowance may be utilized for weatherization
8expenses in the year they are reallocated. The yearly
9administrative expenses of the Supplemental Low-Income Energy
10Assistance Fund may not exceed 13% 10% of the amount collected
11during that year pursuant to this Section, except when unspent
12funds from the Supplemental Low-Income Energy Assistance Fund
13are reallocated from a previous year; any unspent balance of
14the 13% 10% administrative allowance may be utilized for
15administrative expenses in the year they are reallocated. Of
16the 13% administrative allowance, no less than 8% shall be
17provided to Local Administrative Agencies for administrative
18expenses.
19    (b) Notwithstanding the provisions of Section 16-111 of
20the Public Utilities Act but subject to subsection (k) of this
21Section, each public utility, electric cooperative, as defined
22in Section 3.4 of the Electric Supplier Act, and municipal
23utility, as referenced in Section 3-105 of the Public
24Utilities Act, that is engaged in the delivery of electricity
25or the distribution of natural gas within the State of
26Illinois shall, effective January 1, 2022 effective January 1,

 

 

SB2896- 780 -LRB102 17909 JWD 25989 b

11998, assess each of its customer accounts a monthly Energy
2Assistance Charge for the Supplemental Low-Income Energy
3Assistance Fund. The delivering public utility, municipal
4electric or gas utility, or electric or gas cooperative for a
5self-assessing purchaser remains subject to the collection of
6the fee imposed by this Section. The monthly charge shall be as
7follows:
8        (1) Base Energy Assistance Charge per month on each
9    account for residential electrical service;
10        (2) Base Energy Assistance Charge per month on each
11    account for residential gas service;
12        (3) Ten times the Base Energy Assistance Charge per
13    month on each account for nonresidential electric service
14    which had less than 10 megawatts of peak demand during the
15    previous calendar year;
16        (4) Ten times the Base Energy Assistance Charge per
17    month on each account for nonresidential gas service which
18    had distributed to it less than 4,000,000 therms of gas
19    during the previous calendar year;
20        (5) Three hundred and seventy-five times the Base
21    Energy Assistance Charge per month on each account for
22    nonresidential electric service which had 10 megawatts or
23    greater of peak demand during the previous calendar year;
24    and
25        (6) Three hundred and seventy-five times the Base
26    Energy Assistance Charge per month on each account for

 

 

SB2896- 781 -LRB102 17909 JWD 25989 b

1    nonresidential gas service which had 4,000,000 or more
2    therms of gas distributed to it during the previous
3    calendar year.
4    The Base Energy Assistance Charge shall be $0.48 per month
5for the calendar year beginning January 1, 2022 and shall
6increase by $0.16 per month for any calendar year, provided no
7less than 80% of the previous State fiscal year's available
8Supplemental Low-Income Energy Assistance Fund funding was
9exhausted. The maximum Base Energy Assistance Charge shall not
10exceed $0.96 per month for any calendar year.
11        (1) $0.48 per month on each account for residential
12    electric service;
13        (2) $0.48 per month on each account for residential
14    gas service;
15        (3) $4.80 per month on each account for
16    non-residential electric service which had less than 10
17    megawatts of peak demand during the previous calendar
18    year;
19        (4) $4.80 per month on each account for
20    non-residential gas service which had distributed to it
21    less than 4,000,000 therms of gas during the previous
22    calendar year;
23        (5) $360 per month on each account for non-residential
24    electric service which had 10 megawatts or greater of peak
25    demand during the previous calendar year; and
26        (6) $360 per month on each account for non-residential

 

 

SB2896- 782 -LRB102 17909 JWD 25989 b

1    gas service which had 4,000,000 or more therms of gas
2    distributed to it during the previous calendar year.
3    The incremental change to such charges imposed by Public
4Act 99-933 and this amendatory Act of the 102nd General
5Assembly this amendatory Act of the 96th General Assembly
6shall not (i) be used for any purpose other than to directly
7assist customers and (ii) be applicable to utilities serving
8less than 25,000 100,000 customers in Illinois on January 1,
92021 2009. The incremental change to such charges imposed by
10this amendatory Act of the 102nd General Assembly are intended
11to increase utilization of the Percentage of Income Payment
12Plan (PIPP or PIP Plan) and shall be applied such that PIP Plan
13enrollment is at least doubled, as compared to 2020
14enrollment, by 2024.
15    In addition, electric and gas utilities have committed,
16and shall contribute, a one-time payment of $22 million to the
17Fund, within 10 days after the effective date of the tariffs
18established pursuant to Sections 16-111.8 and 19-145 of the
19Public Utilities Act to be used for the Department's cost of
20implementing the programs described in Section 18 of this
21amendatory Act of the 96th General Assembly, the Arrearage
22Reduction Program described in Section 18, and the programs
23described in Section 8-105 of the Public Utilities Act. If a
24utility elects not to file a rider within 90 days after the
25effective date of this amendatory Act of the 96th General
26Assembly, then the contribution from such utility shall be

 

 

SB2896- 783 -LRB102 17909 JWD 25989 b

1made no later than February 1, 2010.
2    (c) For purposes of this Section:
3        (1) "residential electric service" means electric
4    utility service for household purposes delivered to a
5    dwelling of 2 or fewer units which is billed under a
6    residential rate, or electric utility service for
7    household purposes delivered to a dwelling unit or units
8    which is billed under a residential rate and is registered
9    by a separate meter for each dwelling unit;
10        (2) "residential gas service" means gas utility
11    service for household purposes distributed to a dwelling
12    of 2 or fewer units which is billed under a residential
13    rate, or gas utility service for household purposes
14    distributed to a dwelling unit or units which is billed
15    under a residential rate and is registered by a separate
16    meter for each dwelling unit;
17        (3) "non-residential electric service" means electric
18    utility service which is not residential electric service;
19    and
20        (4) "non-residential gas service" means gas utility
21    service which is not residential gas service.
22    (d) Within 30 days after the effective date of this
23amendatory Act of the 96th General Assembly, each public
24utility engaged in the delivery of electricity or the
25distribution of natural gas shall file with the Illinois
26Commerce Commission tariffs incorporating the Energy

 

 

SB2896- 784 -LRB102 17909 JWD 25989 b

1Assistance Charge in other charges stated in such tariffs,
2which shall become effective no later than the beginning of
3the first billing cycle following such filing.
4    (e) The Energy Assistance Charge assessed by electric and
5gas public utilities shall be considered a charge for public
6utility service.
7    (f) By the 20th day of the month following the month in
8which the charges imposed by the Section were collected, each
9public utility, municipal utility, and electric cooperative
10shall remit to the Department of Revenue all moneys received
11as payment of the Energy Assistance Charge on a return
12prescribed and furnished by the Department of Revenue showing
13such information as the Department of Revenue may reasonably
14require; provided, however, that a utility offering an
15Arrearage Reduction Program or Supplemental Arrearage
16Reduction Program pursuant to Section 18 of this Act shall be
17entitled to net those amounts necessary to fund and recover
18the costs of such Programs as authorized by that Section that
19is no more than the incremental change in such Energy
20Assistance Charge authorized by Public Act 96-33. If a
21customer makes a partial payment, a public utility, municipal
22utility, or electric cooperative may elect either: (i) to
23apply such partial payments first to amounts owed to the
24utility or cooperative for its services and then to payment
25for the Energy Assistance Charge or (ii) to apply such partial
26payments on a pro-rata basis between amounts owed to the

 

 

SB2896- 785 -LRB102 17909 JWD 25989 b

1utility or cooperative for its services and to payment for the
2Energy Assistance Charge.
3    If any payment provided for in this Section exceeds the
4distributor's liabilities under this Act, as shown on an
5original return, the Department may authorize the distributor
6to credit such excess payment against liability subsequently
7to be remitted to the Department under this Act, in accordance
8with reasonable rules adopted by the Department. If the
9Department subsequently determines that all or any part of the
10credit taken was not actually due to the distributor, the
11distributor's discount shall be reduced by an amount equal to
12the difference between the discount as applied to the credit
13taken and that actually due, and that distributor shall be
14liable for penalties and interest on such difference.
15    (g) The Department of Revenue shall deposit into the
16Supplemental Low-Income Energy Assistance Fund all moneys
17remitted to it in accordance with subsection (f) of this
18Section. ; provided, however, that the amounts remitted by
19each utility shall be used to provide assistance to that
20utility's customers. The utilities shall coordinate with the
21Department to establish an equitable and practical methodology
22for implementing this subsection (g) beginning with the 2010
23program year.
24    (h) On or before December 31, 2002, the Department shall
25prepare a report for the General Assembly on the expenditure
26of funds appropriated from the Low-Income Energy Assistance

 

 

SB2896- 786 -LRB102 17909 JWD 25989 b

1Block Grant Fund for the program authorized under Section 4 of
2this Act.
3    (i) The Department of Revenue may establish such rules as
4it deems necessary to implement this Section.
5    (j) The Department of Commerce and Economic Opportunity
6may establish such rules as it deems necessary to implement
7this Section.
8    (k) The charges imposed by this Section shall only apply
9to customers of municipal electric or gas utilities and
10electric or gas cooperatives if the municipal electric or gas
11utility or electric or gas cooperative makes an affirmative
12decision to impose the charge. If a municipal electric or gas
13utility or an electric cooperative makes an affirmative
14decision to impose the charge provided by this Section, the
15municipal electric or gas utility or electric cooperative
16shall inform the Department of Revenue in writing of such
17decision when it begins to impose the charge. If a municipal
18electric or gas utility or electric or gas cooperative does
19not assess this charge, the Department may not use funds from
20the Supplemental Low-Income Energy Assistance Fund to provide
21benefits to its customers under the program authorized by
22Section 4 of this Act.
23    In its use of federal funds under this Act, the Department
24may not cause a disproportionate share of those federal funds
25to benefit customers of systems which do not assess the charge
26provided by this Section.

 

 

SB2896- 787 -LRB102 17909 JWD 25989 b

1    This Section is repealed on January 1, 2025 unless renewed
2by action of the General Assembly.
3(Source: P.A. 99-457, eff. 1-1-16; 99-906, eff. 6-1-17;
499-933, eff. 1-27-17; 100-863, eff. 8-14-18; 100-1171, eff.
51-4-19.)
 
6    (305 ILCS 20/18)
7    Sec. 18. Financial assistance; payment plans.
8    (a) The Percentage of Income Payment Plan (PIPP or PIP
9Plan) is hereby created as a mandatory bill payment assistance
10program for low-income residential customers of utilities
11serving more than 100,000 100,000 retail customers as of
12January 1, 2021 2009. The PIP Plan will:
13        (1) bring participants' gas and electric bills into
14    the range of affordability;
15        (2) provide incentives for participants to make timely
16    payments;
17        (3) encourage participants to reduce usage and
18    participate in conservation and energy efficiency measures
19    that reduce the customer's bill and payment requirements;
20    and
21        (4) identify participants whose homes are most in need
22    of weatherization; and .
23        (5) endeavor to maximize participation and spend at
24    least 80% of the funding available for the year.
25    (b) For purposes of this Section:

 

 

SB2896- 788 -LRB102 17909 JWD 25989 b

1        (1) "LIHEAP" means the energy assistance program
2    established under the Illinois Energy Assistance Act and
3    the Low-Income Home Energy Assistance Act of 1981.
4        (2) "Plan participant" is an eligible participant who
5    is also eligible for the PIPP and who will receive either a
6    percentage of income payment credit under the PIPP
7    criteria set forth in this Act or a benefit pursuant to
8    Section 4 of this Act. Plan participants are a subset of
9    eligible participants.
10        (3) "Pre-program arrears" means the amount a plan
11    participant owes for gas or electric service at the time
12    the participant is determined to be eligible for the PIPP
13    or the program set forth in Section 4 of this Act.
14        (4) "Eligible participant" means any person who has
15    applied for, been accepted and is receiving residential
16    service from a gas or electric utility and who is also
17    eligible for LIHEAP or otherwise satisfies the eligibility
18    criteria set forth in paragraph (1) of subsection (c).
19    (c) The PIP Plan shall be administered as follows:
20        (1) The Department shall coordinate with Local
21    Administrative Agencies (LAAs), to determine eligibility
22    for the Illinois Low Income Home Energy Assistance Program
23    (LIHEAP) pursuant to the Energy Assistance Act, provided
24    that eligible income shall be no more than 150% of the
25    poverty level or 60% of the State median income, except
26    that for the period from the effective date of this

 

 

SB2896- 789 -LRB102 17909 JWD 25989 b

1    amendatory Act of the 101st General Assembly through June
2    30, 2021, eligible income shall be no more than 200% of the
3    poverty level. Applicants will be screened to determine
4    whether the applicant's projected payments for electric
5    service or natural gas service over a 12-month period
6    exceed the criteria established in this Section. The
7    Department, in consultation with the Policy Advisory
8    Council, may adjust the percentage of poverty level
9    annually to determine income eligibility. To maintain the
10    financial integrity of the program, the Department may
11    limit eligibility to households with income below 125% of
12    the poverty level.
13        (2) The Department shall establish the percentage of
14    income formula to determine the amount of a monthly credit
15    for participants with eligible income based on poverty
16    level. , not to exceed $150 per month per household, not to
17    exceed $1,800 annually; however, for the period from the
18    effective date of this amendatory Act of the 101st General
19    Assembly through June 30, 2021, the monthly credit for
20    participants with eligible income over 100% of the poverty
21    level may be as much as $200 per month per household, not
22    to exceed $2,400 annually, and, the monthly credit for
23    participants with eligible income 100% or less of the
24    poverty level may be as much as $250 per month per
25    household, not to exceed $3,000 annually. Credits will be
26    applied to PIP Plan participants' utility bills based on

 

 

SB2896- 790 -LRB102 17909 JWD 25989 b

1    the portion of the bill that is the responsibility of the
2    participant provided that the percentage shall be no more
3    than a total of 6% of the relevant income for gas and
4    electric utility bills combined, but in any event no less
5    than $10 per month, unless the household does not pay
6    directly for heat, in which case its payment shall be 2.4%
7    of income but in any event no less than $5 per month. The
8    Department, in consultation with the Policy Advisory
9    Council, may adjust such monthly credit amounts annually
10    and may establish a minimum credit amount based on the
11    cost of administering the program and may deny credits to
12    otherwise eligible participants if the cost of
13    administering the credit exceeds the actual amount of any
14    monthly credit to a participant. If the participant takes
15    both gas and electric service, 50% 66.67% of the credit
16    shall be allocated to the entity that provides the
17    participant's primary energy supply for heating. Each
18    participant shall enter into a levelized payment plan for,
19    as applicable, gas and electric service and such plans
20    shall be implemented by the utility so that a
21    participant's usage and required payments are reviewed and
22    adjusted regularly, but no more frequently than quarterly.
23    Nothing in this Section is intended to prohibit a
24    customer, who is otherwise eligible for LIHEAP, from
25    participating in the program described in Section 4 of
26    this Act. Eligible participants who receive such a benefit

 

 

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1    shall be considered plan participants and shall be
2    eligible to participate in the Arrearage Reduction Program
3    described in item (5) of this subsection (c).
4        (3) The Department shall remit, through the LAAs, to
5    the utility or participating alternative supplier that
6    portion of the plan participant's bill that is not the
7    responsibility of the participant. In the event that the
8    Department fails to timely remit payment to the utility,
9    the utility shall be entitled to recover all costs related
10    to such nonpayment through the automatic adjustment clause
11    tariffs established pursuant to Section 16-111.8 and
12    Section 19-145 of the Public Utilities Act. For purposes
13    of this item (3) of this subsection (c), payment is due on
14    the date specified on the participant's bill. The
15    Department, the Department of Revenue and LAAs shall adopt
16    processes that provide for the timely payment required by
17    this item (3) of this subsection (c).
18        (4) A plan participant is responsible for all actual
19    charges for utility service in excess of the PIPP credit.
20    Pre-program arrears that are included in the Arrearage
21    Reduction Program described in item (5) of this subsection
22    (c) shall not be included in the calculation of the
23    levelized payment plan. Emergency or crisis assistance
24    payments shall not affect the amount of any PIPP credit to
25    which a participant is entitled.
26        (5) Electric and gas utilities subject to this Section

 

 

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1    shall implement an Arrearage Reduction Program (ARP) for
2    plan participants as follows: for each month that a plan
3    participant timely pays his or her utility bill, the
4    utility shall apply a credit to a portion of the
5    participant's pre-program arrears, if any, equal to
6    one-twelfth of such arrearage provided that the total
7    amount of arrearage credits shall equal no more than
8    $1,000 annually for each participant for gas and no more
9    than $1,000 annually for each participant for electricity.
10    In the third year of the PIPP, the Department, in
11    consultation with the Policy Advisory Council established
12    pursuant to Section 5 of this Act, shall determine by rule
13    an appropriate per participant total cap on such amounts,
14    if any. Those plan participants participating in the ARP
15    shall not be subject to the imposition of any additional
16    late payment fees on pre-program arrears covered by the
17    ARP. In all other respects, the utility shall bill and
18    collect the monthly bill of a plan participant pursuant to
19    the same rules, regulations, programs and policies as
20    applicable to residential customers generally.
21    Participation in the Arrearage Reduction Program shall be
22    limited to the maximum amount of funds available as set
23    forth in subsection (f) of Section 13 of this Act. In the
24    event any donated funds under Section 13 of this Act are
25    specifically designated for the purpose of funding the
26    ARP, the Department shall remit such amounts to the

 

 

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1    utilities upon verification that such funds are needed to
2    fund the ARP. Nothing in this Section shall preclude a
3    utility from continuing to implement, and apply credits
4    under, an ARP in the event that the PIPP or LIHEAP is
5    suspended due to lack of funding such that the plan
6    participant does not receive a benefit under either the
7    PIPP or LIHEAP.
8        (5.5) In addition to the ARP described in paragraph
9    (5) of this subsection (c), utilities may also implement a
10    Supplemental Arrearage Reduction Program (SARP) for
11    eligible participants who are not able to become plan
12    participants due to PIPP timing or funding constraints. If
13    a utility elects to implement a SARP, it shall be
14    administered as follows: for each month that a SARP
15    participant timely pays his or her utility bill, the
16    utility shall apply a credit to a portion of the
17    participant's pre-program arrears, if any, equal to
18    one-twelfth of such arrearage, provided that the utility
19    may limit the total amount of arrearage credits to no more
20    than $1,000 annually for each participant for gas and no
21    more than $1,000 annually for each participant for
22    electricity. SARP participants shall not be subject to the
23    imposition of any additional late payment fees on
24    pre-program arrears covered by the SARP. In all other
25    respects, the utility shall bill and collect the monthly
26    bill of a SARP participant under the same rules,

 

 

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1    regulations, programs, and policies as applicable to
2    residential customers generally. Participation in the SARP
3    shall be limited to the maximum amount of funds available
4    as set forth in subsection (f) of Section 13 of this Act.
5    In the event any donated funds under Section 13 of this Act
6    are specifically designated for the purpose of funding the
7    SARP, the Department shall remit such amounts to the
8    utilities upon verification that such funds are needed to
9    fund the SARP.
10        (6) The Department may terminate a plan participant's
11    eligibility for the PIP Plan upon notification by the
12    utility that the participant's monthly utility payment is
13    more than 75 45 days past due. One-twelfth of a customer's
14    arrearage shall be deducted from the total arrearage owed
15    for each on-time payment made by the customer.
16        (7) The Department, in consultation with the Policy
17    Advisory Council, may adjust the number of PIP Plan
18    participants annually, if necessary, to match the
19    availability of funds. Any plan participant who qualifies
20    for a PIPP credit under a utility's PIPP shall be entitled
21    to participate in and receive a credit under such
22    utility's ARP for so long as such utility has ARP funds
23    available, regardless of whether the customer's
24    participation under another utility's PIPP or ARP has been
25    curtailed or limited because of a lack of funds.
26        (8) The Department shall fully implement the PIPP at

 

 

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1    the earliest possible date it is able to effectively
2    administer the PIPP. Within 90 days of the effective date
3    of this amendatory Act of the 96th General Assembly, the
4    Department shall, in consultation with utility companies,
5    participating alternative suppliers, LAAs and the Illinois
6    Commerce Commission (Commission), issue a detailed
7    implementation plan which shall include detailed testing
8    protocols and analysis of the capacity for implementation
9    by the LAAs and utilities. Such consultation process also
10    shall address how to implement the PIPP in the most
11    cost-effective and timely manner, and shall identify
12    opportunities for relying on the expertise of utilities,
13    LAAs and the Commission. Following the implementation of
14    the testing protocols, the Department shall issue a
15    written report on the feasibility of full or gradual
16    implementation. The PIPP shall be fully implemented by
17    September 1, 2011, but may be phased in prior to that date.
18        (9) As part of the screening process established under
19    item (1) of this subsection (c), the Department and LAAs
20    shall assess whether any energy efficiency or demand
21    response measures are available to the plan participant at
22    no cost, and if so, the participant shall enroll in any
23    such program for which he or she is eligible. The LAAs
24    shall assist the participant in the applicable enrollment
25    or application process.
26        (10) Each alternative retail electric and gas supplier

