Sen. Donne E. Trotter

Filed: 5/5/2016

 

 


 

 


 
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1
AMENDMENT TO SENATE BILL 1585

2    AMENDMENT NO. ______. Amend Senate Bill 1585, AS AMENDED,
3by replacing everything after the enacting clause with the
4following:
 
5    "Section 1. Findings.
6    (a) In 2011, the General Assembly encouraged and enabled
7the State's largest electric utilities to undertake
8substantial investment to refurbish, rebuild, modernize, and
9expand Illinois' century-old electric grid. Among those
10investments were the deployment of a smart grid and advanced
11metering infrastructure platform that would be accessible to
12all retail customers through new, digital smart meters. This
13investment, now well underway, not only allows utilities to
14continue to provide safe, reliable, and affordable service to
15the State's current and future utility customers, but also
16empowers the citizens of this State to directly access and
17participate in the rapidly emerging clean energy economy while

 

 

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1also presenting them with unprecedented choices in their source
2of energy supply and pricing.
3    To ensure that the State and its citizens, including
4low-income citizens, are equipped to enjoy the opportunities
5and benefits of the smart grid and evolving clean energy
6marketplace, the General Assembly finds and declares that
7Illinois should continue in its efforts to build the grid of
8the future using the smart grid and advanced metering
9infrastructure platform, as well as maximize the impact of the
10State's existing energy efficiency and renewable energy
11portfolio standards. Specifically, the Generally Assembly
12finds that:
13        (1) the State should encourage the adoption and
14    deployment of cost-effective distributed energy resource
15    technologies and devices, such as photovoltaics, which can
16    encourage private investment in renewable energy
17    resources, stimulate economic growth, enhance the
18    continued diversification of Illinois' energy resource
19    mix, and protect the Illinois environment;
20        (2) the State's existing energy efficiency standard
21    should be updated to ensure that customers continue to
22    realize increased value, to incorporate and optimize
23    measures enabled by the smart grid, including voltage
24    optimization measures, and to provide incentives for
25    electric utilities to achieve the energy savings goals; and
26        (3) the State's electric utilities should initiate

 

 

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1    programs to study the benefits of smart-grid enabled
2    technologies, including, but not limited to, deploying
3    microgrids and electric vehicle charging stations. Such
4    programs are not required to be cost effective so long as a
5    goal of the program is to analyze cost effectiveness. The
6    costs to implement, manage, and analyze such programs shall
7    be recovered through delivery service rates.
8    (b) The General Assembly further finds that the expansion
9of distributed generation technologies and devices across the
10State necessarily disrupts existing electricity generation and
11distribution models and frameworks, including related rate and
12tariff schedules, which can lead to inequitable charges,
13especially for low-income customers who often encounter the
14most substantial obstacles to adopting costly distributed
15generation technologies and devices. As a result, the General
16Assembly finds that low-income customers should be included
17within the State's efforts to expand the use of distributed
18generation technologies and devices. To address these issues,
19electric utilities should also be permitted to file revised
20tariffs related to implementing low-income programs,
21demand-based delivery services charges, and unbundling
22supply-related charges. These changes should be designed to
23ensure both an equitable allocation of costs so that no
24customers have to pay more than their fair share of these costs
25and that all costs are recovered, thus ensuring better and more
26equitable access to distributed generation and other energy

 

 

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1options.
 
2    Section 1.5. Zero emission standard legislative findings.
3The General Assembly finds and declares:
4        (1) Reducing emissions of carbon dioxide and other air
5    pollutants, such as sulfur oxides, nitrogen oxides, and
6    particulate matter, is critical to improving air quality in
7    Illinois for Illinois residents.
8        (2) Sulfur oxides, nitrogen oxides, and particulate
9    emissions have significant adverse health effects on
10    persons exposed to them, and carbon dioxide emissions
11    result in climate change trends that could significantly
12    adversely impact Illinois.
13        (3) The existing renewable portfolio standard has been
14    successful in promoting the growth of renewable energy
15    generation to reduce air pollution in Illinois. However, to
16    achieve its environmental goals, Illinois must expand its
17    commitment to zero emission energy generation and value the
18    environmental attributes of zero emission generation that
19    currently falls outside the scope of the existing renewable
20    portfolio standard, including, but not limited to, nuclear
21    power.
22        (4) Preserving existing zero emission energy
23    generation and promoting new zero emission energy
24    generation is vital to placing the State on a glide path to
25    achieving its environmental goals and ensuring that air

 

 

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1    quality in Illinois continues to improve.
2        (5) The Illinois Commerce Commission, the Illinois
3    Power Agency, the Illinois Environmental Protection
4    Agency, and the Department of Commerce and Economic
5    Opportunity issued a report dated January 5, 2015 titled
6    "Potential Nuclear Power Plant Closings in Illinois" (the
7    Report), which addressed the issues identified by Illinois
8    House Resolution 1146 of the 98th General Assembly, which,
9    among other things, urged the Illinois Environmental
10    Protection Agency to prepare a report showing how the
11    premature closure of existing nuclear power plants in
12    Illinois will affect the societal cost of increased
13    greenhouse gas emissions based upon the Environmental
14    Protection Agency's published societal cost of greenhouse
15    gases.
16        (6) The Report also identified significant adverse
17    consequences for electric reliability in Illinois,
18    including significant voltage and thermal violations in
19    the interstate transmission network, in the event that
20    Illinois' existing nuclear facilities close prematurely.
21    The Report also found that nuclear power plants are among
22    the most reliable sources of energy, which means that
23    electricity from nuclear power plants is available on the
24    electric grid all hours of the day and when needed, thereby
25    always reducing carbon emissions.
26        (7) Illinois House Resolution 1146 further urged that

 

 

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1    the Report make findings concerning potential market-based
2    solutions that will ensure that the premature closure of
3    these nuclear power plants does not occur and that the
4    associated dire consequences to the environment, electric
5    reliability, and the regional economy are averted.
6        (8) The Report identified potential market-based
7    solutions that will ensure that the premature closure of
8    these nuclear power plants does not occur and that the
9    associated dire consequences to the environment, electric
10    reliability, and the regional economy are averted.
11    The General Assembly therefore finds that it is necessary
12to establish and implement a zero emission standard, which will
13increase the State's reliance on zero emission energy through
14the procurement of zero emission energy credits from zero
15emission resources, in order to achieve the State's
16environmental objectives and reduce the adverse impact of
17emitted air pollutants on the health and welfare of the State's
18citizens.
 
19    Section 5. The Illinois Power Agency Act is amended by
20changing Sections 1-5, 1-10, 1-56, and 1-75 as follows:
 
21    (20 ILCS 3855/1-5)
22    Sec. 1-5. Legislative declarations and findings. The
23General Assembly finds and declares:
24        (1) The health, welfare, and prosperity of all Illinois

 

 

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1    citizens require the provision of adequate, reliable,
2    affordable, efficient, and environmentally sustainable
3    electric service at the lowest total cost over time, taking
4    into account any benefits of price stability.
5        (2) (Blank). The transition to retail competition is
6    not complete. Some customers, especially residential and
7    small commercial customers, have failed to benefit from
8    lower electricity costs from retail and wholesale
9    competition.
10        (3) (Blank). Escalating prices for electricity in
11    Illinois pose a serious threat to the economic well-being,
12    health, and safety of the residents of and the commerce and
13    industry of the State.
14        (4) It To protect against this threat to economic
15    well-being, health, and safety it is necessary to improve
16    the process of procuring electricity to serve Illinois
17    residents, to promote investment in energy efficiency and
18    demand-response measures, and to maintain and support
19    development of clean coal technologies, generation
20    resources that operate at all hours of the day and under
21    all weather conditions, zero emission resources, and
22    renewable resources.
23        (5) Procuring a diverse electricity supply portfolio
24    will ensure the lowest total cost over time for adequate,
25    reliable, efficient, and environmentally sustainable
26    electric service.

 

 

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1        (6) Including cost-effective renewable resources and
2    zero emission credits from zero emission resources in that
3    portfolio will reduce long-term direct and indirect costs
4    to consumers by decreasing environmental impacts and by
5    avoiding or delaying the need for new generation,
6    transmission, and distribution infrastructure.
7        (7) Energy efficiency, demand-response measures, zero
8    emission energy, and renewable energy are resources
9    currently underused in Illinois.
10        (8) The State should encourage the use of advanced
11    clean coal technologies that capture and sequester carbon
12    dioxide emissions to advance environmental protection
13    goals and to demonstrate the viability of coal and
14    coal-derived fuels in a carbon-constrained economy.
15        (9) The General Assembly enacted Public Act 96-0795 to
16    reform the State's purchasing processes, recognizing that
17    government procurement is susceptible to abuse if
18    structural and procedural safeguards are not in place to
19    ensure independence, insulation, oversight, and
20    transparency.
21        (10) The principles that underlie the procurement
22    reform legislation apply also in the context of power
23    purchasing.
24    The General Assembly therefore finds that it is necessary
25to create the Illinois Power Agency and that the goals and
26objectives of that Agency are to accomplish each of the

 

 

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1following:
2        (A) Develop electricity procurement plans to ensure
3    adequate, reliable, affordable, efficient, and
4    environmentally sustainable electric service at the lowest
5    total cost over time, taking into account any benefits of
6    price stability, for electric utilities that on December
7    31, 2005 provided electric service to at least 100,000
8    customers in Illinois and for small multi-jurisdictional
9    electric utilities that (i) on December 31, 2005 served
10    less than 100,000 customers in Illinois and (ii) request a
11    procurement plan for their Illinois jurisdictional load.
12    The procurement plan shall be updated on an annual basis
13    and shall include renewable energy resources and,
14    beginning with the planning year commencing June 1, 2017,
15    zero emission credits from zero emission resources
16    sufficient to achieve the standards specified in this Act.
17        (B) Conduct competitive procurement processes to
18    procure the supply resources identified in the procurement
19    plan.
20        (C) Develop electric generation and co-generation
21    facilities that use indigenous coal or renewable
22    resources, or both, financed with bonds issued by the
23    Illinois Finance Authority.
24        (D) Supply electricity from the Agency's facilities at
25    cost to one or more of the following: municipal electric
26    systems, governmental aggregators, or rural electric

 

 

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1    cooperatives in Illinois.
2        (E) Ensure that the process of power procurement is
3    conducted in an ethical and transparent fashion, immune
4    from improper influence.
5        (F) Continue to review its policies and practices to
6    determine how best to meet its mission of providing the
7    lowest cost power to the greatest number of people, at any
8    given point in time, in accordance with applicable law.
9        (G) Operate in a structurally insulated, independent,
10    and transparent fashion so that nothing impedes the
11    Agency's mission to secure power at the best prices the
12    market will bear, provided that the Agency meets all
13    applicable legal requirements.
14(Source: P.A. 97-325, eff. 8-12-11; 97-618, eff. 10-26-11;
1597-813, eff. 7-13-12.)
 
16    (20 ILCS 3855/1-10)
17    Sec. 1-10. Definitions.
18    "Agency" means the Illinois Power Agency.
19    "Agency loan agreement" means any agreement pursuant to
20which the Illinois Finance Authority agrees to loan the
21proceeds of revenue bonds issued with respect to a project to
22the Agency upon terms providing for loan repayment installments
23at least sufficient to pay when due all principal of, interest
24and premium, if any, on those revenue bonds, and providing for
25maintenance, insurance, and other matters in respect of the

 

 

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1project.
2    "Authority" means the Illinois Finance Authority.
3    "Brownfield site project" means photovoltaics located at a
4site that is:
5        (1) located in an area that, on April 5, 2004, was in
6    non-attainment for the National Ambient Air Quality
7    Standard 1997 PM2.5 Standard;
8        (2) interconnected at the distribution system level of
9    either an electric utility as defined in this Section, a
10    municipal utility, or an electric cooperative, as defined
11    in Section 3-119 of the Public Utilities Act; and
12        (3) regulated by any of the following entities under
13    the following programs:
14            (i) the United States Environmental Protection
15        Agency under the federal Comprehensive Environmental
16        Response, Compensation, and Liability Act of 1980, as
17        amended;
18            (ii) the United States Environmental Protection
19        Agency under the Corrective Action Program of the
20        federal Resource Conservation and Recovery Act, as
21        amended; or
22            (iii) the Illinois Environmental Protection Agency
23        under the Illinois Site Remediation Program.
24    "Clean coal facility" means an electric generating
25facility that uses primarily coal as a feedstock and that
26captures and sequesters carbon dioxide emissions at the

 

 

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1following levels: at least 50% of the total carbon dioxide
2emissions that the facility would otherwise emit if, at the
3time construction commences, the facility is scheduled to
4commence operation before 2016, at least 70% of the total
5carbon dioxide emissions that the facility would otherwise emit
6if, at the time construction commences, the facility is
7scheduled to commence operation during 2016 or 2017, and at
8least 90% of the total carbon dioxide emissions that the
9facility would otherwise emit if, at the time construction
10commences, the facility is scheduled to commence operation
11after 2017. The power block of the clean coal facility shall
12not exceed allowable emission rates for sulfur dioxide,
13nitrogen oxides, carbon monoxide, particulates and mercury for
14a natural gas-fired combined-cycle facility the same size as
15and in the same location as the clean coal facility at the time
16the clean coal facility obtains an approved air permit. All
17coal used by a clean coal facility shall have high volatile
18bituminous rank and greater than 1.7 pounds of sulfur per
19million btu content, unless the clean coal facility does not
20use gasification technology and was operating as a conventional
21coal-fired electric generating facility on June 1, 2009 (the
22effective date of Public Act 95-1027).
23    "Clean coal SNG brownfield facility" means a facility that
24(1) has commenced construction by July 1, 2015 on an urban
25brownfield site in a municipality with at least 1,000,000
26residents; (2) uses a gasification process to produce

 

 

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1substitute natural gas; (3) uses coal as at least 50% of the
2total feedstock over the term of any sourcing agreement with a
3utility and the remainder of the feedstock may be either
4petroleum coke or coal, with all such coal having a high
5bituminous rank and greater than 1.7 pounds of sulfur per
6million Btu content unless the facility reasonably determines
7that it is necessary to use additional petroleum coke to
8deliver additional consumer savings, in which case the facility
9shall use coal for at least 35% of the total feedstock over the
10term of any sourcing agreement; and (4) captures and sequesters
11at least 85% of the total carbon dioxide emissions that the
12facility would otherwise emit.
13    "Clean coal SNG facility" means a facility that uses a
14gasification process to produce substitute natural gas, that
15sequesters at least 90% of the total carbon dioxide emissions
16that the facility would otherwise emit, that uses at least 90%
17coal as a feedstock, with all such coal having a high
18bituminous rank and greater than 1.7 pounds of sulfur per
19million btu content, and that has a valid and effective permit
20to construct emission sources and air pollution control
21equipment and approval with respect to the federal regulations
22for Prevention of Significant Deterioration of Air Quality
23(PSD) for the plant pursuant to the federal Clean Air Act;
24provided, however, a clean coal SNG brownfield facility shall
25not be a clean coal SNG facility.
26    "Commission" means the Illinois Commerce Commission.

 

 

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

 

 

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1    "Department" means the Department of Commerce and Economic
2Opportunity.
3    "Director" means the Director of the Illinois Power Agency.
4    "Demand-response" means measures that decrease peak
5electricity demand or shift demand from peak to off-peak
6periods.
7    "Distributed renewable energy generation device" means a
8device that is:
9        (1) powered by wind, solar thermal energy,
10    photovoltaic cells and panels, biodiesel, crops and
11    untreated and unadulterated organic waste biomass, tree
12    waste, and hydropower that does not involve new
13    construction or significant expansion of hydropower dams;
14        (2) interconnected at the distribution system level of
15    either an electric utility as defined in this Section, an
16    alternative retail electric supplier as defined in Section
17    16-102 of the Public Utilities Act, a municipal utility as
18    defined in Section 3-105 of the Public Utilities Act, or a
19    rural electric cooperative as defined in Section 3-119 of
20    the Public Utilities Act;
21        (3) located on the customer side of the customer's
22    electric meter and is primarily used to offset that
23    customer's electricity load or used in a community solar
24    project; and
25        (4) limited in nameplate capacity to no more than 2,000
26    kilowatts.

 

 

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1    For an electric utility that services 3,000,000 or less
2customers in the State, "energy "Energy efficiency" means
3measures that reduce the amount of electricity or natural gas
4required to achieve a given end use. "Energy efficiency" also
5includes measures that reduce the total Btus of electricity and
6natural gas needed to meet the end use or uses.
7    For an electric utility that services more than 3,000,000
8customers in the State, "energy efficiency" means measures that
9reduce the amount of electricity or natural gas required to
10achieve a given end use. "Energy efficiency" includes voltage
11optimization measures that optimize the voltage at points on
12the electric distribution voltage system and thereby conserve
13energy consumption by electric customers. "Energy efficiency"
14also includes measures that reduce the total Btus of
15electricity, natural gas, and other fuels needed to meet the
16end use or uses.
17    "Electric utility" has the same definition as found in
18Section 16-102 of the Public Utilities Act.
19    "Facility" means an electric generating unit or a
20co-generating unit that produces electricity along with
21related equipment necessary to connect the facility to an
22electric transmission or distribution system.
23    "Governmental aggregator" means one or more units of local
24government that individually or collectively procure
25electricity to serve residential retail electrical loads
26located within its or their jurisdiction.

 

 

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1    "Local government" means a unit of local government as
2defined in Section 1 of Article VII of the Illinois
3Constitution.
4    "Municipality" means a city, village, or incorporated
5town.
6    "Person" means any natural person, firm, partnership,
7corporation, either domestic or foreign, company, association,
8limited liability company, joint stock company, or association
9and includes any trustee, receiver, assignee, or personal
10representative thereof.
11    "Project" means the planning, bidding, and construction of
12a facility.
13    "Public utility" has the same definition as found in
14Section 3-105 of the Public Utilities Act.
15    "Real property" means any interest in land together with
16all structures, fixtures, and improvements thereon, including
17lands under water and riparian rights, any easements,
18covenants, licenses, leases, rights-of-way, uses, and other
19interests, together with any liens, judgments, mortgages, or
20other claims or security interests related to real property.
21    "Renewable energy credit" means a tradable credit that
22represents the environmental attributes of a certain amount of
23energy produced from a renewable energy resource.
24    "Renewable energy resources" includes energy and its
25associated renewable energy credit or renewable energy credits
26from wind, solar thermal energy, photovoltaic cells and panels,

 

 

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1biodiesel, anaerobic digestion, crops and untreated and
2unadulterated organic waste biomass, tree waste, hydropower
3that does not involve new construction or significant expansion
4of hydropower dams, and other alternative sources of
5environmentally preferable energy. For purposes of this Act,
6landfill gas produced in the State is considered a renewable
7energy resource. "Renewable energy resources" does not include
8the incineration or burning of tires, garbage, general
9household, institutional, and commercial waste, industrial
10lunchroom or office waste, landscape waste other than tree
11waste, railroad crossties, utility poles, or construction or
12demolition debris, other than untreated and unadulterated
13waste wood.
14    "Retail customer" has the same definition as found in
15Section 16-102 of the Public Utilities Act.
16    "Revenue bond" means any bond, note, or other evidence of
17indebtedness issued by the Authority, the principal and
18interest of which is payable solely from revenues or income
19derived from any project or activity of the Agency.
20    "Sequester" means permanent storage of carbon dioxide by
21injecting it into a saline aquifer, a depleted gas reservoir,
22or an oil reservoir, directly or through an enhanced oil
23recovery process that may involve intermediate storage,
24regardless of whether these activities are conducted by a clean
25coal facility, a clean coal SNG facility, a clean coal SNG
26brownfield facility, or a party with which a clean coal

 

 

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1facility, clean coal SNG facility, or clean coal SNG brownfield
2facility has contracted for such purposes.
3    "Sourcing agreement" means (i) in the case of an electric
4utility, an agreement between the owner of a clean coal
5facility and such electric utility, which agreement shall have
6terms and conditions meeting the requirements of paragraph (3)
7of subsection (d) of Section 1-75, (ii) in the case of an
8alternative retail electric supplier, an agreement between the
9owner of a clean coal facility and such alternative retail
10electric supplier, which agreement shall have terms and
11conditions meeting the requirements of Section 16-115(d)(5) of
12the Public Utilities Act, and (iii) in case of a gas utility,
13an agreement between the owner of a clean coal SNG brownfield
14facility and the gas utility, which agreement shall have the
15terms and conditions meeting the requirements of subsection
16(h-1) of Section 9-220 of the Public Utilities Act.
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    For an electric utility that serves 3,000,000 or less
22customers in the State, "total "Total resource cost test" or
23"TRC test" means a standard that is met if, for an investment
24in energy efficiency or demand-response measures, the
25benefit-cost ratio is greater than one. The benefit-cost ratio
26is the ratio of the net present value of the total benefits of

 

 

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1the program to the net present value of the total costs as
2calculated over the lifetime of the measures. A total resource
3cost test compares the sum of avoided electric utility costs,
4representing the benefits that accrue to the system and the
5participant in the delivery of those efficiency measures, as
6well as other quantifiable societal benefits, including
7avoided natural gas utility costs, to the sum of all
8incremental costs of end-use measures that are implemented due
9to the program (including both utility and participant
10contributions), plus costs to administer, deliver, and
11evaluate each demand-side program, to quantify the net savings
12obtained by substituting the demand-side program for supply
13resources. In calculating avoided costs of power and energy
14that an electric utility would otherwise have had to acquire,
15reasonable estimates shall be included of financial costs
16likely to be imposed by future regulations and legislation on
17emissions of greenhouse gases.
18    For an electric utility that serves more than 3,000,000
19customers in the State, "total resource cost test" or "TRC
20test" means a standard that is met if, for an investment in
21energy efficiency or demand-response measures, the
22benefit-cost ratio is greater than one. The benefit-cost ratio
23is the ratio of the net present value of the total benefits of
24the program to the net present value of the total costs as
25calculated over the lifetime of the measures. A total resource
26cost test compares the sum of avoided electric utility costs,

 

 

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1representing the benefits that accrue to the system and the
2participant in the delivery of those efficiency measures, as
3well as other quantifiable societal benefits, including
4avoided costs associated with natural gas or other fuels, to
5the sum of all incremental costs of end-use measures that are
6implemented due to the program (including both utility and
7participant contributions), plus costs to administer, deliver,
8and evaluate each demand-side program, to quantify the net
9savings obtained by substituting the demand-side program for
10supply resources. In calculating avoided costs of power and
11energy that an electric utility would otherwise have had to
12acquire, reasonable estimates shall be included of financial
13costs likely to be imposed by future regulations and
14legislation on emissions of greenhouse gases. In discounting
15future societal costs and benefits for the purpose of
16calculating net present values, a societal discount rate based
17on actual, long-term Treasury bond yields should be used.
18Notwithstanding anything to the contrary, the benefits
19identified in this definition shall only be included in the TRC
20test if they are measurable and quantifiable, and the TRC test
21shall not include or take into account a calculation of market
22price suppression effects or demand reduction induced price
23effects, which is intended to be a restatement and
24clarification of existing law by this amendatory Act of the
2599th General Assembly.
26    "Zero emission credit" means a tradable credit that

 

 

09900SB1585sam002- 22 -LRB099 09533 EGJ 48253 a

1represents the environmental attributes of one megawatt hour of
2energy produced from a zero emission resource.
3    "Zero emission resource" means a facility that: (1) is
4fueled by nuclear power; (2) does not emit any air pollution,
5including sulfur dioxide, nitrogen oxide, or carbon dioxide, as
6reported in the Generation Attribute Tracking System; and (3)
7is located in PJM Interconnection, LLC or the Midcontinent
8Independent System Operator, Inc.
9(Source: P.A. 97-96, eff. 7-13-11; 97-239, eff. 8-2-11; 97-491,
10eff. 8-22-11; 97-616, eff. 10-26-11; 97-813, eff. 7-13-12;
1198-90, eff. 7-15-13.)
 
12    (20 ILCS 3855/1-56)
13    Sec. 1-56. Illinois Power Agency Renewable Energy
14Resources Fund.
15    (a) The Illinois Power Agency Renewable Energy Resources
16Fund is created as a special fund in the State treasury.
17    (b) Through May 31, 2018, the The Illinois Power Agency
18Renewable Energy Resources Fund shall be administered by the
19Agency to procure renewable energy credits in the percentages
20specified in this subsection (b) resources. Renewable energy
21credits Prior to June 1, 2011, resources procured pursuant to
22this Section shall be procured from facilities located in
23Illinois, provided the resources are available from those
24facilities. If resources are not available in Illinois, then
25they shall be procured in states that adjoin Illinois. If

 

 

09900SB1585sam002- 23 -LRB099 09533 EGJ 48253 a

1resources are not available in Illinois or in states that
2adjoin Illinois, then they may be purchased elsewhere.
3Beginning June 1, 2011, resources procured pursuant to this
4Section shall be procured from facilities located in Illinois
5or states that adjoin Illinois. If renewable energy credits
6resources are not available in Illinois or in states that
7adjoin Illinois, then they may be procured elsewhere. To the
8extent available, at least 75% of these renewable energy
9credits resources shall come from wind generation. Of the
10renewable energy credits resources procured pursuant to this
11Section at least the following specified percentages shall come
12from photovoltaics on the following schedule: 0.5% by June 1,
132012; 1.5% by June 1, 2013; 3% by June 1, 2014; and 6% by June
141, 2015 and thereafter. Of the renewable energy credits
15resources procured pursuant to this Section, at least the
16following percentages shall come from distributed renewable
17energy generation devices: 0.5% by June 1, 2013, 0.75% by June
181, 2014, and 1% by June 1, 2015 and thereafter. To the extent
19available, half of the renewable energy credits resources
20procured from distributed renewable energy generation shall
21come from devices of less than 25 kilowatts in nameplate
22capacity. Renewable energy credits resources procured from
23distributed generation devices may also count towards the
24required percentages for wind and solar photovoltaics.
25Procurement of renewable energy credits resources from
26distributed renewable energy generation devices shall be done

 

 

09900SB1585sam002- 24 -LRB099 09533 EGJ 48253 a

1on an annual basis through multi-year contracts of no less than
25 years, and shall consist solely of renewable energy credits.
3Of the renewable energy credits from photovoltaics that are not
4distributed renewable energy generation devices procured
5pursuant to this Section, at least one-half shall come from
6brownfield site projects, if available. The Agency shall create
7application requirements for brownfield site projects that
8shall include, as appropriate, credit requirements for
9suppliers, demonstrated site control, bid bond requirements,
10construction completion deadlines, or other appropriate
11conditions to ensure confidence that selected bids will result
12in successful projects.
13    The Agency shall create credit requirements for suppliers
14of distributed renewable energy. In order to minimize the
15administrative burden of contracting entities, the Agency
16shall solicit the use of third-party organizations to aggregate
17distributed renewable energy into groups of no less than one
18megawatt in installed capacity. These third-party
19organizations shall administer contracts with individual
20distributed renewable energy generation device owners. An
21individual distributed renewable energy generation device
22owner shall have the ability to measure the output of his or
23her distributed renewable energy generation device.
24    (b-5) Beginning June 1, 2018, the Illinois Power Agency
25Renewable Energy Resources Fund shall be administered by the
26Agency to implement distributed generation programs, including

 

 

09900SB1585sam002- 25 -LRB099 09533 EGJ 48253 a

1low-income distributed generation programs and low-income
2community distributed generation programs, and to purchase
3renewable energy credits from the distributed generation
4projects developed by these programs. The Agency shall be
5authorized to retain one or more consultants to develop,
6administer, aggregate, operate, maintain, and evaluate
7distributed generation projects, and the Agency shall retain
8the consultant or consultants in the same manner, to the extent
9practicable, as the Agency retains others to administer
10provisions of this Act, including, but not limited to, the
11procurement administrator. The Agency may conduct a
12procurement process to procure one or more third parties to
13implement all or a portion of the programs offered under this
14subsection (b-5), and electric utilities and their affiliates
15shall not be precluded from participating in such procurement.
16    The Agency, together with any consultants the Agency has
17retained, shall coordinate with Local Administrative Agencies
18to determine eligibility criteria for low-income distributed
19generation projects, provided that eligible income shall be no
20more than 150% of the poverty level. The Agency, in connection
21with Local Administrative Agencies, shall further develop the
22application process and participation rules that will govern
23low-income customers' participation in the projects.
24    The costs incurred by the Agency associated with the
25distributed generation programs and projects implemented
26pursuant to this subsection (b-5) shall be recovered from the

 

 

09900SB1585sam002- 26 -LRB099 09533 EGJ 48253 a

1Illinois Power Agency Renewable Energy Resources Fund. Such
2costs shall include consultant, third-party, and aggregator
3costs and such other administrative costs that the Agency deems
4(and the Commission find) appropriate to develop, administer,
5install, and operate distributed generation projects.
6    The Agency shall specify in each renewable energy resources
7plan how the moneys available in the Illinois Power Agency
8Renewable Energy Resources Fund for a given planning year shall
9be allocated to satisfy the requirements of this subsection
10(b-5), provided that 75% of the funding shall be allocated to
11low-income distributed generation projects and programs that
12use photovoltaic technology, 12.5% of the funding shall be
13allocated to not-for-profit distributed generation programs
14that use photovoltaic technology, including, but not limited to
15community distributed generation projects, and 12.5% of the
16funding shall be allocated to public building distributed
17generation programs that use photovoltaic technology.
18    The distributed generation projects and programs
19implemented under this subsection (b-5) shall conform to the
20definition of "distributed renewable energy generation device"
21as set forth in Section 1-10 of this Act and shall otherwise
22comply with the criteria and billing requirements set forth in
23subsection (i) of Section 16-107.6 of the Public Utilities Act;
24however, the low-income community distributed generation
25projects described in this subsection (b-5) shall not be
26subject to the requirement that the participant's address must

 

 

09900SB1585sam002- 27 -LRB099 09533 EGJ 48253 a

1be located within 5 miles of the location of the project.
2    (b-10) Upon the submission of all payments required by
3Section 16-115D of the Public Utilities Act, no funds shall be
4deposited into the Illinois Power Agency Renewable Energy
5Resources Fund unless directed by order of the Commission.
6    (b-15) Upon the balance of the Illinois Power Agency
7Renewable Energy Resources Fund falling below $5,000, the Fund
8shall be terminated, and any remaining funds shall be
9transferred to the Low Income Home Energy Assistance Program,
10as authorized by the Energy Assistance Act.
11    The Agency shall create credit requirements for suppliers
12of distributed renewable energy. In order to minimize the
13administrative burden on contracting entities, the Agency
14shall solicit the use of third-party organizations to aggregate
15distributed renewable energy into groups of no less than one
16megawatt in installed capacity. These third-party
17organizations shall administer contracts with individual
18distributed renewable energy generation device owners. An
19individual distributed renewable energy generation device
20owner shall have the ability to measure the output of his or
21her distributed renewable energy generation device.
22    (c) Pursuant to a renewable energy resources plan approved
23by the Commission under Section 16-111.5 of the Public
24Utilities Act, the The Agency shall procure renewable energy
25credits using moneys in the Illinois Power Agency Renewable
26Energy Resources Fund or moneys projected to be deposited into

 

 

09900SB1585sam002- 28 -LRB099 09533 EGJ 48253 a

1the Fund resources at least once each year in conjunction with
2a procurement event for electric utilities required to comply
3with Section 1-75 of the Act and shall, whenever possible,
4enter into long-term contracts on an annual basis for a portion
5of the incremental requirement for the given procurement year.
6    (d) The price paid to procure renewable energy credits
7using monies from the Illinois Power Agency Renewable Energy
8Resources Fund shall not exceed market-based benchmarks
9established by the procurement administrator in consultation
10with Commission staff, Agency staff, and the procurement
11monitor the winning bid prices paid for like resources procured
12for electric utilities required to comply with Section 1-75 of
13this Act.
14    (e) All renewable energy credits procured using monies from
15the Illinois Power Agency Renewable Energy Resources Fund shall
16be permanently retired.
17    (f) The procurement process described in this Section is
18exempt from the requirements of the Illinois Procurement Code,
19pursuant to Section 20-10 of that Code.
20    (g) All disbursements from the Illinois Power Agency
21Renewable Energy Resources Fund shall be made only upon
22warrants of the Comptroller drawn upon the Treasurer as
23custodian of the Fund upon vouchers signed by the Director or
24by the person or persons designated by the Director for that
25purpose. The Comptroller is authorized to draw the warrant upon
26vouchers so signed. The Treasurer shall accept all warrants so

 

 

09900SB1585sam002- 29 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 30 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 31 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 32 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 33 -LRB099 09533 EGJ 48253 a

1    within 90 days after the effective date of this amendatory
2    Act of the 98th General Assembly and shall consider any
3    comments made by stakeholders or the public. Upon
4    development of the supplemental procurement plan within
5    this 90-day period, copies of the supplemental procurement
6    plan shall be posted and made publicly available on the
7    Agency's and Commission's websites. All interested parties
8    shall have 14 days following the date of posting to provide
9    comment to the Agency on the supplemental procurement plan.
10    All comments submitted to the Agency shall be specific,
11    supported by data or other detailed analyses, and, if
12    objecting to all or a portion of the supplemental
13    procurement plan, accompanied by specific alternative
14    wording or proposals. All comments shall be posted on the
15    Agency's and Commission's websites. Within 14 days
16    following the end of the 14-day review period, the Agency
17    shall revise the supplemental procurement plan as
18    necessary based on the comments received and file its
19    revised supplemental procurement plan with the Commission
20    for approval.
21        (2) Within 5 days after the filing of the supplemental
22    procurement plan at the Commission, any person objecting to
23    the supplemental procurement plan shall file an objection
24    with the Commission. Within 10 days after the filing, the
25    Commission shall determine whether a hearing is necessary.
26    The Commission shall enter its order confirming or

 

 

09900SB1585sam002- 34 -LRB099 09533 EGJ 48253 a

1    modifying the supplemental procurement plan within 90 days
2    after the filing of the supplemental procurement plan by
3    the Agency.
4        (3) The Commission shall approve the supplemental
5    procurement plan of renewable energy credits to be procured
6    from new or existing photovoltaics, including, but not
7    limited to, distributed photovoltaic generation, if the
8    Commission determines that it will ensure adequate,
9    reliable, affordable, efficient, and environmentally
10    sustainable electric service in the form of renewable
11    energy credits at the lowest total cost over time, taking
12    into account any benefits of price stability.
13        (4) The supplemental procurement process under this
14    subsection (i) shall include each of the following
15    components:
16            (A) Procurement administrator. The Agency may
17        retain a procurement administrator in the manner set
18        forth in item (2) of subsection (a) of Section 1-75 of
19        this Act to conduct the supplemental procurement or may
20        elect to use the same procurement administrator
21        administering the Agency's annual procurement under
22        Section 1-75.
23            (B) Procurement monitor. The procurement monitor
24        retained by the Commission pursuant to Section
25        16-111.5 of the Public Utilities Act shall:
26                (i) monitor interactions among the procurement

 

 

09900SB1585sam002- 35 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 36 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 37 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 38 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 39 -LRB099 09533 EGJ 48253 a

1    days after opening the sealed bids. The report shall
2    contain the procurement monitor's assessment of bidder
3    behavior in the process as well as an assessment of the
4    procurement administrator's compliance with the
5    procurement process and rules. The Commission shall review
6    the confidential reports submitted by the procurement
7    administrator and procurement monitor and shall accept or
8    reject the recommendations of the procurement
9    administrator within 2 business days after receipt of the
10    reports.
11        (6) Within 3 business days after the Commission
12    decision approving the results of a procurement event, the
13    Agency shall enter into binding contractual arrangements
14    with the winning suppliers using the standard form
15    contracts.
16        (7) The names of the successful bidders and the average
17    of the winning bid prices for each contract type and for
18    each contract term shall be made available to the public
19    within 2 days after the supplemental procurement event. The
20    Commission, the procurement monitor, the procurement
21    administrator, the Agency, and all participants in the
22    procurement process shall maintain the confidentiality of
23    all other supplier and bidding information in a manner
24    consistent with all applicable laws, rules, regulations,
25    and tariffs. Confidential information, including the
26    confidential reports submitted by the procurement

 

 

09900SB1585sam002- 40 -LRB099 09533 EGJ 48253 a

1    administrator and procurement monitor pursuant to this
2    Section, shall not be made publicly available and shall not
3    be discoverable by any party in any proceeding, absent a
4    compelling demonstration of need, nor shall those reports
5    be admissible in any proceeding other than one for law
6    enforcement purposes.
7        (8) The supplemental procurement provided in this
8    subsection (i) shall not be subject to the requirements and
9    limitations of subsections (c) and (d) of this Section.
10        (9) Expenses incurred in connection with the
11    procurement process held pursuant to this Section,
12    including, but not limited to, the cost of developing the
13    supplemental procurement plan, the procurement
14    administrator, procurement monitor, and the cost of the
15    retirement of renewable energy credits purchased pursuant
16    to the supplemental procurement shall be paid for from the
17    Illinois Power Agency Renewable Energy Resources Fund. The
18    Agency shall enter into an interagency agreement with the
19    Commission to reimburse the Commission for its costs
20    associated with the procurement monitor for the
21    supplemental procurement process.
22(Source: P.A. 97-616, eff. 10-26-11; 98-672, eff. 6-30-14.)
 
23    (20 ILCS 3855/1-75)
24    Sec. 1-75. Planning and Procurement Bureau. The Planning
25and Procurement Bureau has the following duties and

 

 

09900SB1585sam002- 41 -LRB099 09533 EGJ 48253 a

1responsibilities:
2    (a) The Planning and Procurement Bureau shall each year,
3beginning in 2008, develop procurement plans and conduct
4competitive procurement processes in accordance with the
5requirements of Section 16-111.5 of the Public Utilities Act
6for the eligible retail customers of electric utilities that on
7December 31, 2005 provided electric service to at least 100,000
8customers in Illinois. Beginning with the planning year
9commencing on June 1, 2017, the Planning and Procurement Bureau
10shall include in such plans and processes the procurement of
11zero emission credits from zero emission resources pursuant to
12subsection (d-5) of this Section for all of the utilities'
13retail customers. For planning years beginning on or after June
141, 2018, the Planning and Procurement Bureau shall include in
15such plans and processes the procurement of renewable energy
16resources for all of the utilities' retail customers in the
17amounts set forth in subsection (c) of this Section. The
18Planning and Procurement Bureau shall also develop procurement
19plans and conduct competitive procurement processes in
20accordance with the requirements of Section 16-111.5 of the
21Public Utilities Act for the eligible retail customers of small
22multi-jurisdictional electric utilities that (i) on December
2331, 2005 served less than 100,000 customers in Illinois and
24(ii) request a procurement plan for their Illinois
25jurisdictional load. This Section shall not apply to a small
26multi-jurisdictional utility until such time as a small

 

 

09900SB1585sam002- 42 -LRB099 09533 EGJ 48253 a

1multi-jurisdictional utility requests the Agency to prepare a
2procurement plan for their Illinois jurisdictional load. For
3the purposes of this Section, the term "eligible retail
4customers" has the same definition as found in Section
516-111.5(a) of the Public Utilities Act.
6        (1) The Agency shall each year, beginning in 2008, as
7    needed, issue a request for qualifications for experts or
8    expert consulting firms to develop the procurement plans in
9    accordance with Section 16-111.5 of the Public Utilities
10    Act. In order to qualify an expert or expert consulting
11    firm must have:
12            (A) direct previous experience assembling
13        large-scale power supply plans or portfolios for
14        end-use customers;
15            (B) an advanced degree in economics, mathematics,
16        engineering, risk management, or a related area of
17        study;
18            (C) 10 years of experience in the electricity
19        sector, including managing supply risk;
20            (D) expertise in wholesale electricity market
21        rules, including those established by the Federal
22        Energy Regulatory Commission and regional transmission
23        organizations;
24            (E) expertise in credit protocols and familiarity
25        with contract protocols;
26            (F) adequate resources to perform and fulfill the

 

 

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

 

 

09900SB1585sam002- 44 -LRB099 09533 EGJ 48253 a

1        (3) The Agency shall provide affected utilities and
2    other interested parties with the lists of qualified
3    experts or expert consulting firms identified through the
4    request for qualifications processes that are under
5    consideration to develop the procurement plans and to serve
6    as the procurement administrator. The Agency shall also
7    provide each qualified expert's or expert consulting
8    firm's response to the request for qualifications. All
9    information provided under this subparagraph shall also be
10    provided to the Commission. The Agency may provide by rule
11    for fees associated with supplying the information to
12    utilities and other interested parties. These parties
13    shall, within 5 business days, notify the Agency in writing
14    if they object to any experts or expert consulting firms on
15    the lists. Objections shall be based on:
16            (A) failure to satisfy qualification criteria;
17            (B) identification of a conflict of interest; or
18            (C) evidence of inappropriate bias for or against
19        potential bidders or the affected utilities.
20        The Agency shall remove experts or expert consulting
21    firms from the lists within 10 days if there is a
22    reasonable basis for an objection and provide the updated
23    lists to the affected utilities and other interested
24    parties. If the Agency fails to remove an expert or expert
25    consulting firm from a list, an objecting party may seek
26    review by the Commission within 5 days thereafter by filing

 

 

09900SB1585sam002- 45 -LRB099 09533 EGJ 48253 a

1    a petition, and the Commission shall render a ruling on the
2    petition within 10 days. There is no right of appeal of the
3    Commission's ruling.
4        (4) The Agency shall issue requests for proposals to
5    the qualified experts or expert consulting firms to develop
6    a procurement plan for the affected utilities and to serve
7    as procurement administrator.
8        (5) The Agency shall select an expert or expert
9    consulting firm to develop procurement plans based on the
10    proposals submitted and shall award contracts of up to 5
11    years to those selected.
12        (6) The Agency shall select an expert or expert
13    consulting firm, with approval of the Commission, to serve
14    as procurement administrator based on the proposals
15    submitted. If the Commission rejects, within 5 days, the
16    Agency's selection, the Agency shall submit another
17    recommendation within 3 days based on the proposals
18    submitted. The Agency shall award a 5-year contract to the
19    expert or expert consulting firm so selected with
20    Commission approval.
21    (b) The experts or expert consulting firms retained by the
22Agency shall, as appropriate, prepare procurement plans, and
23conduct a competitive procurement process as prescribed in
24Section 16-111.5 of the Public Utilities Act, to ensure
25adequate, reliable, affordable, efficient, and environmentally
26sustainable electric service at the lowest total cost over

 

 

09900SB1585sam002- 46 -LRB099 09533 EGJ 48253 a

1time, taking into account any benefits of price stability, for
2the applicable eligible retail customers of electric utilities
3that on December 31, 2005 provided electric service to at least
4100,000 customers in the State of Illinois, and for eligible
5Illinois retail customers of small multi-jurisdictional
6electric utilities that (i) on December 31, 2005 served less
7than 100,000 customers in Illinois and (ii) request a
8procurement plan for their Illinois jurisdictional load.
9    (c) Renewable portfolio standard.
10        (1) Through May 31, 2018, the The procurement plans
11    shall include cost-effective renewable energy resources
12    equal to a . A minimum percentage of each utility's actual
13    total supply to serve the load for of eligible retail
14    customers, as defined in Section 16-111.5(a) of the Public
15    Utilities Act, as follows procured for each of the
16    following years shall be generated from cost-effective
17    renewable energy resources: at least 2% by June 1, 2008; at
18    least 4% by June 1, 2009; at least 5% by June 1, 2010; at
19    least 6% by June 1, 2011; at least 7% by June 1, 2012; at
20    least 8% by June 1, 2013; at least 9% by June 1, 2014; at
21    least 10% by June 1, 2015; at least 11.5% by June 1, 2016;
22    and at least 13% by June 1, 2017.
23        For planning years commencing on or after June 1, 2018,
24    the procurement plans shall include cost-effective
25    renewable energy resources equal to a minimum percentage of
26    each utility's actual load for retail customers whose

 

 

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1    electric service has not been declared competitive
2    pursuant to Section 16-113 of the Public Utilities Act, as
3    follows: at least 14.5% by June 1, 2018, and increasing by
4    at least 1.5% each year thereafter to at least 25% by June
5    1, 2025.
6        For planning years commencing on or after June 1, 2018,
7    the procurement plans shall include cost-effective
8    renewable energy resources equal to the applicable portion
9    of each utility's actual load for retail customers whose
10    electric service has been declared competitive pursuant to
11    Section 16-113 of the Public Utilities Act as follows: at
12    least 14.5% by June 1, 2018, and increasing by at least
13    1.5% each year thereafter to at least 25% by June 1, 2025.
14        Beginning June 1, 2018, the applicable portion shall be
15    50% of each utility's actual load for retail customers
16    whose electric service has been declared competitive
17    pursuant to Section 16-113 of the Public Utilities Act. No
18    later than a date set by the Agency, the applicable portion
19    shall increase to 75% of each utility's actual load for
20    such retail customers, and, no later than a date set by the
21    Agency, the applicable portion shall increase to 100% of
22    each utility's actual load for such retail customers.
23    However, if an alternative retail electric supplier owns
24    facilities on December 31, 2015 that generate renewable
25    energy resources and supplies to certain customers
26    pursuant to Section 16-115D of the Public Utilities Act,

 

 

09900SB1585sam002- 48 -LRB099 09533 EGJ 48253 a

1    then the applicable portion identified in this paragraph
2    (1) shall be reduced for a given year by the amount of
3    those renewable energy resources supplied to those retail
4    customers.
5            (A) For those planning years commencing prior to
6        June 1, 2018, the following requirements shall apply:
7                (i) To the extent that it is available, at
8            least 75% of the renewable energy resources used to
9            meet these standards shall come from wind
10            generation and, beginning on June 1, 2011, at least
11            the following percentages of the renewable energy
12            resources used to meet these standards shall come
13            from photovoltaics on the following schedule: 0.5%
14            by June 1, 2012, 1.5% by June 1, 2013; 3% by June
15            1, 2014; and 6% by June 1, of each year thereafter
16            through May 31, 2018 2015 and thereafter.
17                (ii) Of the renewable energy resources
18            procured pursuant to this Section, at least the
19            following percentages shall come from distributed
20            renewable energy generation devices: 0.5% by June
21            1, 2013, 0.75% by June 1, 2014, and 1% by June 1,
22            2015 and each year thereafter through May 31, 2018.
23            To the extent available, half of the renewable
24            energy resources procured from distributed
25            renewable energy generation shall come from
26            devices of less than 25 kilowatts in nameplate

 

 

09900SB1585sam002- 49 -LRB099 09533 EGJ 48253 a

1            capacity. Renewable energy resources procured from
2            distributed generation devices may also count
3            towards the required percentages for wind and
4            solar photovoltaics. Procurement of renewable
5            energy resources from distributed renewable energy
6            generation devices shall be done on an annual basis
7            through multi-year contracts of no less than 5
8            years, and shall consist solely of renewable
9            energy credits.
10            (B) For those planning years commencing after May
11        31, 2018 and ending May 31, 2026, the following
12        procurement requirements shall be achieved, to the
13        extent the resources are available:
14                (i) for each planning year, 75% of the total
15            renewable energy credits procured shall come from
16            wind generation, provided that such credits do not
17            include any generating unit whose costs were being
18            recovered through rates regulated by any state or
19            states on January 1, 2017;
20                (ii) no later than the planning year ending May
21            31, 2021, 5% of the total renewable energy credits
22            procured or the equivalent amount of renewable
23            energy credits from 1,000 megawatts of
24            photovoltaic distributed generation nameplate
25            capacity, whichever is greater, shall come from
26            new photovoltaic distributed generation projects;

 

 

09900SB1585sam002- 50 -LRB099 09533 EGJ 48253 a

1            of that amount, to the extent possible, the Agency
2            shall procure 75% from photovoltaic distributed
3            generation projects having an installed nameplate
4            capacity of less than 2 megawatts and shall procure
5            25% from brownfield site projects or utility-scale
6            photovoltaic projects that are greater than 2
7            megawatts of installed nameplate capacity; and
8                (iii) no later than the planning year ending
9            May 31, 2026, 6% of the total renewable energy
10            credits procured or the equivalent amount of
11            renewable energy credits from 1,500 megawatts of
12            photovoltaic distributed generation nameplate
13            capacity, whichever is greater, shall come from
14            new photovoltaic distributed generation projects;
15            of that amount, to the extent possible, the Agency
16            shall procure 75% from photovoltaic distributed
17            generation projects having an installed nameplate
18            capacity of less than 2 megawatts and shall procure
19            25% from brownfield site projects or utility-scale
20            photovoltaic projects that are greater than 2
21            megawatts of installed nameplate capacity.
22            (C) The Agency may procure contracts of at least 15
23        years in length for the resources procured under items
24        (ii) and (iii) of subparagraph (B) of paragraph (1) of
25        this subsection (c), for which payment shall be made in
26        full by the contracting utilities at such time that the

 

 

09900SB1585sam002- 51 -LRB099 09533 EGJ 48253 a

1        facility producing the renewable energy credits is
2        interconnected at the distribution system level of the
3        utility and energized.
4            (D) The Agency shall create credit requirements
5        for suppliers of distributed renewable energy. In
6        order to minimize the administrative burden on
7        contracting entities, the Agency shall solicit the use
8        of third-party organizations to aggregate distributed
9        renewable energy into groups of no less than one
10        megawatt in installed capacity. These third-party
11        organizations shall administer contracts with
12        individual distributed renewable energy generation
13        device owners. An individual distributed renewable
14        energy generation device owner shall have the ability
15        to measure the output of his or her distributed
16        renewable energy generation device.
17            (E) For purposes of this subsection (c),
18        "cost-effective" means that the costs of procuring
19        renewable energy resources do not cause the limit
20        stated in paragraph (2) of this subsection (c) to be
21        exceeded and do not exceed benchmarks based on market
22        prices for renewable energy resources in the region,
23        which shall be developed by the procurement
24        administrator, in consultation with the Commission
25        staff, Agency staff, and the procurement monitor and
26        shall be subject to Commission review and approval. A

 

 

09900SB1585sam002- 52 -LRB099 09533 EGJ 48253 a

1        utility shall be deemed to have fully complied with the
2        requirements of this subsection (c) by entering into
3        contracts to procure the applicable percentage of
4        renewable energy resources by June 1 of each year.
5            (F) Renewable energy credits from photovoltaic
6        distributed generation that are the subject of items
7        (ii) and (iii) of subparagraph (B) of paragraph (1) of
8        this subsection (c) shall be purchased before any other
9        renewable energy credits are purchased until such time
10        as the targets specified therein have been achieved.
11        (2) For purposes of this subsection (c), the required
12    procurement of cost-effective renewable energy resources
13    for a particular year commencing prior to June 1, 2018
14    shall be measured as a percentage of the actual amount of
15    electricity (megawatt-hours) supplied by the electric
16    utility to eligible retail customers in the planning year
17    ending immediately prior to the procurement, and, for
18    planning years commencing on and after June 1, 2018, the
19    required procurement of cost-effective renewable energy
20    resources for a particular year shall be measured as a
21    percentage of the actual amount of electricity
22    (megawatt-hours) delivered by the electric utility in the
23    planning year ending immediately prior to the procurement,
24    to all retail customers in its service territory. For
25    purposes of this subsection (c), the amount paid per
26    kilowatthour means the total amount paid for electric

 

 