 

 

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1    serving residential customers shall elect whether to
2    participate in the PIPP or ARP described in this Section.
3    Any such supplier electing to participate in the PIPP
4    shall provide to the Department such information as the
5    Department may require, including, without limitation,
6    information sufficient for the Department to determine the
7    proportionate allocation of credits between the
8    alternative supplier and the utility. If a utility in
9    whose service territory an alternative supplier serves
10    customers contributes money to the ARP fund which is not
11    recovered from ratepayers, then an alternative supplier
12    which participates in ARP in that utility's service
13    territory shall also contribute to the ARP fund in an
14    amount that is commensurate with the number of alternative
15    supplier customers who elect to participate in the
16    program.
17        (11) The PIPP shall be designed and implemented each
18    year to maximize participation and spend at least 80% of
19    the funding available for the year.
20    (d) The Department, in consultation with the Policy
21Advisory Council, shall develop and implement a program to
22educate customers about the PIP Plan and about their rights
23and responsibilities under the percentage of income component.
24The Department, in consultation with the Policy Advisory
25Council, shall establish a process that LAAs shall use to
26contact customers in jeopardy of losing eligibility due to

 

 

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1late payments. The Department shall ensure that LAAs are
2adequately funded to perform all necessary educational tasks.
3    (e) The PIPP shall be administered in a manner which
4ensures that credits to plan participants will not be counted
5as income or as a resource in other means-tested assistance
6programs for low-income households or otherwise result in the
7loss of federal or State assistance dollars for low-income
8households.
9    (f) In order to ensure that implementation costs are
10minimized, the Department and utilities shall work together to
11identify cost-effective ways to transfer information
12electronically and to employ available protocols that will
13minimize their respective administrative costs as follows:
14        (1) The Commission may require utilities to provide
15    such information on customer usage and billing and payment
16    information as required by the Department to implement the
17    PIP Plan and to provide written notices and communications
18    to plan participants.
19        (2) Each utility and participating alternative
20    supplier shall file annual reports with the Department and
21    the Commission that cumulatively summarize and update
22    program information as required by the Commission's rules.
23    The reports shall track implementation costs and contain
24    such information as is necessary to evaluate the success
25    of the PIPP.
26        (2.5) The Department shall annually prepare and submit

 

 

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1    a report to the General Assembly, the Commission, and the
2    Policy Advisory Council that identifies the following
3    amounts for the most recently completed year: total moneys
4    collected under subsection (b) of Section 13 of this Act
5    for all PIPPs implemented in the State; moneys allocated
6    to each utility for implementation of its PIPP; and moneys
7    allocated to each utility for other purposes, including a
8    description of each of those purposes. The Commission
9    shall publish the report on its website.
10        (3) The Department and the Commission shall have the
11    authority to promulgate rules and regulations necessary to
12    execute and administer the provisions of this Section.
13    (g) Each utility shall be entitled to recover reasonable
14administrative and operational costs incurred to comply with
15this Section from the Supplemental Low Income Energy
16Assistance Fund. The utility may net such costs against monies
17it would otherwise remit to the Funds, and each utility shall
18include in the annual report required under subsection (f) of
19this Section an accounting for the funds collected.
20(Source: P.A. 101-636, eff. 6-10-20.)
 
21    (305 ILCS 20/20 new)
22    Sec. 20. Expanded eligibility. All programs pursuant to
23this Act shall be available to eligible low-income Illinois
24residents who qualify for assistance under Sections 6 and 18,
25regardless of immigration status, using the Supplemental

 

 

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1Low-Income Energy Assistance Fund for customers of utilities
2and vendors that collect the Energy Assistance Charge and pay
3into the Supplemental Low-Income Energy Assistance Fund.
 
4    Section 30-50. The Environmental Protection Act is amended
5by changing Sections 2 and 9.15 and by adding Section 3.1325 as
6follows:
 
7    (415 ILCS 5/2)  (from Ch. 111 1/2, par. 1002)
8    Sec. 2. (a) The General Assembly finds:
9        (i) that environmental damage seriously endangers the
10    public health and welfare, as more specifically described
11    in later sections of this Act;
12        (ii) that because environmental damage does not
13    respect political boundaries, it is necessary to establish
14    a unified state-wide program for environmental protection
15    and to cooperate fully with other States and with the
16    United States in protecting the environment;
17        (iii) that air, water, and other resource pollution,
18    public water supply, solid waste disposal, noise, and
19    other environmental problems are closely interrelated and
20    must be dealt with as a unified whole in order to safeguard
21    the environment;
22        (iv) that it is the obligation of the State Government
23    to manage its own activities so as to minimize
24    environmental damage; to encourage and assist local

 

 

SB2896- 800 -LRB102 17909 JWD 25989 b

1    governments to adopt and implement
2    environmental-protection programs consistent with this
3    Act; to promote the development of technology for
4    environmental protection and conservation of natural
5    resources; to do its part to stop and reverse the effects
6    of climate change by moving toward 100% clean energy
7    generation; and in appropriate cases to afford financial
8    assistance in preventing environmental damage;
9        (v) that in order to alleviate the burden on
10    enforcement agencies, to assure that all interests are
11    given a full hearing, and to increase public participation
12    in the task of protecting the environment, private as well
13    as governmental remedies must be provided;
14        (vi) that despite the existing laws and regulations
15    concerning environmental damage there exist continuing
16    destruction and damage to the environment and harm to the
17    public health, safety and welfare of the people of this
18    State, and that among the most significant sources of this
19    destruction, damage, and harm are the improper and unsafe
20    transportation, treatment, storage, disposal, and dumping
21    of hazardous wastes;
22        (vii) that it is necessary to supplement and
23    strengthen existing criminal sanctions regarding
24    environmental damage, by enacting specific penalties for
25    injury to public health and welfare and the environment.
26    (b) It is the purpose of this Act, as more specifically

 

 

SB2896- 801 -LRB102 17909 JWD 25989 b

1described in later sections, to establish a unified,
2state-wide program supplemented by private remedies, to
3restore, protect and enhance the quality of the environment,
4and to assure that adverse effects upon the environment are
5fully considered and borne by those who cause them.
6    (c) The terms and provisions of this Act shall be
7liberally construed so as to effectuate the purposes of this
8Act as set forth in subsection (b) of this Section, but to the
9extent that this Act prescribes criminal penalties, it shall
10be construed in accordance with the Criminal Code of 2012.
11(Source: P.A. 97-1150, eff. 1-25-13.)
 
12    (415 ILCS 5/3.1325 new)
13    Sec. 3.1325. Clean Energy. "Clean Energy" means energy
14generation that is substantially free (90% or greater) of
15carbon dioxide emissions.
 
16    (415 ILCS 5/9.15)
17    Sec. 9.15. Greenhouse gases.
18    (a) An air pollution construction permit shall not be
19required due to emissions of greenhouse gases if the
20equipment, site, or source is not subject to regulation, as
21defined by 40 CFR 52.21, as now or hereafter amended, for
22greenhouse gases or is otherwise not addressed by the Board in
23regulations for greenhouse gases. These exemptions do . This
24exemption does not relieve an owner or operator from the

 

 

SB2896- 802 -LRB102 17909 JWD 25989 b

1obligation to comply with other applicable rules or
2regulations.
3    (b) An air pollution operating permit shall not be
4required due to emissions of greenhouse gases if the
5equipment, site, or source is not subject to regulation, as
6defined by Section 39.5 of this Act, for greenhouse gases or is
7otherwise not addressed by the Board in regulations for
8greenhouse gases. These exemptions do . This exemption does
9not relieve an owner or operator from the obligation to comply
10with other applicable rules or regulations.
11    (c) (Blank). Notwithstanding any provision to the contrary
12in this Section, an air pollution construction or operating
13permit shall not be required due to emissions of greenhouse
14gases if any of the following events occur:
15        (1) enactment of federal legislation depriving the
16    Administrator of the USEPA of authority to regulate
17    greenhouse gases under the Clean Air Act;
18        (2) the issuance of any opinion, ruling, judgment,
19    order, or decree by a federal court depriving the
20    Administrator of the USEPA of authority to regulate
21    greenhouse gases under the Clean Air Act; or
22        (3) action by the President of the United States or
23    the President's authorized agent, including the
24    Administrator of the USEPA, to repeal or withdraw the
25    Greenhouse Gas Tailoring Rule (75 Fed. Reg. 31514, June 3,
26    2010).

 

 

SB2896- 803 -LRB102 17909 JWD 25989 b

1    This subsection (c) does not relieve an owner or operator
2from the obligation to comply with applicable rules or
3regulations other than those relating to greenhouse gases.
4    (d) (Blank). If any event listed in subsection (c) of this
5Section occurs, permits issued after such event shall not
6impose permit terms or conditions addressing greenhouse gases
7during the effectiveness of any event listed in subsection
8(c).
9    (e) (Blank). If an event listed in subsection (c) of this
10Section occurs, any owner or operator with a permit that
11includes terms or conditions addressing greenhouse gases may
12elect to submit an application to the Agency to address a
13revision or repeal of such terms or conditions. The Agency
14shall expeditiously process such permit application in
15accordance with applicable laws and regulations.
16    (f) Definitions. As used in this Section:
17    "Carbon dioxide equivalent emissions" or "CO2e" means the
18sum total of the mass amount of emissions in tons per year,
19calculated by multiplying the mass amount of each of the 6
20greenhouse gases specified in Section 3.207 of the Act (in
21tons per year) by its associated global warming potential as
22set forth in 40 CFR 98, subpart A, table A-1, and then adding
23them all together.
24    "Electric generating unit" or "EGU" means a fossil
25fuel-fired stationary boiler, combustion turbine, or combined
26cycle system that serves a generator that has a nameplate

 

 

SB2896- 804 -LRB102 17909 JWD 25989 b

1capacity greater than 25 MWe and produces electricity for
2sale.
3    "Large greenhouse gas-emitting" or "large GHG-emitting
4unit" means a unit that is an electric generating unit or other
5fossil fuel-fired unit that itself has a nameplate capacity or
6serves a generator that has a nameplate capacity greater than
725 MWe and that produces electricity (including, but not
8limited to, coal-fired, coal-derived, oil-fired, natural
9gas-fired, and cogeneration units).
10    (g) The Agency shall, within 365 days after the effective
11date of this amendatory Act of the 102nd General Assembly,
12initiate a rulemaking to amend Title 35 of the Illinois
13Administrative Code to establish declining greenhouse gas
14emissions caps beginning in 2024 from all large GHG-emitting
15units so as to progressively eliminate all greenhouse gas
16emissions from such units by the year 2030 for EGUs that use
17coal as a fuel, and by the year 2045 for remaining large
18GHG-emitting units, except under conditions described in
19subsection (j), and to establish aggregate statewide emissions
20caps. No later than 365 days after receipt of the Agency's
21proposal under this Section, the Board shall adopt rules that
22establish declining emissions caps for greenhouse gases for
23each individual large GHG-emitting unit in Illinois, as well
24as an aggregate statewide greenhouse gas emissions cap. The
25Board may set different declining caps for each unit, but caps
26must decline to zero emissions for all EGUs that use coal as a

 

 

SB2896- 805 -LRB102 17909 JWD 25989 b

1fuel by 2030 and all other large GHG-emitting units by 2045,
2except under conditions described in subsection (j).
3    (h) As part of its rulemaking proposal, the Agency:
4        (1) Shall conduct a stakeholder process prior to
5    initiating a rulemaking proceeding before the Illinois
6    Pollution Control Board that encourages the meaningful
7    participation of Illinois residents. This process should
8    include a public comment period, during which the Agency
9    shall:
10            (A) encourage and accept written public comments
11        from across the State;
12            (B) hold three public outreach events; and
13            (C) ensure access for residents by providing
14        opportunity for oral public comment outside the
15        workday.
16        (2) May set declining rates of greenhouse gas
17    emissions from individual large GHG-emitting units based
18    on factors such as the amount of greenhouse gas emissions
19    at a unit, electric grid supply and reliability, and unit
20    operational schedule.
21        (3) May set greenhouse gas emissions caps that result
22    in zero emissions from certain EGUs that use coal as a fuel
23    earlier than 2030 and from other large GHG-emitting units
24    earlier than 2045, as supported by the Agency's assessment
25    of units.
26    (i) The Agency's rulemaking proposal and the Board's

 

 

SB2896- 806 -LRB102 17909 JWD 25989 b

1adopted rule shall address the following:
2        (1) Aggregate statewide emissions caps. The Agency
3    shall establish a schedule by which the aggregate cap
4    shall decline consistently. A baseline shall be calculated
5    by averaging the total actual greenhouse gas emissions,
6    calculated in terms of CO2e, from the years 2018, 2019, and
7    2020 from all large GHG-emitting units for which the
8    Agency has issued a permit to operate or a permit to
9    construct as of the date the Agency proposes the rule to
10    the Board. For any units that were not yet operating in
11    2018 but were operating by January 1, 2020, the baseline
12    amount included within the aggregate statewide emissions
13    cap shall be the total actual greenhouse gas emissions,
14    calculated in terms of CO2e, from the unit in 2020. For any
15    units that were not yet operating by January 1, 2020, the
16    baseline amount included within the aggregate statewide
17    emissions cap shall be an amount that is proposed by the
18    Agency and adopted by the Board, consistent with expected
19    operations and taking into account any other operational
20    factors that have occurred prior to the proposal and
21    adoption of the rule. To ensure consistent progress toward
22    the goal of eliminating all greenhouse gas emissions from
23    large GHG-emitting units, the aggregate emissions cap
24    shall decrease by no less than 20% of the baseline amount
25    in every five-year period.
26        (2) Unit-specific emissions caps. Greenhouse gas

 

 

SB2896- 807 -LRB102 17909 JWD 25989 b

1    emissions caps, calculated in terms of CO2e, shall be
2    established for individual large GHG-emitting units by
3    evaluating individual units and setting appropriate
4    declining caps for emission reductions. Greenhouse gas
5    emissions caps shall apply to each large GHG-emitting unit
6    in the State and the sum of all unit-specific emissions
7    caps shall total to no more than the aggregate statewide
8    greenhouse gas emissions cap. The Agency shall include in
9    its rulemaking proposal a declining greenhouse gas
10    emission cap, calculated in terms of CO2e, that delineates
11    each unit's allowable greenhouse gas emissions in every
12    year until the unit reaches zero greenhouse gas emissions.
13    (j) The Agency's proposal and the Board's adopted rule
14shall include language that allows EGUs that use coal as a fuel
15to continue emitting greenhouse gases after 2030 and other
16large GHG-emitting units to continue emitting greenhouse gases
17after 2045, or after any earlier deadline specified in the
18rulemaking, only in such circumstance that it has been
19determined that ongoing operation of the unit is necessary to
20maintain power grid supply and reliability for EGUs or is
21necessary to serve as an emergency backup to operations for
22other large GHG-emitting units. The rule must include language
23mandating that:
24        (1) each large GHG-emitting unit that is a participant
25    in a regional transmission organization submit
26    documentation to the appropriate regional transmission

 

 

SB2896- 808 -LRB102 17909 JWD 25989 b

1    organization by deadlines specified in the rulemaking that
2    meets all applicable regulatory requirements necessary to
3    obtain approval to permanently cease operating the large
4    GHG-emitting unit;
5        (2) if any large GHG-emitting unit that is a
6    participant in a regional transmission organization cannot
7    obtain such permission because the regional transmission
8    organization determines that operation of the unit is
9    required to maintain transmission supply and reliability,
10    the unit may continue operating but the owner or operator
11    of the unit must use its best efforts to resolve the supply
12    and reliability requirement with the regional transmission
13    organization and cease operation as soon as practicable;
14    and
15        (3) any large GHG-emitting unit that is not a
16    participant in a regional transmission organization be
17    allowed to continue emitting greenhouse gases after 2045
18    in the capacity of an emergency backup unit if the owner or
19    operator can justify the need for such extension to the
20    Agency, in consultation with the Illinois Commerce
21    Commission.
22    (k) Annual report. Each year by June 30, beginning in
232025, the Agency shall prepare and publish on its website a
24report setting forth the actual greenhouse gas emissions from
25individual units and the aggregate statewide emissions from
26all units for the prior year.

 

 

SB2896- 809 -LRB102 17909 JWD 25989 b

1    (l) Greenhouse gas emissions fee. On and after January 1,
22022, the owner or operator of each large GHG-emitting unit
3shall, on an annual basis, pay a fee to the Agency for such
4unit as described below.
5        (1) In 2022, the fee amount for each unit shall be
6    $8.00 per ton of CO2e emitted from July 1, 2021, through
7    December 31, 2021. In each subsequent year, the fee amount
8    for each unit shall be based on the tons of CO2e emitted
9    from January 1 through December 31, plus 3%.
10        (2) No later than February 1, 2022, the owner or
11    operator shall submit a report to the Agency's Bureau of
12    Air Compliance Section, specifying the tons of CO2e
13    emitted from July 1, 2021, through December 31, 2021, with
14    supporting calculations for each of the 6 greenhouse gases
15    and any subcategories thereof. No later than February 1 of
16    each subsequent year, the owner or operator shall submit a
17    report to the Agency's Bureau of Air Compliance Section,
18    specifying the tons of CO2e emitted in the prior year with
19    supporting calculations for each of the 6 greenhouse gases
20    and any subcategories thereof.
21        (3) No later than March 1, 2022, the Agency shall send
22    a billing statement to the owner or operator indicating
23    the amount of greenhouse gas emissions fees owed for July
24    1, 2021, through December 31, 2021. No later than March 1
25    of each subsequent year, the Agency shall send a billing
26    statement to the owner or operator indicating the amount

 

 

SB2896- 810 -LRB102 17909 JWD 25989 b

1    of greenhouse gas emissions fees owed for the previous
2    year.
3        (4) The owner or operator shall pay all greenhouse gas
4    emissions fees by April 1 each year. Payment shall be made
5    through the Illinois E-Pay system or by a check or money
6    order payable to either the "Treasurer, State of Illinois"
7    or the "Illinois Environmental Protection Agency". The
8    check or money order shall be accompanied by the billing
9    statement that includes the site name and identification
10    number assigned by the Agency's Bureau of Air. If paying
11    by check or money order, payment shall be directed to the
12    Agency's Fiscal Services Section. Payment shall not
13    include any fees due to the Agency for any purpose other
14    than greenhouse gas emissions fees. Failure to timely pay
15    the fees will subject the owner or operator to possible
16    enforcement under Section 31 of the Act and collection
17    actions.
18        (5) Greenhouse gas emissions fees shall not be
19    refunded unless the amount paid is in excess of the amount
20    billed or the amount billed is determined by the Agency to
21    be incorrect. The owner or operator shall request
22    reconsideration of the amount of the greenhouse gas
23    emissions fees as determined by the Agency within 30 days
24    after issuance of a billing statement. Failure to request
25    reconsideration within this period shall constitute waiver
26    of all rights to seek reconsideration of the amount from

 

 

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1    the Agency, waiver of all rights to a refund, and waiver of
2    all rights to appeal. All requests for reconsideration
3    shall be in writing, directed to the Agency's Bureau of
4    Air Compliance Section, and shall include all pertinent
5    facts and arguments in support of the request.
6        (6) Subject to the waiver provisions set forth in
7    paragraph (5) of this subsection (l), the owner or
8    operator may appeal the Agency's determination of the
9    greenhouse gas emissions fees pursuant to the
10    Administrative Review Law.
11        (7) The Agency shall have the authority to establish
12    additional procedures for the collection of greenhouse gas
13    emissions fees if necessary.
14    (m) Greenhouse Gas Emissions Reinvestment Fund.
15        (1) There is hereby created the Greenhouse Gas
16    Emissions Reinvestment Fund, a special fund in the State
17    Treasury, subject to appropriations unless otherwise
18    provided in this Section. All moneys collected from the
19    greenhouse gas emissions fee under subsection (l) shall be
20    deposited into the Greenhouse Gas Emissions Reinvestment
21    Fund.
22        (2) Whenever the Agency determines that a refund
23    should be made from the greenhouse gas emissions fee
24    collected under subsection (l) to a claimant, the Agency
25    shall submit a voucher for payment to the State
26    Comptroller, who shall cause the order to be drawn for the

 

 