09900SB1585sam002- 53 -LRB099 09533 EGJ 48253 a

1    service expressed on a per kilowatthour basis. For purposes
2    of this subsection (c), the total amount paid for electric
3    service includes without limitation amounts paid for
4    supply, transmission, distribution, surcharges, and add-on
5    taxes.
6        Notwithstanding the requirements of this subsection
7    (c), the total of renewable energy resources procured
8    pursuant to the procurement plan for any single year shall
9    be subject to the limitations of this paragraph (2). Such
10    procurement shall be reduced for all retail customers based
11    on the reduced by an amount necessary to limit the annual
12    estimated average net increase due to the costs of these
13    resources included in the amounts paid by eligible retail
14    customers in connection with electric service to:
15            (A) in 2008, no more than 0.5% of the amount paid
16        per kilowatthour by those customers during the year
17        ending May 31, 2007;
18            (B) in 2009, the greater of an additional 0.5% of
19        the amount paid per kilowatthour by those customers
20        during the year ending May 31, 2008 or 1% of the amount
21        paid per kilowatthour by those customers during the
22        year ending May 31, 2007;
23            (C) in 2010, the greater of an additional 0.5% of
24        the amount paid per kilowatthour by those customers
25        during the year ending May 31, 2009 or 1.5% of the
26        amount paid per kilowatthour by those customers during

 

 

09900SB1585sam002- 54 -LRB099 09533 EGJ 48253 a

1        the year ending May 31, 2007;
2            (D) in 2011, the greater of an additional 0.5% of
3        the amount paid per kilowatthour by those customers
4        during the year ending May 31, 2010 or 2% of the amount
5        paid per kilowatthour by those customers during the
6        year ending May 31, 2007; and
7            (E) thereafter, the amount of renewable energy
8        resources procured pursuant to the procurement plan
9        for any single year shall be reduced by an amount
10        necessary to limit the estimated average net increase
11        due to the cost of these resources included in the
12        amounts paid by eligible retail customers in
13        connection with electric service to no more than the
14        greater of 2.015% of the amount paid per kilowatthour
15        by those customers during the year ending May 31, 2007
16        or the incremental amount per kilowatthour paid for
17        these resources in 2011. To arrive at a maximum dollar
18        amount of renewable energy resources to be procured for
19        the particular planning year, the resulting per
20        kilowatthour amount shall be applied to the actual
21        amount of kilowatthours of electricity delivered by
22        the electric utility in the planning year immediately
23        prior to the procurement to all retail customers in its
24        service territory. The calculations required by this
25        paragraph (2) shall be made only once for each planning
26        year at the time that the renewable energy resources

 

 

09900SB1585sam002- 55 -LRB099 09533 EGJ 48253 a

1        are procured. Once the determination as to the amount
2        of renewable energy resources to procure is made based
3        on the calculations set forth in this paragraph (2) and
4        the contracts procuring those amounts are executed, no
5        subsequent rate impact determinations shall be made
6        and no adjustments to those contract amounts shall be
7        allowed. All costs incurred under such contracts shall
8        be fully recoverable by the electric utility as
9        provided in this Section.
10            No later than June 30, 2011, the Commission shall
11        review the limitation on the amount of renewable energy
12        resources procured pursuant to this subsection (c) and
13        report to the General Assembly its findings as to
14        whether that limitation unduly constrains the
15        procurement of cost-effective renewable energy
16        resources.
17        (3) Through June 1, 2011, renewable energy resources
18    shall be counted for the purpose of meeting the renewable
19    energy standards set forth in paragraph (1) of this
20    subsection (c) only if they are generated from facilities
21    located in the State, provided that cost-effective
22    renewable energy resources are available from those
23    facilities. If those cost-effective resources are not
24    available in Illinois, they shall be procured in states
25    that adjoin Illinois and may be counted towards compliance.
26    If those cost-effective resources are not available in

 

 

09900SB1585sam002- 56 -LRB099 09533 EGJ 48253 a

1    Illinois or in states that adjoin Illinois, they shall be
2    purchased elsewhere and shall be counted towards
3    compliance. After June 1, 2011, cost-effective renewable
4    energy resources located in Illinois and in states that
5    adjoin Illinois may be counted towards compliance with the
6    standards set forth in paragraph (1) of this subsection
7    (c). If those cost-effective resources are not available in
8    Illinois or in states that adjoin Illinois, they shall be
9    purchased elsewhere and shall be counted towards
10    compliance.
11        (4) The electric utility shall retire all renewable
12    energy credits used to comply with the standard.
13        (5) Beginning with the year commencing June 1, 2010, an
14    electric utility subject to this subsection (c) shall apply
15    the lesser of the maximum alternative compliance payment
16    rate or the most recent estimated alternative compliance
17    payment rate for its service territory for the
18    corresponding compliance period, established pursuant to
19    subsection (d) of Section 16-115D of the Public Utilities
20    Act to its retail customers that take service pursuant to
21    the electric utility's hourly pricing tariff or tariffs.
22    The electric utility shall retain all amounts collected as
23    a result of the application of the alternative compliance
24    payment rate or rates to such customers, and, beginning in
25    2011, the utility shall include in the information provided
26    under item (1) of subsection (d) of Section 16-111.5 of the

 

 

09900SB1585sam002- 57 -LRB099 09533 EGJ 48253 a

1    Public Utilities Act the amounts collected under the
2    alternative compliance payment rate or rates for the prior
3    year ending May 31. Notwithstanding any limitation on the
4    procurement of renewable energy resources imposed by item
5    (2) of this subsection (c), the Agency shall increase its
6    spending on the purchase of renewable energy resources to
7    be procured by the electric utility for the next plan year
8    by an amount equal to the amounts collected by the utility
9    under the alternative compliance payment rate or rates in
10    the prior year ending May 31. Beginning April 1, 2012, and
11    each year thereafter, the Agency shall prepare a public
12    report for the General Assembly and Illinois Commerce
13    Commission that shall include, but not necessarily be
14    limited to:
15            (A) a comparison of the costs associated with the
16        Agency's procurement of renewable energy resources to
17        (1) the Agency's costs associated with electricity
18        generated by other types of generation facilities and
19        (2) the benefits associated with the Agency's
20        procurement of renewable energy resources; and
21            (B) an analysis of the rate impacts associated with
22        the Illinois Power Agency's procurement of renewable
23        resources, including, but not limited to, any
24        long-term contracts, on the eligible retail customers
25        of electric utilities.
26        The analysis shall include the Agency's estimate of the

 

 

09900SB1585sam002- 58 -LRB099 09533 EGJ 48253 a

1    total dollar impact that the Agency's procurement of
2    renewable resources has had on the annual electricity bills
3    of the customer classes that comprise each eligible retail
4    customer class taking service from an electric utility. The
5    Agency's report shall also analyze how the operation of the
6    alternative compliance payment mechanism, any long-term
7    contracts, or other aspects of the applicable renewable
8    portfolio standards impacts the rates of customers of
9    alternative retail electric suppliers.
10        (6) Beginning with the planning year commencing June 1,
11    2018, the procurement plan shall include a renewable energy
12    resources plan for the procurement of renewable energy
13    credits in accordance with the requirements of Section 1-56
14    of this Act and renewable energy resources in accordance
15    with the requirements of this Section. The renewable energy
16    resources plan shall ensure adequate, reliable,
17    affordable, efficient, and environmentally sustainable
18    renewable energy resources at the lowest total cost over
19    time, taking into account any benefits of price stability.
20    The renewable energy resources plan shall also include the
21    items set forth in subparagraphs (i) through (iii) of
22    paragraph (5) of subsection (b) of Section 16-111.5 of the
23    Public Utilities Act.
24        Nothing in this paragraph (6) is intended to alter any
25    of the limitations or conditions otherwise imposed on the
26    purchase of renewable energy credits or renewable energy

 

 

09900SB1585sam002- 59 -LRB099 09533 EGJ 48253 a

1    resources by any other section of this Act.
2        (7) The electric utility shall be entitled to recover
3    all of its costs associated with the procurement of
4    renewable energy resources pursuant to this Section
5    through an automatic adjustment clause tariff in
6    accordance with subsection (k) of Section 16-108 of the
7    Public Utilities Act. All procurement of renewable energy
8    resources in the procurement plans of the electric
9    utilities shall be pursuant to a competitive bidding
10    process and shall be approved by the Commission pursuant to
11    Section 16-111.5 of the Public Utilities Act.
12    (d) Clean coal portfolio standard.
13        (1) The procurement plans shall include electricity
14    generated using clean coal. Each utility shall enter into
15    one or more sourcing agreements with the initial clean coal
16    facility, as provided in paragraph (3) of this subsection
17    (d), covering electricity generated by the initial clean
18    coal facility representing at least 5% of each utility's
19    total supply to serve the load of eligible retail customers
20    in 2015 and each year thereafter, as described in paragraph
21    (3) of this subsection (d), subject to the limits specified
22    in paragraph (2) of this subsection (d). It is the goal of
23    the State that by January 1, 2025, 25% of the electricity
24    used in the State shall be generated by cost-effective
25    clean coal facilities. For purposes of this subsection (d),
26    "cost-effective" means that the expenditures pursuant to

 

 

09900SB1585sam002- 60 -LRB099 09533 EGJ 48253 a

1    such sourcing agreements do not cause the limit stated in
2    paragraph (2) of this subsection (d) to be exceeded and do
3    not exceed cost-based benchmarks, which shall be developed
4    to assess all expenditures pursuant to such sourcing
5    agreements covering electricity generated by clean coal
6    facilities, other than the initial clean coal facility, by
7    the procurement administrator, in consultation with the
8    Commission staff, Agency staff, and the procurement
9    monitor and shall be subject to Commission review and
10    approval.
11        A utility party to a sourcing agreement shall
12    immediately retire any emission credits that it receives in
13    connection with the electricity covered by such agreement.
14        Utilities shall maintain adequate records documenting
15    the purchases under the sourcing agreement to comply with
16    this subsection (d) and shall file an accounting with the
17    load forecast that must be filed with the Agency by July 15
18    of each year, in accordance with subsection (d) of Section
19    16-111.5 of the Public Utilities Act.
20        A utility shall be deemed to have complied with the
21    clean coal portfolio standard specified in this subsection
22    (d) if the utility enters into a sourcing agreement as
23    required by this subsection (d).
24        (2) For purposes of this subsection (d), the required
25    execution of sourcing agreements with the initial clean
26    coal facility for a particular year shall be measured as a

 

 

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

 

 

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

 

 

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

 

 

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

 

 

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1            Public Utilities Act, whether generated from the
2            synthesis gas derived from coal, from SNG, or from
3            natural gas, shall be credited against the revenue
4            requirement for this initial clean coal facility;
5            (B) power purchase provisions, which shall:
6                (i) provide that the utility party to such
7            sourcing agreement shall pay the contract price
8            for electricity delivered under such sourcing
9            agreement;
10                (ii) require delivery of electricity to the
11            regional transmission organization market of the
12            utility that is party to such sourcing agreement;
13                (iii) require the utility party to such
14            sourcing agreement to buy from the initial clean
15            coal facility in each hour an amount of energy
16            equal to all clean coal energy made available from
17            the initial clean coal facility during such hour
18            times a fraction, the numerator of which is such
19            utility's retail market sales of electricity
20            (expressed in kilowatthours sold) 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

 

 

09900SB1585sam002- 66 -LRB099 09533 EGJ 48253 a

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

 

 

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1            kilowatthours sold) in the State by alternative
2            retail electric suppliers during such prior month
3            that are subject to the requirements of this
4            subsection (d) and paragraph (5) of subsection (d)
5            of Section 16-115 of the Public Utilities Act,
6            provided that the amount paid by the utility in any
7            year will be limited by paragraph (2) of this
8            subsection (d);
9                (ii) provide that the utility's payment
10            obligation in respect of the quantity of
11            electricity determined pursuant to the preceding
12            clause (i) shall be limited to an amount equal to
13            (1) the difference between the contract price
14            determined pursuant to subparagraph (A) of
15            paragraph (3) of this subsection (d) and the
16            day-ahead price for electricity delivered to the
17            regional transmission organization market of the
18            utility that is party to such sourcing agreement
19            (or any successor delivery point at which such
20            utility's supply obligations are financially
21            settled on an hourly basis) (the "reference
22            price") on the day preceding the day on which the
23            electricity is delivered to the initial clean coal
24            facility busbar, multiplied by (2) the quantity of
25            electricity determined pursuant to the preceding
26            clause (i); and

 

 

09900SB1585sam002- 68 -LRB099 09533 EGJ 48253 a

1                (iii) not require the utility to take physical
2            delivery of the electricity produced by the
3            facility;
4            (D) general provisions, which shall:
5                (i) specify a term of no more than 30 years,
6            commencing on the commercial operation date of the
7            facility;
8                (ii) provide that utilities shall maintain
9            adequate records documenting purchases under the
10            sourcing agreements entered into to comply with
11            this subsection (d) and shall file an accounting
12            with the load forecast that must be filed with the
13            Agency by July 15 of each year, in accordance with
14            subsection (d) of Section 16-111.5 of the Public
15            Utilities Act;
16                (iii) provide that all costs associated with
17            the initial clean coal facility will be
18            periodically reported to the Federal Energy
19            Regulatory Commission and to purchasers in
20            accordance with applicable laws governing
21            cost-based wholesale power contracts;
22                (iv) permit the Illinois Power Agency to
23            assume ownership of the initial clean coal
24            facility, without monetary consideration and
25            otherwise on reasonable terms acceptable to the
26            Agency, if the Agency so requests no less than 3

 

 

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1            years prior to the end of the stated contract term;
2                (v) require the owner of the initial clean coal
3            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 that
14            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 any
26            given year. No costs of any such purchases of

 

 

09900SB1585sam002- 70 -LRB099 09533 EGJ 48253 a

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 the
22            course of the review specified in item (vii),
23            reduce the allowable return on equity for the
24            facility if the facility wilfully fails to comply
25            with the carbon capture and sequestration
26            requirements set forth in this item (v);

 

 

09900SB1585sam002- 71 -LRB099 09533 EGJ 48253 a

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

 

 

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1            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 delivered
7            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 the
14            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 the
23            power purchase provisions, are subject to review
24            under the public interest standard applied by the
25            Federal Energy Regulatory Commission pursuant to
26            Sections 205 and 206 of the Federal Power Act; and

 

 

09900SB1585sam002- 73 -LRB099 09533 EGJ 48253 a

1                (xiii) conform with customary lender
2            requirements in power purchase agreements used as
3            the basis for financing non-utility generators.
4        (4) Effective date of sourcing agreements with the
5    initial clean coal facility.
6        Any proposed sourcing agreement with the initial clean
7    coal facility shall not become effective unless the
8    following reports are prepared and submitted and
9    authorizations and approvals obtained:
10            (i) Facility cost report. The owner of the initial
11        clean coal facility shall submit to the Commission, the
12        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, in
25        consultation with the Agency, shall submit a report to
26        the General Assembly setting forth its analysis of the

 

 

09900SB1585sam002- 74 -LRB099 09533 EGJ 48253 a

1        facility cost report. Such report shall include, but
2        not be limited to, a comparison of the costs associated
3        with electricity generated by the initial clean coal
4        facility to the costs associated with electricity
5        generated by other types of generation facilities, an
6        analysis of the rate impacts on residential and small
7        business customers over the life of the sourcing
8        agreements, and an analysis of the likelihood that the
9        initial clean coal facility will commence commercial
10        operation by and be delivering power to the facility's
11        busbar by 2016. To assist in the preparation of its
12        report, the Commission, in consultation with the
13        Agency, may hire one or more experts or consultants,
14        the costs of which shall be paid for by the owner of
15        the initial clean coal facility. The Commission and
16        Agency may begin the process of selecting such experts
17        or consultants prior to receipt of the facility cost
18        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

 

 

09900SB1585sam002- 75 -LRB099 09533 EGJ 48253 a

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 that
14        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 or
19        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 core
25            plant based on one or more front end engineering
26            and design studies for the gasification island and

 

 

09900SB1585sam002- 76 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 77 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 78 -LRB099 09533 EGJ 48253 a

1            (D) The facility cost report shall also include an
2        analysis of the initial clean coal facility's ability
3        to deliver power and energy into the applicable
4        regional transmission organization markets and an
5        analysis of the expected capacity factor for the
6        initial clean coal facility.
7            (E) Amounts paid to third parties unrelated to the
8        owner or owners of the initial clean coal facility to
9        prepare the core plant construction cost quote,
10        including the front end engineering and design study,
11        and the operating and maintenance cost quote will be
12        reimbursed through Coal Development Bonds.
13        (5) Re-powering and retrofitting coal-fired power
14    plants previously owned by Illinois utilities to qualify as
15    clean coal facilities. During the 2009 procurement
16    planning process and thereafter, the Agency and the
17    Commission shall consider sourcing agreements covering
18    electricity generated by power plants that were previously
19    owned by Illinois utilities and that have been or will be
20    converted into clean coal facilities, as defined by Section
21    1-10 of this Act. Pursuant to such procurement planning
22    process, the owners of such facilities may propose to the
23    Agency sourcing agreements with utilities and alternative
24    retail electric suppliers required to comply with
25    subsection (d) of this Section and item (5) of subsection
26    (d) of Section 16-115 of the Public Utilities Act, covering

 

 

09900SB1585sam002- 79 -LRB099 09533 EGJ 48253 a

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

 

 

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1    electricity delivered by each electric utility to retail
2    customers in the State during calendar year 2014.
3    Notwithstanding whether a procurement event is conducted
4    pursuant to Section 16-111.5 of the Public Utilities Act,
5    the Agency and Commission shall immediately initiate an
6    initial procurement process upon the effective date of this
7    amendatory Act of the 99th General Assembly, which shall
8    procure cost-effective zero emission credits from zero
9    emission resources, in an amount equal to, for each
10    planning year, 16% of each electric utility's annual retail
11    sales of electricity to retail customers in the State
12    during calendar year 2014.
13        The initial procurement plan and process shall be
14    subject to the following provisions:
15            (A) To assist the Agency in preparing its proposed
16        initial procurement plan, those zero emission
17        resources that intend to participate in the
18        procurement shall submit to the Agency the following
19        information for each zero emission resource on or
20        before the date established by the Agency:
21                (i) the in-service date and remaining useful
22            life of the zero emission resource;
23                (ii) the projected zero emission credits to be
24            generated over the remaining useful life of the
25            zero emission resource;
26                (iii) the annual zero emission resource cost

 

 

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1            projections, expressed on a per megawatthour
2            basis, over the next 4 planning years, which shall
3            include the following: operation and maintenance
4            expenses; fully allocated overhead costs, which
5            shall be allocated using the methodology developed
6            by the Institute for Nuclear Power Operations;
7            fuel expenditures; non-fuel capital expenditures;
8            spent fuel expenditures; a return on working
9            capital; and any other costs necessary for
10            continued operations, provided that "necessary"
11            means, for purposes of this item (iii), that the
12            costs could reasonably be avoided only by ceasing
13            operations of the zero emission resource. In
14            addition, those cost projections shall be adjusted
15            to reflect operational risks that include, but are
16            not limited to, operational cost risk, which is the
17            risk that operating costs will be higher than
18            reasonably anticipated, and capacity factor risk,
19            which is the risk that per megawatthour costs will
20            be higher than anticipated because of a lower than
21            expected capacity factor. The cost projections
22            shall be further adjusted by a per megawatthour
23            facility adjustment to reflect market risks that
24            include, but are not limited to, liquidated
25            damages risk, which is the risk of a forced outage
26            and the associated costs of covering contractual

 

 

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1            obligations; volatility risk, which is the risk
2            that output from the resource may not be able to be
3            sold at the same forward prices used as set forth
4            in this paragraph (1); and basis risk, which is the
5            risk that the difference between the nodal energy
6            price for the resource and the associated
7            zone-wide energy price will exceed the values
8            calculated as set forth in this paragraph (1); and
9                (iv) a commitment to continue operating, for
10            the duration of the contract or contracts executed
11            pursuant to the initial procurement held under
12            this subsection (d-5), the zero emission resource
13            that produces the zero emission credits to be
14            procured in the procurement.
15            (B) Zero emission resources that bid into the
16        initial procurement must commit to deliver all zero
17        emission credits from the zero emission resource
18        during the remaining useful life of the resource, and
19        each winning zero emission resource shall be
20        compensated for each planning year in an amount that
21        equals the difference between the weighted average of
22        all zero emission resources' average annual zero
23        emission resource cost, expressed on a price per
24        megawatthour basis, for the applicable planning year
25        and each zero emission resource's projected energy
26        revenues and projected capacity revenues for the

 

 

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1        applicable planning year. However, if the difference
2        is a sum that is less than zero, then no compensation
3        shall be provided to any entity. The components of this
4        calculation are defined as follows:
5                (i) Weighted average of all zero emission
6            resources' average annual zero emission resource
7            cost: during the first 4 planning years, the
8            weighted average of all zero emission resources'
9            average annual zero emission resource cost shall
10            be $42 per megawatthour. Thereafter, for each
11            applicable planning year, the Agency shall
12            calculate for each zero emission resource the
13            average annual zero emission resource cost over
14            the consecutive 4-year planning period ending
15            immediately prior to the applicable planning year,
16            and the average annual zero emission resource cost
17            over the consecutive 4-year planning period ending
18            on May 31 of the applicable planning year. The
19            Agency shall use the 4-year cost projections
20            submitted by zero emission resources pursuant to
21            subparagraph (D) of this paragraph (1), and the
22            averages calculated by the Agency shall be
23            expressed on a price per megawatthour basis for the
24            applicable year.
25                The weighted average of all zero emission
26            resources' average annual zero emission resource

 

 

09900SB1585sam002- 84 -LRB099 09533 EGJ 48253 a

1            cost for planning years commencing after the first
2            4 planning years shall be calculated using the
3            following formula: the weighted average of all
4            zero emission resources' average annual zero
5            emission resource cost, expressed on a price per
6            megawatt hour basis, established by the Commission
7            for the planning year immediately preceding the
8            applicable planning year multiplied by a ratio
9            where the numerator is the weighted average of all
10            zero emission resources' average annual zero
11            emission resource costs over the consecutive
12            4-year planning period ending on May 31 of the
13            applicable planning year and the denominator is
14            the weighted average of all zero emission
15            resources' average annual zero emission resource
16            costs over the consecutive 4-year planning period
17            ending immediately prior to the applicable
18            planning year. The submissions and calculations
19            required by this item (i) shall be made according
20            to the schedule set forth in subparagraph (D) of
21            this paragraph (1).
22                (ii) Projected energy revenues: the zero
23            emission resource shall calculate projected energy
24            revenues for the applicable planning year based on
25            actual forward market prices as published by the
26            Intercontinental Exchange, which shall be

 

 

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1            calculated as the average forward market energy
2            price at the PJM Interconnection, LLC Northern
3            Illinois Hub for all trade dates during the
4            immediately preceding 12-month period that began
5            on April 1 and ended March 31 and adjusted to
6            reflect the historic basis price difference
7            between the Northern Illinois Hub and the average
8            day ahead price for energy during that period at
9            the generating facility bus that is producing the
10            credit.
11                (iii) Projected capacity revenues: for the
12            planning years commencing June 1, 2017, June 1,
13            2018, and June 1, 2019, the zero emission resource
14            shall calculate projected capacity revenues for
15            the applicable planning year based on
16            unit-specific market prices determined by the
17            applicable regional transmission organization's
18            procurement process, PJM Interconnection LLC or
19            the Midcontinent Independent System Operator,
20            Inc.; for planning years commencing after May 31,
21            2020, the zero emission resource shall calculate
22            projected capacity revenues for the applicable
23            planning year based on the zonal forward market
24            prices determined by the applicable regional
25            transmission organization's procurement process,
26            PJM Interconnection LLC or the Midcontinent

 

 

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1            Independent System Operator, Inc.
2            (C) No later than 45 days after the effective date
3        of this amendatory Act of the 99th General Assembly,
4        the Agency shall submit to the Commission the proposed
5        initial procurement plan. The plan shall be consistent
6        with the provisions of this paragraph (1) and shall
7        provide that winning bids shall be selected based on
8        public interest criteria that include minimizing
9        carbon dioxide emissions that result from electricity
10        consumed in Illinois and minimizing sulfur dioxide,
11        nitrogen oxide, and particulate matter emissions that
12        adversely affect the citizens of this State. In
13        particular, the selection of winning bids shall take
14        into account the incremental environmental and
15        reliability benefits resulting from the procurement,
16        including any existing environmental and reliability
17        benefits that are preserved by the procurement and
18        would cease to exist if the procurement were not held.
19        The Commission shall, after notice and hearing, but no
20        later than 30 days after the Agency submits its plan,
21        approve the plan or approve with modification. The
22        Agency shall conduct the request for proposals process
23        as soon as reasonably practicable after the effective
24        date of this amendatory Act of the 99th General
25        Assembly, and each utility shall enter into binding
26        contractual arrangements with the winning suppliers.

 

 

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1        The procurement shall be completed no later than May
2        31, 2017. Notwithstanding the provisions of this
3        subparagraph (C), the Agency and Commission shall
4        conduct the procurement and plan approval processes
5        required by this subsection (d-5) in conjunction with
6        the procurement and plan approval processes required
7        by subsection (c) of this Section and Section 16-111.5
8        of the Public Utilities Act, to the extent practicable.
9            Following the initial procurement event described
10        in this paragraph (1), the Agency and Commission shall
11        initiate additional procurement processes, as
12        necessary, to replace any zero emission credits that
13        were not delivered due to a supplier default or in the
14        event that additional zero emission credits must be
15        procured. Any such processes shall be conducted
16        regardless of whether a procurement event is conducted
17        pursuant to Section 16-111.5 of the Public Utilities
18        Act. Each utility shall enter into binding contractual
19        arrangements with the winning suppliers.
20            (D) Following the initial procurement event
21        described in this paragraph (1), each zero emission
22        resource that has executed a contract to deliver zero
23        emission credits pursuant to this paragraph (1) shall
24        submit its updated zero emission resource cost
25        projections for the next 4 planning years, and
26        projected energy revenues and projected capacity

 

 

09900SB1585sam002- 88 -LRB099 09533 EGJ 48253 a

1        revenues for the next planning years, as those costs
2        and revenues are defined in subparagraphs (A) and (B)
3        of this paragraph (1), no later than April 10, 2018 and
4        each April 10 thereafter. Consistent with subparagraph
5        (B), the Agency shall determine the weighted average of
6        all zero emission resources' average annual zero
7        emission resource cost for the planning year that
8        commences 4 years after the current planning year, on a
9        per megawatthour basis, and shall calculate the
10        payments to be made under each contract for the next
11        planning year based on the updated projected energy
12        revenues and capacity revenues submitted by the zero
13        emission resources. The Agency shall publish the
14        weighted average of all zero emission resources'
15        average annual zero emission resource cost and payment
16        calculations no later than May 25, 2018 and every May
17        25 thereafter.
18            (E) The contracts executed pursuant to this
19        subsection (d-5) shall provide that the Agency,
20        Commission, or zero emission resource may terminate a
21        contract or contracts to be effective on June 1 of a
22        given planning year, provided that notice of such
23        termination must be made at least 4 years prior to the
24        effective date of such termination and the earliest
25        date on which a contract termination may take effect
26        under this subparagraph (C) is the earlier of June 1,

 

 

09900SB1585sam002- 89 -LRB099 09533 EGJ 48253 a

1        2023 or 2 years after the State has adopted and
2        implemented a plan pursuant to the provisions of
3        Section 111(d) of the federal Clean Air Act, 42 U.S. C.
4        7411(d), as amended.
5            (F) Notwithstanding the requirements of this
6        subsection (d-5), the contracts executed pursuant to
7        this subsection (d-5) shall provide that the zero
8        emission resource may, as applicable, suspend or
9        terminate performance under the contracts in the
10        following instances:
11                (i) A zero emission resource shall be excused
12            from its performance under the contract for any
13            cause beyond the control of the resource,
14            including, but not restricted to, acts of God,
15            flood, drought, earthquake, storm, fire,
16            lightning, epidemic, war, riot, civil disturbance
17            or disobedience, labor dispute, labor or material
18            shortage, sabotage, acts of public enemy,
19            explosions, orders, regulations or restrictions
20            imposed by governmental, military, or lawfully
21            established civilian authorities, which, in any of
22            the foregoing cases, by exercise of commercially
23            reasonable efforts the zero emission resource
24            could not reasonably have been expected to avoid,
25            and which, by the exercise of commercially
26            reasonable efforts, it has been unable to

 

 

09900SB1585sam002- 90 -LRB099 09533 EGJ 48253 a

1            overcome. In such event, the zero emission
2            resource shall be excused from performance for the
3            duration of the event, including, but not limited
4            to, delivery of zero emission credits, and no
5            payment shall be due to the zero emission resource
6            during the duration of the event.
7                (ii) A zero emission resource shall be
8            permitted to terminate the contract if legislation
9            is enacted into law by the General Assembly that
10            imposes or authorizes a new tax, special
11            assessment, or fee on the generation of
12            electricity, the ownership or leasehold of a
13            generating unit, or the privilege or occupation of
14            such generation, ownership, or leasehold of
15            generation units by a zero emission resource.
16            However, the provisions of this item (ii) do not
17            apply to any generally applicable tax, special
18            assessment or fee, or requirements imposed by
19            federal law.
20                (iii) A zero emission resource shall be
21            permitted to terminate the contract in the event
22            that the resource requires capital expenditures
23            that were neither known nor reasonably foreseeable
24            at the time it executed the contract and that a
25            prudent owner or operator of such resource would
26            not undertake.

 

 

09900SB1585sam002- 91 -LRB099 09533 EGJ 48253 a

1                (iv) A zero emission resource shall be
2            permitted to terminate the contract in the event
3            the Nuclear Regulatory Commission terminates the
4            resource's license.
5            (G) For purposes of this subsection (d-5),
6        "cost-effective" means that the costs of procuring
7        zero emission credits do not cause the limit stated in
8        paragraph (2) of this subsection (d-5) to be exceeded.
9        (2) For purposes of this subsection (d-5), the required
10    procurement of cost-effective zero emission credits for a
11    particular period shall be measured as a percentage of the
12    actual amount of electricity (megawatthours) delivered by
13    the electric utility to all retail customers in the
14    planning year ending immediately prior to the procurement,
15    as incorporated in the procurement plan approved by the
16    Commission. For purposes of this subsection (d-5), the
17    amount paid per kilowatthour means the total amount paid
18    for electric service expressed on a per kilowatthour basis.
19    For purposes of this subsection (d-5), the total amount
20    paid for electric service includes, without limitation,
21    amounts paid for supply, transmission, distribution,
22    surcharges, and add-on taxes.
23        Notwithstanding the requirements of this subsection
24    (d-5), the total of zero emission credits procured pursuant
25    to a procurement plan shall be subject to the limitations
26    of this paragraph (2). For each 4-year period, the

 

 

09900SB1585sam002- 92 -LRB099 09533 EGJ 48253 a

1    procurement shall be reduced for all retail customers based
2    on the amount necessary to limit the annual estimated
3    average net increase over each period due to the costs of
4    these credits included in the amounts paid by eligible
5    retail customers in connection with electric service to no
6    more than 2.015% of the amount paid per kilowatthour by
7    eligible retail customers during the year ending May 31,
8    2009. The result of this computation shall apply to and
9    reduce the procurement for all retail customers, and all
10    those customers shall pay the same single, uniform cents
11    per kilowatthour charge pursuant to subsection (k) of
12    Section 16-108 of the Public Utilities Act. To arrive at a
13    maximum dollar amount of zero emission credits to be
14    procured for the particular planning year, the resulting
15    per kilowatthour amount shall be applied to the actual
16    amount of kilowatthours of electricity delivered by the
17    electric utility in the planning year immediately prior to
18    the procurement, to all retail customers in its service
19    territory. The calculations required by this paragraph (2)
20    shall be made only once for each procurement plan year.
21    Once the determination as to the amount of zero emission
22    credits to procure is made based on the calculations set
23    forth in this paragraph (2), no subsequent rate impact
24    determinations shall be made and no adjustments to those
25    contract amounts shall be allowed. All costs incurred under
26    those contracts and in implementing this subsection (d-5)

 

 

09900SB1585sam002- 93 -LRB099 09533 EGJ 48253 a

1    shall be recovered by the electric utility as provided in
2    this Section.
3        No later than June 30, 2019, the Commission shall
4    review the limitation on the amount of zero emission
5    credits procured pursuant to this subsection (d-5) and
6    report to the General Assembly its findings as to whether
7    that limitation unduly constrains the procurement of
8    cost-effective zero emission credits.
9        (3) Cost-effective zero emission credits procured from
10    zero emission resources shall satisfy the applicable
11    definitions set forth in Section 1-10 of this Act.
12        (4) The electric utility shall retire all zero emission
13    credits used to comply with the requirements of this
14    subsection (d-5).
15        (5) Electric utilities shall be entitled to recover all
16    of the costs associated with the procurement of zero
17    emission credits through an automatic adjustment clause
18    tariff in accordance with subsection (k) of Section 16-108
19    of the Public Utilities Act.
20    (e) The draft procurement plans are subject to public
21comment, as required by Section 16-111.5 of the Public
22Utilities Act.
23    (f) The Agency shall submit the final procurement plan to
24the Commission. The Agency shall revise a procurement plan if
25the Commission determines that it does not meet the standards
26set forth in Section 16-111.5 of the Public Utilities Act.

 

 

09900SB1585sam002- 94 -LRB099 09533 EGJ 48253 a

1    (g) The Agency shall assess fees to each affected utility
2to recover the costs incurred in preparation of the annual
3procurement plan for the utility.
4    (h) The Agency shall assess fees to each bidder to recover
5the costs incurred in connection with a competitive procurement
6process.
7    (i) A renewable energy credit, carbon emission credit, or
8zero emission credit can only be used once to comply with a
9single portfolio or other standard as set forth in subsection
10(c), subsection (d), or subsection (d-5) of this Section,
11respectively. A renewable energy credit, carbon emission
12credit, or zero emission credit cannot be used to satisfy the
13requirements of more than one standard. In the event more than
14one type of credit is issued for the same megawatt hour of
15energy, only one credit can be used to satisfy the requirements
16of a single standard. After such use, the credit must be
17retired together with any other credits issued for the same
18megawatt hour of energy.
19(Source: P.A. 97-325, eff. 8-12-11; 97-616, eff. 10-26-11;
2097-618, eff. 10-26-11; 97-658, eff. 1-13-12; 97-813, eff.
217-13-12; 98-463, eff. 8-16-13.)
 
22    Section 10. The Public Utilities Act is amended by changing
23Sections 8-103, 8-104, 16-107, 16-107.5, 16-108, 16-111.5,
2416-111.5B, 16-111.7, 16-115D, and 16-127 and by adding Sections
258-103B, 9-105, 9-107, 16-103.3, 16-107.6, 16-107.7, 16-108.9,

 

 

09900SB1585sam002- 95 -LRB099 09533 EGJ 48253 a

1and 16-108.10 as follows:
 
2    (220 ILCS 5/8-103)
3    Sec. 8-103. Energy efficiency and demand-response
4measures.
5    (a) It is the policy of the State that electric utilities
6are required to use cost-effective energy efficiency and
7demand-response measures to reduce delivery load. Requiring
8investment in cost-effective energy efficiency and
9demand-response measures will reduce direct and indirect costs
10to consumers by decreasing environmental impacts and by
11avoiding or delaying the need for new generation, transmission,
12and distribution infrastructure. It serves the public interest
13to allow electric utilities to recover costs for reasonably and
14prudently incurred expenses for energy efficiency and
15demand-response measures. As used in this Section,
16"cost-effective" means that the measures satisfy the total
17resource cost test. The low-income measures described in
18subsection (f)(4) of this Section shall not be required to meet
19the total resource cost test. For purposes of this Section, the
20terms "energy-efficiency", "demand-response", "electric
21utility", and "total resource cost test" shall have the
22meanings set forth in the Illinois Power Agency Act. For
23purposes of this Section, the amount per kilowatthour means the
24total amount paid for electric service expressed on a per
25kilowatthour basis. For purposes of this Section, the total

 

 

09900SB1585sam002- 96 -LRB099 09533 EGJ 48253 a

1amount paid for electric service includes without limitation
2estimated amounts paid for supply, transmission, distribution,
3surcharges, and add-on-taxes.
4    (a-5) This Section applies to electric utilities serving
53,000,000 or less retail customers in the State. Through
6December 31, 2017, this Section also applies to electric
7utilities serving more than 3,000,000 retail customers in the
8State.
9    (b) Electric utilities shall implement cost-effective
10energy efficiency measures to meet the following incremental
11annual energy savings goals:
12        (1) 0.2% of energy delivered in the year commencing
13    June 1, 2008;
14        (2) 0.4% of energy delivered in the year commencing
15    June 1, 2009;
16        (3) 0.6% of energy delivered in the year commencing
17    June 1, 2010;
18        (4) 0.8% of energy delivered in the year commencing
19    June 1, 2011;
20        (5) 1% of energy delivered in the year commencing June
21    1, 2012;
22        (6) 1.4% of energy delivered in the year commencing
23    June 1, 2013;
24        (7) 1.8% of energy delivered in the year commencing
25    June 1, 2014; and
26        (8) 2% of energy delivered in the year commencing June

 

 

09900SB1585sam002- 97 -LRB099 09533 EGJ 48253 a

1    1, 2015 and each year thereafter.
2    Electric utilities may comply with this subsection (b) by
3meeting the annual incremental savings goal in the applicable
4year or by showing that the total cumulative annual savings
5within a 3-year planning period associated with measures
6implemented after May 31, 2014 was equal to the sum of each
7annual incremental savings requirement from May 31, 2014
8through the end of the applicable year.
9    (c) Electric utilities shall implement cost-effective
10demand-response measures to reduce peak demand by 0.1% over the
11prior year for eligible retail customers, as defined in Section
1216-111.5 of this Act, and for customers that elect hourly
13service from the utility pursuant to Section 16-107 of this
14Act, provided those customers have not been declared
15competitive. This requirement commences June 1, 2008 and
16continues for 10 years.
17    (d) Notwithstanding the requirements of subsections (b)
18and (c) of this Section, an electric utility shall reduce the
19amount of energy efficiency and demand-response measures
20implemented over a 3-year planning period by an amount
21necessary to limit the estimated average annual increase in the
22amounts paid by retail customers in connection with electric
23service due to the cost of those measures to:
24        (1) in 2008, no more than 0.5% of the amount paid per
25    kilowatthour by those customers during the year ending May
26    31, 2007;

 

 

09900SB1585sam002- 98 -LRB099 09533 EGJ 48253 a

1        (2) in 2009, the greater of an additional 0.5% of the
2    amount paid per kilowatthour by those customers during the
3    year ending May 31, 2008 or 1% of the amount paid per
4    kilowatthour by those customers during the year ending May
5    31, 2007;
6        (3) in 2010, the greater of an additional 0.5% of the
7    amount paid per kilowatthour by those customers during the
8    year ending May 31, 2009 or 1.5% of the amount paid per
9    kilowatthour by those customers during the year ending May
10    31, 2007;
11        (4) in 2011, the greater of an additional 0.5% of the
12    amount paid per kilowatthour by those customers during the
13    year ending May 31, 2010 or 2% of the amount paid per
14    kilowatthour by those customers during the year ending May
15    31, 2007; and
16        (5) thereafter, the amount of energy efficiency and
17    demand-response measures implemented for any single year
18    shall be reduced by an amount necessary to limit the
19    estimated average net increase due to the cost of these
20    measures included in the amounts paid by eligible retail
21    customers in connection with electric service to no more
22    than the greater of 2.015% of the amount paid per
23    kilowatthour by those customers during the year ending May
24    31, 2007 or the incremental amount per kilowatthour paid
25    for these measures in 2011.
26    No later than June 30, 2011, the Commission shall review

 

 

09900SB1585sam002- 99 -LRB099 09533 EGJ 48253 a

1the limitation on the amount of energy efficiency and
2demand-response measures implemented pursuant to this Section
3and report to the General Assembly its findings as to whether
4that limitation unduly constrains the procurement of energy
5efficiency and demand-response measures.
6    (e) Electric utilities shall be responsible for overseeing
7the design, development, and filing of energy efficiency and
8demand-response plans with the Commission. Electric utilities
9shall implement 100% of the demand-response measures in the
10plans. Electric utilities shall implement 75% of the energy
11efficiency measures approved by the Commission, and may, as
12part of that implementation, outsource various aspects of
13program development and implementation. The remaining 25% of
14those energy efficiency measures approved by the Commission
15shall be implemented by the Department of Commerce and Economic
16Opportunity, and must be designed in conjunction with the
17utility and the filing process. The Department may outsource
18development and implementation of energy efficiency measures.
19A minimum of 10% of the entire portfolio of cost-effective
20energy efficiency measures shall be procured from units of
21local government, municipal corporations, school districts,
22and community college districts. The Department shall
23coordinate the implementation of these measures.
24    The apportionment of the dollars to cover the costs to
25implement the Department's share of the portfolio of energy
26efficiency measures shall be made to the Department once the

 

 

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1Department has executed rebate agreements, grants, or
2contracts for energy efficiency measures and provided
3supporting documentation for those rebate agreements, grants,
4and contracts to the utility. The Department is authorized to
5adopt any rules necessary and prescribe procedures in order to
6ensure compliance by applicants in carrying out the purposes of
7rebate agreements for energy efficiency measures implemented
8by the Department made under this Section.
9    The details of the measures implemented by the Department
10shall be submitted by the Department to the Commission in
11connection with the utility's filing regarding the energy
12efficiency and demand-response measures that the utility
13implements.
14    A utility providing approved energy efficiency and
15demand-response measures in the State shall be permitted to
16recover costs of those measures through an automatic adjustment
17clause tariff filed with and approved by the Commission. The
18tariff shall be established outside the context of a general
19rate case. Each year the Commission shall initiate a review to
20reconcile any amounts collected with the actual costs and to
21determine the required adjustment to the annual tariff factor
22to match annual expenditures.
23    Each utility shall include, in its recovery of costs, the
24costs estimated for both the utility's and the Department's
25implementation of energy efficiency and demand-response
26measures. Costs collected by the utility for measures

 

 

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1implemented by the Department shall be submitted to the
2Department pursuant to Section 605-323 of the Civil
3Administrative Code of Illinois, shall be deposited into the
4Energy Efficiency Portfolio Standards Fund, and shall be used
5by the Department solely for the purpose of implementing these
6measures. A utility shall not be required to advance any moneys
7to the Department but only to forward such funds as it has
8collected. The Department shall report to the Commission on an
9annual basis regarding the costs actually incurred by the
10Department in the implementation of the measures. Any changes
11to the costs of energy efficiency measures as a result of plan
12modifications shall be appropriately reflected in amounts
13recovered by the utility and turned over to the Department.
14    The portfolio of measures, administered by both the
15utilities and the Department, shall, in combination, be
16designed to achieve the annual savings targets described in
17subsections (b) and (c) of this Section, as modified by
18subsection (d) of this Section.
19    The utility and the Department shall agree upon a
20reasonable portfolio of measures and determine the measurable
21corresponding percentage of the savings goals associated with
22measures implemented by the utility or Department.
23    No utility shall be assessed a penalty under subsection (f)
24of this Section for failure to make a timely filing if that
25failure is the result of a lack of agreement with the
26Department with respect to the allocation of responsibilities

 

 

09900SB1585sam002- 102 -LRB099 09533 EGJ 48253 a

1or related costs or target assignments. In that case, the
2Department and the utility shall file their respective plans
3with the Commission and the Commission shall determine an
4appropriate division of measures and programs that meets the
5requirements of this Section.
6    If the Department is unable to meet incremental annual
7performance goals for the portion of the portfolio implemented
8by the Department, then the utility and the Department shall
9jointly submit a modified filing to the Commission explaining
10the performance shortfall and recommending an appropriate
11course going forward, including any program modifications that
12may be appropriate in light of the evaluations conducted under
13item (7) of subsection (f) of this Section. In this case, the
14utility obligation to collect the Department's costs and turn
15over those funds to the Department under this subsection (e)
16shall continue only if the Commission approves the
17modifications to the plan proposed by the Department.
18    (f) No later than November 15, 2007, each electric utility
19shall file an energy efficiency and demand-response plan with
20the Commission to meet the energy efficiency and
21demand-response standards for 2008 through 2010. No later than
22October 1, 2010, each electric utility shall file an energy
23efficiency and demand-response plan with the Commission to meet
24the energy efficiency and demand-response standards for 2011
25through 2013. Every 3 years thereafter, each electric utility
26shall file, no later than September 1, an energy efficiency and

 

 

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1demand-response plan with the Commission. If a utility does not
2file such a plan by September 1 of an applicable year, it shall
3face a penalty of $100,000 per day until the plan is filed.
4Each utility's plan shall set forth the utility's proposals to
5meet the utility's portion of the energy efficiency standards
6identified in subsection (b) and the demand-response standards
7identified in subsection (c) of this Section as modified by
8subsections (d) and (e), taking into account the unique
9circumstances of the utility's service territory. The
10Commission shall seek public comment on the utility's plan and
11shall issue an order approving or disapproving each plan within
125 months after its submission. If the Commission disapproves a
13plan, the Commission shall, within 30 days, describe in detail
14the reasons for the disapproval and describe a path by which
15the utility may file a revised draft of the plan to address the
16Commission's concerns satisfactorily. If the utility does not
17refile with the Commission within 60 days, the utility shall be
18subject to penalties at a rate of $100,000 per day until the
19plan is filed. This process shall continue, and penalties shall
20accrue, until the utility has successfully filed a portfolio of
21energy efficiency and demand-response measures. Penalties
22shall be deposited into the Energy Efficiency Trust Fund. In
23submitting proposed energy efficiency and demand-response
24plans and funding levels to meet the savings goals adopted by
25this Act the utility shall:
26        (1) Demonstrate that its proposed energy efficiency

 

 

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1    and demand-response measures will achieve the requirements
2    that are identified in subsections (b) and (c) of this
3    Section, as modified by subsections (d) and (e).
4        (2) Present specific proposals to implement new
5    building and appliance standards that have been placed into
6    effect.
7        (3) Present estimates of the total amount paid for
8    electric service expressed on a per kilowatthour basis
9    associated with the proposed portfolio of measures
10    designed to meet the requirements that are identified in
11    subsections (b) and (c) of this Section, as modified by
12    subsections (d) and (e).
13        (4) Coordinate with the Department to present a
14    portfolio of energy efficiency measures proportionate to
15    the share of total annual utility revenues in Illinois from
16    households at or below 150% of the poverty level. The
17    energy efficiency programs shall be targeted to households
18    with incomes at or below 80% of area median income.
19        (5) Demonstrate that its overall portfolio of energy
20    efficiency and demand-response measures, not including
21    programs covered by item (4) of this subsection (f), are
22    cost-effective using the total resource cost test and
23    represent a diverse cross-section of opportunities for
24    customers of all rate classes to participate in the
25    programs.
26        (6) Include a proposed cost-recovery tariff mechanism

 

 

09900SB1585sam002- 105 -LRB099 09533 EGJ 48253 a

1    to fund the proposed energy efficiency and demand-response
2    measures and to ensure the recovery of the prudently and
3    reasonably incurred costs of Commission-approved programs.
4        (7) Provide for an annual independent evaluation of the
5    performance of the cost-effectiveness of the utility's
6    portfolio of measures and the Department's portfolio of
7    measures, as well as a full review of the 3-year results of
8    the broader net program impacts and, to the extent
9    practical, for adjustment of the measures on a
10    going-forward basis as a result of the evaluations. The
11    resources dedicated to evaluation shall not exceed 3% of
12    portfolio resources in any given year.
13    (g) No more than 3% of energy efficiency and
14demand-response program revenue may be allocated for
15demonstration of breakthrough equipment and devices.
16    (h) This Section does not apply to an electric utility that
17on December 31, 2005 provided electric service to fewer than
18100,000 customers in Illinois.
19    (i) If, after 2 years, an electric utility fails to meet
20the efficiency standard specified in subsection (b) of this
21Section, as modified by subsections (d) and (e), it shall make
22a contribution to the Low-Income Home Energy Assistance
23Program. The combined total liability for failure to meet the
24goal shall be $1,000,000, which shall be assessed as follows: a
25large electric utility shall pay $665,000, and a medium
26electric utility shall pay $335,000. If, after 3 years, an

 

 

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1electric utility fails to meet the efficiency standard
2specified in subsection (b) of this Section, as modified by
3subsections (d) and (e), it shall make a contribution to the
4Low-Income Home Energy Assistance Program. The combined total
5liability for failure to meet the goal shall be $1,000,000,
6which shall be assessed as follows: a large electric utility
7shall pay $665,000, and a medium electric utility shall pay
8$335,000. In addition, the responsibility for implementing the
9energy efficiency measures of the utility making the payment
10shall be transferred to the Illinois Power Agency if, after 3
11years, or in any subsequent 3-year period, the utility fails to
12meet the efficiency standard specified in subsection (b) of
13this Section, as modified by subsections (d) and (e). The
14Agency shall implement a competitive procurement program to
15procure resources necessary to meet the standards specified in
16this Section as modified by subsections (d) and (e), with costs
17for those resources to be recovered in the same manner as
18products purchased through the procurement plan as provided in
19Section 16-111.5. The Director shall implement this
20requirement in connection with the procurement plan as provided
21in Section 16-111.5.
22    For purposes of this Section, (i) a "large electric
23utility" is an electric utility that, on December 31, 2005,
24served more than 2,000,000 electric customers in Illinois; (ii)
25a "medium electric utility" is an electric utility that, on
26December 31, 2005, served 2,000,000 or fewer but more than

 

 

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1100,000 electric customers in Illinois; and (iii) Illinois
2electric utilities that are affiliated by virtue of a common
3parent company are considered a single electric utility.
4    (j) If, after 3 years, or any subsequent 3-year period, the
5Department fails to implement the Department's share of energy
6efficiency measures required by the standards in subsection
7(b), then the Illinois Power Agency may assume responsibility
8for and control of the Department's share of the required
9energy efficiency measures. The Agency shall implement a
10competitive procurement program to procure resources necessary
11to meet the standards specified in this Section, with the costs
12of these resources to be recovered in the same manner as
13provided for the Department in this Section.
14    (k) No electric utility shall be deemed to have failed to
15meet the energy efficiency standards to the extent any such
16failure is due to a failure of the Department or the Agency.
17    (l) Electric utilities' 3-year energy efficiency and
18demand-response plans approved by the Commission on or before
19the effective date of this amendatory Act of the 99th General
20Assembly for the period June 1, 2014 through May 31, 2017 shall
21continue to be in force and effect through December 31, 2017 so
22that the energy efficiency programs set forth in those plans
23continue to be offered during the period June 1, 2017 through
24December 31, 2017. Each utility is authorized to increase, on a
25pro rata basis, the energy savings goals and budgets approved
26in its plan to reflect the additional 7 months of the plan's

 

 

09900SB1585sam002- 108 -LRB099 09533 EGJ 48253 a

1operation.
2(Source: P.A. 97-616, eff. 10-26-11; 97-841, eff. 7-20-12;
398-90, eff. 7-15-13.)
 