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1    amount specified and to the person named in the
2    notification from the Agency. This paragraph (2) shall
3    constitute an irrevocable and continuing appropriation of
4    all amounts necessary for the payment of refunds out of
5    the Fund as authorized under this paragraph (2).
6        (3) On July 1, 2022 and on July 1 of each year
7    thereafter, the Agency, in consultation with the
8    Governor's Office of Management and Budget, shall identify
9    the following allocations from amounts available in the
10    Greenhouse Gas Emissions Reinvestment Fund and shall
11    prepare and certify to the State Comptroller the transfer
12    and allocations of stated sums of money from the
13    Greenhouse Gas Emissions Reinvestment Fund to other named
14    funds in the State treasury as applicable.
15            (A) The Agency shall first determine the
16        allocation which shall remain in the Greenhouse Gas
17        Emissions Reinvestment Fund, subject to
18        appropriations, to pay for the direct and indirect
19        costs associated with the implementation,
20        administration, and enforcement of Section 9.15 of the
21        Environmental Protection Act, including the payment of
22        refunds from the greenhouse gas emissions fee under
23        collected subsection (l) of Section 9.15 of the
24        Environmental Protection Act by the Agency, together
25        with the annual audit to determine whether there is a
26        need for State support for the Illinois nuclear fleet

 

 

SB2896- 813 -LRB102 17909 JWD 25989 b

1        under Section 8-201.12 of the Public Utilities Act.
2            (B) After the allocations have been made as
3        provided in subparagraph (A) of paragraph (3) of this
4        subsection (m), from the remaining amounts the Agency
5        shall certify to the State Comptroller and the State
6        Treasurer shall transfer into the following named
7        funds according to the following allocations:
8                (i) 30% shall be transferred to the Energy
9            Transition Assistance Fund for use by the
10            Department of Commerce and Economic Opportunity
11            for job training, workforce assistance, and just
12            transition programs for equity-focused
13            populations, and for use by the Illinois Student
14            Assistance Commission for a displaced energy
15            worker dependent transition scholarship;
16                (ii) 5% shall be transferred to the Alternate
17            Fuels Fund for the Agency to administer and
18            provide rebates for consumers who purchase
19            electric vehicles pursuant to the Electric Vehicle
20            Rebate Act;
21                (iii) 5% shall be transferred to the Energy
22            Transition Assistance Fund for distribution by the
23            Department of Commerce and Economic Opportunity
24            for assistance for communities who have
25            experienced the closure of a power generation
26            facility after 2016 pursuant to the Energy

 

 

SB2896- 814 -LRB102 17909 JWD 25989 b

1            Transition Community Grant Program;
2                (iv) 5% shall be transferred to the Energy
3            Efficiency Trust Fund for the Illinois
4            Environmental Protection Agency for energy
5            efficiency programs, including weatherization;
6                (v) 5% shall be transferred to the Clean Air
7            Act Permit Fund for use by the Environmental
8            Protection Agency including the implementation,
9            administration, and enforcement of the Clean Air
10            Act by the Agency;
11                (vi) 5% shall be transferred to the Public
12            Utilities Fund for use by the Illinois Commerce
13            Commission for costs of administering the changes
14            made to the Public Utilities Act by this
15            amendatory Act of the 102nd General Assembly;
16                (vii) 5% shall be transferred to the State
17            Parks Fund for the Department of Natural Resources
18            for the maintenance, and development of State
19            parks including infrastructure improvements to
20            promote outdoor recreation and sustainable energy;
21                (viii) 1% shall be transferred to the Plugging
22            and Restoration Fund for the Department of Natural
23            Resources for the purposes of plugging, replugging
24            or repairing any well, and restoring the site of
25            any well, determined by the Department to be
26            abandoned;

 

 

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1                (ix) 1% shall be transferred to the Illinois
2            Power Agency Operations Fund for use by the
3            Illinois Power Agency;
4                (x) 10% shall be transferred to the Budget
5            Stabilization Fund;
6                (xi) 2% for transfers to the State Garage
7            Revolving Fund for purposes of State fleet
8            electrification pursuant to Executive Order
9            2021-08; and
10                (xii) 2% shall be transferred to the Illinois
11            Power Agency.
12            27%, or any remaining balance in the Fund, shall
13        be retained for use by the Agency for the costs of
14        implementing the changes made to the Environmental
15        Protection Act by this amendatory Act of the 102nd
16        General Assembly or distributed in addition to
17        transfers listed in items (i) through (xii) of this
18        subparagraph (B).
19        (4) On June 30, 2025 and on June 30 of each year
20    thereafter, the Agency shall prepare and publish on its
21    website a report describing the amount of greenhouse gas
22    emissions fees collected that year from large greenhouse
23    gas-emitting units.
24(Source: P.A. 97-95, eff. 7-12-11.)
 
25    Section 30-55. The Alternate Fuels Act is amended by

 

 

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1changing Sections 1, 5, 10, 15, and 40 and by adding Section 27
2as follows:
 
3    (415 ILCS 120/1)
4    Sec. 1. Short title. This Act may be cited as the Electric
5Vehicle Rebate Alternate Fuels Act.
6(Source: P.A. 89-410.)
 
7    (415 ILCS 120/5)
8    Sec. 5. Purpose. The General Assembly declares that it is
9the public policy of the State to promote and encourage the use
10of electric alternate fuel in vehicles as a means to improve
11air quality in the State, reduce greenhouse gas emissions, and
12to meet the requirements of the federal Clean Air Act
13Amendments of 1990 and the federal Energy Policy Act of 1992.
14The General Assembly further declares that the State can play
15a leadership role by increasing the adoption in the
16development of vehicles powered by electricity alternate
17fuels, as well as in the establishment of the necessary
18infrastructure to support this emerging technology.
19(Source: P.A. 89-410.)
 
20    (415 ILCS 120/10)
21    Sec. 10. Definitions. As used in this Act:
22    "Agency" means the Environmental Protection Agency.
23    "Alternate fuel" means liquid petroleum gas, natural gas,

 

 

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1E85 blend fuel, fuel composed of a minimum 80% ethanol, 80%
2bio-based methanol, fuels that are at least 80% derived from
3biomass, hydrogen fuel, or electricity, excluding on-board
4electric generation.
5    "Alternate fuel vehicle" means any vehicle that is
6operated in Illinois and is capable of using an alternate
7fuel.
8    "Biodiesel fuel" means a renewable fuel conforming to the
9industry standard ASTM-D6751 and registered with the U.S.
10Environmental Protection Agency.
11    "Car sharing organization" means an organization whose
12primary business is a membership-based service that allows
13members to drive cars by the hour in order to extend the public
14transit system, reduce personal car ownership, save consumers
15money, increase the use of alternative transportation, and
16improve environmental sustainability.
17    "Conventional", when used to modify the word "vehicle",
18"engine", or "fuel", means gasoline or diesel or any
19reformulations of those fuels.
20    "Covered Area" means the counties of Cook, DuPage, Kane,
21Lake, McHenry, and Will, together with Aux Sable and Goose
22Lake Townships in Grundy County and Oswego Township in Kendall
23County and those portions of Grundy County and Kendall County
24that are included in the following ZIP code areas, as
25designated by the U.S. Postal Service on the effective date of
26this amendatory Act of 1998: 60416, 60444, 60447, 60450,

 

 

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160481, 60538, and 60543.
2    "Director" means the Director of the Environmental
3Protection Agency.
4    "Domestic renewable fuel" means a fuel, produced in the
5United States, composed of a minimum 80% ethanol, 80%
6bio-based methanol, or 20% biodiesel fuel.
7    "E85 blend fuel" means fuel that contains 85% ethanol and
815% gasoline.
9    "Electric vehicle" means a vehicle that is licensed to
10drive on public roadways, is exclusively predominantly powered
11by, and exclusively primarily refueled with, electricity, and
12does not have restrictions confining it to operate on only
13certain types of streets or roads. "Electric vehicle" does not
14include hybrid electric vehicles and extended-range electric
15vehicles that are also equipped with conventional fueled
16propulsion or auxiliary engines or electric motorcycles.
17    "GVWR" means Gross Vehicle Weight Rating.
18    "Location" means (i) a parcel of real property or (ii)
19multiple, contiguous parcels of real property that are
20separated by private roadways, public roadways, or private or
21public rights-of-way and are owned, operated, leased, or under
22common control of one party.
23    "Low-income" means persons and families whose average
24income does not exceed 80% of area median income, adjusted for
25family size and revised every 2 years.
26    "Original equipment manufacturer" or "OEM" means a

 

 

SB2896- 819 -LRB102 17909 JWD 25989 b

1manufacturer of alternate fuel vehicles or a manufacturer or
2remanufacturer of alternate fuel engines used in vehicles
3greater than 8500 pounds GVWR.
4    "Rental vehicle" means any motor vehicle that is owned or
5controlled primarily for the purpose of short-term leasing or
6rental pursuant to a contract.
7(Source: P.A. 97-90, eff. 7-11-11.)
 
8    (415 ILCS 120/15)
9    Sec. 15. Rulemaking. The Agency shall promulgate rules as
10necessary and dedicate sufficient resources to implement the
11purposes of Section 27 30 of this Act. Such rules shall be
12consistent with applicable the provisions of the federal Clean
13Air Act Amendments of 1990 and any regulations promulgated
14pursuant thereto. The Secretary of State may promulgate rules
15to implement Section 35 of this Act. The Department of
16Commerce and Economic Opportunity may promulgate rules to
17implement Section 25 of this Act.
18(Source: P.A. 94-793, eff. 5-19-06.)
 
19    (415 ILCS 120/27 new)
20    Sec. 27. Covered Areas; low-income rebate.
21    (a) Beginning July 1, 2022, and continuing as long as
22funds are available, each low-income person residing in a
23Covered Area shall be eligible to apply for a rebate, in the
24amounts set forth below, following the purchase of an electric

 

 

SB2896- 820 -LRB102 17909 JWD 25989 b

1vehicle in Illinois. The Agency shall issue rebates consistent
2with the provisions of this Act and any implementing
3regulations adopted by the Agency. In no event shall a rebate
4amount exceed the purchase price of the vehicle.
5        (1) On and after July 1, 2022 through June 30, 2026, a
6    $4,000 rebate for the purchase of an electric vehicle.
7        (2) On and after July 1, 2026 through June 30, 2028, a
8    $2,000 rebate for the purchase of an electric vehicle.
9        (3) On and after July 1, 2028 through June 30, 2030, a
10    $1,000 rebate for the purchase of an electric vehicle.
11    (b) To be eligible to receive a low-income rebate, a
12purchaser must:
13        (1) Be a low-income person residing in a Covered Area,
14    both at the time the vehicle is purchased and at the time
15    the rebate is issued.
16        (2) Purchase an electric vehicle in Illinois on or
17    after July 1, 2022 and be the owner of the vehicle at the
18    time the rebate is issued. Rented or leased vehicles,
19    vehicles purchased from an out-of-state dealership, and
20    vehicles delivered to or received by the purchaser
21    out-of-state are not eligible for a rebate under this Act.
22        (3) Apply for the rebate within 90 days after the
23    vehicle purchase date, and provide to the Agency proof of
24    residence, proof of low-income status, proof of vehicle
25    ownership, and proof that the vehicle was purchased in
26    Illinois, including a copy of a purchase agreement noting

 

 

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1    an Illinois seller. The purchaser must notify the Agency
2    of any changes in residency, low-income status, or
3    ownership of the vehicle that occur between application
4    for a rebate and issuance of a rebate.
5    (c) The purchaser must retain ownership of the vehicle for
6a minimum of 12 consecutive months immediately following the
7vehicle purchase date. The purchaser must continue to reside
8in a Covered Area during that time frame and register the
9vehicle in Illinois during that time frame. Rebate recipients
10who fail to satisfy any of the above criteria will be required
11to reimburse the Agency all or part of the original rebate
12amount and shall notify the Agency within 60 days of failing to
13satisfy the criteria.
14    (d) Rebates administered under this Section shall be
15available for both new and used passenger electric vehicles.
16    (e) A rebate administered under this Act may only be
17applied for and awarded one time per Vehicle Identification
18Number. A rebate may only be applied for and awarded once per
19purchaser in any 10-year period.
 
20    (415 ILCS 120/40)
21    Sec. 40. Appropriations from the Alternate Fuels Fund.
22    (a) User Fees Funds. The Agency shall estimate the amount
23of user fees expected to be collected under Section 35 of this
24Act for each fiscal year. User fee funds shall be deposited
25into and distributed from the Alternate Fuels Fund in the

 

 

SB2896- 822 -LRB102 17909 JWD 25989 b

1following manner:
2        (1) An In each of fiscal years 1999, 2000, 2001, 2002,
3    and 2003, an amount not to exceed $200,000, and beginning
4    in fiscal year 2004 an annual amount not to exceed
5    $225,000, may be appropriated to the Agency from the
6    Alternate Fuels Fund to pay its costs of administering the
7    programs authorized by Section 27 30 of this Act. Up to
8    $200,000 may be appropriated to the Office of the
9    Secretary of State in each of fiscal years 1999, 2000,
10    2001, 2002, and 2003 from the Alternate Fuels Fund to pay
11    the Secretary of State's costs of administering the
12    programs authorized under this Act. Beginning in fiscal
13    year 2004 and in each fiscal year thereafter, an amount
14    not to exceed $225,000 may be appropriated to the
15    Secretary of State from the Alternate Fuels Fund to pay
16    the Secretary of State's costs of administering the
17    programs authorized under this Act.
18        (2) In fiscal years 2023, 2024, 2025, 2026, and 2027,
19    and each fiscal year thereafter 1999, 2000, 2001, and
20    2002, after appropriation of the amounts authorized by
21    item (1) of subsection (a) of this Section, the remaining
22    moneys estimated to be collected during each fiscal year
23    shall be appropriated as follows: 80% of the remaining
24    moneys shall be appropriated to fund the programs
25    authorized by Section 27 30, and 20% shall be appropriated
26    to fund the programs authorized by Section 25. In fiscal

 

 

SB2896- 823 -LRB102 17909 JWD 25989 b

1    year 2004 and each fiscal year thereafter, after
2    appropriation of the amounts authorized by item (1) of
3    subsection (a) of this Section, the remaining moneys
4    estimated to be collected during each fiscal year shall be
5    appropriated as follows: 70% of the remaining moneys shall
6    be appropriated to fund the programs authorized by Section
7    30 and 30% shall be appropriated to fund the programs
8    authorized by Section 31.
9        (3) (Blank).
10        (4) Moneys appropriated to fund the programs
11    authorized in Section 27 Sections 25 and 30 shall be
12    expended only after they have been collected and deposited
13    into the Alternate Fuels Fund.
14    (b) General Revenue Fund Appropriations. General Revenue
15Fund amounts appropriated to and deposited into the Alternate
16Fuels Fund shall be distributed from the Alternate Fuels Fund
17to fund the programs authorized in Section 27. in the
18following manner:
19        (1) In each of fiscal years 2003 and 2004, an amount
20    not to exceed $50,000 may be appropriated to the
21    Department of Commerce and Community Affairs (now
22    Department of Commerce and Economic Opportunity) from the
23    Alternate Fuels Fund to pay its costs of administering the
24    programs authorized by Sections 31 and 32.
25        (2) In each of fiscal years 2003 and 2004, an amount
26    not to exceed $50,000 may be appropriated to the

 

 

SB2896- 824 -LRB102 17909 JWD 25989 b

1    Department of Commerce and Community Affairs (now
2    Department of Commerce and Economic Opportunity) to fund
3    the programs authorized by Section 32.
4        (3) In each of fiscal years 2003 and 2004, after
5    appropriation of the amounts authorized in items (1) and
6    (2) of subsection (b) of this Section, the remaining
7    moneys received from the General Revenue Fund shall be
8    appropriated as follows: 52.632% of the remaining moneys
9    shall be appropriated to fund the programs authorized by
10    Sections 25 and 30 and 47.368% of the remaining moneys
11    shall be appropriated to fund the programs authorized by
12    Section 31. The moneys appropriated to fund the programs
13    authorized by Sections 25 and 30 shall be used as follows:
14    20% shall be used to fund the programs authorized by
15    Section 25, and 80% shall be used to fund the programs
16    authorized by Section 30.
17    Moneys appropriated to fund the programs authorized in
18Section 31 shall be expended only after they have been
19deposited into the Alternate Fuels Fund.
20(Source: P.A. 93-32, eff. 7-1-03; 94-793, eff. 5-19-06.)
 
21    (415 ILCS 120/20 rep.)
22    (415 ILCS 120/22 rep.)
23    (415 ILCS 120/24 rep.)
24    (415 ILCS 120/30 rep.)
25    (415 ILCS 120/31 rep.)

 

 

SB2896- 825 -LRB102 17909 JWD 25989 b

1    (415 ILCS 120/32 rep.)
2    Section 30-56. The Alternate Fuels Act is amended by
3repealing Sections 20, 22, 24, 30, 31, and 32.
 
4    Section 30-60. The First Informer Broadcasters Act is
5amended by adding Section 20 as follows:
 
6    (430 ILCS 170/20 new)
7    Sec. 20. Cybersecurity Measures for Municipal Power and
8Distribution Cooperatives.
9    (a) It is the policy of the State of Illinois to ensure
10that the systems which deliver power to its residents are
11protected from physical and cyber risks and attacks, including
12through municipal power agencies and distribution
13cooperatives.
14    (b) Legislative Findings. The General Assembly finds:
15        (1) That a substantial number of Illinois residents
16    and businesses rely on power delivered through municipal
17    power agencies and distribution cooperatives.
18        (2) That all utilities, including municipal power
19    agencies and distribution cooperatives, are the target of
20    physical and cyber threats and attacks.
21        (3) That cyber attacks have the ability to destabilize
22    portions of the grid, leaving Illinois residents without
23    power and access to critical services.
24        (4) That it is in the interest of the State of Illinois

 

 

SB2896- 826 -LRB102 17909 JWD 25989 b

1    to understand the nature of threats and to work with
2    municipal agencies and cooperatives to support their
3    planning for such threats.
4    (c) Planning Summaries. Starting on December 31, 2021 and
5on or before December 31 of every year thereafter, each
6municipal power agency and distribution cooperative shall file
7with the Illinois Emergency Management Agency (IEMA) and the
8Illinois Commerce Commission (Commission) a summary of its
9planning process and preparedness for addressing cyber and
10physical security risks.
11        (1) In preparing the summary, the municipal power
12    agency or distribution cooperative shall assess risks and
13    the extent to which they can be exploited by bad actors,
14    security controls, previous attacks and vulnerabilities
15    that led to those attacks, incident and vulnerability
16    management, efforts being taken to mitigate risks,
17    continuity of power planning, training and awareness, and
18    any other information the municipal power agency or
19    distribution cooperative deems relevant to a thorough
20    assessment of its preparedness for cyber and physical
21    security attacks.
22        (2) The summary shall be high-level and contain little
23    explicit information. As part of its summary, the filing
24    entity need not report any confidential, proprietary, or
25    other information in the plan that could in any way
26    compromise or decrease the filing entity's ability to

 

 

SB2896- 827 -LRB102 17909 JWD 25989 b

1    prevent, mitigate, or recover from potential system
2    disruptions caused by physical events, or cyber attacks.
3        (3) IEMA and the Commission shall, to the extent
4    possible, coordinate with other State or federal agencies
5    to assist the filing entity in developing its report and
6    mitigating issues raised by the report.
 
7    Section 30-63. The Renewable Energy Facilities
8Agricultural Impact Mitigation Act is amended by changing
9Section 15 as follows:
 
10    (505 ILCS 147/15)
11    Sec. 15. Agricultural impact mitigation agreement.
12    (a) A commercial renewable energy facility owner of a
13commercial wind energy facility or a commercial solar energy
14facility that is located on landowner property shall enter
15into an agricultural impact mitigation agreement with the
16Department outlining construction and deconstruction standards
17and policies designed to preserve the integrity of any
18agricultural land that is impacted by commercial renewable
19energy facility construction and deconstruction. The
20construction and deconstruction of any commercial wind energy
21facility or commercial solar energy facility shall be in
22conformance with the Department's standard agricultural impact
23mitigation agreement referenced in subsection (f) of this
24Section. The Department shall have the authority to halt the

 

 

SB2896- 828 -LRB102 17909 JWD 25989 b

1construction or deconstruction of a commercial wind energy
2facility or a commercial solar energy facility that does not
3meet or exceed the terms and conditions included in the
4Department's standard agricultural impact mitigation agreement
5referenced in subsection (f) of this Section, but shall allow
6other portions of the construction that are in compliance to
7continue. The Except as provided in subsection (a-5) of this
8Section, the terms and conditions of the Department's standard
9agricultural impact mitigation agreement are subject to and
10may be modified by an underlying agreement between the
11landowner and the commercial solar energy facility owner,
12subject to approval by the Department.
13    (a-5) Prior to the commencement of construction, the
14commercial renewable energy facility owner of a commercial
15wind energy facility or a commercial solar energy facility a
16commercial solar energy facility owner shall submit to the
17county in which the commercial wind energy facility or
18commercial solar energy facility commercial solar facility is
19to be located a deconstruction plan. A commercial solar energy
20facility owner commercial renewable energy facility owner
21shall provide the county with an appropriate financial
22assurance mechanism consistent with or exceeding the
23requirements of the Department's standard agricultural impact
24mitigation agreement for and to assure deconstruction in the
25event of an abandonment of a commercial wind energy facility
26or commercial solar energy facility.