4    (220 ILCS 5/8-103B new)
5    Sec. 8-103B. Energy efficiency and demand-response
6measures.
7    (a) It is the policy of the State that electric utilities
8are required to use cost-effective energy efficiency and
9demand-response measures to reduce delivery load. Requiring
10investment in cost-effective energy efficiency and
11demand-response measures will reduce direct and indirect costs
12to consumers by decreasing environmental impacts and by
13avoiding or delaying the need for new generation, transmission,
14and distribution infrastructure. It serves the public interest
15to allow electric utilities to recover costs for reasonably and
16prudently incurred expenses for energy efficiency and
17demand-response measures. As used in this Section,
18"cost-effective" means that the measures satisfy the total
19resource cost test. The low-income measures described in
20subsection (c) of this Section shall not be required to meet
21the total resource cost test. For purposes of this Section, the
22terms "energy-efficiency", "demand-response", "electric
23utility", and "total resource cost test" have the meanings set
24forth in the Illinois Power Agency Act. For purposes of this
25Section, the amount per kilowatthour means the total amount

 

 

09900SB1585sam002- 109 -LRB099 09533 EGJ 48253 a

1paid for electric service expressed on a per kilowatthour
2basis. For purposes of this Section, the total amount paid for
3electric service includes, without limitation, estimated
4amounts paid for supply, transmission, distribution,
5surcharges, and add-on taxes.
6    (a-5) After December 31, 2017, this Section applies to
7electric utilities serving more than 3,000,000 retail
8customers in the State.
9    (b) For purposes of this Section, electric utilities
10subject to this Section shall be deemed to have achieved a
11cumulative persisting annual savings of 6.6%, or 5,777,692
12megawatt-hours (MWhs), for the year ending December 31, 2017,
13which is based on the deemed average weather normalized sales
14of electric power and energy during calendar years 2014, 2015,
15and 2016 of 88,000,000 MWhs. The 88,000,000 MWhs of deemed
16electric power and energy sales shall also serve as the
17baseline value for calculating the cumulative persisting
18annual savings in subsection (b-5). After 2017, the deemed
19value of cumulative persisting annual savings shall be reduced
20each year, as follows, and the applicable value shall be
21applied to and count toward the utility's achievement of the
22cumulative persisting annual savings goals set forth in
23subsection (b-5):
24        (1) 5.8%, or 5,071,018 MWhs, deemed cumulative
25    persisting annual savings for the year ending December 31,
26    2018;

 

 

09900SB1585sam002- 110 -LRB099 09533 EGJ 48253 a

1        (2) 5.2%, or 4,553,371 MWhs, deemed cumulative
2    persisting annual savings for the year ending December 31,
3    2019;
4        (3) 4.5%, or 3,998.012 MWhs, deemed cumulative
5    persisting annual savings for the year ending December 31,
6    2020;
7        (4) 4%, or 3,533,219 MWhs, deemed cumulative
8    persisting annual savings for the year ending December 31,
9    2021;
10        (5) 3.5%, or 3,108,290 MWhs, deemed cumulative
11    persisting annual savings for the year ending December 31,
12    2022;
13        (6) 3.1%, or 2,738,689 MWhs, deemed cumulative
14    persisting annual savings for the year ending December 31,
15    2023;
16        (7) 2.8%, or 2,463,055 MWhs, deemed cumulative
17    persisting annual savings for the year ending December 31,
18    2024;
19        (8) 2.5%, or 2,221,716 MWhs, deemed cumulative
20    persisting annual savings for the year ending December 31,
21    2025;
22        (9) 2.3%, or 2,017,109 MWhs, deemed cumulative
23    persisting annual savings for the year ending December 31,
24    2026;
25        (10) 2.1%, or 1,822,754 MWhs, deemed cumulative
26    persisting annual savings for the year ending December 31,

 

 

09900SB1585sam002- 111 -LRB099 09533 EGJ 48253 a

1    2027;
2        (11) 1.8%, or 1,624,769 MWhs, deemed cumulative
3    persisting annual savings for the year ending December 31,
4    2028;
5        (12) 1.7%, or 1,460,039 MWhs, deemed cumulative
6    persisting annual savings for the year ending December 31,
7    2029; and
8        (13) 1.5%, or 1,181,647 MWhs, deemed cumulative
9    persisting annual savings for the year ending December 31,
10    2030.
11    For purposes of this Section, "cumulative persisting
12annual savings" means the total electric energy savings in a
13given year from measures installed in that year or in previous
14years that are still operational and providing savings in that
15year because the measures have not yet reached the end of their
16useful lives.
17    (b-5) Beginning in 2018, electric utilities shall achieve
18the following cumulative persisting annual savings goals, as
19modified by subsection (f) of this Section and as compared to
20the deemed baseline of 88,000,000 MWhs of electric power and
21energy sales set forth in subsection (b), through the
22implementation of cost-effective energy efficiency measures
23during the applicable year and in prior years by the utility
24and, if applicable, the Department:
25        (1) 8% cumulative persisting annual savings for the
26    year ending December 31, 2018;

 

 

09900SB1585sam002- 112 -LRB099 09533 EGJ 48253 a

1        (2) 9.5% cumulative persisting annual savings for the
2    year ending December 31, 2019;
3        (3) 11% cumulative persisting annual savings for the
4    year ending December 31, 2020;
5        (4) 12.5% cumulative persisting annual savings for the
6    year ending December 31, 2021;
7        (5) 14% cumulative persisting annual savings for the
8    year ending December 31, 2022;
9        (6) 15.5% cumulative persisting annual savings for the
10    year ending December 31, 2023;
11        (7) 17% cumulative persisting annual savings for the
12    year ending December 31, 2024;
13        (8) 18.5% cumulative persisting annual savings for the
14    year ending December 31, 2025;
15        (9) 19.4% cumulative persisting annual savings for the
16    year ending December 31, 2026;
17        (10) 20.3% cumulative persisting annual savings for
18    the year ending December 31, 2027;
19        (11) 21.2% cumulative persisting annual savings for
20    the year ending December 31, 2028;
21        (12) 22.1% cumulative persisting annual savings for
22    the year ending December 31, 2029; and
23        (13) 23% cumulative persisting annual savings for the
24    year ending December 31, 2030.
25    (b-10) Each electric utility that serves more than
263,000,000 retail customers in the State shall include

 

 

09900SB1585sam002- 113 -LRB099 09533 EGJ 48253 a

1cost-effective voltage optimization measures in its plans
2submitted pursuant to subsection (f) or (g) of this Section,
3and the costs incurred by a utility to implement the measures
4pursuant to a Commission-approved plan shall be recovered, at
5the utility's election, either through the automatic
6adjustment clause tariff approved under subsection (d) of this
7Section, an energy efficiency formula rate tariff approved
8under subsection (d) of this Section, or pursuant to the
9provisions of Article IX or Section 16-108.5 of this Act. For
10purposes of this Section, the measure life of voltage
11optimization measures shall be 15 years. The measure life
12period is independent of the depreciation rate of the voltage
13optimization assets deployed.
14    In the event an electric utility jointly offers an energy
15efficiency measure or program with a gas utility pursuant to
16plans approved under this Section and Section 8-104 of this
17Act, the electric utility may continue offering the program,
18including the gas energy efficiency measures, in the event the
19gas utility discontinues funding the program. In that event, up
20to 30% of the annual savings goal calculated pursuant to
21subsection (b) of this Section may be met through savings of
22fuels other than electricity, and the energy savings value
23associated with such other fuels shall be converted to electric
24energy savings on an equivalent Btu basis for the premises.
25However, the utility shall prioritize gas savings for
26low-income residential customers to the extent practicable. An

 

 

09900SB1585sam002- 114 -LRB099 09533 EGJ 48253 a

1electric utility may recover the costs of offering the gas
2energy efficiency measures pursuant to this subsection (b-10).
3    For those energy efficiency measures or programs that are
4not jointly offered with a gas utility pursuant to plans
5approved under this Section and Section 8-104, the electric
6utility may count savings of fuels other than electricity
7toward the achievement of its annual savings goal, and the
8energy savings value associated with such other fuels shall be
9converted to electric energy savings on an equivalent Btu basis
10at the premises.
11    (c) Electric utilities shall be responsible for overseeing
12the design, development, and filing of energy efficiency plans
13with the Commission and may, as part of that implementation,
14outsource various aspects of program development and
15implementation. A minimum of 10% of the entire portfolio budget
16for a given year shall be used to procure cost-effective energy
17efficiency measures from units of local government, municipal
18corporations, school districts, public housing, and community
19college districts, provided that a minimum percentage of
20available funds shall be used to procure energy efficiency from
21public housing, which percentage shall be equal to public
22housing's share of public building energy consumption.
23    The utilities shall also implement energy efficiency
24measures targeted at low-income households, which, for
25purposes of this Section, shall be defined as households at or
26below 80% of area median income, and expenditures to implement

 

 

09900SB1585sam002- 115 -LRB099 09533 EGJ 48253 a

1the measures shall be no less than $50,000,000 per year. For
2the multi-year plan commencing on January 1, 2018, the energy
3savings attributable to such programs shall not be less than
429,239,766 kilowatt-hours per year for the years commencing
5January 1, 2018 and January 1, 2019. For every 2-year period
6thereafter, the utility shall submit an informational filing to
7the Commission 90 days prior to the beginning of the 2-year
8period that calculates the (i) cost per kilowatt-hour of energy
9savings to be achieved and (ii) the resulting annual energy
10savings to be achieved each year, under the low-income programs
11during the applicable 2-year period.
12    Each electric utility shall assess opportunities to
13implement cost-effective energy efficiency measures and
14programs through a public housing authority or authorities
15located in its service territory. If such opportunities are
16identified, the utility shall propose such measures and
17programs to address the opportunities. Expenditures to address
18such opportunities shall be credited toward the minimum
19procurement and expenditure requirements set forth in this
20subsection (c).
21    Implementation of energy efficiency measures and programs
22targeted at low-income households should be contracted, when it
23is practicable, to independent third parties that have
24demonstrated capabilities to serve such households, with a
25preference for not-for-profit entities and government agencies
26that have existing relationships with or experience serving

 

 

09900SB1585sam002- 116 -LRB099 09533 EGJ 48253 a

1low-income communities in the State.
2    Each electric utility shall develop and implement
3reporting procedures that address and assist in determining the
4amount of energy savings that can be applied to the low-income
5procurement and expenditure requirements set forth in this
6subsection (c).
7    The electric utilities shall also convene a low-income
8energy efficiency advisory committee to assist in the design
9and evaluation of the low-income energy efficiency programs.
10The committee shall be comprised of the electric utilities
11subject to the requirements of this Section, the gas utilities
12subject to the requirements of Section 8-104 of this Act, the
13utilities' low-income energy efficiency implementation
14contractors, and representatives of community-based
15organizations.
16    (d) A utility providing approved energy efficiency
17measures and, if applicable, demand-response measures in the
18State shall be permitted to recover costs of those measures as
19follows:
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 amounts
25    collected with the actual costs and to determine the
26    required adjustment to the annual tariff factor to match

 

 

09900SB1585sam002- 117 -LRB099 09533 EGJ 48253 a

1    annual expenditures.
2        (2) A utility may recover its costs through an energy
3    efficiency formula rate approved by the Commission
4    pursuant to a filing under subsection (f) or (g) of this
5    Section, which shall specify the cost components that form
6    the basis of the rate charged to customers with sufficient
7    specificity to operate in a standardized manner and be
8    updated annually with transparent information that
9    reflects the utility's actual costs to be recovered during
10    the applicable rate year, which is the period beginning
11    with the first billing day of January and extending through
12    the last billing day of the following December. The energy
13    efficiency formula rate shall be implemented through a
14    tariff filed with the Commission under subsection (f) or
15    (g) of this Section that is consistent with the provisions
16    of this paragraph (2) and that shall be applicable to all
17    delivery services customers. The Commission shall conduct
18    an investigation of the tariff in a manner consistent with
19    the provisions of this paragraph (2), subsection (f) or (g)
20    of this Section, and the provisions of Article IX of this
21    Act to the extent they do not conflict with this paragraph
22    (2). The energy efficiency formula rate approved by the
23    Commission shall remain in effect at the discretion of the
24    utility and shall do the following:
25            (A) Provide for the recovery of the utility's
26        actual costs incurred under this Section that are

 

 

09900SB1585sam002- 118 -LRB099 09533 EGJ 48253 a

1        prudently incurred and reasonable in amount consistent
2        with Commission practice and law. The sole fact that a
3        cost differs from that incurred in a prior calendar
4        year or that an investment is different from that made
5        in a prior calendar year shall not imply the imprudence
6        or unreasonableness of that cost or investment.
7            (B) Reflect the utility's actual year-end capital
8        structure for the applicable calendar year, excluding
9        goodwill, subject to a determination of prudence and
10        reasonableness consistent with Commission practice and
11        law.
12            (C) Include a cost of equity, which shall be
13        calculated as the sum of the following:
14                (i) the average for the applicable calendar
15            year of the monthly average yields of 30-year U.S.
16            Treasury bonds published by the Board of Governors
17            of the Federal Reserve System in its weekly H.15
18            Statistical Release or successor publication; and
19                (ii) 580 basis points.
20            At such time as the Board of Governors of the
21        Federal Reserve System ceases to include the monthly
22        average yields of 30-year U.S. Treasury bonds in its
23        weekly H.15 Statistical Release or successor
24        publication, the monthly average yields of the U.S.
25        Treasury bonds then having the longest duration
26        published by the Board of Governors in its weekly H.15

 

 

09900SB1585sam002- 119 -LRB099 09533 EGJ 48253 a

1        Statistical Release or successor publication shall
2        instead be used for purposes of this paragraph (2).
3            (D) Permit and set forth protocols, subject to a
4        determination of prudence and reasonableness
5        consistent with Commission practice and law, for the
6        following:
7                (i) recovery of incentive compensation expense
8            that is based on the achievement of operational
9            metrics, including metrics related to budget
10            controls, outage duration and frequency, safety,
11            customer service, efficiency and productivity, and
12            environmental compliance; however, this protocol
13            shall not apply if such expense related to costs
14            incurred under this Section is recovered under
15            Article IX or Section 16-108.5 of this Act;
16            incentive compensation expense that is based on
17            net income or an affiliate's earnings per share
18            shall not be recoverable under the energy
19            efficiency formula rate;
20                (ii) recovery of pension and other
21            post-employment benefits expense, provided that
22            such costs are supported by an actuarial study;
23            however, this protocol shall not apply if such
24            expense related to costs incurred under this
25            Section is recovered under Article IX or Section
26            16-108.5 of this Act;

 

 

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1                (iii) recovery of existing regulatory assets
2            over the periods previously authorized by the
3            Commission;
4                (iv) as described in subsection (e),
5            amortization of costs incurred under this Section;
6            and
7                (v) projected, weather normalized billing
8            determinants for the applicable rate year.
9            (E) Provide for an annual reconciliation, as
10        described in paragraph (3) of this subsection (d), less
11        any deferred taxes related to the reconciliation, with
12        interest at an annual rate of return equal to the
13        utility's weighted average cost of capital, including
14        a revenue conversion factor calculated to recover or
15        refund all additional income taxes that may be payable
16        or receivable as a result of that return, of the energy
17        efficiency revenue requirement reflected in rates for
18        each calendar year, beginning with the calendar year in
19        which the utility files its energy efficiency formula
20        rate tariff pursuant to this paragraph (2), with what
21        the revenue requirement would have been had the actual
22        cost information for the applicable calendar year been
23        available at the filing date.
24        The utility shall file, together with its tariff, the
25    projected costs to be incurred by the utility during the
26    rate year pursuant the utility's multi-year plan approved

 

 

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1    under subsection (f) or (g) of this Section, including, but
2    not limited to, the projected capital investment costs and
3    projected regulatory asset balances with correspondingly
4    updated depreciation and amortization reserves and
5    expense, that shall populate the energy efficiency formula
6    rate and set the initial rates under the formula.
7        The Commission shall review the proposed tariff in
8    conjunction with its review of a proposed multi-year plan,
9    as specified in paragraph (5) of subsection (g) of this
10    Section. The review shall be based on the same evidentiary
11    standards, including, but not limited to, those concerning
12    the prudence and reasonableness of the costs incurred by
13    the utility, the Commission applies in a hearing to review
14    a filing for a general increase in rates under Article IX
15    of this Act. The initial rates shall take effect beginning
16    with the January monthly billing period following the
17    Commission's approval.
18        Rate design and cost allocation across customer
19    classes shall be consistent with the utility's automatic
20    adjustment clause tariff in effect on the effective date of
21    this amendatory Act of the 99th General Assembly.
22        In the event the energy efficiency formula rate is
23    terminated, the then current rates shall remain in effect
24    until such time as the energy efficiency costs are
25    incorporated into new rates that are set pursuant to this
26    subsection (d) or Article IX of this Act, subject to

 

 

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

 

 

09900SB1585sam002- 123 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 124 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 125 -LRB099 09533 EGJ 48253 a

1        whether the Commission enters upon a hearing pursuant
2        to this paragraph (3).
3            (C) The filing shall include relevant and
4        necessary data and documentation for the applicable
5        rate year. Normalization adjustments shall not be
6        required.
7        Within 45 days after the utility files its annual
8    update of cost inputs to the energy efficiency formula
9    rate, the Commission shall have the authority, either upon
10    complaint or its own initiative, but with reasonable
11    notice, to enter upon a hearing concerning whether the
12    projected costs to be incurred by the utility and recovered
13    during the applicable rate year, and that are reflected in
14    the inputs to the energy efficiency formula rate, are
15    consistent with the utility's approved multi-year plan
16    under subsection (f) or (g) of this Section and whether the
17    costs incurred by the utility during the prior rate year
18    were prudent and reasonable. During the course of the
19    hearing, each objection shall be stated with particularity
20    and evidence provided in support thereof, after which the
21    utility shall have the opportunity to rebut the evidence.
22    Discovery shall be allowed consistent with the
23    Commission's Rules of Practice, which Rules of Practice
24    shall be enforced by the Commission or the assigned hearing
25    examiner. The Commission shall apply the same evidentiary
26    standards, including, but not limited to, those concerning

 

 

09900SB1585sam002- 126 -LRB099 09533 EGJ 48253 a

1    the prudence and reasonableness of the costs incurred by
2    the utility, in the hearing as it would apply in a hearing
3    to review a filing for a general increase in rates under
4    Article IX of this Act. The Commission shall not, however,
5    have the authority in a proceeding under this paragraph (3)
6    to consider or order any changes to the structure or
7    protocols of the energy efficiency formula rate approved
8    pursuant to paragraph (2) of this subsection (d). In a
9    proceeding under this paragraph (3), the Commission shall
10    enter its order no later than the earlier of 195 days after
11    the utility's filing of its annual update of cost inputs to
12    the energy efficiency formula rate or December 15. The
13    Commission's determinations of the prudence and
14    reasonableness of the costs incurred for the applicable
15    calendar year shall be final upon entry of the Commission's
16    order and shall not be subject to reopening, reexamination,
17    or collateral attack in any other Commission proceeding,
18    case, docket, order, rule, or regulation; however, nothing
19    in this paragraph (3) shall prohibit a party from
20    petitioning the Commission to rehear or appeal to the
21    courts the order pursuant to the provisions of this Act.
22        In the event the Commission does not, either upon
23    complaint or its own initiative, enter upon a hearing
24    within 45 days after the utility files the annual update of
25    cost inputs to its energy efficiency formula rate, then the
26    costs incurred for the applicable calendar year shall be

 

 

09900SB1585sam002- 127 -LRB099 09533 EGJ 48253 a

1    deemed prudent and reasonable and the filed charges shall
2    not be subject to reopening, reexamination, or collateral
3    attack in any other proceeding, case, docket, order, rule,
4    or regulation.
5    (e) Beginning on the effective date of this amendatory Act
6of the 99th General Assembly, a utility subject to the
7requirements of this Section may elect to defer the full amount
8of its expenses incurred pursuant to this Section for each
9annual period as a regulatory asset. The total expenses
10deferred as a regulatory asset in a given year shall be
11amortized and recovered over a period that is equal to the
12weighted average of the energy efficiency measure lives
13implemented for that year that are reflected in the regulatory
14asset. The unamortized balance shall be recognized as of
15December 31 for a given year. The utility shall also earn a
16return on the total of the unamortized balances of all of the
17energy efficiency regulatory assets, less any deferred taxes
18related to those unamortized balances, at an annual rate equal
19to the utility's weighted average cost of capital that
20includes, based on a year-end capital structure, the utility's
21actual cost of debt for the applicable calendar year and a cost
22of equity, which shall be calculated as the sum of the (i) the
23average for the applicable calendar year of the monthly average
24yields of 30-year U.S. Treasury bonds published by the Board of
25Governors of the Federal Reserve System in its weekly H.15
26Statistical Release or successor publication; and (ii) 580

 

 

09900SB1585sam002- 128 -LRB099 09533 EGJ 48253 a

1basis points, including a revenue conversion factor calculated
2to recover or refund all additional income taxes that may be
3payable or receivable as a result of that return. Capital
4investment costs, including, but not limited to, capital
5investment costs associated with voltage optimization measures
6that are described in subsection (b) of this Section, shall be
7depreciated and recovered over their useful lives consistent
8with generally accepted accounting principles. The weighted
9average cost of capital shall be applied to the capital
10investment cost balance, less any accumulated depreciation and
11accumulated deferred income taxes, as of December 31 for a
12given year.
13    When an electric utility creates a regulatory asset
14pursuant to the provisions of this Section, the costs are
15recovered over a period during which customers also receive a
16benefit which is in the public interest. Accordingly, it is the
17intent of the General Assembly that an electric utility that
18elects to create a regulatory asset pursuant to the provisions
19of this Section shall recover all of the associated costs as
20set forth in this Section. After the Commission has approved
21the prudence and reasonableness of the costs that comprise the
22regulatory asset, the electric utility shall be permitted to
23recover all such costs, and the value and recoverability
24through rates of the associated regulatory asset shall not be
25limited, altered, impaired, or reduced.
26    (f) Beginning in 2017, each electric utility shall file an

 

 

09900SB1585sam002- 129 -LRB099 09533 EGJ 48253 a

1energy efficiency plan with the Commission to meet the energy
2efficiency standards for the next applicable multi-year period
3beginning January 1 of the year following the filing, according
4to the following schedule:
5        (1) No later than 30 days after the effective date of
6    this amendatory Act of the 99th General Assembly or May 1,
7    2017, whichever is later, each electric utility shall file
8    a 4-year energy efficiency plan commencing on January 1,
9    2018 that is designed to achieve the cumulative persisting
10    annual savings goals specified in paragraphs (1) through
11    (4) of subsection (b-5) of this Section through
12    implementation of energy efficiency measures; however, the
13    goals shall be reduced if the plan demonstrates that
14    achievement of such goals is not cost effective.
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 through
20    implementation of energy efficiency measures; however, the
21    goals shall be reduced if the plan demonstrates that
22    achievement of such goals is not cost effective.
23        (3) No later than March 1, 2025, each electric utility
24    shall file a 5-year energy efficiency plan commencing on
25    January 1, 2026 that is designed to achieve the cumulative
26    persisting annual savings goals specified in paragraphs

 

 

09900SB1585sam002- 130 -LRB099 09533 EGJ 48253 a

1    (9) through (13) of subsection (b-5) of this Section
2    through implementation of energy efficiency measures;
3    however, the goals shall be reduced if the plan
4    demonstrates that achievement of such goals is not cost
5    effective.
6    If a utility does not file such a plan on or before the
7applicable filing deadline for the plan, it shall face a
8penalty of $100,000 per day until the plan is filed.
9    Each utility's plan shall set forth the utility's proposals
10to meet the utility's portion of the energy efficiency
11standards identified in subsection (b), as modified by
12subsections (d) and (e) of this Section, if applicable, taking
13into account the unique circumstances of the utility's service
14territory. For those plans commencing on January 1, 2018, the
15Commission shall seek public comment on the utility's plan and
16shall issue an order approving or disapproving each plan no
17later than August 31, 2017. For those plans commencing after
18December 31, 2021, the Commission shall seek public comment on
19the utility's plan and shall issue an order approving or
20disapproving each plan within 6 months after its submission. If
21the Commission disapproves a plan, the Commission shall, within
2230 days, describe in detail the reasons for the disapproval and
23describe a path by which the utility may file a revised draft
24of the plan to address the Commission's concerns
25satisfactorily. If the utility does not refile with the
26Commission within 60 days, the utility shall be subject to

 

 

09900SB1585sam002- 131 -LRB099 09533 EGJ 48253 a

1penalties at a rate of $100,000 per day until the plan is
2filed. This process shall continue, and penalties shall accrue,
3until the utility has successfully filed a portfolio of energy
4efficiency and demand-response measures. Penalties shall be
5deposited into the Energy Efficiency Trust Fund.
6    (g) In submitting proposed plans and funding levels to meet
7the savings goals adopted by this Act the utility shall:
8        (1) Demonstrate that its proposed energy efficiency
9    measures and, if applicable, demand-response measures will
10    achieve the requirements that are identified in
11    subsections (b) and (c) of this Section, as modified by
12    subsections (d) and (e), if applicable.
13        (2) Present specific proposals to implement new
14    building and appliance standards that have been placed into
15    effect.
16        (3) Demonstrate that its overall portfolio of
17    measures, not including low-income programs described in
18    subsection (c) of this Section, is cost-effective using the
19    total resource cost test and represent a diverse
20    cross-section of opportunities for customers of all rate
21    classes to participate in the programs. Consistent with
22    existing law, individual measures need not be cost
23    effective, and the design of the portfolio, including its
24    individual programs and measures, shall be subject to
25    practical implementation considerations and limitations.
26        (4) Present a third-party energy efficiency

 

 

09900SB1585sam002- 132 -LRB099 09533 EGJ 48253 a

1    implementation program subject to the following
2    requirements:
3            (A) beginning with the year commencing January 1,
4        2019, the utility shall fund third-party energy
5        efficiency programs in an amount that is no less than
6        $50,000,000 per year;
7            (B) during 2018, the utility shall conduct a
8        solicitation process for purposes of requesting
9        proposals from third-party vendors for those
10        third-party energy efficiency programs to be offered
11        during one or more of the years commencing January 1,
12        2019, January 1, 2020, and January 1, 2021; for those
13        multi-year plans commencing on January 1, 2022 and
14        January 1, 2026, the utility shall conduct a
15        solicitation process during 2021 and 2025,
16        respectively, for purposes of requesting proposals
17        from third-party vendors for those third-party energy
18        efficiency programs to be offered during one or more
19        years of the respective multi-year plan period; for
20        each solicitation process, the utility shall identify
21        the sector, technology, or geographical area for which
22        it is seeking requests for proposals;
23            (C) the utility shall propose the bidder
24        qualifications, performance measurement process, and
25        contract structure, which must include a performance
26        payment mechanism and general terms and conditions;

 

 

09900SB1585sam002- 133 -LRB099 09533 EGJ 48253 a

1        the proposed qualifications, process, and structure
2        shall be subject to Commission approval;
3            (D) the utility shall retain an independent third
4        party to score the proposals received through the
5        solicitation process described in this paragraph (4),
6        rank them according to their cost per lifetime
7        kilowatt-hours saved, and assemble the portfolio of
8        third-party programs;
9            (E) for purposes of determining under paragraph
10        (7) of this subsection (g) the amount of cumulative
11        persisting annual savings achieved by the utility, the
12        programs implemented by third parties pursuant to this
13        paragraph (4) shall be deemed to have achieved 80% of
14        their projected savings regardless of the savings
15        determined by the independent evaluator; if the
16        independent evaluator determines that one or more
17        programs achieved more than 80% of their projected
18        savings, such incremental amount shall be credited to
19        the utility's overall energy savings for the
20        applicable year; and
21            (F) in the event a third-party vendor fails to
22        achieve 2 consecutive quarterly performance targets,
23        the utility shall have the right to cancel the contract
24        and reallocate the funds to other third-party programs
25        or programs administered by the utility.
26        The electric utility shall recover all costs

 

 

09900SB1585sam002- 134 -LRB099 09533 EGJ 48253 a

1    associated with Commission-approved, third-party
2    administered programs regardless of the success of those
3    programs, which is a restatement and clarification of
4    existing law by this amendatory Act of the 99th General
5    Assembly.
6        (5) Include a proposed or revised cost-recovery tariff
7    mechanism, as provided for under subsection (d) of this
8    Section, to fund the proposed energy efficiency and
9    demand-response measures and to ensure the recovery of the
10    prudently and reasonably incurred costs of
11    Commission-approved programs.
12        (6) Provide for an annual independent evaluation of the
13    performance of the cost-effectiveness of the utility's
14    portfolio of measures, as well as a full review of the
15    multi-year plan results of the broader net program impacts
16    and, to the extent practical, for adjustment of the
17    measures on a going-forward basis as a result of the
18    evaluations. The resources dedicated to evaluation shall
19    not exceed 3% of portfolio resources in any given year.
20        (7) Through December 31, 2030, provide for an
21    adjustment to the return on equity component of the
22    utility's weighted average cost of capital calculated
23    pursuant to subsection (d) of this Section:
24            (A) If the independent evaluator determines that
25        the utility achieved a cumulative persisting annual
26        savings that is less than the applicable annual

 

 

09900SB1585sam002- 135 -LRB099 09533 EGJ 48253 a

1        incremental goal set forth in subsection (b) of this
2        Section, then the return on equity component shall be
3        reduced by a maximum of 200 basis points in the event
4        that the utility achieved no more than 75% of such
5        goal. If the utility achieved more than 75% of the
6        applicable annual incremental goal but less than 100%
7        of such goal, then the return on equity component shall
8        be reduced by 8 basis points for each percent by which
9        the utility failed to achieve the goal.
10            (B) If the independent evaluator determines that
11        the utility achieved a cumulative persisting annual
12        savings that is more than the applicable annual
13        incremental goal set forth in subsection (b) of this
14        Section, then the return on equity component shall be
15        increased by a maximum of 200 basis points in the event
16        that the utility achieved at least 125% of such goal.
17        If the utility achieved more than 100% of the
18        applicable annual incremental goal but less than 125%
19        of such goal, then the return on equity component shall
20        be increased by 8 basis points for each percent by
21        which the utility achieved above the goal.
22        In the event that third-party implementation under
23    paragraph (4) of this subsection (g) or the low-income
24    energy efficiency programs under subsection (c) of this
25    Section fail to perform as anticipated, the utility's
26    annual goal shall be adjusted downward in proportion to the

 

 

09900SB1585sam002- 136 -LRB099 09533 EGJ 48253 a

1    failure to perform. The utility shall provide a methodology
2    to adjust the annual goal in the event of such a failure to
3    perform.
4        For purposes of this Section, the term "applicable
5    annual incremental goal" means the difference between the
6    cumulative persisting annual savings goal for the calendar
7    year that is the subject of the independent evaluator's
8    determination and the cumulative persisting annual savings
9    goal for the immediately preceding calendar year, as such
10    goals are defined in subsection (b-5) of this Section and
11    as such goals may have been modified as provided for under
12    paragraphs (1) through (3) of subsection (f) and to account
13    for any adjustments resulting from the methodology
14    approved under this paragraph (7) to address performance
15    failure related to low-income and third-party administered
16    energy efficiency programs.
17        The utility shall submit the energy savings data to the
18    independent evaluator no later than 30 days after the close
19    of the plan year. The independent evaluator shall determine
20    the cumulative persisting annual savings for a given plan
21    year no later than 120 days after the close of the plan
22    year. The utility shall submit an informational filing to
23    the Commission no later than 160 days after the close of
24    the plan year that attaches the independent evaluator's
25    final report identifying the cumulative persisting annual
26    savings for the year and calculates any resulting change to

 

 

09900SB1585sam002- 137 -LRB099 09533 EGJ 48253 a

1    the utility's return on equity component of the weighted
2    average cost of capital applicable to the next plan year
3    beginning with the January monthly billing period and
4    extending through the December monthly billing period.
5    Following the utility's submittal of its informational
6    filing for a given year, the Commission may, on its own
7    motion or by petition, initiate an investigation of such
8    filing, provided, however, that the utility's proposed
9    return on equity calculation shall be deemed the final,
10    approved calculation on December 15 of the year in which it
11    is filed unless the Commission enters an order on or before
12    December 15, after notice and hearing, that modifies such
13    calculation consistent with this Section.
14        The adjustments to the return on equity component
15    described in this paragraph (7) shall be applied as
16    described in this paragraph through a separate tariff
17    mechanism, which shall be filed by the utility under
18    subsection (f) or (g) of this Section.
19    (h) No more than 6% of energy efficiency and
20demand-response program revenue may be allocated for research,
21development, or pilot deployment of new equipment or measures.
22    (i) When practicable, electric utilities shall incorporate
23advanced metering infrastructure data into the planning,
24implementation, and evaluation of energy efficiency measures
25and programs.
26    (j) Consistent with existing law, the independent

 

 

09900SB1585sam002- 138 -LRB099 09533 EGJ 48253 a

1evaluator shall follow the guidelines and use the savings set
2forth in Commission-approved energy efficiency policy manuals
3and technical reference manuals, as each may be updated from
4time to time. Until such time as values for the following
5measures are incorporated into such Commission-approved
6manuals, the following measure life values shall apply:
7        (1) With respect to operational energy efficiency
8    measures:
9            (A) a 5-year measure life value shall be used for
10        energy savings resulting from operational energy
11        efficiency measures that are implemented and
12        validated; and
13            (B) a 10-year measure life value shall be used for
14        energy savings resulting from operational energy
15        efficiency measures that are implemented, validated,
16        and persisting, as confirmed through a
17        monitoring-based or hardwired feedback mechanism.
18        For purposes of this Section, operational energy
19    efficiency measures are those measures that adjust or
20    optimize operational set points and hours of operation of
21    energy using systems.
22        (2) A 20-year measure life value shall be used for
23    energy savings resulting from light emitting diode
24    streetlights.
25        (3) A 25-year measure life value shall be used for
26    energy savings resulting from energy efficiency measures

 

 

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1    implemented in integrated whole-building new construction.
2    (k) Notwithstanding any provision of law to the contrary, a
310-year measure life value shall be used for energy savings
4resulting from energy efficiency measures implemented for
5low-income households under subsection (c) of this Section.
6    (l) Notwithstanding any provision of law to the contrary,
7an electric utility subject to the requirements of this Section
8may file a tariff cancelling an automatic adjustment clause
9tariff in effect under this Section or Section 8-103, which
10shall take effect no later than one business day after the date
11such tariff is filed. Thereafter, the utility shall be
12authorized to defer and recover its expenses incurred under
13this Section through a new tariff authorized under subsection
14(d) of this Section or in the utility's next rate case under
15Article IX or Section 16-108.5 of this Act, with interest at an
16annual rate equal to the utility's weighted average cost of
17capital as approved by the Commission in such case. If the
18utility elects to file a new tariff under subsection (d) of
19this Section, the utility may file the tariff within 10 days
20after the effective date of this amendatory Act of the 99th
21General Assembly, and the cost inputs to such tariff shall be
22based on the projected costs to be incurred by the utility
23during the calendar year in which the new tariff is filed and
24that were not recovered under the tariff that was cancelled as
25provided for in this paragraph. Such costs shall include those
26incurred or to be incurred by the utility under its multi-year

 

 

09900SB1585sam002- 140 -LRB099 09533 EGJ 48253 a

1plan approved under subsection (f) or (g) of this Section,
2including, but not limited to, projected capital investment
3costs and projected regulatory asset balances with
4correspondingly updated depreciation and amortization reserves
5and expense. The Commission shall, after notice and hearing,
6approve, or approve with modification, such tariff and cost
7inputs no later than 75 days after the utility filed the
8tariff, provided that such approval, or approval with
9modification, shall be consistent with the provisions of this
10Section to the extent they do not conflict with this subsection
11(l). The tariff approved by the Commission shall take effect no
12later than 5 days after the Commission enters its order
13approving the tariff.
14    No later than 60 days after the effective date of the
15tariff cancelling the utility's automatic adjustment clause
16tariff, the utility shall file a reconciliation that reconciles
17the moneys collected under its automatic adjustment clause
18tariff with the costs incurred during the period beginning June
191, 2016 and ending on the date that the electric utility's
20automatic adjustment clause tariff was cancelled. In the event
21the reconciliation reflects an under-collection, the utility
22shall recover the costs as specified in this subsection (l). If
23the reconciliation reflects an over-collection, the utility
24shall apply the amount of such over-collection as a one-time
25credit to retail customers' bills.
 

 

 

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1    (220 ILCS 5/8-104)
2    Sec. 8-104. Natural gas energy efficiency programs.
3    (a) It is the policy of the State that natural gas
4utilities and the Department of Commerce and Economic
5Opportunity are required to use cost-effective energy
6efficiency to reduce direct and indirect costs to consumers. It
7serves the public interest to allow natural gas utilities to
8recover costs for reasonably and prudently incurred expenses
9for cost-effective energy efficiency measures.
10    (b) For purposes of this Section, "energy efficiency" means
11measures that reduce the amount of energy required to achieve a
12given end use. "Energy efficiency" also includes measures that
13reduce the total Btus of electricity and natural gas needed to
14meet the end use or uses. "Cost-effective" means that the
15measures satisfy the total resource cost test which, for
16purposes of this Section, means a standard that is met if, for
17an investment in energy efficiency, the benefit-cost ratio is
18greater than one. The benefit-cost ratio is the ratio of the
19net present value of the total benefits of the measures to the
20net present value of the total costs as calculated over the
21lifetime of the measures. The total resource cost test compares
22the sum of avoided natural gas utility costs, representing the
23benefits that accrue to the system and the participant in the
24delivery of those efficiency measures, as well as other
25quantifiable societal benefits, including avoided electric
26utility costs, to the sum of all incremental costs of end use

 

 

09900SB1585sam002- 142 -LRB099 09533 EGJ 48253 a

1measures (including both utility and participant
2contributions), plus costs to administer, deliver, and
3evaluate each demand-side measure, to quantify the net savings
4obtained by substituting demand-side measures for supply
5resources. In calculating avoided costs, reasonable estimates
6shall be included for financial costs likely to be imposed by
7future regulation of emissions of greenhouse gases. The
8low-income programs described in item (4) of subsection (f) of
9this Section shall not be required to meet the total resource
10cost test.
11    (c) Natural gas utilities shall implement cost-effective
12energy efficiency measures to meet at least the following
13natural gas savings requirements, which shall be based upon the
14total amount of gas delivered to retail customers, other than
15the customers described in subsection (m) of this Section,
16during calendar year 2009 multiplied by the applicable
17percentage. Natural gas utilities may comply with this Section
18by meeting the annual incremental savings goal in the
19applicable year or by showing that total cumulative annual
20savings within a multi-year 3-year planning period associated
21with measures implemented after May 31, 2011 were equal to the
22sum of each annual incremental savings requirement from the
23first day of the multi-year planning period May 31, 2011
24through the last day of the multi-year planning period end of
25the applicable year:
26        (1) 0.2% by May 31, 2012;

 

 

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1        (2) an additional 0.4% by May 31, 2013, increasing
2    total savings to .6%;
3        (3) an additional 0.6% by May 31, 2014, increasing
4    total savings to 1.2%;
5        (4) an additional 0.8% by May 31, 2015, increasing
6    total savings to 2.0%;
7        (5) an additional 1% by May 31, 2016, increasing total
8    savings to 3.0%;
9        (6) an additional 1.2% by May 31, 2017, increasing
10    total savings to 4.2%;
11        (7) an additional 1.4% in the year commencing January
12    1, 2018 by May 31, 2018, increasing total savings to 5.6%;
13        (8) an additional 1.5% in the year commencing January
14    1, 2019 by May 31, 2019, increasing total savings to 7.1%;
15    and
16        (9) an additional 1.5% in each 12-month period
17    thereafter.
18    (d) Notwithstanding the requirements of subsection (c) of
19this Section, a natural gas utility shall limit the amount of
20energy efficiency implemented in any multi-year 3-year
21reporting period established by subsection (f) of Section 8-104
22of this Act, by an amount necessary to limit the estimated
23average increase in the amounts paid by retail customers in
24connection with natural gas service to no more than 2% in the
25applicable multi-year 3-year reporting period. The energy
26savings requirements in subsection (c) of this Section may be

 

 

09900SB1585sam002- 144 -LRB099 09533 EGJ 48253 a

1reduced by the Commission for the subject plan, if the utility
2demonstrates by substantial evidence that it is highly unlikely
3that the requirements could be achieved without exceeding the
4applicable spending limits in any multi-year 3-year reporting
5period. No later than September 1, 2013, the Commission shall
6review the limitation on the amount of energy efficiency
7measures implemented pursuant to this Section and report to the
8General Assembly, in the report required by subsection (k) of
9this Section, its findings as to whether that limitation unduly
10constrains the procurement of energy efficiency measures.
11    (e) The provisions of this subsection (e) apply to those
12multi-year plans that commence prior to January 1, 2018 Natural
13gas utilities shall be responsible for overseeing the design,
14development, and filing of their efficiency plans with the
15Commission. The utility shall utilize 75% of the available
16funding associated with energy efficiency programs approved by
17the Commission, and may outsource various aspects of program
18development and implementation. The remaining 25% of available
19funding shall be used by the Department of Commerce and
20Economic Opportunity to implement energy efficiency measures
21that achieve no less than 20% of the requirements of subsection
22(c) of this Section. Such measures shall be designed in
23conjunction with the utility and approved by the Commission.
24The Department may outsource development and implementation of
25energy efficiency measures. A minimum of 10% of the entire
26portfolio of cost-effective energy efficiency measures shall

 

 

09900SB1585sam002- 145 -LRB099 09533 EGJ 48253 a

1be procured from local government, municipal corporations,
2school districts, and community college districts. Five
3percent of the entire portfolio of cost-effective energy
4efficiency measures may be granted to local government and
5municipal corporations for market transformation initiatives.
6The Department shall coordinate the implementation of these
7measures and shall integrate delivery of natural gas efficiency
8programs with electric efficiency programs delivered pursuant
9to Section 8-103 of this Act, unless the Department can show
10that integration is not feasible.
11    The apportionment of the dollars to cover the costs to
12implement the Department's share of the portfolio of energy
13efficiency measures shall be made to the Department once the
14Department has executed rebate agreements, grants, or
15contracts for energy efficiency measures and provided
16supporting documentation for those rebate agreements, grants,
17and contracts to the utility. The Department is authorized to
18adopt any rules necessary and prescribe procedures in order to
19ensure compliance by applicants in carrying out the purposes of
20rebate agreements for energy efficiency measures implemented
21by the Department made under this Section.
22    The details of the measures implemented by the Department
23shall be submitted by the Department to the Commission in
24connection with the utility's filing regarding the energy
25efficiency measures that the utility implements.
26    The portfolio of measures, administered by both the

 

 

09900SB1585sam002- 146 -LRB099 09533 EGJ 48253 a

1utilities and the Department, shall, in combination, be
2designed to achieve the annual energy savings requirements set
3forth in subsection (c) of this Section, as modified by
4subsection (d) of this Section.
5    The utility and the Department shall agree upon a
6reasonable portfolio of measures and determine the measurable
7corresponding percentage of the savings goals associated with
8measures implemented by the Department.
9    No utility shall be assessed a penalty under subsection (f)
10of this Section for failure to make a timely filing if that
11failure is the result of a lack of agreement with the
12Department with respect to the allocation of responsibilities
13or related costs or target assignments. In that case, the
14Department and the utility shall file their respective plans
15with the Commission and the Commission shall determine an
16appropriate division of measures and programs that meets the
17requirements of this Section.
18    (e-5) The provisions of this subsection (e-5) shall be
19applicable to those multi-year plans that commence after
20December 31, 2017. Natural gas utilities shall be responsible
21for overseeing the design, development, and filing of their
22efficiency plans with the Commission and may outsource
23development and implementation of energy efficiency measures.
24A minimum of 10% of the entire portfolio of cost-effective
25energy efficiency measures shall be procured from local
26government, municipal corporations, school districts, and

 

 

09900SB1585sam002- 147 -LRB099 09533 EGJ 48253 a

1community college districts. Five percent of the entire
2portfolio of cost-effective energy efficiency measures may be
3granted to local government and municipal corporations for
4market transformation initiatives.
5    The utilities shall also present a portfolio of energy
6efficiency measures proportionate to the share of total annual
7utility revenues in Illinois from households at or below 150%
8of the poverty level. Such programs shall be targeted to
9households with incomes at or below 80% of area median income.
10    (e-10) A utility providing approved energy efficiency
11measures in this State shall be permitted to recover costs of
12those measures through an automatic adjustment clause tariff
13filed with and approved by the Commission. The tariff shall be
14established outside the context of a general rate case and
15shall be applicable to the utility's customers other than the
16customers described in subsection (m) of this Section. Each
17year the Commission shall initiate a review to reconcile any
18amounts collected with the actual costs and to determine the
19required adjustment to the annual tariff factor to match annual
20expenditures.
21    (e-15) For those multi-year plans that commence prior to
22January 1, 2018, each Each utility shall include, in its
23recovery of costs, the costs estimated for both the utility's
24and the Department's implementation of energy efficiency
25measures. Costs collected by the utility for measures
26implemented by the Department shall be submitted to the

 

 

09900SB1585sam002- 148 -LRB099 09533 EGJ 48253 a

1Department pursuant to Section 605-323 of the Civil
2Administrative Code of Illinois, shall be deposited into the
3Energy Efficiency Portfolio Standards Fund, and shall be used
4by the Department solely for the purpose of implementing these
5measures. A utility shall not be required to advance any moneys
6to the Department but only to forward such funds as it has
7collected. The Department shall report to the Commission on an
8annual basis regarding the costs actually incurred by the
9Department in the implementation of the measures. Any changes
10to the costs of energy efficiency measures as a result of plan
11modifications shall be appropriately reflected in amounts
12recovered by the utility and turned over to the Department.
13    The portfolio of measures, administered by both the
14utilities and the Department, shall, in combination, be
15designed to achieve the annual energy savings requirements set
16forth in subsection (c) of this Section, as modified by
17subsection (d) of this Section.
18    The utility and the Department shall agree upon a
19reasonable portfolio of measures and determine the measurable
20corresponding percentage of the savings goals associated with
21measures implemented by the Department.
22    No utility shall be assessed a penalty under subsection (f)
23of this Section for failure to make a timely filing if that
24failure is the result of a lack of agreement with the
25Department with respect to the allocation of responsibilities
26or related costs or target assignments. In that case, the

 

 

09900SB1585sam002- 149 -LRB099 09533 EGJ 48253 a

1Department and the utility shall file their respective plans
2with the Commission and the Commission shall determine an
3appropriate division of measures and programs that meets the
4requirements of this Section.
5    If the Department is unable to meet performance
6requirements for the portion of the portfolio implemented by
7the Department, then the utility and the Department shall
8jointly submit a modified filing to the Commission explaining
9the performance shortfall and recommending an appropriate
10course going forward, including any program modifications that
11may be appropriate in light of the evaluations conducted under
12item (8) of subsection (f) of this Section. In this case, the
13utility obligation to collect the Department's costs and turn
14over those funds to the Department under this subsection (e)
15shall continue only if the Commission approves the
16modifications to the plan proposed by the Department.
17    (f) No later than October 1, 2010, each gas utility shall
18file an energy efficiency plan with the Commission to meet the
19energy efficiency standards through May 31, 2014. No later than
20October 1, 2013, each gas utility shall file an energy
21efficiency plan with the Commission to meet the energy
22efficiency standards through May 31, 2017. Beginning in 2017
23and every 4 Every 3 years thereafter, each utility shall file,
24no later than October 1, an energy efficiency plan with the
25Commission to meet the energy efficiency standards for the next
26applicable 4-year period beginning January 1 of the year

 

 

09900SB1585sam002- 150 -LRB099 09533 EGJ 48253 a

1following the filing. For those multi-year plans commencing on
2January 1, 2018, each utility shall file its proposed energy
3efficiency plan no later than 30 days after the effective date
4of this amendatory Act of the 99th General Assembly or May 1,
52017, whichever is later. Beginning in 2021 and every 4 years
6thereafter, each utility shall file its energy efficiency plan
7no later than March 1. If a utility does not file such a plan on
8or before the applicable filing deadline for the plan by
9October 1 of the applicable year, then it shall face a penalty
10of $100,000 per day until the plan is filed.
11    Each utility's plan shall set forth the utility's proposals
12to meet the utility's portion of the energy efficiency
13standards identified in subsection (c) of this Section, as
14modified by subsection (d) of this Section, taking into account
15the unique circumstances of the utility's service territory.
16For those plans commencing after December 31, 2021, the The
17Commission shall seek public comment on the utility's plan and
18shall issue an order approving or disapproving each plan within
196 months after its submission. For those plans commencing on
20January 1, 2018, the Commission shall seek public comment on
21the utility's plan and shall issue an order approving or
22disapproving each plan no later than August 31, 2017. If the
23Commission disapproves a plan, the Commission shall, within 30
24days, describe in detail the reasons for the disapproval and
25describe a path by which the utility may file a revised draft
26of the plan to address the Commission's concerns

 

 

09900SB1585sam002- 151 -LRB099 09533 EGJ 48253 a

1satisfactorily. If the utility does not refile with the
2Commission within 60 days after the disapproval, the utility
3shall be subject to penalties at a rate of $100,000 per day
4until the plan is filed. This process shall continue, and
5penalties shall accrue, until the utility has successfully
6filed a portfolio of energy efficiency measures. Penalties
7shall be deposited into the Energy Efficiency Trust Fund and
8the cost of any such penalties may not be recovered from
9ratepayers. In submitting proposed energy efficiency plans and
10funding levels to meet the savings goals adopted by this Act
11the utility shall:
12        (1) Demonstrate that its proposed energy efficiency
13    measures will achieve the requirements that are identified
14    in subsection (c) of this Section, as modified by
15    subsection (d) of this Section.
16        (2) Present specific proposals to implement new
17    building and appliance standards that have been placed into
18    effect.
19        (3) Present estimates of the total amount paid for gas
20    service expressed on a per therm basis associated with the
21    proposed portfolio of measures designed to meet the
22    requirements that are identified in subsection (c) of this
23    Section, as modified by subsection (d) of this Section.
24        (4) For those multi-year plans that commence prior to
25    January 1, 2018, coordinate Coordinate with the Department
26    to present a portfolio of energy efficiency measures

 

 

09900SB1585sam002- 152 -LRB099 09533 EGJ 48253 a

1    proportionate to the share of total annual utility revenues
2    in Illinois from households at or below 150% of the poverty
3    level. Such programs shall be targeted to households with
4    incomes at or below 80% of area median income.
5        (5) Demonstrate that its overall portfolio of energy
6    efficiency measures, not including low-income programs
7    described in covered by item (4) of this subsection (f) and
8    subsection (e-5) of this Section, are cost-effective using
9    the total resource cost test and represent a diverse cross
10    section of opportunities for customers of all rate classes
11    to participate in the programs.
12        (6) Demonstrate that a gas utility affiliated with an
13    electric utility that is required to comply with Section
14    8-103 or 8-103B of this Act has integrated gas and electric
15    efficiency measures into a single program that reduces
16    program or participant costs and appropriately allocates
17    costs to gas and electric ratepayers. For those multi-year
18    plans that commence prior to January 1, 2018, the The
19    Department shall integrate all gas and electric programs it
20    delivers in any such utilities' service territories,
21    unless the Department can show that integration is not
22    feasible or appropriate.
23        (7) Include a proposed cost recovery tariff mechanism
24    to fund the proposed energy efficiency measures and to
25    ensure the recovery of the prudently and reasonably
26    incurred costs of Commission-approved programs.