 

 

SB2896- 829 -LRB102 17909 JWD 25989 b

1    (b) The agricultural impact mitigation agreement for a
2commercial wind energy facility shall include, but is not
3limited to, such items as restoration of agricultural land
4affected by construction, deconstruction (including upon
5abandonment of a commercial wind energy facility),
6construction staging, and storage areas; support structures;
7aboveground facilities; guy wires and anchors; underground
8cabling depth; topsoil replacement; protection and repair of
9agricultural drainage tiles; rock removal; repair of
10compaction and rutting; land leveling; prevention of soil
11erosion; repair of damaged soil conservation practices;
12compensation for damages to private property; clearing of
13trees and brush; interference with irrigation systems; access
14roads; weed control; pumping of water from open excavations;
15advance notice of access to private property; indemnification
16of landowners; and deconstruction plans and financial
17assurance for deconstruction (including upon abandonment of a
18commercial wind energy facility).
19    (b-5) The agricultural impact mitigation agreement for a
20commercial solar energy facility shall include, but is not
21limited to, such items as restoration of agricultural land
22affected by construction, deconstruction (including upon
23abandonment of a commercial solar energy facility); support
24structures; aboveground facilities; guy wires and anchors;
25underground cabling depth; topsoil removal and replacement;
26rerouting and permanent repair of agricultural drainage tiles;

 

 

SB2896- 830 -LRB102 17909 JWD 25989 b

1rock removal; repair of compaction and rutting; construction
2during wet weather; land leveling; prevention of soil erosion;
3repair of damaged soil conservation practices; compensation
4for damages to private property; clearing of trees and brush;
5access roads; weed control; advance notice of access to
6private property; indemnification of landowners; and
7deconstruction plans and financial assurance for
8deconstruction (including upon abandonment of a commercial
9solar energy facility). The commercial solar energy facility
10owner shall enter into one agricultural impact mitigation
11agreement for each commercial solar energy facility.
12    (c) For commercial wind energy facility owners seeking a
13permit from a county or municipality for the construction of a
14commercial wind energy facility, the agricultural impact
15mitigation agreement shall be entered into prior to the public
16hearing required prior to a siting decision of a county or
17municipality regarding the commercial wind energy facility.
18The agricultural impact mitigation agreement is binding on any
19subsequent commercial wind energy facility owner that takes
20ownership of the commercial wind energy facility that is the
21subject of the agreement.
22    (c-5) A commercial solar energy facility owner shall, not
23less than 45 days prior to commencement of actual
24construction, submit to the Department a standard agricultural
25impact mitigation agreement as referenced in subsection (f) of
26this Section signed by the commercial solar energy facility

 

 

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1owner and including all information required by the
2Department. The commercial solar energy facility owner shall
3provide either a copy of that submitted agreement or a copy of
4the fully executed project-specific agricultural impact
5mitigation agreement to the landowner not less than 30 days
6prior to the commencement of construction. The agricultural
7impact mitigation agreement is binding on any subsequent
8commercial solar energy facility owner that takes ownership of
9the commercial solar energy facility that is the subject of
10the agreement.
11    (d) If a commercial renewable energy facility owner seeks
12an extension of a permit granted by a county or municipality
13for the construction of a commercial wind energy facility
14prior to the effective date of this Act, the agricultural
15impact mitigation agreement shall be entered into prior to a
16decision by the county or municipality to grant the permit
17extension.
18    (e) The Department may adopt rules that are necessary and
19appropriate for the implementation and administration of
20agricultural impact mitigation agreements as required under
21this Act.
22    (f) The Department shall make available on its website a
23standard agricultural impact mitigation agreement applicable
24to all commercial wind energy facilities or commercial solar
25energy facilities within 60 days after the effective date of
26this amendatory Act of the 100th General Assembly.

 

 

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1    (g) Nothing in this amendatory Act of the 100th General
2Assembly and nothing in an agricultural impact mitigation
3agreement shall be construed to apply to or otherwise impair
4an underlying agreement for a commercial solar energy facility
5entered into prior to the effective date of this amendatory
6Act of the 100th General Assembly.
7(Source: P.A. 99-132, eff. 7-24-15; 100-598, eff. 6-29-18.)
 
8    Section 30-65. The Consumer Fraud and Deceptive Business
9Practices Act is amended by adding Section 10e as follows:
 
10    (815 ILCS 505/10e new)
11    Sec. 10e. Filed Rate Doctrine. The filed rate doctrine
12shall not be a defense to an action under this Act against any
13entity regulated by the Illinois Commerce Commission. The
14remedies for violations of the Public Utilities Act and its
15rules do not replace, are in addition to and not in
16substitution for, the remedies that may be imposed for
17violations of this Act.
 
18    Section 30-70. The Illinois Worker Adjustment and
19Retraining Notification Act is amended by changing Section 10
20as follows:
 
21    (820 ILCS 65/10)
22    Sec. 10. Notice.

 

 

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1    (a) An employer may not order a mass layoff, relocation,
2or employment loss unless, 60 days before the order takes
3effect, the employer gives written notice of the order to the
4following:
5        (1) affected employees and representatives of affected
6    employees; and
7        (2) the Department of Commerce and Economic
8    Opportunity and the chief elected official of each
9    municipal and county government within which the
10    employment loss, relocation, or mass layoff occurs.
11    (b) An employer of an investor-owned electric generating
12plant or coal mining operation may not order a mass layoff,
13relocation, or employment loss unless, 2 years before the
14order takes effect, the employer gives written notice of the
15order to the following:
16        (1) affected employees and representatives of affected
17    employees; and
18        (2) the Department of Commerce and Economic
19    Opportunity and the chief elected official of each
20    municipal and county government within which the
21    employment loss, relocation, or mass layoff occurs.
22    (b) An employer required to give notice of any mass
23layoff, relocation, or employment loss under this Act shall
24include in its notice the elements required by the federal
25Worker Adjustment and Retraining Notification Act (29 U.S.C.
262101 et seq.).

 

 

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1    (c) Notwithstanding the requirements of subsection (a), an
2employer is not required to provide notice if a mass layoff,
3relocation, or employment loss is necessitated by a physical
4calamity or an act of terrorism or war.
5    (d) The mailing of notice to an employee's last known
6address or inclusion of notice in the employee's paycheck
7shall be considered acceptable methods for fulfillment of the
8employer's obligation to give notice to each affected employee
9under this Act.
10    (e) In the case of a sale of part or all of an employer's
11business, the seller shall be responsible for providing notice
12for any plant closing or mass layoff in accordance with this
13Section, up to and including the effective date of the sale.
14After the effective date of the sale of part or all of an
15employer's business, the purchaser shall be responsible for
16providing notice for any plant closing or mass layoff in
17accordance with this Section. Notwithstanding any other
18provision of this Act, any person who is an employee of the
19seller (other than a part-time employee) as of the effective
20date of the sale shall be considered an employee of the
21purchaser immediately after the effective date of the sale.
22    (f) An employer which is receiving State or local economic
23development incentives for doing or continuing to do business
24in this State may be required to provide additional notice
25pursuant to Section 15 of the Business Economic Support Act.
26    (g) The rights and remedies provided to employees by this

 

 

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1Act are in addition to, and not in lieu of, any other
2contractual or statutory rights and remedies of the employees,
3and are not intended to alter or affect such rights and
4remedies, except that the period of notification required by
5this Act shall run concurrently with any period of
6notification required by contract or by any other law.
7    (h) It is the sense of the General Assembly that an
8employer who is not required to comply with the notice
9requirements of this Section should, to the extent possible,
10provide notice to its employees about a proposal to close a
11plant or permanently reduce its workforce.
12(Source: P.A. 93-915, eff. 1-1-05.)
 
13    Section 30-75. The Prevailing Wage Act is amended by
14changing Section 2 as follows:
 
15    (820 ILCS 130/2)  (from Ch. 48, par. 39s-2)
16    Sec. 2. This Act applies to the wages of laborers,
17mechanics and other workers employed in any public works, as
18hereinafter defined, by any public body and to anyone under
19contracts for public works. This includes any maintenance,
20repair, assembly, or disassembly work performed on equipment
21whether owned, leased, or rented.
22    As used in this Act, unless the context indicates
23otherwise:
24    "Public works" means all fixed works constructed or

 

 

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1demolished by any public body, or paid for wholly or in part
2out of public funds. "Public works" as defined herein includes
3all projects financed in whole or in part with bonds, grants,
4loans, or other funds made available by or through the State or
5any of its political subdivisions, including but not limited
6to: bonds issued under the Industrial Project Revenue Bond Act
7(Article 11, Division 74 of the Illinois Municipal Code), the
8Industrial Building Revenue Bond Act, the Illinois Finance
9Authority Act, the Illinois Sports Facilities Authority Act,
10or the Build Illinois Bond Act; loans or other funds made
11available pursuant to the Build Illinois Act; loans or other
12funds made available pursuant to the Riverfront Development
13Fund under Section 10-15 of the River Edge Redevelopment Zone
14Act; or funds from the Fund for Illinois' Future under Section
156z-47 of the State Finance Act, funds for school construction
16under Section 5 of the General Obligation Bond Act, funds
17authorized under Section 3 of the School Construction Bond
18Act, funds for school infrastructure under Section 6z-45 of
19the State Finance Act, and funds for transportation purposes
20under Section 4 of the General Obligation Bond Act. "Public
21works" also includes (i) all projects financed in whole or in
22part with funds from the Department of Commerce and Economic
23Opportunity under the Illinois Renewable Fuels Development
24Program Act for which there is no project labor agreement;
25(ii) all work performed pursuant to a public private agreement
26under the Public Private Agreements for the Illiana Expressway

 

 

SB2896- 837 -LRB102 17909 JWD 25989 b

1Act or the Public-Private Agreements for the South Suburban
2Airport Act; and (iii) all projects undertaken under a
3public-private agreement under the Public-Private Partnerships
4for Transportation Act. "Public works" also includes all
5projects at leased facility property used for airport purposes
6under Section 35 of the Local Government Facility Lease Act.
7"Public works" also includes: the construction of a new wind
8power facility by a business designated as a High Impact
9Business under Section 5.5(a)(3)(E) of the Illinois Enterprise
10Zone Act; and any project greater than 2,000 kilowatts and
11less than 10,000 kilowatts financed in whole or in part with
12renewable energy credits procured pursuant to subparagraph (K)
13of paragraph (2) of subsection (a) of Section 1-75 and
14paragraph (3) of subsection (a) of Section 1-75 of the
15Illinois Power Agency Act. "Public works" does not include
16work done directly by any public utility company, whether or
17not done under public supervision or direction, or paid for
18wholly or in part out of public funds. "Public works" also
19includes any corrective action performed pursuant to Title XVI
20of the Environmental Protection Act for which payment from the
21Underground Storage Tank Fund is requested. "Public works"
22does not include projects undertaken by the owner at an
23owner-occupied single-family residence or at an owner-occupied
24unit of a multi-family residence. "Public works" does not
25include work performed for soil and water conservation
26purposes on agricultural lands, whether or not done under

 

 

SB2896- 838 -LRB102 17909 JWD 25989 b

1public supervision or paid for wholly or in part out of public
2funds, done directly by an owner or person who has legal
3control of those lands.
4    "Construction" means all work on public works involving
5laborers, workers or mechanics. This includes any maintenance,
6repair, assembly, or disassembly work performed on equipment
7whether owned, leased, or rented.
8    "Locality" means the county where the physical work upon
9public works is performed, except (1) that if there is not
10available in the county a sufficient number of competent
11skilled laborers, workers and mechanics to construct the
12public works efficiently and properly, "locality" includes any
13other county nearest the one in which the work or construction
14is to be performed and from which such persons may be obtained
15in sufficient numbers to perform the work and (2) that, with
16respect to contracts for highway work with the Department of
17Transportation of this State, "locality" may at the discretion
18of the Secretary of the Department of Transportation be
19construed to include two or more adjacent counties from which
20workers may be accessible for work on such construction.
21    "Public body" means the State or any officer, board or
22commission of the State or any political subdivision or
23department thereof, or any institution supported in whole or
24in part by public funds, and includes every county, city,
25town, village, township, school district, irrigation, utility,
26reclamation improvement or other district and every other

 

 

SB2896- 839 -LRB102 17909 JWD 25989 b

1political subdivision, district or municipality of the state
2whether such political subdivision, municipality or district
3operates under a special charter or not.
4    "Labor organization" means an organization that is the
5exclusive representative of an employer's employees recognized
6or certified pursuant to the National Labor Relations Act.
7    The terms "general prevailing rate of hourly wages",
8"general prevailing rate of wages" or "prevailing rate of
9wages" when used in this Act mean the hourly cash wages plus
10annualized fringe benefits for training and apprenticeship
11programs approved by the U.S. Department of Labor, Bureau of
12Apprenticeship and Training, health and welfare, insurance,
13vacations and pensions paid generally, in the locality in
14which the work is being performed, to employees engaged in
15work of a similar character on public works.
16(Source: P.A. 100-1177, eff. 6-1-19.)
 
17    Section 30-80. The Public Utilities Act is amended by
18changing Section 8-103B as follows:
 
19    (220 ILCS 5/8-103B)
20    Sec. 8-103B. Energy efficiency and demand-response
21measures.
22    (a) It is the policy of the State that electric utilities
23are required to use cost-effective energy efficiency and
24demand-response measures to reduce delivery load. Requiring

 

 

SB2896- 840 -LRB102 17909 JWD 25989 b

1investment in cost-effective energy efficiency and
2demand-response measures will reduce direct and indirect costs
3to consumers by decreasing environmental impacts and by
4avoiding or delaying the need for new generation,
5transmission, and distribution infrastructure. It serves the
6public interest to allow electric utilities to recover costs
7for reasonably and prudently incurred expenditures for energy
8efficiency and demand-response measures. As used in this
9Section, "cost-effective" means that the measures satisfy the
10total resource cost test. The low-income measures described in
11subsection (c) of this Section shall not be required to meet
12the total resource cost test. For purposes of this Section,
13the terms "energy-efficiency", "demand-response", "electric
14utility", and "total resource cost test" have the meanings set
15forth in the Illinois Power Agency Act. "Black, indigenous,
16and people of color" and "BIPOC" means people who are members
17of the groups described in subparagraphs (a) through (e) of
18paragraph (A) of subsection (1) of Section 2 of the Business
19Enterprise for Minorities, Women, and Persons with
20Disabilities Act.
21    (a-5) This Section applies to electric utilities serving
22more than 500,000 retail customers in the State for those
23multi-year plans commencing after December 31, 2017.
24    (b) For purposes of this Section, electric utilities
25subject to this Section that serve more than 3,000,000 retail
26customers in the State shall be deemed to have achieved a

 

 

SB2896- 841 -LRB102 17909 JWD 25989 b

1cumulative persisting annual savings of 6.6% from energy
2efficiency measures and programs implemented during the period
3beginning January 1, 2012 and ending December 31, 2017, which
4percent is based on the deemed average weather normalized
5sales of electric power and energy during calendar years 2014,
62015, and 2016 of 88,000,000 MWhs. For the purposes of this
7subsection (b) and subsection (b-5), the 88,000,000 MWhs of
8deemed electric power and energy sales shall be reduced by the
9number of MWhs equal to the sum of the annual consumption of
10customers that are exempt from subsections (a) through (j) of
11this Section under subsection (l) of this Section, as averaged
12across the calendar years 2014, 2015, and 2016. After 2017,
13the deemed value of cumulative persisting annual savings from
14energy efficiency measures and programs implemented during the
15period beginning January 1, 2012 and ending December 31, 2017,
16shall be reduced each year, as follows, and the applicable
17value shall be applied to and count toward the utility's
18achievement of the cumulative persisting annual savings goals
19set forth in subsection (b-5):
20        (1) 5.8% deemed cumulative persisting annual savings
21    for the year ending December 31, 2018;
22        (2) 5.2% deemed cumulative persisting annual savings
23    for the year ending December 31, 2019;
24        (3) 4.5% deemed cumulative persisting annual savings
25    for the year ending December 31, 2020;
26        (4) 4.0% deemed cumulative persisting annual savings

 

 

SB2896- 842 -LRB102 17909 JWD 25989 b

1    for the year ending December 31, 2021;
2        (5) 3.5% deemed cumulative persisting annual savings
3    for the year ending December 31, 2022;
4        (6) 3.1% deemed cumulative persisting annual savings
5    for the year ending December 31, 2023;
6        (7) 2.8% deemed cumulative persisting annual savings
7    for the year ending December 31, 2024;
8        (8) 2.5% deemed cumulative persisting annual savings
9    for the year ending December 31, 2025;
10        (9) 2.3% deemed cumulative persisting annual savings
11    for the year ending December 31, 2026;
12        (10) 2.1% deemed cumulative persisting annual savings
13    for the year ending December 31, 2027;
14        (11) 1.8% deemed cumulative persisting annual savings
15    for the year ending December 31, 2028;
16        (12) 1.7% deemed cumulative persisting annual savings
17    for the year ending December 31, 2029; and
18        (13) 1.5% deemed cumulative persisting annual savings
19    for the year ending December 31, 2030; .
20        (14) 1.3% deemed cumulative persisting annual savings
21    for the year ending December 31, 2031;
22        (15) 1.1% deemed cumulative persisting annual savings
23    for the year ending December 31, 2032;
24        (16) 0.9% deemed cumulative persisting annual savings
25    for the year ending December 31, 2033;
26        (17) 0.7% deemed cumulative persisting annual savings

 

 

SB2896- 843 -LRB102 17909 JWD 25989 b

1    for the year ending December 31, 2034;
2        (18) 0.5% deemed cumulative persisting annual savings
3    for the year ending December 31, 2035;
4        (19) 0.4% deemed cumulative persisting annual savings
5    for the year ending December 31, 2036;
6        (20) 0.3% deemed cumulative persisting annual savings
7    for the year ending December 31, 2037;
8        (21) 0.2% deemed cumulative persisting annual savings
9    for the year ending December 31, 2038;
10        (22) 0.1% deemed cumulative persisting annual savings
11    for the year ending December 31, 2039; and
12        (23) 0.0% deemed cumulative persisting annual savings
13    for the year ending December 31, 2040 and all subsequent
14    years.
15    For purposes of this Section, "cumulative persisting
16annual savings" means the total electric energy savings in a
17given year from measures installed in that year or in previous
18years, but no earlier than January 1, 2012, that are still
19operational and providing savings in that year because the
20measures have not yet reached the end of their useful lives.
21    (b-5) Beginning in 2018, electric utilities subject to
22this Section that serve more than 3,000,000 retail customers
23in the State shall achieve the following cumulative persisting
24annual savings goals, as modified by subsection (f) of this
25Section and as compared to the deemed baseline of 88,000,000
26MWhs of electric power and energy sales set forth in

 

 

SB2896- 844 -LRB102 17909 JWD 25989 b

1subsection (b), as reduced by the number of MWhs equal to the
2sum of the annual consumption of customers that are exempt
3from subsections (a) through (j) of this Section under
4subsection (l) of this Section as averaged across the calendar
5years 2014, 2015, and 2016, through the implementation of
6energy efficiency measures during the applicable year and in
7prior years, but no earlier than January 1, 2012:
8        (1) 7.8% cumulative persisting annual savings for the
9    year ending December 31, 2018;
10        (2) 9.1% cumulative persisting annual savings for the
11    year ending December 31, 2019;
12        (3) 10.4% cumulative persisting annual savings for the
13    year ending December 31, 2020;
14        (4) 11.8% cumulative persisting annual savings for the
15    year ending December 31, 2021;
16        (5) 13.1% cumulative persisting annual savings for the
17    year ending December 31, 2022;
18        (6) 14.4% cumulative persisting annual savings for the
19    year ending December 31, 2023;
20        (7) 15.7% cumulative persisting annual savings for the
21    year ending December 31, 2024;
22        (8) 17% cumulative persisting annual savings for the
23    year ending December 31, 2025;
24        (9) 17.9% cumulative persisting annual savings for the
25    year ending December 31, 2026;
26        (10) 18.8% cumulative persisting annual savings for

 

 

SB2896- 845 -LRB102 17909 JWD 25989 b

1    the year ending December 31, 2027;
2        (11) 19.7% cumulative persisting annual savings for
3    the year ending December 31, 2028;
4        (12) 20.6% cumulative persisting annual savings for
5    the year ending December 31, 2029; and
6        (13) 21.5% cumulative persisting annual savings for
7    the year ending December 31, 2030.
8    No later than December 31, 2021, the Illinois Commerce
9Commission shall establish additional cumulative persisting
10annual savings goals for the years 2031 through 2035. No later
11than December 31, 2024, the Illinois Commerce Commission shall
12establish additional cumulative persisting annual savings
13goals for the years 2036 through 2040. The Commission shall
14also establish additional cumulative persisting annual savings
15goals every 5 years thereafter to ensure utilities always have
16goals that extend at least 11 years into the future. The
17cumulative persisting annual savings goals beyond the year
182030 shall increase by 0.9 percentage points per year, absent
19a Commission decision to initiate a proceeding to consider
20establishing goals that increase by more or less than that
21amount. Such a proceeding must be conducted in accordance with
22the procedures described in subsection (f) of this Section. If
23such a proceeding is initiated, the cumulative persisting
24annual savings goals established by the Commission through
25that proceeding shall reflect the Commission's best estimate
26of the maximum amount of additional savings that are forecast