 

 

09900SB1585sam002- 153 -LRB099 09533 EGJ 48253 a

1        (8) Provide for quarterly status reports tracking
2    implementation of and expenditures for the utility's
3    portfolio of measures and, if applicable, the Department's
4    portfolio of measures, an annual independent review, and a
5    full independent evaluation of the multi-year 3-year
6    results of the performance and the cost-effectiveness of
7    the utility's and, if applicable, Department's portfolios
8    of measures and broader net program impacts and, to the
9    extent practical, for adjustment of the measures on a going
10    forward basis as a result of the evaluations. The resources
11    dedicated to evaluation shall not exceed 3% of portfolio
12    resources in any given multi-year 3-year period.
13    (g) No more than 3% of expenditures on energy efficiency
14measures may be allocated for demonstration of breakthrough
15equipment and devices.
16    (h) Illinois natural gas utilities that are affiliated by
17virtue of a common parent company may, at the utilities'
18request, be considered a single natural gas utility for
19purposes of complying with this Section.
20    (i) If, after 3 years, a gas utility fails to meet the
21efficiency standard specified in subsection (c) of this Section
22as modified by subsection (d), then it shall make a
23contribution to the Low-Income Home Energy Assistance Program.
24The total liability for failure to meet the goal shall be
25assessed as follows:
26        (1) a large gas utility shall pay $600,000;

 

 

09900SB1585sam002- 154 -LRB099 09533 EGJ 48253 a

1        (2) a medium gas utility shall pay $400,000; and
2        (3) a small gas utility shall pay $200,000.
3    For purposes of this Section, (i) a "large gas utility" is
4a gas utility that on December 31, 2008, served more than
51,500,000 gas customers in Illinois; (ii) a "medium gas
6utility" is a gas utility that on December 31, 2008, served
7fewer than 1,500,000, but more than 500,000 gas customers in
8Illinois; and (iii) a "small gas utility" is a gas utility that
9on December 31, 2008, served fewer than 500,000 and more than
10100,000 gas customers in Illinois. The costs of this
11contribution may not be recovered from ratepayers.
12    If a gas utility fails to meet the efficiency standard
13specified in subsection (c) of this Section, as modified by
14subsection (d) of this Section, in any 2 consecutive multi-year
153-year planning periods, then the responsibility for
16implementing the utility's energy efficiency measures shall be
17transferred to an independent program administrator selected
18by the Commission. Reasonable and prudent costs incurred by the
19independent program administrator to meet the efficiency
20standard specified in subsection (c) of this Section, as
21modified by subsection (d) of this Section, may be recovered
22from the customers of the affected gas utilities, other than
23customers described in subsection (m) of this Section. The
24utility shall provide the independent program administrator
25with all information and assistance necessary to perform the
26program administrator's duties including but not limited to

 

 

09900SB1585sam002- 155 -LRB099 09533 EGJ 48253 a

1customer, account, and energy usage data, and shall allow the
2program administrator to include inserts in customer bills. The
3utility may recover reasonable costs associated with any such
4assistance.
5    (j) No utility shall be deemed to have failed to meet the
6energy efficiency standards to the extent any such failure is
7due to a failure of the Department.
8    (k) Not later than January 1, 2012, the Commission shall
9develop and solicit public comment on a plan to foster
10statewide coordination and consistency between statutorily
11mandated natural gas and electric energy efficiency programs to
12reduce program or participant costs or to improve program
13performance. Not later than September 1, 2013, the Commission
14shall issue a report to the General Assembly containing its
15findings and recommendations.
16    (l) This Section does not apply to a gas utility that on
17January 1, 2009, provided gas service to fewer than 100,000
18customers in Illinois.
19    (m) Subsections (a) through (k) of this Section do not
20apply to customers of a natural gas utility that have a North
21American Industry Classification System code number that is
2222111 or any such code number beginning with the digits 31, 32,
23or 33 and (i) annual usage in the aggregate of 4 million therms
24or more within the service territory of the affected gas
25utility or with aggregate usage of 8 million therms or more in
26this State and complying with the provisions of item (l) of

 

 

09900SB1585sam002- 156 -LRB099 09533 EGJ 48253 a

1this subsection (m); or (ii) using natural gas as feedstock and
2meeting the usage requirements described in item (i) of this
3subsection (m), to the extent such annual feedstock usage is
4greater than 60% of the customer's total annual usage of
5natural gas.
6        (1) Customers described in this subsection (m) of this
7    Section shall apply, on a form approved on or before
8    October 1, 2009 by the Department, to the Department to be
9    designated as a self-directing customer ("SDC") or as an
10    exempt customer using natural gas as a feedstock from which
11    other products are made, including, but not limited to,
12    feedstock for a hydrogen plant, on or before the 1st day of
13    February, 2010. Thereafter, application may be made not
14    less than 6 months before the filing date of the gas
15    utility energy efficiency plan described in subsection (f)
16    of this Section; however, a new customer that commences
17    taking service from a natural gas utility after February 1,
18    2010 may apply to become a SDC or exempt customer up to 30
19    days after beginning service. Customers described in this
20    subsection (m) that have not already been approved by the
21    Department may apply to be designated a self-directing
22    customer or exempt customer, on a form approved by the
23    Department, between September 1, 2013 and September 30,
24    2013. Customer applications that are approved by the
25    Department under this amendatory Act of the 98th General
26    Assembly shall be considered to be a self-directing

 

 

09900SB1585sam002- 157 -LRB099 09533 EGJ 48253 a

1    customer or exempt customer, as applicable, for the current
2    3-year planning period effective December 1, 2013. Such
3    application shall contain the following:
4            (A) the customer's certification that, at the time
5        of its application, it qualifies to be a SDC or exempt
6        customer described in this subsection (m) of this
7        Section;
8            (B) in the case of a SDC, the customer's
9        certification that it has established or will
10        establish by the beginning of the utility's multi-year
11        3-year planning period commencing subsequent to the
12        application, and will maintain for accounting
13        purposes, an energy efficiency reserve account and
14        that the customer will accrue funds in said account to
15        be held for the purpose of funding, in whole or in
16        part, energy efficiency measures of the customer's
17        choosing, which may include, but are not limited to,
18        projects involving combined heat and power systems
19        that use the same energy source both for the generation
20        of electrical or mechanical power and the production of
21        steam or another form of useful thermal energy or the
22        use of combustible gas produced from biomass, or both;
23            (C) in the case of a SDC, the customer's
24        certification that annual funding levels for the
25        energy efficiency reserve account will be equal to 2%
26        of the customer's cost of natural gas, composed of the

 

 

09900SB1585sam002- 158 -LRB099 09533 EGJ 48253 a

1        customer's commodity cost and the delivery service
2        charges paid to the gas utility, or $150,000, whichever
3        is less;
4            (D) in the case of a SDC, the customer's
5        certification that the required reserve account
6        balance will be capped at 3 years' worth of accruals
7        and that the customer may, at its option, make further
8        deposits to the account to the extent such deposit
9        would increase the reserve account balance above the
10        designated cap level;
11            (E) in the case of a SDC, the customer's
12        certification that by October 1 of each year, beginning
13        no sooner than October 1, 2012, the customer will
14        report to the Department information, for the 12-month
15        period ending May 31 of the same year, on all deposits
16        and reductions, if any, to the reserve account during
17        the reporting year, and to the extent deposits to the
18        reserve account in any year are in an amount less than
19        $150,000, the basis for such reduced deposits; reserve
20        account balances by month; a description of energy
21        efficiency measures undertaken by the customer and
22        paid for in whole or in part with funds from the
23        reserve account; an estimate of the energy saved, or to
24        be saved, by the measure; and that the report shall
25        include a verification by an officer or plant manager
26        of the customer or by a registered professional

 

 

09900SB1585sam002- 159 -LRB099 09533 EGJ 48253 a

1        engineer or certified energy efficiency trade
2        professional that the funds withdrawn from the reserve
3        account were used for the energy efficiency measures;
4            (F) in the case of an exempt customer, the
5        customer's certification of the level of gas usage as
6        feedstock in the customer's operation in a typical year
7        and that it will provide information establishing this
8        level, upon request of the Department;
9            (G) in the case of either an exempt customer or a
10        SDC, the customer's certification that it has provided
11        the gas utility or utilities serving the customer with
12        a copy of the application as filed with the Department;
13            (H) in the case of either an exempt customer or a
14        SDC, certification of the natural gas utility or
15        utilities serving the customer in Illinois including
16        the natural gas utility accounts that are the subject
17        of the application; and
18            (I) in the case of either an exempt customer or a
19        SDC, a verification signed by a plant manager or an
20        authorized corporate officer attesting to the
21        truthfulness and accuracy of the information contained
22        in the application.
23        (2) The Department shall review the application to
24    determine that it contains the information described in
25    provisions (A) through (I) of item (1) of this subsection
26    (m), as applicable. The review shall be completed within 30

 

 

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1    days after the date the application is filed with the
2    Department. Absent a determination by the Department
3    within the 30-day period, the applicant shall be considered
4    to be a SDC or exempt customer, as applicable, for all
5    subsequent multi-year 3-year planning periods, as of the
6    date of filing the application described in this subsection
7    (m). If the Department determines that the application does
8    not contain the applicable information described in
9    provisions (A) through (I) of item (1) of this subsection
10    (m), it shall notify the customer, in writing, of its
11    determination that the application does not contain the
12    required information and identify the information that is
13    missing, and the customer shall provide the missing
14    information within 15 working days after the date of
15    receipt of the Department's notification.
16        (3) The Department shall have the right to audit the
17    information provided in the customer's application and
18    annual reports to ensure continued compliance with the
19    requirements of this subsection. Based on the audit, if the
20    Department determines the customer is no longer in
21    compliance with the requirements of items (A) through (I)
22    of item (1) of this subsection (m), as applicable, the
23    Department shall notify the customer in writing of the
24    noncompliance. The customer shall have 30 days to establish
25    its compliance, and failing to do so, may have its status
26    as a SDC or exempt customer revoked by the Department. The

 

 

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1    Department shall treat all information provided by any
2    customer seeking SDC status or exemption from the
3    provisions of this Section as strictly confidential.
4        (4) Upon request, or on its own motion, the Commission
5    may open an investigation, no more than once every 3 years
6    and not before October 1, 2014, to evaluate the
7    effectiveness of the self-directing program described in
8    this subsection (m).
9    Customers described in this subsection (m) that applied to
10the Department on January 3, 2013, were approved by the
11Department on February 13, 2013 to be a self-directing customer
12or exempt customer, and receive natural gas from a utility that
13provides gas service to at least 500,000 retail customers in
14Illinois and electric service to at least 1,000,000 retail
15customers in Illinois shall be considered to be a
16self-directing customer or exempt customer, as applicable, for
17the current 3-year planning period effective December 1, 2013.
18    (n) The applicability of this Section to customers
19described in subsection (m) of this Section is conditioned on
20the existence of the SDC program. In no event will any
21provision of this Section apply to such customers after January
221, 2020.
23    (o) Utilities' 3-year energy efficiency plans approved by
24the Commission on or before the effective date of this
25amendatory Act of the 99th General Assembly for the period June
261, 2014 through May 31, 2017 shall continue to be in force and

 

 

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1effect through December 31, 2017 so that the energy efficiency
2programs set forth in those plans continue to be offered during
3the period June 1, 2017 through December 31, 2017. Each utility
4is authorized to increase, on a pro rata basis, the energy
5savings goals and budgets approved in its plan to reflect the
6additional 7 months of the plan's operation.
7(Source: P.A. 97-813, eff. 7-13-12; 97-841, eff. 7-20-12;
898-90, eff. 7-15-13; 98-225, eff. 8-9-13; 98-604, eff.
912-17-13.)
 
10    (220 ILCS 5/9-105 new)
11    Sec. 9-105. Demand-based delivery services charge.
12    (a) Beginning with the January 2019 monthly billing period
13for an electric utility that serves more than 3,000,000 retail
14customers in the State and beginning with the January 2021
15monthly billing period for an electric utility that serves
163,000,000 or less retail customers but more than 500,000 retail
17customers in the State, such utility may recover its costs of
18providing delivery services to retail customers through a
19charge based on kilowatts of demand. A utility that elects to
20recover its costs as provided in this Section shall file its
21tariffs pursuant to Section 9-201 of this Act, provided that a
22participating utility as defined in Section 16-108.5 of this
23Act shall file such tariffs pursuant to subsection (e) of
24Section 16-108.5.
25    (b) Tariffs filed by a utility under subsection (a) of this

 

 

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1Section shall be subject to the following provisions:
2        (1) The categories of costs being recovered through a
3    fixed charge on the effective date of this amendatory Act
4    of the 99th General Assembly shall continue to be recovered
5    through a fixed charge; however, this paragraph (1) shall
6    not limit the consideration and inclusion of additional
7    cost components to be recovered through a fixed charge.
8        (2) The categories of costs being recovered through
9    riders or automatic adjustment clause tariffs on the
10    effective date of this amendatory Act of the 99th General
11    Assembly and add-on taxes and other separately-stated
12    charges or adjustments may, at the utility's election,
13    continue to be recovered in the manner they are being
14    collected, provided that nothing in this paragraph (2)
15    shall prohibit addition or elimination of a rider or an
16    automatic adjustment clause tariff or preclude the utility
17    from revising those riders or automatic adjustment clause
18    tariffs, pursuant to this Article IX or any applicable
19    provisions of this Act, regardless of whether such riders
20    or automatic adjustment clause tariffs assess charges on a
21    kilowatt-hour or kilowatt basis.
22        (3) Taxes assessed on a kilowatt-hour basis shall
23    continue to be recovered on a kilowatt-hour basis.
24        (4) The costs of providing delivery services to those
25    retail customers subject to the tariff that are not
26    recovered under paragraphs (1) through (3) of this

 

 

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1    subsection (b) shall be recovered through a charge based on
2    kilowatts of demand, and the tariffs shall be designed to
3    allocate costs to the cost causer generally based on the
4    demands that customers place on the utility's systems.
5        (5) For purposes of this Section, the kilowatts of
6    demand for each residential customer of an electric utility
7    that serves more than 3,000,000 retail customers in the
8    State shall be calculated based on the maximum kilowatts
9    delivered to the customer during a 30-minute interval over
10    a 16-hour period beginning at 6 a.m. and ending at 10 p.m.
11    Central Prevailing Time on a non-holiday weekday during the
12    monthly billing period or periods for which the bill is
13    rendered; the kilowatts of demand for each residential
14    customer of an electric utility that serves 3,000,000 or
15    less retail customers but more than 500,000 retail
16    customers in the State shall be calculated based on the
17    maximum kilowatts delivered to the customer during a
18    60-minute interval over a 16-hour period beginning at 6
19    a.m. and ending at 10 p.m. Central Prevailing Time on a
20    non-holiday weekday during the monthly billing period or
21    periods for which the bill is rendered. For purposes of
22    this Section, 30-minute intervals shall begin on the hour
23    and 30 minutes past the hour and 60-minute intervals shall
24    begin on the hour. An electric utility may elect to
25    estimate retail customers' kilowatt demands if the
26    interval data necessary to determine such customers'

 

 

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1    kilowatt demands is not available.
2    (c) An electric utility that elects to recover its costs of
3providing delivery services to retail customers pursuant to
4subsection (a) of this Section shall notify the Commission of
5its election to do so no later than 20 months before the tariff
6to recover such costs would take effect under this Section. An
7electric utility that makes such election shall also be subject
8to the following provisions, as applicable:
9        (1) If the utility elects to recover, pursuant to this
10    Section, its costs of providing delivery services to
11    residential retail customers, then the utility shall also
12    file a tariff that limits the amount of the delivery
13    services revenue requirement that is allocated to be
14    recovered from such customers through the customer charge
15    to no more than 14% on average among residential retail
16    customers. The tariff shall take effect at the same time
17    the utility's tariff authorized by subsection (a) of this
18    Section takes effect.
19        (2) If the utility elects to recover, pursuant to this
20    Section, its costs of providing delivery services to
21    eligible retail customers, as defined by Section 16-111.5
22    of this Act, then the utility shall also offer a
23    market-based, time-of-use rate for eligible retail
24    customers that choose to take power and energy supply
25    service from the utility. The utility shall file its
26    time-of-use rate tariff no later than 120 days after its

 

 

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1    demand-based rates applicable to such customers take
2    effect pursuant to subsection (a) of this Section.
3        (3) Beginning with the year in which a utility elects
4    to recover, pursuant to this Section, its costs of
5    providing delivery services to such eligible retail
6    customers, the utility shall spend $15,000,000 over 3 years
7    in customer education and outreach efforts designed to
8    inform eligible retail customers about the rate design
9    changes to be implemented pursuant to this Section and to
10    empower such customers regarding how to respond to the new
11    rate design. The investment shall be a recoverable expense.
12        (4) If the electric utility also has a
13    performance-based formula rate in effect pursuant to
14    Section 16-108.5 of this Act, then the utility shall be
15    permitted to revise the formula rate and schedules to
16    reduce the 50 basis point values to zero that would
17    otherwise apply under paragraph (5) of subsection (c) of
18    Section 16-108.5 of this Act. If the utility no longer has
19    a performance-based formula rate in effect pursuant to
20    Section 16-108.5 of this Act, then the utility shall be
21    permitted to implement the revenue balancing adjustment
22    tariff described in Section 9-107 of this Act.
 
23    (220 ILCS 5/9-107 new)
24    Sec. 9-107. Revenue balancing adjustment tariff.
25    (a) In this Section:

 

 

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1    "Reconciliation period" means a period beginning with the
2January monthly billing period and extending through the
3December monthly billing period.
4    "Rate case reconciliation revenue requirement" means the
5final distribution revenue requirement or requirements
6approved by the Commission in the utility's rate case or
7formula rate proceeding to set the rates initially applicable
8in the relevant reconciliation period after the conclusion of
9the period. In the event the Commission has approved more than
10one revenue requirement for the reconciliation period, the
11amount of rate case revenue under each approved revenue
12requirement shall be prorated based upon the number of days
13under which each revenue requirement was in effect.
14    (b) An electric utility that is authorized under paragraph
15(4) of subsection (c) of Section 9-105 of this Act to implement
16a revenue balancing adjustment tariff under this Section
17because the utility no longer has a performance-based formula
18rate in effect pursuant to Section 16-108.5 of this Act, may
19file the tariff for the purpose of preventing undercollections
20or overcollections of distribution revenues as compared to the
21revenue requirement or requirements approved by the Commission
22on which the rates giving rise to those revenues were based.
23The tariff shall calculate an annual adjustment that reflects
24any difference between the actual delivery service revenue
25collected for services provided during the relevant
26reconciliation period and the rate case reconciliation revenue

 

 

09900SB1585sam002- 168 -LRB099 09533 EGJ 48253 a

1requirement for the relevant reconciliation period and shall
2set forth the reconciliation categories or classes, or a
3combination of both, in a manner determined at the utility's
4discretion.
5    (c) A utility that elects to file the tariff authorized by
6this Section shall file the tariff outside the context of a
7general rate case or formula rate proceeding, and the
8Commission shall, after notice and hearing, approve the tariff
9or approve with modification no later than 120 days after the
10utility files the tariff, and the tariff shall remain in effect
11at the discretion of the utility. The tariff shall also require
12that the electric utility submit an annual revenue balancing
13reconciliation report to the Commission reflecting the
14difference between the actual delivery service revenue and rate
15case revenue for the applicable reconciliation and identifying
16the charges or credits to be applied thereafter. The annual
17revenue balancing reconciliation report shall be filed with the
18Commission no later than March 20 of the year following a
19reconciliation period. The Commission may initiate a review of
20the revenue balancing reconciliation report each year to
21determine if any subsequent adjustment is necessary to align
22actual delivery service revenue and rate case revenue. In the
23event the Commission elects to initiate such review, the
24Commission shall, after notice and hearing, enter an order
25approving, or approving as modified, such revenue balancing
26reconciliation report no later than 120 days after the utility

 

 

09900SB1585sam002- 169 -LRB099 09533 EGJ 48253 a

1files its report with the Commission. If the Commission does
2not initiate such review, the revenue balancing reconciliation
3report and the identified charges or credits shall be deemed
4accepted and approved 120 days after the utility files the
5report and shall not be subject to review in any other
6proceeding.
 
7    (220 ILCS 5/16-103.3 new)
8    Sec. 16-103.3. Unbundling of charges related to
9electricity supply and regional transmission organization
10services. Beginning with the January 2019 monthly billing
11period, an electric utility that provides electric service to
12more than 3,000,000 retail customers in the State shall
13restructure its retail electricity supply charges applicable
14to eligible retail customers, as defined by Section 16-111.5 of
15this Act, for whom the electric utility procures electric power
16and energy pursuant to Section 1-75 of the Illinois Power
17Agency Act and Section 16-111.5 of this Act. The restructuring
18shall allocate to these customers, and separately state, the
19following: the costs of electric capacity, costs of
20transmission services, and charges for network integration
21transmission service, transmission enhancement, and locational
22reliability, as these terms are defined in the PJM
23Interconnection Open Access Transmission Tariff on March 1,
242016. In the event the Open Access Transmission Tariff
25subsequently renames those terms, the services reflected under

 

 

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1those terms shall continue to be subject to the restructuring
2described in this Section.
3    It is the intent of this Section that eligible retail
4customers taking electricity supply service from an electric
5utility that provides electric service to more than 3,000,000
6retail customers in the State pay charges for the electricity
7supply and regional transmission organization-related services
8costs that generally reflect the manner in which the associated
9costs are incurred.
 
10    (220 ILCS 5/16-107)
11    Sec. 16-107. Real-time pricing.
12    (a) Each electric utility shall file, on or before May 1,
131998, a tariff or tariffs which allow nonresidential retail
14customers in the electric utility's service area to elect
15real-time pricing beginning October 1, 1998.
16    (b) Each electric utility shall file, on or before May 1,
172000, a tariff or tariffs which allow residential retail
18customers in the electric utility's service area to elect
19real-time pricing beginning October 1, 2000.
20    (b-5) Each electric utility shall file a tariff or tariffs
21allowing residential retail customers in the electric
22utility's service area to elect real-time pricing beginning
23January 2, 2007. The Commission may, after notice and hearing,
24approve the tariff or tariffs. A customer who elects real-time
25pricing shall remain on such rate for a minimum of 12 months.

 

 

09900SB1585sam002- 171 -LRB099 09533 EGJ 48253 a

1The Commission may, after notice and hearing, approve the
2tariff or tariffs, provided that the Commission finds that the
3potential for demand reductions will result in net economic
4benefits to all residential customers of the electric utility.
5In examining economic benefits from demand reductions, the
6Commission shall, at a minimum, consider the following:
7improvements to system reliability and power quality,
8reduction in wholesale market prices and price volatility,
9electric utility cost avoidance and reductions, market power
10mitigation, and other benefits of demand reductions, but only
11to the extent that the effects of reduced demand can be
12demonstrated to lower the cost of electricity delivered to
13residential customers. A tariff or tariffs approved pursuant to
14this subsection (b-5) shall, at a minimum, describe (i) the
15methodology for determining the market price of energy to be
16reflected in the real-time rate and (ii) the manner in which
17customers who elect real-time pricing will be provided with
18ready access to hourly market prices, including, but not
19limited to, day-ahead hourly energy prices. A customer who
20elects real-time pricing pursuant to a tariff approved under
21this subsection (b-5) and thereafter terminates the election
22shall not return to taking service under the tariff for a
23period of 12 months following the date on which the customer
24terminated real-time pricing. However, this limitation shall
25cease to apply on such date that the provision of electric
26power and energy is declared competitive under Section 16-113

 

 

09900SB1585sam002- 172 -LRB099 09533 EGJ 48253 a

1of this Act for the customer group or groups to which this
2subsection (b-5) applies.
3    A proceeding under this subsection (b-5) may not exceed 120
4days in length.
5    (b-10) Each electric utility providing real-time pricing
6pursuant to subsection (b-5) shall install a meter capable of
7recording hourly interval energy use at the service location of
8each customer that elects real-time pricing pursuant to this
9subsection.
10    (b-15) If the Commission issues an order pursuant to
11subsection (b-5), the affected electric utility shall contract
12with an entity not affiliated with the electric utility to
13serve as a program administrator to develop and implement a
14program to provide consumer outreach, enrollment, and
15education concerning real-time pricing and to establish and
16administer an information system and technical and other
17customer assistance that is necessary to enable customers to
18manage electricity use. The program administrator: (i) shall be
19selected and compensated by the electric utility, subject to
20Commission approval; (ii) shall have demonstrated technical
21and managerial competence in the development and
22administration of demand management programs; and (iii) may
23develop and implement risk management, energy efficiency, and
24other services related to energy use management for which the
25program administrator shall be compensated by participants in
26the program receiving such services. The electric utility shall

 

 

09900SB1585sam002- 173 -LRB099 09533 EGJ 48253 a

1provide the program administrator with all information and
2assistance necessary to perform the program administrator's
3duties, including, but not limited to, customer, account, and
4energy use data. The electric utility shall permit the program
5administrator to include inserts in residential customer bills
62 times per year to assist with customer outreach and
7enrollment.
8    The program administrator shall submit an annual report to
9the electric utility no later than April 1 of each year
10describing the operation and results of the program, including
11information concerning the number and types of customers using
12real-time pricing, changes in customers' energy use patterns,
13an assessment of the value of the program to both participants
14and non-participants, and recommendations concerning
15modification of the program and the tariff or tariffs filed
16under subsection (b-5). This report shall be filed by the
17electric utility with the Commission within 30 days of receipt
18and shall be available to the public on the Commission's web
19site.
20    (b-20) The Commission shall monitor the performance of
21programs established pursuant to subsection (b-15) and shall
22order the termination or modification of a program if it
23determines that the program is not, after a reasonable period
24of time for development not to exceed 4 years, resulting in net
25benefits to the residential customers of the electric utility.
26    (b-25) An electric utility shall be entitled to recover

 

 

09900SB1585sam002- 174 -LRB099 09533 EGJ 48253 a

1reasonable costs incurred in complying with this Section,
2provided that recovery of the costs is fairly apportioned among
3its residential customers as provided in this subsection
4(b-25). The electric utility may apportion greater costs on the
5residential customers who elect real-time pricing, but may also
6impose some of the costs of real-time pricing on customers who
7do not elect real-time pricing, provided that the Commission
8determines that the cost savings resulting from real-time
9pricing will exceed the costs imposed on customers for
10maintaining the program.
11    (c) The electric utility's tariff or tariffs filed pursuant
12to this Section shall be subject to Article IX.
13    (d) This Section does not apply to any electric utility
14providing service to 100,000 or fewer customers.
15(Source: P.A. 94-977, eff. 6-30-06.)
 