 

 

SB2896- 846 -LRB102 17909 JWD 25989 b

1to be cost-effectively achievable unless such best estimates
2would result in goals that represent less than 0.5 percentage
3point annual increases in total cumulative persisting annual
4savings. The Commission may only establish goals that
5represent less than 0.5 percentage point annual increases in
6cumulative persisting annual savings if it can demonstrate,
7based on clear and convincing evidence and through independent
8analysis, that 0.5 percentage point increases are not
9cost-effectively achievable. The Commission shall inform its
10decision based on an energy efficiency potential study that
11conforms to the requirements of subsection (f-5) of this
12Section.
13    (b-10) For purposes of this Section, electric utilities
14subject to this Section that serve less than 3,000,000 retail
15customers but more than 500,000 retail customers in the State
16shall be deemed to have achieved a cumulative persisting
17annual savings of 6.6% from energy efficiency measures and
18programs implemented during the period beginning January 1,
192012 and ending December 31, 2017, which is based on the deemed
20average weather normalized sales of electric power and energy
21during calendar years 2014, 2015, and 2016 of 36,900,000 MWhs.
22For the purposes of this subsection (b-10) and subsection
23(b-15), the 36,900,000 MWhs of deemed electric power and
24energy sales shall be reduced by the number of MWhs equal to
25the sum of the annual consumption of customers that are exempt
26from subsections (a) through (j) of this Section under

 

 

SB2896- 847 -LRB102 17909 JWD 25989 b

1subsection (l) of this Section, as averaged across the
2calendar years 2014, 2015, and 2016. After 2017, the deemed
3value of cumulative persisting annual savings from energy
4efficiency measures and programs implemented during the period
5beginning January 1, 2012 and ending December 31, 2017, shall
6be reduced each year, as follows, and the applicable value
7shall be applied to and count toward the utility's achievement
8of the cumulative persisting annual savings goals set forth in
9subsection (b-15):
10        (1) 5.8% deemed cumulative persisting annual savings
11    for the year ending December 31, 2018;
12        (2) 5.2% deemed cumulative persisting annual savings
13    for the year ending December 31, 2019;
14        (3) 4.5% deemed cumulative persisting annual savings
15    for the year ending December 31, 2020;
16        (4) 4.0% deemed cumulative persisting annual savings
17    for the year ending December 31, 2021;
18        (5) 3.5% deemed cumulative persisting annual savings
19    for the year ending December 31, 2022;
20        (6) 3.1% deemed cumulative persisting annual savings
21    for the year ending December 31, 2023;
22        (7) 2.8% deemed cumulative persisting annual savings
23    for the year ending December 31, 2024;
24        (8) 2.5% deemed cumulative persisting annual savings
25    for the year ending December 31, 2025;
26        (9) 2.3% deemed cumulative persisting annual savings

 

 

SB2896- 848 -LRB102 17909 JWD 25989 b

1    for the year ending December 31, 2026;
2        (10) 2.1% deemed cumulative persisting annual savings
3    for the year ending December 31, 2027;
4        (11) 1.8% deemed cumulative persisting annual savings
5    for the year ending December 31, 2028;
6        (12) 1.7% deemed cumulative persisting annual savings
7    for the year ending December 31, 2029; and
8        (13) 1.5% deemed cumulative persisting annual savings
9    for the year ending December 31, 2030; .
10        (14) 1.3% deemed cumulative persisting annual savings
11    for the year ending December 31, 2031;
12        (15) 1.1% deemed cumulative persisting annual savings
13    for the year ending December 31, 2032;
14        (16) 0.9% deemed cumulative persisting annual savings
15    for the year ending December 31, 2033;
16        (17) 0.7% deemed cumulative persisting annual savings
17    for the year ending December 31, 2034;
18        (18) 0.5% deemed cumulative persisting annual savings
19    for the year ending December 31, 2035;
20        (19) 0.4% deemed cumulative persisting annual savings
21    for the year ending December 31, 2036;
22        (20) 0.3% deemed cumulative persisting annual savings
23    for the year ending December 31, 2037;
24        (21) 0.2% deemed cumulative persisting annual savings
25    for the year ending December 31, 2038;
26        (22) 0.1% deemed cumulative persisting annual savings

 

 

SB2896- 849 -LRB102 17909 JWD 25989 b

1    for the year ending December 31, 2039; and
2        (23) 0.0% deemed cumulative persisting annual savings
3    for the year ending December 31, 2040 and all subsequent
4    years.
5    (b-15) Beginning in 2018, electric utilities subject to
6this Section that serve less than 3,000,000 retail customers
7but more than 500,000 retail customers in the State shall
8achieve the following cumulative persisting annual savings
9goals, as modified by subsection (b-20) and subsection (f) of
10this Section and as compared to the deemed baseline as reduced
11by the number of MWhs equal to the sum of the annual
12consumption of customers that are exempt from subsections (a)
13through (j) of this Section under subsection (l) of this
14Section as averaged across the calendar years 2014, 2015, and
152016, through the implementation of energy efficiency measures
16during the applicable year and in prior years, but no earlier
17than January 1, 2012:
18        (1) 7.4% cumulative persisting annual savings for the
19    year ending December 31, 2018;
20        (2) 8.2% cumulative persisting annual savings for the
21    year ending December 31, 2019;
22        (3) 9.0% cumulative persisting annual savings for the
23    year ending December 31, 2020;
24        (4) 9.8% cumulative persisting annual savings for the
25    year ending December 31, 2021;
26        (5) 10.6% cumulative persisting annual savings for the

 

 

SB2896- 850 -LRB102 17909 JWD 25989 b

1    year ending December 31, 2022;
2        (6) 11.4% cumulative persisting annual savings for the
3    year ending December 31, 2023;
4        (7) 12.2% cumulative persisting annual savings for the
5    year ending December 31, 2024;
6        (8) 13% cumulative persisting annual savings for the
7    year ending December 31, 2025;
8        (9) 13.6% cumulative persisting annual savings for the
9    year ending December 31, 2026;
10        (10) 14.2% cumulative persisting annual savings for
11    the year ending December 31, 2027;
12        (11) 14.8% cumulative persisting annual savings for
13    the year ending December 31, 2028;
14        (12) 15.4% cumulative persisting annual savings for
15    the year ending December 31, 2029; and
16        (13) 16% cumulative persisting annual savings for the
17    year ending December 31, 2030.
18    No later than December 31, 2021, the Illinois Commerce
19Commission shall establish additional cumulative persisting
20annual savings goals for the years 2031 through 2035. No later
21than December 31, 2024, the Illinois Commerce Commission shall
22establish additional cumulative persisting annual savings
23goals for the years 2036 through 2040. The Commission shall
24also establish additional cumulative persisting annual savings
25goals every 5 years thereafter to ensure utilities always have
26goals that extend at least 11 years into the future. The

 

 

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1cumulative persisting annual savings goals beyond the year
22030 shall increase by 0.6 percentage points per year, absent
3a Commission decision to initiate a proceeding to consider
4establishing goals that increase by more or less than that
5amount. Such a proceeding must be conducted in accordance with
6the procedures described in subsection (f) of this Section. If
7such a proceeding is initiated, the cumulative persisting
8annual savings goals established by the Commission through
9that proceeding shall reflect the Commission's best estimate
10of the maximum amount of additional savings that are forecast
11to be cost-effectively achievable unless such best estimates
12would result in goals that represent less than 0.4 percentage
13point annual increases in total cumulative persisting annual
14savings. The Commission may only establish goals that
15represent less than 0.4 percentage point annual increases in
16cumulative persisting annual savings if it can demonstrate,
17based on clear and convincing evidence and through independent
18analysis, that 0.4 percentage point increases are not
19cost-effectively achievable. The Commission shall inform its
20decision based on an energy efficiency potential study that
21conforms to the requirements of subsection (f-5) of this
22Section.
23    The difference between the cumulative persisting annual
24savings goal for the applicable calendar year and the
25cumulative persisting annual savings goal for the immediately
26preceding calendar year is 0.8% for the period of January 1,

 

 

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12018 through December 31, 2025 and 0.6% for the period of
2January 1, 2026 through December 31, 2030.
3    (b-20) Each electric utility subject to this Section may
4include cost-effective voltage optimization measures in its
5plans submitted under subsections (f) and (g) of this Section,
6and the costs incurred by a utility to implement the measures
7under a Commission-approved plan shall be recovered under the
8provisions of Article IX or Section 16-108.5 of this Act. For
9purposes of this Section, the measure life of voltage
10optimization measures shall be 15 years. The measure life
11period is independent of the depreciation rate of the voltage
12optimization assets deployed. Utilities may claim savings from
13voltage optimization on circuits for more than 15 years if
14they can demonstrate that they have made additional
15investments necessary to enable voltage optimization savings
16to continue beyond 15 years. Such demonstrations must be
17subject to the review of independent evaluation.
18    Within 270 days after June 1, 2017 (the effective date of
19Public Act 99-906), an electric utility that serves less than
203,000,000 retail customers but more than 500,000 retail
21customers in the State shall file a plan with the Commission
22that identifies the cost-effective voltage optimization
23investment the electric utility plans to undertake through
24December 31, 2024. The Commission, after notice and hearing,
25shall approve or approve with modification the plan within 120
26days after the plan's filing and, in the order approving or

 

 

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1approving with modification the plan, the Commission shall
2adjust the applicable cumulative persisting annual savings
3goals set forth in subsection (b-15) to reflect any amount of
4cost-effective energy savings approved by the Commission that
5is greater than or less than the following cumulative
6persisting annual savings values attributable to voltage
7optimization for the applicable year:
8        (1) 0.0% of cumulative persisting annual savings for
9    the year ending December 31, 2018;
10        (2) 0.17% of cumulative persisting annual savings for
11    the year ending December 31, 2019;
12        (3) 0.17% of cumulative persisting annual savings for
13    the year ending December 31, 2020;
14        (4) 0.33% of cumulative persisting annual savings for
15    the year ending December 31, 2021;
16        (5) 0.5% of cumulative persisting annual savings for
17    the year ending December 31, 2022;
18        (6) 0.67% of cumulative persisting annual savings for
19    the year ending December 31, 2023;
20        (7) 0.83% of cumulative persisting annual savings for
21    the year ending December 31, 2024; and
22        (8) 1.0% of cumulative persisting annual savings for
23    the year ending December 31, 2025 and all subsequent
24    years.
25    (b-25) In the event an electric utility jointly offers an
26energy efficiency measure or program with a gas utility under

 

 

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1plans approved under this Section and Section 8-104 of this
2Act, the electric utility may continue offering the program,
3including the gas energy efficiency measures, in the event the
4gas utility discontinues funding the program. In that event,
5the energy savings value associated with such other fuels
6shall be converted to electric energy savings on an equivalent
7Btu basis for the premises. However, the electric utility
8shall prioritize programs for low-income residential customers
9to the extent practicable. An electric utility may recover the
10costs of offering the gas energy efficiency measures under
11this subsection (b-25).
12    For those energy efficiency measures or programs that save
13both electricity and other fuels but are not jointly offered
14with a gas utility under plans approved under this Section and
15Section 8-104 or not offered with an affiliated gas utility
16under paragraph (6) of subsection (f) of Section 8-104 of this
17Act, the electric utility may count savings of fuels other
18than electricity toward the achievement of its annual savings
19goal, and the energy savings value associated with such other
20fuels shall be converted to electric energy savings on an
21equivalent Btu basis at the premises.
22    In no event shall more than 10% of each year's applicable
23annual total savings requirement incremental goal as defined
24in paragraph (7.5) (7) of subsection (g) of this Section be met
25through savings of fuels other than electricity.
26    (b-27) Beginning in 2022, an electric utility may offer

 

 

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1and promote measures that electrify space heating, water
2heating, cooling, drying, cooking, industrial processes, and
3other building and industrial end uses that would otherwise be
4served by combustion of fossil fuel at the premises, provided
5that the electrification measures reduce total energy
6consumption at the premises. The electric utility may count
7the reduction in energy consumption at the premises toward
8achievement of its annual savings goals. The reduction in
9energy consumption at the premises shall be calculated as the
10difference between: (A) the reduction in Btu consumption of
11fossil fuels as a result of electrification, converted to
12kilowatt-hour equivalents by dividing by 3,412 Btu's per
13kilowatt hour; and (B) the increase in kilowatt hours of
14electricity consumption resulting from the displacement of
15fossil fuel consumption as a result of electrification. An
16electric utility may recover the costs of offering and
17promoting electrification measures under this subsection
18(b-27).
19    In no event shall electrification savings counted toward
20each year's applicable annual total savings requirement, as
21defined in paragraph (7.5) of subsection (g) of this Section,
22be greater than:
23        (1) 5% per year for each year from 2022 through 2025;
24        (2) 10% per year for each year from 2026 through 2029;
25    and
26        (3) 15% per year for 2030 and all subsequent years.

 

 

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1In addition, a minimum of 25% of all electrification savings
2counted toward a utility's applicable annual total savings
3requirement must be from electrification of end uses in
4low-income housing. The limitations on electrification savings
5that may be counted toward a utility's annual savings goals
6are separate from and in addition to the subsection (b-25)
7limitations governing the counting of the other fuel savings
8resulting from efficiency measures and programs.
9    As part of the annual informational filing to the
10Commission that is required under paragraph (9) of subsection
11(g) of this Section, each utility shall identify the specific
12electrification measures offered under this subjection (b-27);
13the quantity of each electrification measure that was
14installed by its customers; the average total cost, average
15utility cost, average reduction in fossil fuel consumption,
16and average increase in electricity consumption associated
17with each electrification measure; the portion of
18installations of each electrification measure that were in
19low-income single-family housing, low-income multifamily
20housing, non-low-income single-family housing, non-low-income
21multifamily housing, commercial buildings, and industrial
22facilities; and the quantity of savings associated with each
23measure category in each customer category that are being
24counted toward the utility's applicable annual total savings
25requirement. Prior to installing an electrification measure,
26the utility shall provide a customer with an estimate of the

 

 

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1impact of the new measure on the customer's average monthly
2electric bill and total annual energy expenses.
3    (c) Electric utilities shall be responsible for overseeing
4the design, development, and filing of energy efficiency plans
5with the Commission and may, as part of that implementation,
6outsource various aspects of program development and
7implementation. A minimum of 10%, for electric utilities that
8serve more than 3,000,000 retail customers in the State, and a
9minimum of 7%, for electric utilities that serve less than
103,000,000 retail customers but more than 500,000 retail
11customers in the State, of the utility's entire portfolio
12funding level for a given year shall be used to procure
13cost-effective energy efficiency measures from units of local
14government, municipal corporations, school districts, public
15housing, and community college districts, provided that a
16minimum percentage of available funds shall be used to procure
17energy efficiency from public housing, which percentage shall
18be equal to public housing's share of public building energy
19consumption.
20    The utilities shall also implement energy efficiency
21measures targeted at low-income households, which, for
22purposes of this Section, shall be defined as households at or
23below 80% of area median income, and expenditures to implement
24the measures shall be no less than $40,000,000 $25,000,000 per
25year for electric utilities that serve more than 3,000,000
26retail customers in the State and no less than $13,000,000

 

 

SB2896- 858 -LRB102 17909 JWD 25989 b

1$8,350,000 per year for electric utilities that serve less
2than 3,000,000 retail customers but more than 500,000 retail
3customers in the State. The ratio of spending on efficiency
4programs targeted at low-income multifamily buildings to
5spending on efficiency programs targeted at low-income
6single-family buildings shall be designed to achieve levels of
7savings from each building type that are approximately
8proportional to the magnitude of cost-effective lifetime
9savings potential in each building type. Investment in
10low-income whole-building weatherization programs shall
11constitute a minimum of 80% of a utility's total budget
12specifically dedicated to serving low-income customers.
13    The utilities shall work to bundle low-income energy
14efficiency offerings with other programs that serve low-income
15households to maximize the benefits going to these households.
16The utilities shall market and implement low-income energy
17efficiency programs in coordination with low-income assistance
18programs, Solar for All, and weatherization whenever
19practicable. The program implementer shall walk the customer
20through the enrollment process for any programs for which the
21customer is eligible. The utilities shall also pilot targeting
22customers with high arrearages, high energy intensity (ratio
23of energy usage divided by home or unit square footage), or
24energy assistance programs with energy efficiency offerings,
25and then track reduction in arrearages as a result of the
26targeting. This targeting and bundling of low-income energy

 

 

SB2896- 859 -LRB102 17909 JWD 25989 b

1programs shall be offered to both low-income single-family and
2multifamily customers (owners and residents).
3    The utilities shall invest in all health and safety
4measures appropriate and necessary for comprehensively
5weatherizing a home or multifamily building, and shall
6implement a health and safety fund of 0.5 at least 15% of the
7total income-qualified weatherization budget, for electric
8utilities that serve more than 3,000,000 retail customers in
9the State, and a minimum of 15% of the total portfolio budget,
10for electric utilities that serve less than 3,000,000 retail
11customers but more than 500,000 retail customers in the State,
12of the utility's entire portfolio funding level for a given
13year, that shall be used for the purpose of making grants for
14technical assistance, construction, reconstruction,
15improvement, or repair of buildings to facilitate their
16participation in the energy efficiency programs targeted at
17low-income single-family and multifamily households. These
18funds may also be used for the purpose of making grants for
19technical assistance, construction, reconstruction,
20improvement, or repair of the following buildings to
21facilitate their participation in the energy efficiency
22programs created by this Section: (1) buildings that are owned
23or operated by registered 501(c)(3) public charities; and (2)
24day care centers, day care homes, or group day care homes, as
25defined under 89 Ill. Adm. Code Part 406, 407, or 408,
26respectively. Utilities shall also ensure that thermal

 

 

SB2896- 860 -LRB102 17909 JWD 25989 b

1insulating materials used for energy efficiency programs
2targeted at low-income single-family and multifamily
3households do not contain any substance that is a Category 1
4respiratory sensitizer as defined by Appendix A to 29 CFR
51910.1200 (Health Hazard Criteria: A.4 Respiratory or Skin
6Sensitization) that was intentionally added or is present at
7greater than 0.1% (1000 ppm) by weight in the product.
8    Each electric utility shall assess opportunities to
9implement cost-effective energy efficiency measures and
10programs through a public housing authority or authorities
11located in its service territory. If such opportunities are
12identified, the utility shall propose such measures and
13programs to address the opportunities. Expenditures to address
14such opportunities shall be credited toward the minimum
15procurement and expenditure requirements set forth in this
16subsection (c).
17    Implementation of energy efficiency measures and programs
18targeted at low-income households should be contracted, when
19it is practicable, to independent third parties that have
20demonstrated capabilities to serve such households, with a
21preference for not-for-profit entities and government agencies
22that have existing relationships with or experience serving
23low-income communities in the State.
24    Each electric utility shall develop and implement
25reporting procedures that address and assist in determining
26the amount of energy savings that can be applied to the

 

 

SB2896- 861 -LRB102 17909 JWD 25989 b

1low-income procurement and expenditure requirements set forth
2in this subsection (c). Each electric utility shall also track
3the types and quantities or volumes of insulation and air
4sealing materials, and their associated energy saving
5benefits, installed in energy efficiency programs targeted at
6low-income single-family and multifamily households.
7    The electric utilities shall participate in also convene a
8low-income energy efficiency accountability advisory committee
9("the committee"), which will directly inform to assist in the
10design, implementation, and evaluation of the low-income and
11public-housing energy efficiency programs. The committee shall
12be comprised of the electric utilities subject to the
13requirements of this Section, the gas utilities subject to the
14requirements of Section 8-104.1 8-104 of this Act, the
15utilities' low-income energy efficiency implementation
16contractors, nonprofit organizations, community action
17agencies, advocacy groups, State and local governmental
18agencies, public-housing organizations, and representatives of
19community-based organizations, especially those living in or
20working with environmental justice communities and BIPOC
21communities. The committee shall be composed of 2
22geographically differentiated subcommittees: one for
23stakeholders in northern Illinois and one for stakeholders in
24central and southern Illinois. The subcommittees shall meet
25together at least twice per year.
26    There shall be one statewide leadership committee led by

 

 

SB2896- 862 -LRB102 17909 JWD 25989 b

1and composed of community-based organizations that are
2representative of BIPOC and environmental justice communities
3and that includes equitable representation from BIPOC
4communities. The leadership committee shall be composed of an
5equal number of representatives from the 2 subcommittees. The
6subcommittees shall address specific programs and issues, with
7the leadership committee convening targeted workgroups as
8needed. The leadership committee may elect to work with an
9independent facilitator to solicit and organize feedback,
10recommendations and meeting participation from a wide variety
11of community-based stakeholders. If a facilitator is used,
12they shall be fair and responsive to the needs of all
13stakeholders involved in the committee.
14     All committee meetings must be accessible, with rotating
15locations if meetings are held in-person, virtual
16participation options, and materials and agendas circulated in
17advance.
18    There shall also be opportunities for direct input by
19committee members outside of committee meetings, such as via
20individual meetings, surveys, emails and calls, to ensure
21robust participation by stakeholders with limited capacity and
22ability to attend committee meetings. Committee meetings shall
23emphasize opportunities to bundle and coordinate delivery of
24low-income energy efficiency with other programs that serve
25low-income communities, such as Solar for All and bill payment
26assistance programs. Meetings shall include educational

 

 

SB2896- 863 -LRB102 17909 JWD 25989 b

1opportunities for stakeholders to learn more about these
2additional offerings, and the committee shall assist in
3figuring out the best methods for coordinated delivery and
4implementation of offerings when serving low-income
5communities. The committee shall directly and equitably
6influence and inform utility low-income and public-housing
7energy efficiency programs and priorities. Participating
8utilities shall implement recommendations from the committee
9whenever possible.
10    Participating utilities shall track and report how input
11from the committee has led to new approaches and changes in
12their energy efficiency portfolios. This reporting shall occur
13at committee meetings and in quarterly energy efficiency
14reports to the Stakeholder Advisory Group and Illinois
15Commerce Commission, and other relevant reporting mechanisms.
16Participating utilities shall also report on relevant equity
17data and metrics requested by the committee, such as energy
18burden data, geographic, racial, and other relevant
19demographic data on where programs are being delivered and
20what populations programs are serving.
21    The Illinois Commerce Commission shall oversee and have
22relevant staff participate in the committee. The committee
23shall have a budget of 0.25% of each utility's entire
24efficiency portfolio funding for a given year. The budget
25shall be overseen by the Commission. The budget shall be used
26to provide grants for community-based organizations serving on

 

 

SB2896- 864 -LRB102 17909 JWD 25989 b

1the leadership committee, stipends for community-based
2organizations participating in the committee, grants for
3community-based organizations to do energy efficiency outreach
4and education, and relevant meeting needs as determined by the
5leadership committee. The education and outreach shall
6include, but is not limited to, basic energy efficiency
7education, information about low-income energy efficiency
8programs, and information on the committee's purpose,
9structure, and activities.
10    (d) Notwithstanding any other provision of law to the
11contrary, a utility providing approved energy efficiency
12measures and, if applicable, demand-response measures in the
13State shall be permitted to recover all reasonable and
14prudently incurred costs of those measures from all retail
15customers, except as provided in subsection (l) of this
16Section, as follows, provided that nothing in this subsection
17(d) permits the double recovery of such costs from customers:
18        (1) The utility may recover its costs through an
19    automatic adjustment clause tariff filed with and approved
20    by the Commission. The tariff shall be established outside
21    the context of a general rate case. Each year the
22    Commission shall initiate a review to reconcile any
23    amounts collected with the actual costs and to determine
24    the required adjustment to the annual tariff factor to
25    match annual expenditures. To enable the financing of the
26    incremental capital expenditures, including regulatory

 

 

SB2896- 865 -LRB102 17909 JWD 25989 b

1    assets, for electric utilities that serve less than
2    3,000,000 retail customers but more than 500,000 retail
3    customers in the State, the utility's actual year-end
4    capital structure that includes a common equity ratio,
5    excluding goodwill, of up to and including 50% of the
6    total capital structure shall be deemed reasonable and
7    used to set rates.
8        (2) A utility may recover its costs through an energy
9    efficiency formula rate approved by the Commission under a
10    filing under subsections (f) and (g) of this Section,
11    which shall specify the cost components that form the
12    basis of the rate charged to customers with sufficient
13    specificity to operate in a standardized manner and be
14    updated annually with transparent information that
15    reflects the utility's actual costs to be recovered during
16    the applicable rate year, which is the period beginning
17    with the first billing day of January and extending
18    through the last billing day of the following December.
19    The energy efficiency formula rate shall be implemented
20    through a tariff filed with the Commission under
21    subsections (f) and (g) of this Section that is consistent
22    with the provisions of this paragraph (2) and that shall
23    be applicable to all delivery services customers. The
24    Commission shall conduct an investigation of the tariff in
25    a manner consistent with the provisions of this paragraph
26    (2), subsections (f) and (g) of this Section, and the

 

 

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1    provisions of Article IX of this Act to the extent they do
2    not conflict with this paragraph (2). The energy
3    efficiency formula rate approved by the Commission shall
4    remain in effect at the discretion of the utility and
5    shall do the following:
6            (A) Provide for the recovery of the utility's
7        actual costs incurred under this Section that are
8        prudently incurred and reasonable in amount consistent
9        with Commission practice and law. The sole fact that a
10        cost differs from that incurred in a prior calendar
11        year or that an investment is different from that made
12        in a prior calendar year shall not imply the
13        imprudence or unreasonableness of that cost or
14        investment.
15            (B) Reflect the utility's actual year-end capital
16        structure for the applicable calendar year, excluding
17        goodwill, subject to a determination of prudence and
18        reasonableness consistent with Commission practice and
19        law. To enable the financing of the incremental
20        capital expenditures, including regulatory assets, for
21        electric utilities that serve less than 3,000,000
22        retail customers but more than 500,000 retail
23        customers in the State, a participating electric
24        utility's actual year-end capital structure that
25        includes a common equity ratio, excluding goodwill, of
26        up to and including 50% of the total capital structure

 

 

SB2896- 867 -LRB102 17909 JWD 25989 b

1        shall be deemed reasonable and used to set rates.
2            (C) Include a cost of equity, which shall be
3        calculated as the sum of the following:
4                (i) the average for the applicable calendar
5            year of the monthly average yields of 30-year U.S.
6            Treasury bonds published by the Board of Governors
7            of the Federal Reserve System in its weekly H.15
8            Statistical Release or successor publication; and
9                (ii) 580 basis points.
10            At such time as the Board of Governors of the
11        Federal Reserve System ceases to include the monthly
12        average yields of 30-year U.S. Treasury bonds in its
13        weekly H.15 Statistical Release or successor
14        publication, the monthly average yields of the U.S.
15        Treasury bonds then having the longest duration
16        published by the Board of Governors in its weekly H.15
17        Statistical Release or successor publication shall
18        instead be used for purposes of this paragraph (2).
19            (D) Permit and set forth protocols, subject to a
20        determination of prudence and reasonableness
21        consistent with Commission practice and law, for the
22        following:
23                (i) recovery of incentive compensation expense
24            that is based on the achievement of operational
25            metrics, including metrics related to budget
26            controls, outage duration and frequency, safety,

 

 

SB2896- 868 -LRB102 17909 JWD 25989 b

1            customer service, efficiency and productivity, and
2            environmental compliance; however, this protocol
3            shall not apply if such expense related to costs
4            incurred under this Section is recovered under
5            Article IX or Section 16-108.5 of this Act;
6            incentive compensation expense that is based on
7            net income or an affiliate's earnings per share
8            shall not be recoverable under the energy
9            efficiency formula rate;
10                (ii) recovery of pension and other
11            post-employment benefits expense, provided that
12            such costs are supported by an actuarial study;
13            however, this protocol shall not apply if such
14            expense related to costs incurred under this
15            Section is recovered under Article IX or Section
16            16-108.5 of this Act;
17                (iii) recovery of existing regulatory assets
18            over the periods previously authorized by the
19            Commission;
20                (iv) as described in subsection (e),
21            amortization of costs incurred under this Section;
22            and
23                (v) projected, weather normalized billing
24            determinants for the applicable rate year.
25            (E) Provide for an annual reconciliation, as
26        described in paragraph (3) of this subsection (d),

 

 

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1        less any deferred taxes related to the reconciliation,
2        with interest at an annual rate of return equal to the
3        utility's weighted average cost of capital, including
4        a revenue conversion factor calculated to recover or
5        refund all additional income taxes that may be payable
6        or receivable as a result of that return, of the energy
7        efficiency revenue requirement reflected in rates for
8        each calendar year, beginning with the calendar year
9        in which the utility files its energy efficiency
10        formula rate tariff under this paragraph (2), with
11        what the revenue requirement would have been had the
12        actual cost information for the applicable calendar
13        year been available at the filing date.
14        The utility shall file, together with its tariff, the
15    projected costs to be incurred by the utility during the
16    rate year under the utility's multi-year plan approved
17    under subsections (f) and (g) of this Section, including,
18    but not limited to, the projected capital investment costs
19    and projected regulatory asset balances with
20    correspondingly updated depreciation and amortization
21    reserves and expense, that shall populate the energy
22    efficiency formula rate and set the initial rates under
23    the formula.
24        The Commission shall review the proposed tariff in
25    conjunction with its review of a proposed multi-year plan,
26    as specified in paragraph (5) of subsection (g) of this

 

 

SB2896- 870 -LRB102 17909 JWD 25989 b

1    Section. The review shall be based on the same evidentiary
2    standards, including, but not limited to, those concerning
3    the prudence and reasonableness of the costs incurred by
4    the utility, the Commission applies in a hearing to review
5    a filing for a general increase in rates under Article IX
6    of this Act. The initial rates shall take effect beginning
7    with the January monthly billing period following the
8    Commission's approval.
9        The tariff's rate design and cost allocation across
10    customer classes shall be consistent with the utility's
11    automatic adjustment clause tariff in effect on June 1,
12    2017 (the effective date of Public Act 99-906); however,
13    the Commission may revise the tariff's rate design and
14    cost allocation in subsequent proceedings under paragraph
15    (3) of this subsection (d).
16        If the energy efficiency formula rate is terminated,
17    the then current rates shall remain in effect until such
18    time as the energy efficiency costs are incorporated into
19    new rates that are set under this subsection (d) or
20    Article IX of this Act, subject to retroactive rate
21    adjustment, with interest, to reconcile rates charged with
22    actual costs.
23        (3) The provisions of this paragraph (3) shall only
24    apply to an electric utility that has elected to file an
25    energy efficiency formula rate under paragraph (2) of this
26    subsection (d). Subsequent to the Commission's issuance of

 

 

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1    an order approving the utility's energy efficiency formula
2    rate structure and protocols, and initial rates under
3    paragraph (2) of this subsection (d), the utility shall
4    file, on or before June 1 of each year, with the Chief
5    Clerk of the Commission its updated cost inputs to the
6    energy efficiency formula rate for the applicable rate
7    year and the corresponding new charges, as well as the
8    information described in paragraph (9) of subsection (g)
9    of this Section. Each such filing shall conform to the
10    following requirements and include the following
11    information:
12            (A) The inputs to the energy efficiency formula
13        rate for the applicable rate year shall be based on the
14        projected costs to be incurred by the utility during
15        the rate year under the utility's multi-year plan
16        approved under subsections (f) and (g) of this
17        Section, including, but not limited to, projected
18        capital investment costs and projected regulatory
19        asset balances with correspondingly updated
20        depreciation and amortization reserves and expense.
21        The filing shall also include a reconciliation of the
22        energy efficiency revenue requirement that was in
23        effect for the prior rate year (as set by the cost
24        inputs for the prior rate year) with the actual
25        revenue requirement for the prior rate year
26        (determined using a year-end rate base) that uses

 

 

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1        amounts reflected in the applicable FERC Form 1 that
2        reports the actual costs for the prior rate year. Any
3        over-collection or under-collection indicated by such
4        reconciliation shall be reflected as a credit against,
5        or recovered as an additional charge to, respectively,
6        with interest calculated at a rate equal to the
7        utility's weighted average cost of capital approved by
8        the Commission for the prior rate year, the charges
9        for the applicable rate year. Such over-collection or
10        under-collection shall be adjusted to remove any
11        deferred taxes related to the reconciliation, for
12        purposes of calculating interest at an annual rate of
13        return equal to the utility's weighted average cost of
14        capital approved by the Commission for the prior rate
15        year, including a revenue conversion factor calculated
16        to recover or refund all additional income taxes that
17        may be payable or receivable as a result of that
18        return. Each reconciliation shall be certified by the
19        participating utility in the same manner that FERC
20        Form 1 is certified. The filing shall also include the
21        charge or credit, if any, resulting from the
22        calculation required by subparagraph (E) of paragraph
23        (2) of this subsection (d).
24            Notwithstanding any other provision of law to the
25        contrary, the intent of the reconciliation is to
26        ultimately reconcile both the revenue requirement

 

 

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1        reflected in rates for each calendar year, beginning
2        with the calendar year in which the utility files its
3        energy efficiency formula rate tariff under paragraph
4        (2) of this subsection (d), with what the revenue
5        requirement determined using a year-end rate base for
6        the applicable calendar year would have been had the
7        actual cost information for the applicable calendar
8        year been available at the filing date.
9            For purposes of this Section, "FERC Form 1" means
10        the Annual Report of Major Electric Utilities,
11        Licensees and Others that electric utilities are
12        required to file with the Federal Energy Regulatory
13        Commission under the Federal Power Act, Sections 3,
14        4(a), 304 and 209, modified as necessary to be
15        consistent with 83 Ill. Admin. Code Part 415 as of May
16        1, 2011. Nothing in this Section is intended to allow
17        costs that are not otherwise recoverable to be
18        recoverable by virtue of inclusion in FERC Form 1.
19            (B) The new charges shall take effect beginning on
20        the first billing day of the following January billing
21        period and remain in effect through the last billing
22        day of the next December billing period regardless of
23        whether the Commission enters upon a hearing under
24        this paragraph (3).
25            (C) The filing shall include relevant and
26        necessary data and documentation for the applicable

 

 

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1        rate year. Normalization adjustments shall not be
2        required.
3        Within 45 days after the utility files its annual
4    update of cost inputs to the energy efficiency formula
5    rate, the Commission shall with reasonable notice,
6    initiate a proceeding concerning whether the projected
7    costs to be incurred by the utility and recovered during
8    the applicable rate year, and that are reflected in the
9    inputs to the energy efficiency formula rate, are
10    consistent with the utility's approved multi-year plan
11    under subsections (f) and (g) of this Section and whether
12    the costs incurred by the utility during the prior rate
13    year were prudent and reasonable. The Commission shall
14    also have the authority to investigate the information and
15    data described in paragraph (9) of subsection (g) of this
16    Section, including the proposed adjustment to the
17    utility's return on equity component of its weighted
18    average cost of capital. During the course of the
19    proceeding, each objection shall be stated with
20    particularity and evidence provided in support thereof,
21    after which the utility shall have the opportunity to
22    rebut the evidence. Discovery shall be allowed consistent
23    with the Commission's Rules of Practice, which Rules of
24    Practice shall be enforced by the Commission or the
25    assigned administrative law judge. The Commission shall
26    apply the same evidentiary standards, including, but not

 

 

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1    limited to, those concerning the prudence and
2    reasonableness of the costs incurred by the utility,
3    during the proceeding as it would apply in a proceeding to
4    review a filing for a general increase in rates under
5    Article IX of this Act. The Commission shall not, however,
6    have the authority in a proceeding under this paragraph
7    (3) to consider or order any changes to the structure or
8    protocols of the energy efficiency formula rate approved
9    under paragraph (2) of this subsection (d). In a
10    proceeding under this paragraph (3), the Commission shall
11    enter its order no later than the earlier of 195 days after
12    the utility's filing of its annual update of cost inputs
13    to the energy efficiency formula rate or December 15. The
14    utility's proposed return on equity calculation, as
15    described in paragraphs (7) through (9) of subsection (g)
16    of this Section, shall be deemed the final, approved
17    calculation on December 15 of the year in which it is filed
18    unless the Commission enters an order on or before
19    December 15, after notice and hearing, that modifies such
20    calculation consistent with this Section. The Commission's
21    determinations of the prudence and reasonableness of the
22    costs incurred, and determination of such return on equity
23    calculation, for the applicable calendar year shall be
24    final upon entry of the Commission's order and shall not
25    be subject to reopening, reexamination, or collateral
26    attack in any other Commission proceeding, case, docket,

 

 

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1    order, rule, or regulation; however, nothing in this
2    paragraph (3) shall prohibit a party from petitioning the
3    Commission to rehear or appeal to the courts the order
4    under the provisions of this Act.
5    (e) Beginning on June 1, 2017 (the effective date of
6Public Act 99-906), a utility subject to the requirements of
7this Section may elect to defer, as a regulatory asset, up to
8the full amount of its expenditures incurred under this
9Section for each annual period, including, but not limited to,
10any expenditures incurred above the funding level set by
11subsection (f) of this Section for a given year. The total
12expenditures deferred as a regulatory asset in a given year
13shall be amortized and recovered over a period that is equal to
14the weighted average of the energy efficiency measure lives
15implemented for that year that are reflected in the regulatory
16asset. The unamortized balance shall be recognized as of
17December 31 for a given year. The utility shall also earn a
18return on the total of the unamortized balances of all of the
19energy efficiency regulatory assets, less any deferred taxes
20related to those unamortized balances, at an annual rate equal
21to the utility's weighted average cost of capital that
22includes, based on a year-end capital structure, the utility's
23actual cost of debt for the applicable calendar year and a cost
24of equity, which shall be calculated as the sum of the (i) the
25average for the applicable calendar year of the monthly
26average yields of 30-year U.S. Treasury bonds published by the

 

 

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1Board of Governors of the Federal Reserve System in its weekly
2H.15 Statistical Release or successor publication; and (ii)
3580 basis points, including a revenue conversion factor
4calculated to recover or refund all additional income taxes
5that may be payable or receivable as a result of that return.
6Capital investment costs shall be depreciated and recovered
7over their useful lives consistent with generally accepted
8accounting principles. The weighted average cost of capital
9shall be applied to the capital investment cost balance, less
10any accumulated depreciation and accumulated deferred income
11taxes, as of December 31 for a given year.
12    When an electric utility creates a regulatory asset under
13the provisions of this Section, the costs are recovered over a
14period during which customers also receive a benefit which is
15in the public interest. Accordingly, it is the intent of the
16General Assembly that an electric utility that elects to
17create a regulatory asset under the provisions of this Section
18shall recover all of the associated costs as set forth in this
19Section. After the Commission has approved the prudence and
20reasonableness of the costs that comprise the regulatory
21asset, the electric utility shall be permitted to recover all
22such costs, and the value and recoverability through rates of
23the associated regulatory asset shall not be limited, altered,
24impaired, or reduced.
25    (f) Beginning in 2017, each electric utility shall file an
26energy efficiency plan with the Commission to meet the energy

 

 

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1efficiency standards for the next applicable multi-year period
2beginning January 1 of the year following the filing,
3according to the schedule set forth in paragraphs (1) through
4(3) of this subsection (f). If a utility does not file such a
5plan on or before the applicable filing deadline for the plan,
6it shall face a penalty of $100,000 per day until the plan is
7filed.
8        (1) No later than 30 days after June 1, 2017 (the
9    effective date of Public Act 99-906), each electric
10    utility shall file a 4-year energy efficiency plan
11    commencing on January 1, 2018 that is designed to achieve
12    the cumulative persisting annual savings goals specified
13    in paragraphs (1) through (4) of subsection (b-5) of this
14    Section or in paragraphs (1) through (4) of subsection
15    (b-15) of this Section, as applicable, through
16    implementation of energy efficiency measures; however, the
17    goals may be reduced if the utility's expenditures are
18    limited pursuant to subsection (m) of this Section or, for
19    a utility that serves less than 3,000,000 retail
20    customers, if each of the following conditions are met:
21    (A) the plan's analysis and forecasts of the utility's
22    ability to acquire energy savings demonstrate that
23    achievement of such goals is not cost effective; and (B)
24    the amount of energy savings achieved by the utility as
25    determined by the independent evaluator for the most
26    recent year for which savings have been evaluated

 

 

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1    preceding the plan filing was less than the average annual
2    amount of savings required to achieve the goals for the
3    applicable 4-year plan period. Except as provided in
4    subsection (m) of this Section, annual increases in
5    cumulative persisting annual savings goals during the
6    applicable 4-year plan period shall not be reduced to
7    amounts that are less than the maximum amount of
8    cumulative persisting annual savings that is forecast to
9    be cost-effectively achievable during the 4-year plan
10    period. The Commission shall review any proposed goal
11    reduction as part of its review and approval of the
12    utility's proposed plan.
13        (2) No later than March 1, 2021, each electric utility
14    shall file a 4-year energy efficiency plan commencing on
15    January 1, 2022 that is designed to achieve the cumulative
16    persisting annual savings goals specified in paragraphs
17    (5) through (8) of subsection (b-5) of this Section or in
18    paragraphs (5) through (8) of subsection (b-15) of this
19    Section, as applicable, through implementation of energy
20    efficiency measures; however, the goals may be reduced if
21    either (1) clear and convincing evidence demonstrates,
22    through independent analysis, that the expenditure limits
23    in subsection (m) of this Section preclude full
24    achievement of the goals or (2) the utility's expenditures
25    are limited pursuant to subsection (m) of this Section or,
26    each of the following conditions are met: (A) the plan's

 

 

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1    analysis and forecasts of the utility's ability to acquire
2    energy savings demonstrate by clear and convincing
3    evidence and through independent analysis that achievement
4    of such goals is not cost effective; and (B) the amount of
5    energy savings achieved by the utility as determined by
6    the independent evaluator for the most recent year for
7    which savings have been evaluated preceding the plan
8    filing was less than the average annual amount of savings
9    required to achieve the goals for the applicable 4-year
10    plan period. If there is not clear and convincing evidence
11    that achieving the savings goals specified in paragraph
12    (b-5) or (b-15) of this Section is possible both
13    cost-effectively and within the expenditure limits in
14    subsection (m), such savings goals shall not be reduced.
15    Except as provided in subsection (m) of this Section,
16    annual increases in cumulative persisting annual savings
17    goals during the applicable 4-year plan period shall not
18    be reduced to amounts that are less than the maximum
19    amount of cumulative persisting annual savings that is
20    forecast to be cost-effectively achievable during the
21    4-year plan period. The Commission shall review any
22    proposed goal reduction as part of its review and approval
23    of the utility's proposed plan, taking into account the
24    results of the potential study required by subsection
25    (f-5) of this Section.
26        (3) No later than March 1, 2025, each electric utility

 

 

SB2896- 881 -LRB102 17909 JWD 25989 b

1    shall file a 4-year 5-year energy efficiency plan
2    commencing on January 1, 2026 that is designed to achieve
3    the cumulative persisting annual savings goals specified
4    in paragraphs (9) through (12) (13) of subsection (b-5) of
5    this Section or in paragraphs (9) through (12) (13) of
6    subsection (b-15) of this Section, as applicable, through
7    implementation of energy efficiency measures; however, the
8    goals may be reduced if either (1) clear and convincing
9    evidence demonstrates, through independent analysis, that
10    the expenditure limits in subsection (m) of this Section
11    preclude full achievement of the goals or (2) the
12    utility's expenditures are limited pursuant to subsection
13    (m) of this Section or, each of the following conditions
14    are met: (A) the plan's analysis and forecasts of the
15    utility's ability to acquire energy savings demonstrate by
16    clear and convincing evidence and through independent
17    analysis that achievement of such goals is not cost
18    effective; and (B) the amount of energy savings achieved
19    by the utility as determined by the independent evaluator
20    for the most recent year for which savings have been
21    evaluated preceding the plan filing was less than the
22    average annual amount of savings required to achieve the
23    goals for the applicable 4-year 5-year plan period. If
24    there is not clear and convincing evidence that achieving
25    the savings goals specified in paragraphs (b-5) or (b-15)
26    of this Section is possible both cost-effectively and

 

 

SB2896- 882 -LRB102 17909 JWD 25989 b

1    within the expenditure limits in subsection (m), such
2    savings goals shall not be reduced. Except as provided in
3    subsection (m) of this Section, annual increases in
4    cumulative persisting annual savings goals during the
5    applicable 4-year 5-year plan period shall not be reduced
6    to amounts that are less than the maximum amount of
7    cumulative persisting annual savings that is forecast to
8    be cost-effectively achievable during the 4-year 5-year
9    plan period. The Commission shall review any proposed goal
10    reduction as part of its review and approval of the
11    utility's proposed plan, taking into account the results
12    of the potential study required by subsection (f-5) of
13    this Section.
14        (4) No later than March 1, 2029, and every 4 years
15    thereafter, each electric utility shall file a 4-year
16    energy efficiency plan commencing on January 1, 2030, and
17    every 4 years thereafter, respectively, that is designed
18    to achieve the cumulative persisting annual savings goals
19    established by the Illinois Commerce Commission pursuant
20    to direction of subsections (b-5) and (b-15) of this
21    Section, as applicable, through implementation of energy
22    efficiency measures; however, the goals may be reduced if
23    either (1) clear and convincing evidence and independent
24    analysis demonstrates that the expenditure limits in
25    subsection (m) of this Section preclude full achievement
26    of the goals or (2) each of the following conditions are

 

 

SB2896- 883 -LRB102 17909 JWD 25989 b

1    met: (A) the plan's analysis and forecasts of the
2    utility's ability to acquire energy savings demonstrate by
3    clear and convincing evidence and through independent
4    analysis that achievement of such goals is not
5    cost-effective; and (B) the amount of energy savings
6    achieved by the utility as determined by the independent
7    evaluator for the most recent year for which savings have
8    been evaluated preceding the plan filing was less than the
9    average annual amount of savings required to achieve the
10    goals for the applicable 4-year plan period. If there is
11    not clear and convincing evidence that achieving the
12    savings goals specified in paragraphs (b-5) or (b-15) of
13    this Section is possible both cost-effectively and within
14    the expenditure limits in subsection (m), such savings
15    goals shall not be reduced. Except as provided in
16    subsection (m) of this Section, annual increases in
17    cumulative persisting annual savings goals during the
18    applicable 4-year plan period shall not be reduced to
19    amounts that are less than the maximum amount of
20    cumulative persisting annual savings that is forecast to
21    be cost-effectively achievable during the 4-year plan
22    period. The Commission shall review any proposed goal
23    reduction as part of its review and approval of the
24    utility's proposed plan.
25    Each utility's plan shall set forth the utility's
26proposals to meet the energy efficiency standards identified

 

 

SB2896- 884 -LRB102 17909 JWD 25989 b

1in subsection (b-5) or (b-15), as applicable and as such
2standards may have been modified under this subsection (f),
3taking into account the unique circumstances of the utility's
4service territory and results of an energy efficiency
5potential study as described in subsection (f-5) of this
6Section. For those plans commencing on January 1, 2018, the
7Commission shall seek public comment on the utility's plan and
8shall issue an order approving or disapproving each plan no
9later than 105 days after June 1, 2017 (the effective date of
10Public Act 99-906). For those plans commencing after December
1131, 2021, the Commission shall seek public comment on the
12utility's plan and shall issue an order approving or
13disapproving each plan within 6 months after its submission.
14If the Commission disapproves a plan, the Commission shall,
15within 30 days, describe in detail the reasons for the
16disapproval and describe a path by which the utility may file a
17revised draft of the plan to address the Commission's concerns
18satisfactorily. If the utility does not refile with the
19Commission within 60 days, the utility shall be subject to
20penalties at a rate of $100,000 per day until the plan is
21filed. This process shall continue, and penalties shall
22accrue, until the utility has successfully filed a portfolio
23of energy efficiency and demand-response measures. Penalties
24shall be deposited into the Energy Efficiency Trust Fund.
25    (g) In submitting proposed plans and funding levels under
26subsection (f) of this Section to meet the savings goals

 

 

SB2896- 885 -LRB102 17909 JWD 25989 b

1identified in subsection (b-5) or (b-15) of this Section, as
2applicable, the utility shall:
3        (1) Demonstrate that its proposed energy efficiency
4    measures will achieve the applicable requirements that are
5    identified in subsection (b-5) or (b-15) of this Section,
6    as modified by subsection (f) of this Section.
7        (2) (Blank). Present specific proposals to implement
8    new building and appliance standards that have been placed
9    into effect.
10        (2.5) Demonstrate consideration of program options for
11    (A) advancing new building codes, appliance standards, and
12    municipal regulations governing existing and new building
13    efficiency improvements and (B) supporting efforts to
14    improve compliance with new building codes, appliance
15    standards and municipal regulations, as potentially
16    cost-effective means of acquiring energy savings to count
17    toward savings goals.
18        (3) Demonstrate that its overall portfolio of
19    measures, not including low-income programs described in
20    subsection (c) of this Section, is cost-effective using
21    the total resource cost test or complies with paragraphs
22    (1) through (3) of subsection (f) of this Section and
23    represents a diverse cross-section of opportunities for
24    customers of all rate classes, other than those customers
25    described in subsection (l) of this Section, to
26    participate in the programs. Individual measures need not

 

 

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1    be cost effective.
2        (3.5) Demonstrate that the utility's plan integrates
3    the delivery of energy efficiency programs with natural
4    gas efficiency programs, programs promoting distributed
5    solar, programs promoting demand response and other
6    efforts to address bill payment issues, including, but not
7    limited to, LIHEAP and the Percentage of Income Payment
8    Plan, to the extent such integration is practical and has
9    the potential to enhance customer engagement, minimize
10    market confusion, or reduce administrative costs.
11        (4) Present a third-party energy efficiency
12    implementation program subject to the following
13    requirements:
14            (A) beginning with the year commencing January 1,
15        2019, electric utilities that serve more than
16        3,000,000 retail customers in the State shall fund
17        third-party energy efficiency programs in an amount
18        that is no less than $25,000,000 per year, and
19        electric utilities that serve less than 3,000,000
20        retail customers but more than 500,000 retail
21        customers in the State shall fund third-party energy
22        efficiency programs in an amount that is no less than
23        $8,350,000 per year;
24            (B) during 2018, the utility shall conduct a
25        solicitation process for purposes of requesting
26        proposals from third-party vendors for those

 

 

SB2896- 887 -LRB102 17909 JWD 25989 b

1        third-party energy efficiency programs to be offered
2        during one or more of the years commencing January 1,
3        2019, January 1, 2020, and January 1, 2021; for those
4        multi-year plans commencing on January 1, 2022 and
5        January 1, 2026, the utility shall conduct a
6        solicitation process during 2021 and 2025,
7        respectively, for purposes of requesting proposals
8        from third-party vendors for those third-party energy
9        efficiency programs to be offered during one or more
10        years of the respective multi-year plan period; for
11        each solicitation process, the utility shall identify
12        the sector, technology, or geographical area for which
13        it is seeking requests for proposals; the solicitation
14        process must be either for programs that fill gaps in
15        the utility's program portfolio and for programs that
16        target low-income customers, business sectors,
17        building types, geographies, or other specific parts
18        of its customer base with initiatives that would be
19        more effective at reaching these customer segments
20        than the utilities' programs filed in its energy
21        efficiency plans;
22            (C) the utility shall propose the bidder
23        qualifications, performance measurement process, and
24        contract structure, which must include a performance
25        payment mechanism and general terms and conditions;
26        the proposed qualifications, process, and structure

 

 

SB2896- 888 -LRB102 17909 JWD 25989 b

1        shall be subject to Commission approval; and
2            (D) the utility shall retain an independent third
3        party to score the proposals received through the
4        solicitation process described in this paragraph (4),
5        rank them according to their cost per lifetime
6        kilowatt-hours saved, and assemble the portfolio of
7        third-party programs.
8        The electric utility shall recover all costs
9    associated with Commission-approved, third-party
10    administered programs regardless of the success of those
11    programs.
12        (4.5) Implement cost-effective demand-response
13    measures to reduce peak demand by 0.1% over the prior year
14    for eligible retail customers, as defined in Section
15    16-111.5 of this Act, and for customers that elect hourly
16    service from the utility pursuant to Section 16-107 of
17    this Act, provided those customers have not been declared
18    competitive. This requirement continues until December 31,
19    2026.
20        (5) Include a proposed or revised cost-recovery tariff
21    mechanism, as provided for under subsection (d) of this
22    Section, to fund the proposed energy efficiency and
23    demand-response measures and to ensure the recovery of the
24    prudently and reasonably incurred costs of
25    Commission-approved programs.
26        (6) Provide for an annual independent evaluation of

 

 

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1    the performance of the cost-effectiveness of the utility's
2    portfolio of measures, as well as a full review of the
3    multi-year plan results of the broader net program impacts
4    and, to the extent practical, for adjustment of the
5    measures on a going-forward basis as a result of the
6    evaluations. The resources dedicated to evaluation shall
7    not exceed 3% of portfolio resources in any given year.
8        (7) For electric utilities that serve more than
9    3,000,000 retail customers in the State:
10            (A) Through December 31, 2025, provide for an
11        adjustment to the return on equity component of the
12        utility's weighted average cost of capital calculated
13        under subsection (d) of this Section:
14                (i) If the independent evaluator determines
15            that the utility achieved a cumulative persisting
16            annual savings that is less than the applicable
17            annual incremental goal, then the return on equity
18            component shall be reduced by a maximum of 200
19            basis points in the event that the utility
20            achieved no more than 75% of such goal. If the
21            utility achieved more than 75% of the applicable
22            annual incremental goal but less than 100% of such
23            goal, then the return on equity component shall be
24            reduced by 8 basis points for each percent by
25            which the utility failed to achieve the goal.
26                (ii) If the independent evaluator determines

 

 

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1            that the utility achieved a cumulative persisting
2            annual savings that is more than the applicable
3            annual incremental goal, then the return on equity
4            component shall be increased by a maximum of 200
5            basis points in the event that the utility
6            achieved at least 125% of such goal. If the
7            utility achieved more than 100% of the applicable
8            annual incremental goal but less than 125% of such
9            goal, then the return on equity component shall be
10            increased by 8 basis points for each percent by
11            which the utility achieved above the goal. If the
12            applicable annual incremental goal was reduced
13            under paragraphs (1) or (2) of subsection (f) of
14            this Section, then the following adjustments shall
15            be made to the calculations described in this item
16            (ii):
17                    (aa) the calculation for determining
18                achievement that is at least 125% of the
19                applicable annual incremental goal shall use
20                the unreduced applicable annual incremental
21                goal to set the value; and
22                    (bb) the calculation for determining
23                achievement that is less than 125% but more
24                than 100% of the applicable annual incremental
25                goal shall use the reduced applicable annual
26                incremental goal to set the value for 100%

 

 

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1                achievement of the goal and shall use the
2                unreduced goal to set the value for 125%
3                achievement. The 8 basis point value shall
4                also be modified, as necessary, so that the
5                200 basis points are evenly apportioned among
6                each percentage point value between 100% and
7                125% achievement.
8            (B) For the period January 1, 2026 through
9        December 31, 2029 and in all subsequent 4-year periods
10        2030, provide for an adjustment to the return on
11        equity component of the utility's weighted average
12        cost of capital calculated under subsection (d) of
13        this Section:
14                (i) If the independent evaluator determines
15            that the utility achieved a cumulative persisting
16            annual savings that is less than the applicable
17            annual incremental goal, then the return on equity
18            component shall be reduced by a maximum of 200
19            basis points in the event that the utility
20            achieved no more than 66% of such goal. If the
21            utility achieved more than 66% of the applicable
22            annual incremental goal but less than 100% of such
23            goal, then the return on equity component shall be
24            reduced by 6 basis points for each percent by
25            which the utility failed to achieve the goal.
26                (ii) If the independent evaluator determines

 

 

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1            that the utility achieved a cumulative persisting
2            annual savings that is more than the applicable
3            annual incremental goal, then the return on equity
4            component shall be increased by a maximum of 200
5            basis points in the event that the utility
6            achieved at least 134% of such goal. If the
7            utility achieved more than 100% of the applicable
8            annual incremental goal but less than 134% of such
9            goal, then the return on equity component shall be
10            increased by 6 basis points for each percent by
11            which the utility achieved above the goal. If the
12            applicable annual incremental goal was reduced
13            under paragraph (3) of subsection (f) of this
14            Section, then the following adjustments shall be
15            made to the calculations described in this item
16            (ii):
17                    (aa) the calculation for determining
18                achievement that is at least 134% of the
19                applicable annual incremental goal shall use
20                the unreduced applicable annual incremental
21                goal to set the value; and
22                    (bb) the calculation for determining
23                achievement that is less than 134% but more
24                than 100% of the applicable annual incremental
25                goal shall use the reduced applicable annual
26                incremental goal to set the value for 100%

 

 

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1                achievement of the goal and shall use the
2                unreduced goal to set the value for 134%
3                achievement. The 6 basis point value shall
4                also be modified, as necessary, so that the
5                200 basis points are evenly apportioned among
6                each percentage point value between 100% and
7                134% achievement.
8            (C) Notwithstanding the provisions of
9        subparagraphs (A) and (B) of this paragraph (7), if
10        the applicable annual incremental goal for an electric
11        utility is ever less than 0.6% of deemed average
12        weather normalized sales of electric power and energy
13        during calendar years 2014, 2015, and 2016, an
14        adjustment to the return on equity component of the
15        utility's weighted average cost of capital calculated
16        under subsection (d) of this Section shall be made as
17        follows:
18                (i) If the independent evaluator determines
19            that the utility achieved a cumulative persisting
20            annual savings that is less than would have been
21            achieved had the applicable annual incremental
22            goal been achieved, then the return on equity
23            component shall be reduced by a maximum of 200
24            basis points if the utility achieved no more than
25            75% of its applicable annual total savings
26            requirement as defined in paragraph (7.5) of this

 

 

SB2896- 894 -LRB102 17909 JWD 25989 b

1            subsection. If the utility achieved more than 75%
2            of the applicable annual total savings requirement
3            but less than 100% of such goal, then the return on
4            equity component shall be reduced by 8 basis
5            points for each percent by which the utility
6            failed to achieve the goal.
7                (ii) If the independent evaluator determines
8            that the utility achieved a cumulative persisting
9            annual savings that is more than would have been
10            achieved had the applicable annual incremental
11            goal been achieved, then the return on equity
12            component shall be increased by a maximum of 200
13            basis points if the utility achieved at least 125%
14            of its applicable annual total savings
15            requirement. If the utility achieved more than
16            100% of the applicable annual total savings
17            requirement but less than 125% of such goal, then
18            the return on equity component shall be increased
19            by 8 basis points for each percent by which the
20            utility achieved above the applicable annual total
21            savings requirement. If the applicable annual
22            incremental goal was reduced under paragraphs (1)
23            or (2) of subsection (f) of this Section, then the
24            following adjustments shall be made to the
25            calculations described in this item (ii):
26                    (aa) the calculation for determining

 

 

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1                achievement that is at least 125% of the
2                applicable annual total savings requirement
3                shall use the unreduced applicable annual
4                incremental goal to set the value; and
5                    (bb) the calculation for determining
6                achievement that is less than 125% but more
7                than 100% of the applicable annual total
8                savings requirement shall use the reduced
9                applicable annual incremental goal to set the
10                value for 100% achievement of the goal and
11                shall use the unreduced goal to set the value
12                for 125% achievement. The 8 basis point value
13                shall also be modified, as necessary, so that
14                the 200 basis points are evenly apportioned
15                among each percentage point value between 100%
16                and 125% achievement.
17        (7.5) For purposes of this Section, the term
18    "applicable annual incremental goal" means the difference
19    between the cumulative persisting annual savings goal for
20    the calendar year that is the subject of the independent
21    evaluator's determination and the cumulative persisting
22    annual savings goal for the immediately preceding calendar
23    year, as such goals are defined in subsections (b-5) and
24    (b-15) of this Section and as these goals may have been
25    modified as provided for under subsection (b-20) and
26    paragraphs (1) through (3) of subsection (f) of this

 

 

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1    Section. Under subsections (b), (b-5), (b-10), and (b-15)
2    of this Section, a utility must first replace energy
3    savings from measures that have expired reached the end of
4    their measure lives and would otherwise have to be
5    replaced to meet the applicable savings goals identified
6    in subsection (b-5) or (b-15) of this Section before any
7    progress towards achievement of its applicable annual
8    incremental goal may be counted. Savings may expire
9    because measures installed in previous years have reached
10    the end of their lives, because measures installed in
11    previous years are producing lower savings in the current
12    year than in the previous year, or for other reasons
13    identified by independent evaluators. Notwithstanding
14    anything else set forth in this Section, the difference
15    between the actual annual incremental savings achieved in
16    any given year, including the replacement of energy
17    savings from measures that have expired, and the
18    applicable annual incremental goal shall not affect
19    adjustments to the return on equity for subsequent
20    calendar years under this subsection (g).
21        In this Section, "applicable annual total savings
22    requirement" means the total amount of new annual savings
23    that the utility must achieve in any given year to achieve
24    the applicable annual incremental goal. This is equal to
25    the applicable annual incremental goal plus the total new
26    annual savings that are required to replace savings that

 

 

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1    expired in or at the end of the previous year.
2        (8) For electric utilities that serve less than
3    3,000,000 retail customers but more than 500,000 retail
4    customers in the State:
5            (A) Through December 31, 2025, the applicable
6        annual incremental goal shall be compared to the
7        annual incremental savings as determined by the
8        independent evaluator.
9                (i) The return on equity component shall be
10            reduced by 8 basis points for each percent by
11            which the utility did not achieve 84.4% of the
12            applicable annual incremental goal.
13                (ii) The return on equity component shall be
14            increased by 8 basis points for each percent by
15            which the utility exceeded 100% of the applicable
16            annual incremental goal.
17                (iii) The return on equity component shall not
18            be increased or decreased if the annual
19            incremental savings as determined by the
20            independent evaluator is greater than 84.4% of the
21            applicable annual incremental goal and less than
22            100% of the applicable annual incremental goal.
23                (iv) The return on equity component shall not
24            be increased or decreased by an amount greater
25            than 200 basis points pursuant to this
26            subparagraph (A).

 

 

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1            (B) For the period of January 1, 2026 through
2        December 31, 2029 and in all subsequent 4-year periods
3        2030, the applicable annual incremental goal shall be
4        compared to the annual incremental savings as
5        determined by the independent evaluator.
6                (i) The return on equity component shall be
7            reduced by 6 basis points for each percent by
8            which the utility did not achieve 100% of the
9            applicable annual incremental goal.
10                (ii) The return on equity component shall be
11            increased by 6 basis points for each percent by
12            which the utility exceeded 100% of the applicable
13            annual incremental goal.
14                (iii) The return on equity component shall not
15            be increased or decreased by an amount greater
16            than 200 basis points pursuant to this
17            subparagraph (B).
18            (C) Notwithstanding provisions in subparagraphs
19        (A) and (B) of paragraph (7) of this subsection, if the
20        applicable annual incremental goal for an electric
21        utility is ever less than 0.6% of deemed average
22        weather normalized sales of electric power and energy
23        during calendar years 2014, 2015 and 2016, an
24        adjustment to the return on equity component of the
25        utility's weighted average cost of capital calculated
26        under subsection (d) of this Section shall be made as

 

 

SB2896- 899 -LRB102 17909 JWD 25989 b

1        follows:
2                (i) The return on equity component shall be
3            reduced by 8 basis points for each percent by
4            which the utility did not achieve 100% of the
5            applicable annual total savings requirement.
6                (ii) The return on equity component shall be
7            increased by 8 basis points for each percent by
8            which the utility exceeded 100% of the applicable
9            annual total savings requirement.
10                (iii) The return on equity component shall not
11            be increased or decreased by an amount greater
12            than 200 basis points pursuant to this
13            subparagraph (C).
14            (D) (C) If the applicable annual incremental goal
15        was reduced under paragraphs (1), (2), or (3), or (4)
16        of subsection (f) of this Section, then the following
17        adjustments shall be made to the calculations
18        described in subparagraphs (A), and (B), and (C) of
19        this paragraph (8):
20                (i) The calculation for determining
21            achievement that is at least 125% or 134%, as
22            applicable, of the applicable annual incremental
23            goal or the applicable annual total savings
24            requirement, as applicable, shall use the
25            unreduced applicable annual incremental goal to
26            set the value.

 

 

SB2896- 900 -LRB102 17909 JWD 25989 b

1                (ii) For the period through December 31, 2025,
2            the calculation for determining achievement that
3            is less than 125% but more than 100% of the
4            applicable annual incremental goal or the
5            applicable annual total savings requirement, as
6            applicable, shall use the reduced applicable
7            annual incremental goal to set the value for 100%
8            achievement of the goal and shall use the
9            unreduced goal to set the value for 125%
10            achievement. The 8 basis point value shall also be
11            modified, as necessary, so that the 200 basis
12            points are evenly apportioned among each
13            percentage point value between 100% and 125%
14            achievement.
15                (iii) For the period of January 1, 2026
16            through December 31, 2029 and all subsequent
17            4-year periods, the calculation for determining
18            achievement that is less than 125% or 134%, as
19            applicable, but more than 100% of the applicable
20            annual incremental goal or the applicable annual
21            total savings requirement, as applicable, shall
22            use the reduced applicable annual incremental goal
23            to set the value for 100% achievement of the goal
24            and shall use the unreduced goal to set the value
25            for 125% achievement. The 6 or 8 basis point
26            values, as applicable, shall also be modified, as

 

 

SB2896- 901 -LRB102 17909 JWD 25989 b

1            necessary, so that the 200 basis points are evenly
2            apportioned among each percentage point value
3            between 100% and 125% or between 100% and 134%
4            achievement, as applicable 2030, the calculation
5            for determining achievement that is less than 134%
6            but more than 100% of the applicable annual
7            incremental goal shall use the reduced applicable
8            annual incremental goal to set the value for 100%
9            achievement of the goal and shall use the
10            unreduced goal to set the value for 125%
11            achievement. The 6 basis point value shall also be
12            modified, as necessary, so that the 200 basis
13            points are evenly apportioned among each
14            percentage point value between 100% and 134%
15            achievement.
16        (9) The utility shall submit the energy savings data
17    to the independent evaluator no later than 30 days after
18    the close of the plan year. The independent evaluator
19    shall determine the cumulative persisting annual savings
20    for a given plan year, as well as an estimate of job
21    impacts and other macroeconomic impacts of the efficiency
22    programs for that year, no later than 120 days after the
23    close of the plan year. The utility shall submit an
24    informational filing to the Commission no later than 160
25    days after the close of the plan year that attaches the
26    independent evaluator's final report identifying the

 

 

SB2896- 902 -LRB102 17909 JWD 25989 b

1    cumulative persisting annual savings for the year and
2    calculates, under paragraph (7) or (8) of this subsection
3    (g), as applicable, any resulting change to the utility's
4    return on equity component of the weighted average cost of
5    capital applicable to the next plan year beginning with
6    the January monthly billing period and extending through
7    the December monthly billing period. However, if the
8    utility recovers the costs incurred under this Section
9    under paragraphs (2) and (3) of subsection (d) of this
10    Section, then the utility shall not be required to submit
11    such informational filing, and shall instead submit the
12    information that would otherwise be included in the
13    informational filing as part of its filing under paragraph
14    (3) of such subsection (d) that is due on or before June 1
15    of each year.
16        For those utilities that must submit the informational
17    filing, the Commission may, on its own motion or by
18    petition, initiate an investigation of such filing,
19    provided, however, that the utility's proposed return on
20    equity calculation shall be deemed the final, approved
21    calculation on December 15 of the year in which it is filed
22    unless the Commission enters an order on or before
23    December 15, after notice and hearing, that modifies such
24    calculation consistent with this Section.
25        The adjustments to the return on equity component
26    described in paragraphs (7) and (8) of this subsection (g)

 

 

SB2896- 903 -LRB102 17909 JWD 25989 b

1    shall be applied as described in such paragraphs through a
2    separate tariff mechanism, which shall be filed by the
3    utility under subsections (f) and (g) of this Section.
4        (9.5) The utility must demonstrate how it will ensure
5    that program implementation contractors and energy
6    efficiency installation vendors will promote workforce
7    equity and quality jobs.
8        (9.6) Utilities shall collect data necessary to ensure
9    compliance with paragraph (9.5) no less than quarterly and
10    shall communicate progress toward compliance with
11    paragraph (9.5) to program implementation contractors and
12    energy efficiency installation vendors no less than
13    quarterly. Utilities shall work with relevant vendors,
14    providing education, training, and other resources needed
15    to ensure compliance and, where necessary, adjusting or
16    terminating work with vendors that cannot assist with
17    compliance.
18        (10) Utilities required to implement efficiency
19    programs under subsections (b-5) and (b-10) shall report
20    annually to the Illinois Commerce Commission and the
21    General Assembly on how hiring, contracting, job training,
22    and other practices related to its energy efficiency
23    programs enhance the diversity of vendors working on such
24    programs. These reports must include data on vendor and
25    employee diversity, including data on the implementation
26    of paragraphs (9.5) and (9.6). If the utility is not

 

 

SB2896- 904 -LRB102 17909 JWD 25989 b

1    meeting the requirements of paragraphs (9.5) and (9.6),
2    the utility shall submit a plan to adjust their activities
3    so that they meet the requirements of paragraphs (9.5) and
4    (9.6) within the following year.
5    (h) No more than 4% 6% of energy efficiency and
6demand-response program revenue may be allocated for research,
7development, or pilot deployment of new equipment or measures.
8Electric utilities shall work with interested stakeholders to
9formulate a plan for how these funds should be spent,
10incorporate statewide approaches for these allocations, and
11file a four-year plan that demonstrates that collaboration. If
12a utility files a request for modified annual energy savings
13goals with the Commission, then a utility shall forgo spending
14portfolio dollars on research and development proposals.
15    (i) When practicable, electric utilities shall incorporate
16advanced metering infrastructure data into the planning,
17implementation, and evaluation of energy efficiency measures
18and programs, subject to the data privacy and confidentiality
19protections of applicable law.
20    (j) The independent evaluator shall follow the guidelines
21and use the savings set forth in Commission-approved energy
22efficiency policy manuals and technical reference manuals, as
23each may be updated from time to time. Until such time as
24measure life values for energy efficiency measures implemented
25for low-income households under subsection (c) of this Section
26are incorporated into such Commission-approved manuals, the

 

 

SB2896- 905 -LRB102 17909 JWD 25989 b

1low-income measures shall have the same measure life values
2that are established for same measures implemented in
3households that are not low-income households.
4    (k) Notwithstanding any provision of law to the contrary,
5an electric utility subject to the requirements of this
6Section may file a tariff cancelling an automatic adjustment
7clause tariff in effect under this Section or Section 8-103,
8which shall take effect no later than one business day after
9the date such tariff is filed. Thereafter, the utility shall
10be authorized to defer and recover its expenditures incurred
11under this Section through a new tariff authorized under
12subsection (d) of this Section or in the utility's next rate
13case under Article IX or Section 16-108.5 of this Act, with
14interest at an annual rate equal to the utility's weighted
15average cost of capital as approved by the Commission in such
16case. If the utility elects to file a new tariff under
17subsection (d) of this Section, the utility may file the
18tariff within 10 days after June 1, 2017 (the effective date of
19Public Act 99-906), and the cost inputs to such tariff shall be
20based on the projected costs to be incurred by the utility
21during the calendar year in which the new tariff is filed and
22that were not recovered under the tariff that was cancelled as
23provided for in this subsection. Such costs shall include
24those incurred or to be incurred by the utility under its
25multi-year plan approved under subsections (f) and (g) of this
26Section, including, but not limited to, projected capital

 

 

SB2896- 906 -LRB102 17909 JWD 25989 b

1investment costs and projected regulatory asset balances with
2correspondingly updated depreciation and amortization reserves
3and expense. The Commission shall, after notice and hearing,
4approve, or approve with modification, such tariff and cost
5inputs no later than 75 days after the utility filed the
6tariff, provided that such approval, or approval with
7modification, shall be consistent with the provisions of this
8Section to the extent they do not conflict with this
9subsection (k). The tariff approved by the Commission shall
10take effect no later than 5 days after the Commission enters
11its order approving the tariff.
12    No later than 60 days after the effective date of the
13tariff cancelling the utility's automatic adjustment clause
14tariff, the utility shall file a reconciliation that
15reconciles the moneys collected under its automatic adjustment
16clause tariff with the costs incurred during the period
17beginning June 1, 2016 and ending on the date that the electric
18utility's automatic adjustment clause tariff was cancelled. In
19the event the reconciliation reflects an under-collection, the
20utility shall recover the costs as specified in this
21subsection (k). If the reconciliation reflects an
22over-collection, the utility shall apply the amount of such
23over-collection as a one-time credit to retail customers'
24bills.
25    (l) (Blank). For the calendar years covered by a
26multi-year plan commencing after December 31, 2017,

 

 

SB2896- 907 -LRB102 17909 JWD 25989 b

1subsections (a) through (j) of this Section do not apply to any
2retail customers of an electric utility that serves more than
33,000,000 retail customers in the State and whose total
4highest 30 minute demand was more than 10,000 kilowatts, or
5any retail customers of an electric utility that serves less
6than 3,000,000 retail customers but more than 500,000 retail
7customers in the State and whose total highest 15 minute
8demand was more than 10,000 kilowatts. For purposes of this
9subsection (l), "retail customer" has the meaning set forth in
10Section 16-102 of this Act. A determination of whether this
11subsection is applicable to a customer shall be made for each
12multi-year plan beginning after December 31, 2017. The
13criteria for determining whether this subsection (l) is
14applicable to a retail customer shall be based on the 12
15consecutive billing periods prior to the start of the first
16year of each such multi-year plan.
17    (m) Notwithstanding the requirements of this Section, as
18part of a proceeding to approve a multi-year plan under
19subsections (f) and (g) of this Section if the multi-year plan
20has been designed to maximize savings, but does not meet the
21cost cap limitations of this subsection, the Commission shall
22reduce the amount of energy efficiency measures implemented
23for any single year, and whose costs are recovered under
24subsection (d) of this Section, by an amount necessary to
25limit the estimated average net increase due to the cost of the
26measures to no more than

 

 

SB2896- 908 -LRB102 17909 JWD 25989 b

1        (1) 3.5% for each of the 4 years beginning January 1,
2    2018,
3        (2) (blank), 3.75% for each of the 4 years beginning
4    January 1, 2022, and
5        (3) 4% for each of the 4 5 years beginning January 1,
6    2022 2026,
7        (4) 4.25% for the 4 years beginning January 1, 2026,
8    and
9        (5) 4.25% plus an increase sufficient to account for
10    the rate of inflation between January 1, 2026 and January
11    1 of the first year of each subsequent 4-year plan cycle,
12of the average amount paid per kilowatthour by residential
13eligible retail customers during calendar year 2015. An
14electric utility may plan to spend up to 10% more in any year
15during an applicable multi-year plan period to
16cost-effectively achieve additional savings so long as the
17average over the applicable multi-year plan period does not
18exceed the percentages defined in items (1) through (5). To
19determine the total amount that may be spent by an electric
20utility in any single year, the applicable percentage of the
21average amount paid per kilowatthour shall be multiplied by
22the total amount of energy delivered by such electric utility
23in the calendar year 2015, adjusted to reflect the proportion
24of the utility's load attributable to customers who are exempt
25from subsections (a) through (j) of this Section under
26subsection (l) of this Section. For purposes of this

 

 

SB2896- 909 -LRB102 17909 JWD 25989 b

1subsection (m), the amount paid per kilowatthour includes,
2without limitation, estimated amounts paid for supply,
3transmission, distribution, surcharges, and add-on taxes. For
4purposes of this Section, "eligible retail customers" shall
5have the meaning set forth in Section 16-111.5 of this Act.
6Once the Commission has approved a plan under subsections (f)
7and (g) of this Section, no subsequent rate impact
8determinations shall be made.
9    (n) A utility shall take advantage of the efficiencies
10available through existing Illinois Home Weatherization
11Assistance Program infrastructure and services, such as
12enrollment, marketing, quality assurance and implementation,
13which can reduce the need for similar services at a lower cost
14than utility-only programs, subject to capacity constraints at
15community action agencies, for both single-family and
16multifamily weatherization services, to the extent Illinois
17Home Weatherization Assistance Program CAAs provide
18multifamily services. A utility's plan shall demonstrate that
19in formulating annual weatherization budgets, it has sought
20input and coordination with community action agencies
21regarding agencies' capacity to expand and maximize Illinois
22Home Weatherization Assistance Program delivery using the
23ratepayer dollars collected under this Section.
24(Source: P.A. 100-840, eff. 8-13-18; 101-81, eff. 7-12-19.)
 
25
Article 99. General Provisions

 

 

 

SB2896- 910 -LRB102 17909 JWD 25989 b

1    Section 99-99. Effective date. This Act takes effect upon
2becoming law.

 

 

SB2896- 911 -LRB102 17909 JWD 25989 b

1 INDEX
2 Statutes amended in order of appearance
3    New Act
4    820 ILCS 65/10
5    5 ILCS 420/1-121.5 new
6    5 ILCS 420/4A-102from Ch. 127, par. 604A-102
7    5 ILCS 420/4A-103from Ch. 127, par. 604A-103
8    20 ILCS 655/5.5from Ch. 67 1/2, par. 609.1
9    20 ILCS 627/5
10    20 ILCS 627/10
11    20 ILCS 627/15
12    20 ILCS 627/20
13    20 ILCS 627/30 new
14    20 ILCS 627/35 new
15    20 ILCS 627/40 new
16    20 ILCS 627/45 new
17    20 ILCS 627/50 new
18    20 ILCS 1120/2from Ch. 96 1/2, par. 7802
19    20 ILCS 3501/801-1
20    20 ILCS 3501/801-5
21    20 ILCS 3501/801-10
22    20 ILCS 3501/801-40
23    20 ILCS 3501/Art. 850
24    heading new
25    20 ILCS 3501/850-5 new

 

 

SB2896- 912 -LRB102 17909 JWD 25989 b

1    20 ILCS 3501/850-10 new
2    20 ILCS 3501/850-15 new
3    20 ILCS 3125/10
4    20 ILCS 3125/15
5    20 ILCS 3125/20
6    20 ILCS 3125/30
7    20 ILCS 3125/45
8    20 ILCS 3125/55 new
9    20 ILCS 3855/1-5
10    20 ILCS 3855/1-10
11    20 ILCS 3855/1-35
12    20 ILCS 3855/1-56
13    20 ILCS 3855/1-70
14    20 ILCS 3855/1-75
15    20 ILCS 3855/1-92
16    20 ILCS 3855/1-125
17    20 ILCS 3855/1-135 new
18    20 ILCS 3855/1-140 new
19    30 ILCS 105/5.938 new
20    30 ILCS 105/5.939 new
21    30 ILCS 500/1-10
22    55 ILCS 5/5-12020
23    55 ILCS 5/5-12022 new
24    65 ILCS 5/8-11-2.7 new
25    220 ILCS 5/3-105from Ch. 111 2/3, par. 3-105
26    220 ILCS 5/4-604 new

 

 

SB2896- 913 -LRB102 17909 JWD 25989 b

1    220 ILCS 5/5-117
2    220 ILCS 5/8-103B
3    220 ILCS 5/8-103C new
4    220 ILCS 5/8-104.1 new
5    220 ILCS 5/8-201.7 new
6    220 ILCS 5/8-201.8 new
7    220 ILCS 5/8-201.9 new
8    220 ILCS 5/8-201.10 new
9    220 ILCS 5/8-201.11 new
10    220 ILCS 5/8-201.12 new
11    220 ILCS 5/8-201.13 new
12    220 ILCS 5/8-201.14 new
13    220 ILCS 5/8-406from Ch. 111 2/3, par. 8-406
14    220 ILCS 5/8-512 new
15    220 ILCS 5/9-201from Ch. 111 2/3, par. 9-201
16    220 ILCS 5/9-220.3
17    220 ILCS 5/9-221from Ch. 111 2/3, par. 9-221
18    220 ILCS 5/9-227from Ch. 111 2/3, par. 9-227
19    220 ILCS 5/9-229
20    220 ILCS 5/9-241from Ch. 111 2/3, par. 9-241
21    220 ILCS 5/16-107.5
22    220 ILCS 5/16-107.6
23    220 ILCS 5/16-108
24    220 ILCS 5/16-108.5
25    220 ILCS 5/16-108.17 new
26    220 ILCS 5/16-108.18 new

 

 

SB2896- 914 -LRB102 17909 JWD 25989 b

1    220 ILCS 5/16-108.19 new
2    220 ILCS 5/16-108.20 new
3    220 ILCS 5/16-108.21 new
4    220 ILCS 5/16-108.22 new
5    220 ILCS 5/16-111.5
6    220 ILCS 5/16-111.8
7    220 ILCS 5/16-115
8    220 ILCS 5/16-115C
9    220 ILCS 5/19-110
10    220 ILCS 5/19-145
11    220 ILCS 10/3from Ch. 111 2/3, par. 903
12    220 ILCS 10/5from Ch. 111 2/3, par. 905
13    220 ILCS 10/13from Ch. 111 2/3, par. 913
14    305 ILCS 20/6from Ch. 111 2/3, par. 1406
15    305 ILCS 20/13
16    305 ILCS 20/18
17    305 ILCS 20/20 new
18    415 ILCS 5/2from Ch. 111 1/2, par. 1002
19    415 ILCS 5/3.1325 new
20    415 ILCS 5/9.15
21    415 ILCS 120/1
22    415 ILCS 120/5
23    415 ILCS 120/10
24    415 ILCS 120/15
25    415 ILCS 120/27 new
26    415 ILCS 120/40

 

 

SB2896- 915 -LRB102 17909 JWD 25989 b

1    415 ILCS 120/20 rep.
2    415 ILCS 120/22 rep.
3    415 ILCS 120/24 rep.
4    415 ILCS 120/30 rep.
5    415 ILCS 120/31 rep.
6    415 ILCS 120/32 rep.
7    430 ILCS 170/20 new
8    505 ILCS 147/15
9    815 ILCS 505/10e new
10    820 ILCS 65/10
11    820 ILCS 130/2from Ch. 48, par. 39s-2
12    220 ILCS 5/8-103B