16    (220 ILCS 5/16-107.5)
17    Sec. 16-107.5. Net electricity metering.
18    (a) The Legislature finds and declares that a program to
19provide net electricity metering, as defined in this Section,
20for eligible customers can encourage private investment in
21renewable energy resources, stimulate economic growth, enhance
22the continued diversification of Illinois' energy resource
23mix, and protect the Illinois environment.
24    (b) As used in this Section, (i) "eligible customer" means
25a retail customer that owns or operates a solar, wind, or other

 

 

09900SB1585sam002- 175 -LRB099 09533 EGJ 48253 a

1eligible renewable electrical generating facility with a rated
2capacity of not more than 2,000 kilowatts that is located on
3the customer's premises and is intended primarily to offset the
4customer's own electrical requirements; (ii) "electricity
5provider" means an electric utility or alternative retail
6electric supplier; (iii) "eligible renewable electrical
7generating facility" means a generator powered by solar
8electric energy, wind, dedicated crops grown for electricity
9generation, agricultural residues, untreated and unadulterated
10wood waste, landscape trimmings, livestock manure, anaerobic
11digestion of livestock or food processing waste, fuel cells or
12microturbines powered by renewable fuels, or hydroelectric
13energy; and (iv) "net electricity metering" (or "net metering")
14means the measurement, during the billing period applicable to
15an eligible customer, of the net amount of electricity supplied
16by an electricity provider to the customer's premises or
17provided to the electricity provider by the customer.
18    (c) A net metering facility shall be equipped with metering
19equipment that can measure the flow of electricity in both
20directions at the same rate.
21        (1) For eligible customers whose electric service has
22    not been declared competitive pursuant to Section 16-113 of
23    this Act as of July 1, 2011 and whose electric delivery
24    service is provided and measured on a kilowatt-hour basis
25    and electric supply service is not provided based on hourly
26    pricing, this shall typically be accomplished through use

 

 

09900SB1585sam002- 176 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 177 -LRB099 09533 EGJ 48253 a

1    of electricity both into and out of the customer's facility
2    at the same rate and ratio, typically through the use of a
3    dual channel meter. If the eligible customer's existing
4    electric revenue meter does not meet this requirement, then
5    the costs of installing such equipment shall be paid for by
6    the customer.
7    (d) An electricity provider shall measure and charge or
8credit for the net electricity supplied to eligible customers
9or provided by eligible customers whose electric service has
10not been declared competitive pursuant to Section 16-113 of
11this the Act as of July 1, 2011 and whose electric delivery
12service is provided and measured on a kilowatt-hour basis and
13electric supply service is not provided based on hourly pricing
14in the following manner:
15        (1) If the amount of electricity used by the customer
16    during the billing period exceeds the amount of electricity
17    produced by the customer, the electricity provider shall
18    charge the customer for the net electricity supplied to and
19    used by the customer as provided in subsection (e-5) of
20    this Section.
21        (2) If the amount of electricity produced by a customer
22    during the billing period exceeds the amount of electricity
23    used by the customer during that billing period, the
24    electricity provider supplying that customer shall apply a
25    1:1 kilowatt-hour credit to a subsequent bill for service
26    to the customer for the net electricity supplied to the

 

 

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1    electricity provider. The electricity provider shall
2    continue to carry over any excess kilowatt-hour credits
3    earned and apply those credits to subsequent billing
4    periods to offset any customer-generator consumption in
5    those billing periods until all credits are used or until
6    the end of the annualized period.
7        (3) At the end of the year or annualized over the
8    period that service is supplied by means of net metering,
9    or in the event that the retail customer terminates service
10    with the electricity provider prior to the end of the year
11    or the annualized period, any remaining credits in the
12    customer's account shall expire.
13    (d-5) An electricity provider shall measure and charge or
14credit for the net electricity supplied to eligible customers
15or provided by eligible customers whose electric service has
16not been declared competitive pursuant to Section 16-113 of
17this Act as of July 1, 2011 and whose electric delivery service
18is provided and measured on a kilowatt-hour basis and electric
19supply service is provided based on hourly pricing in the
20following manner:
21        (1) If the amount of electricity used by the customer
22    during any hourly period exceeds the amount of electricity
23    produced by the customer, the electricity provider shall
24    charge the customer for the net electricity supplied to and
25    used by the customer according to the terms of the contract
26    or tariff to which the same customer would be assigned to

 

 

09900SB1585sam002- 179 -LRB099 09533 EGJ 48253 a

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

 

 

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

 

 

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1    (e-5) An electricity provider shall provide electric
2service to eligible customers who utilize net metering at
3non-discriminatory rates that are identical, with respect to
4rate structure, retail rate components, and any monthly
5charges, to the rates that the customer would be charged if not
6a net metering customer. An electricity provider shall not
7charge net metering customers any fee or charge or require
8additional equipment, insurance, or any other requirements not
9specifically authorized by interconnection standards
10authorized by the Commission, unless the fee, charge, or other
11requirement would apply to other similarly situated customers
12who are not net metering customers. The customer will remain
13responsible for all taxes, fees, and utility delivery charges
14that would otherwise be applicable to the net amount of
15electricity used by the customer. Subsections (c) through (e)
16of this Section shall not be construed to prevent an
17arms-length agreement between an electricity provider and an
18eligible customer that sets forth different prices, terms, and
19conditions for the provision of net metering service,
20including, but not limited to, the provision of the appropriate
21metering equipment for non-residential customers.
22    (f) Notwithstanding the requirements of subsections (c)
23through (e-5) of this Section, an electricity provider must
24require dual-channel metering for customers operating eligible
25renewable electrical generating facilities with a nameplate
26rating up to 2,000 kilowatts and to whom the provisions of

 

 

09900SB1585sam002- 182 -LRB099 09533 EGJ 48253 a

1neither subsection (d), (d-5), nor (e) of this Section apply.
2In such cases, electricity charges and credits shall be
3determined as follows:
4        (1) The electricity provider shall assess and the
5    customer remains responsible for all taxes, fees, and
6    utility delivery charges that would otherwise be
7    applicable to the gross amount of kilowatt-hours supplied
8    to the eligible customer by the electricity provider.
9        (2) Each month that service is supplied by means of
10    dual-channel metering, the electricity provider shall
11    compensate the eligible customer for any excess
12    kilowatt-hour credits at the electricity provider's
13    avoided cost of electricity supply over the monthly period
14    or as otherwise specified by the terms of a power-purchase
15    agreement negotiated between the customer and electricity
16    provider.
17        (3) For all eligible net metering customers taking
18    service from an electricity provider under contracts or
19    tariffs employing time of use rates, any monthly
20    consumption of electricity shall be calculated according
21    to the terms of the contract or tariff to which the same
22    customer would be assigned to or be eligible for if the
23    customer was not a net metering customer. When those same
24    customer-generators are net generators during any discrete
25    time of use period, the net kilowatt-hours produced shall
26    be valued at the same price per kilowatt-hour as the

 

 

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1    electric service provider would charge for retail
2    kilowatt-hour sales during that same time of use period.
3    (g) For purposes of federal and State laws providing
4renewable energy credits or greenhouse gas credits, the
5eligible customer shall be treated as owning and having title
6to the renewable energy attributes, renewable energy credits,
7and greenhouse gas emission credits related to any electricity
8produced by the qualified generating unit. The electricity
9provider may not condition participation in a net metering
10program on the signing over of a customer's renewable energy
11credits; provided, however, this subsection (g) shall not be
12construed to prevent an arms-length agreement between an
13electricity provider and an eligible customer that sets forth
14the ownership or title of the credits.
15    (h) Within 120 days after the effective date of this
16amendatory Act of the 95th General Assembly, the Commission
17shall establish standards for net metering and, if the
18Commission has not already acted on its own initiative,
19standards for the interconnection of eligible renewable
20generating equipment to the utility system. The
21interconnection standards shall address any procedural
22barriers, delays, and administrative costs associated with the
23interconnection of customer-generation while ensuring the
24safety and reliability of the units and the electric utility
25system. The Commission shall consider the Institute of
26Electrical and Electronics Engineers (IEEE) Standard 1547 and

 

 

09900SB1585sam002- 184 -LRB099 09533 EGJ 48253 a

1the issues of (i) reasonable and fair fees and costs, (ii)
2clear timelines for major milestones in the interconnection
3process, (iii) nondiscriminatory terms of agreement, and (iv)
4any best practices for interconnection of distributed
5generation.
6    (i) All electricity providers shall begin to offer net
7metering no later than April 1, 2008. However, this Section
8shall not apply to an electric utility, or the customers to
9which such utility provides delivery services, beginning on the
10date that the utility's tariff to recover its delivery services
11costs pursuant to subsection (a) of Section 9-105 of this Act
12takes effect, if any. Retail customers that are receiving net
13metering service pursuant to this Section at such time as this
14Section ceases to apply to the electric utility shall be
15entitled to continue the service pursuant to subsections (c)
16and (e) of Section 16-107.7 of this Act.
17    (j) An electricity provider shall provide net metering to
18eligible customers until the load of its net metering customers
19equals 5% of the total peak demand supplied by that electricity
20provider during the previous year. Electricity providers are
21authorized to offer net metering beyond the 5% level if they so
22choose.
23    (k) Each electricity provider shall maintain records and
24report annually to the Commission the total number of net
25metering customers served by the provider, as well as the type,
26capacity, and energy sources of the generating systems used by

 

 

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1the net metering customers. Nothing in this Section shall limit
2the ability of an electricity provider to request the redaction
3of information deemed by the Commission to be confidential
4business information. Each electricity provider shall notify
5the Commission when the total generating capacity of its net
6metering customers is equal to or in excess of the 5% cap
7specified in subsection (j) of this Section.
8    (l) Notwithstanding the definition of "eligible customer"
9in item (i) of subsection (b) of this Section, each electricity
10provider shall consider whether to allow meter aggregation for
11the purposes of net metering on:
12        (1) properties owned or leased by multiple customers
13    that contribute to the operation of an eligible renewable
14    electrical generating facility, such as a community-owned
15    wind project, a community-owned biomass project, a
16    community-owned solar project, or a community methane
17    digester processing livestock waste from multiple sources;
18    and
19        (2) individual units, apartments, or properties owned
20    or leased by multiple customers and collectively served by
21    a common eligible renewable electrical generating
22    facility, such as an apartment building served by
23    photovoltaic panels on the roof.
24    For the purposes of this subsection (l), "meter
25aggregation" means the combination of reading and billing on a
26pro rata basis for the types of eligible customers described in

 

 

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1this Section.
2    (m) Nothing in this Section shall affect the right of an
3electricity provider to continue to provide, or the right of a
4retail customer to continue to receive service pursuant to a
5contract for electric service between the electricity provider
6and the retail customer in accordance with the prices, terms,
7and conditions provided for in that contract. Either the
8electricity provider or the customer may require compliance
9with the prices, terms, and conditions of the contract.
10(Source: P.A. 97-616, eff. 10-26-11; 97-646, eff. 12-30-11;
1197-824, eff. 7-18-12.)
 
12    (220 ILCS 5/16-107.6 new)
13    Sec. 16-107.6. Net electricity metering.
14    (a) This Section shall apply to an electric utility, and
15the customers to which the utility provides delivery services,
16beginning on the date that the utility's tariff to recover its
17delivery services costs through a demand-based rate pursuant to
18subsection (a) of Section 9-105 of this Act takes effect, if
19any. A retail customer that is receiving net metering service
20pursuant to Section 16-107.5 of this Act at the time this
21Section applies to such electric utility, shall be entitled to
22continue such service pursuant to subsections (c) and (e) of
23Section 16-107.7 of this Act.
24    (b) As used in this Section:
25    "Eligible customer" means a retail customer that owns or

 

 

09900SB1585sam002- 187 -LRB099 09533 EGJ 48253 a

1operates a solar, wind, or other eligible renewable electrical
2generating facility with a rated capacity of not more than
32,000 kilowatts that is located on the customer's premises and
4is intended to offset the customer's own electrical
5requirements.
6    "Electricity provider" means an electric utility or
7alternative retail electric supplier.
8    "Eligible renewable electrical generating facility" means
9a generator that is connected to the utility's distribution
10system at a voltage of no greater than 12.47 kilovolts and is
11powered by solar electric energy, wind, dedicated crops grown
12for electricity generation, agricultural residues, untreated
13and unadulterated wood waste, landscape trimmings, livestock
14manure, anaerobic digestion of livestock or food processing
15waste, fuel cells or microturbines powered by renewable fuels,
16or hydroelectric energy.
17    "Net electricity metering" or "net metering" means the
18measurement, during the billing period applicable to an
19eligible customer, of the net amount of electricity supplied by
20an electricity provider to the customer's premises or provided
21to the electricity provider by the customer.
22    (c) A net metering facility shall be equipped with metering
23equipment that can measure the flow of electricity in both
24directions at the same rate. The electricity provider may
25arrange for the local electric utility or a meter service
26provider to install and maintain metering equipment capable of

 

 

09900SB1585sam002- 188 -LRB099 09533 EGJ 48253 a

1measuring the flow of electricity both into and out of the
2eligible customer's facility at the same rate and ratio,
3typically through the use of a dual channel meter.
4    (d) An electricity provider shall charge or credit for the
5net electricity supplied to eligible customers whose electric
6delivery service is provided and measured on a kilowatt demand
7basis and electric supply service is not provided based on
8hourly or time of use pricing in the following manner:
9        (1) If the amount of electricity used by the customer
10    during the billing period exceeds the amount of electricity
11    produced by the customer, then the electricity provider
12    shall charge the customer for the net kilowatt-hour based
13    electricity charges reflected in the customer's electric
14    service rate supplied to and used by the customer as
15    provided in subsection (f) of this Section.
16        (2) If the amount of electricity produced by a customer
17    during the billing period exceeds the amount of electricity
18    used by the customer during that billing period, then the
19    electricity provider supplying that customer shall apply a
20    1:1 kilowatt-hour credit that reflects the kilowatt-hour
21    based charges in the customer's electric service rate to a
22    subsequent bill for service to the customer for the net
23    electricity supplied to the electricity provider. The
24    electricity provider shall continue to carry over any
25    excess kilowatt-hour credits earned and apply those
26    credits to subsequent billing periods to offset any

 

 

09900SB1585sam002- 189 -LRB099 09533 EGJ 48253 a

1    customer-generator consumption in those billing periods
2    until all credits are used or until the end of the
3    annualized period.
4        (3) At the end of the year or annualized over the
5    period that service is supplied by means of net metering,
6    or in the event that the retail customer terminates service
7    with the electricity provider prior to the end of the year
8    or the annualized period, any remaining credits in the
9    customer's account shall expire.
10    (e) An electricity provider shall charge or credit for the
11net electricity supplied to eligible customers whose electric
12delivery service is provided and measured on a kilowatt-demand
13basis and electric supply service is provided based on hourly
14or time of use pricing in the following manner:
15        (1) If the amount of electricity used by the customer
16    during any hourly or time-of-use period exceeds the amount
17    of electricity produced by the customer, then the
18    electricity provider shall charge the customer for the net
19    electricity supplied to and used by the customer as
20    provided in subsection (f) of this Section.
21        (2) If the amount of electricity produced by a customer
22    during any hourly or time of use period exceeds the amount
23    of electricity used by the customer during that hourly or
24    time of use period, the energy provider shall calculate an
25    energy credit for the net kilowatt-hours produced in such
26    period. The value of the energy credit shall be calculated

 

 

09900SB1585sam002- 190 -LRB099 09533 EGJ 48253 a

1    using the same price per kilowatt-hour as the electric
2    service provider would charge for kilowatt-hour energy
3    sales during that same hourly or time of use period.
4    (f) An electricity provider shall provide electric service
5to eligible customers who utilize net metering at
6non-discriminatory rates that are identical, with respect to
7rate structure, retail rate components, and any monthly
8charges, to the rates that the customer would be charged if not
9a net metering customer. An electricity provider shall charge
10the customer for the net electricity supplied to and used by
11the customer according to the terms of the contract or tariff
12to which the same customer would be assigned or be eligible for
13if the customer was not a net metering customer. An electricity
14provider shall not charge net metering customers any fee or
15charge or require additional equipment, insurance, or any other
16requirements not specifically authorized by interconnection
17standards authorized by the Commission, unless the fee, charge,
18or other requirement would apply to other similarly situated
19customers who are not net metering customers. The customer
20remains responsible for the gross amount of delivery services
21charges and supply-related charges that are kilowatt based, as
22well as all taxes and fees related to such charges. The
23customer also remains responsible for all taxes and fees that
24would otherwise be applicable to the net amount of electricity
25used by the customer. Subsections (d) and (e) of this Section
26shall not be construed to prevent an arms-length agreement

 

 

09900SB1585sam002- 191 -LRB099 09533 EGJ 48253 a

1between an electricity provider and an eligible customer that
2sets forth different prices, terms, and conditions for the
3provision of net metering service, including, but not limited
4to, the provision of the appropriate metering equipment for
5non-residential customers. Nothing in this subsection (f)
6shall be interpreted to mandate that a utility that is only
7required to provide delivery services to a given customer must
8also sell electricity to such customer.
9    (g) For purposes of federal and State laws providing
10renewable energy credits or greenhouse gas credits, an
11electricity provider shall not, by virtue of providing net
12metering, be treated as owning and having title to the
13renewable energy attributes, renewable energy credits, and
14greenhouse gas emission credits related to any electricity
15produced by the qualified generating unit. The electric utility
16may not condition participation in a net metering program on
17the signing over of a customer's renewable energy credits;
18provided, however, this subsection (g) shall not be construed
19to prevent an arms-length agreement between an electricity
20provider and an eligible customer that sets forth the ownership
21or title of the credits.
22    (h) Each electricity provider shall maintain records and
23report annually to the Commission the total number of net
24metering customers served by the electricity provider, as well
25as the type, capacity, and energy sources of the generating
26systems used by the net metering customers. Nothing in this

 

 

09900SB1585sam002- 192 -LRB099 09533 EGJ 48253 a

1Section shall limit the ability of an electricity provider to
2request the redaction of confidential business information.
3    (i) Notwithstanding the definition of "eligible customer"
4in subsection (c) of this Section, each electricity provider
5shall allow meter aggregation for the purposes of net metering
6on:
7        (1) properties owned or leased by multiple customers
8    that contribute to the operation of an eligible renewable
9    electrical generating facility through an ownership or
10    leasehold interest of at least 2 kilowatts in such
11    facility, such as a community-owned biomass project, a
12    community-owned solar project, or a community methane
13    digester processing livestock waste from multiple sources,
14    provided that the address at which each such customer
15    receives electric service from the electric utility must be
16    located within 5 miles of the location of the facility and
17    that the facility is also located within the utility's
18    service territory; and
19        (2) individual units, apartments, or properties
20    located in a single building that are owned or leased by
21    multiple customers and collectively served by a common
22    eligible renewable electrical generating facility, such as
23    an office or apartment building, a shopping center or strip
24    mall served by photovoltaic panels on the roof.
25        In addition, the demand of the properties, units, or
26    apartments identified in subparagraphs (1) and (2) of this

 

 

09900SB1585sam002- 193 -LRB099 09533 EGJ 48253 a

1    subsection (i) whose meters are aggregated and that
2    contribute to or are served by an eligible renewable
3    electrical generating facility shall not exceed 2,000
4    kilowatts in nameplate capacity in total. For the purposes
5    of this subsection (i), "meter aggregation" means the
6    combination of reading and billing on a pro rata basis for
7    the types of customers described in this subsection (i).
8    For purposes of facilitating such reading and billing, the
9    owner or operator of the eligible renewable electrical
10    generating facility shall be responsible for determining
11    the amount of the credit that each customer participating
12    in meter aggregation pursuant to this subsection (i) is to
13    receive in the following manner:
14            (A) For those participating customers who receive
15        their energy supply from an electricity provider that
16        is an electric utility, the owner or operator shall, on
17        a monthly basis, calculate the monetary value of the
18        energy credit for each such customer that is to be
19        applied to the customer's electric utility bill by the
20        electricity provider. The owner or operator shall
21        calculate such monthly credit for each such customer in
22        accordance with the customer's share of the eligible
23        renewable electric generating facility's output of
24        power and energy for a given month and the
25        cents-per-kilowatt-hour price of power and energy
26        supply service set forth in the applicable tariff or

 

 

09900SB1585sam002- 194 -LRB099 09533 EGJ 48253 a

1        tariffs of the customer's electricity provider for
2        that same month. In the event that more than one price
3        for power and energy supply service was in effect
4        during the applicable month, the owner or operator
5        shall calculate the credit based on an appropriate
6        weighting. The owner or operator shall electronically
7        transmit such calculations and data to the electricity
8        provider, in a format or method as agreed to by the
9        electricity provider and the owner or operator, on a
10        monthly basis so that the electricity provider can
11        reflect the monetary credits on customers' electric
12        utility bills. The electricity provider shall be
13        permitted to revise its tariffs to implement the
14        provisions of this amendatory Act of the 99th General
15        Assembly. The owner or operator shall separately
16        provide the electricity provider with the
17        documentation detailing the calculations supporting
18        the credit in the manner set forth in the applicable
19        tariff.
20            (B) For those participating customers who receive
21        their energy supply from an alternative retail
22        electric supplier, the owner or operator shall
23        determine the monthly credit, in a dollar amount, and
24        provide the information to the alternative retail
25        electric supplier in a manner set forth in such
26        alternative retail electric supplier's meter

 

 

09900SB1585sam002- 195 -LRB099 09533 EGJ 48253 a

1        aggregation program, or as otherwise agreed between
2        the parties.
3    (j) Each electric utility subject to this Section shall
4file a tariff to implement the provisions of subsection (i) of
5this Section in conjunction with the tariff that the utility
6files to implement subsection (a) of Section 9-105 of this Act,
7which shall, consistent with the provisions of such subsection,
8describe the terms and conditions pursuant to which owners or
9operators of qualifying properties, units, or apartments may
10participate in meter aggregation for purposes of net metering.
11The tariff approved pursuant to this subsection shall become
12effective on the same date that the tariff implementing
13subsection (a) of Section 9-105 of this Act becomes effective.
14    (k) Nothing in this Section shall affect the right of an
15electricity provider to continue to provide, or the right of a
16retail customer to continue to receive service pursuant to a
17contract for electric service between the electricity provider
18and the retail customer in accordance with the prices, terms,
19and conditions provided for in that contract. Either the
20electricity provider or the customer may require compliance
21with the prices, terms, and conditions of the contract.
 
22    (220 ILCS 5/16-107.7 new)
23    Sec. 16-107.7. Distributed generation rebate.
24    (a) In this Section:
25    "Smart inverter" means a device that converts direct

 

 

09900SB1585sam002- 196 -LRB099 09533 EGJ 48253 a

1current into alternating current and can autonomously
2contribute to grid support during excursions from normal
3operating voltage and frequency conditions by providing each of
4the following: dynamic reactive and real power support, voltage
5and frequency ride-through, ramp rate controls, communication
6systems with ability to accept external commands, and other
7functions from the electric utility.
8    "Threshold date" means:
9        (1) For distributed generation that is located in the
10    service territory of an electric utility that serves more
11    than 3,000,000 retail customers in the State, the date on
12    which the combined nameplate capacity of such distributed
13    generation located in such service territory that is
14    enrolled in the rebate programs implemented pursuant to
15    this Section reaches 150 megawatts; and
16        (2) For distributed generation that is located in the
17    service territory of an electric utility that serves
18    3,000,000 or less retail customers in the State, the date
19    on which the combined nameplate capacity of distributed
20    generation located in such service territory that is
21    enrolled the rebate programs implemented pursuant to this
22    Section reaches 75 megawatts.
23    (b) An electric utility that serves more than 200,000
24customers in the State may file a petition with the Commission
25requesting approval of the utility's tariff to provide a rebate
26to a retail customer who owns or operates distributed

 

 

09900SB1585sam002- 197 -LRB099 09533 EGJ 48253 a

1generation that meets the following criteria:
2        (1) has a nameplate generating capacity no greater than
3    2,000 kilowatts and is designed not to exceed the peak load
4    of the customer's premises;
5        (2) is located on the customer's premises, for the
6    customer's own use, and not for commercial use or sales,
7    including, but not limited to, wholesale sales of electric
8    power and energy;
9        (3) is located in the electric utility's service
10    territory; and
11        (4) is connected to the utility's distribution system
12    at a voltage of no greater than 12.47 kilovolts by means of
13    the inverter or smart inverter required by this Section, as
14    applicable.
15The tariff shall provide that the utility shall be permitted to
16operate and control the smart inverter associated with the
17distributed generation that is the subject of the rebate and
18shall address the terms and conditions of the operation and the
19compensation associated with the operation.
20    If an electric utility elects to recover its costs of
21providing delivery services to retail customers pursuant to
22subsection (a) of Section 9-105 of this Act, it shall be
23required to file the proposed tariffs described in this
24Section. Such tariff or tariffs, as applicable, shall be filed
25with the tariffs filed to implement subsection (a) of Section
269-105 of this Act, and shall become effective upon the same

 

 

09900SB1585sam002- 198 -LRB099 09533 EGJ 48253 a

1date that the tariffs filed to implement subsection (a) of
2Section 9-105 become effective.
3    (c) The proposed tariff authorized by subsection (b) of
4this Section shall include the following participation terms
5and formulae to calculate the value of the rebates to be
6applied pursuant to this Section for distributed generation
7that satisfies the criteria set forth in subsection (b) of this
8Section:
9        (1) Until the earlier of the threshold date or December
10    31, 2021:
11            (A) Retail customers may, as applicable, make the
12        following elections:
13                (i) Residential customers that are taking
14            service pursuant to a net metering program offered
15            by an electricity provider under the terms of
16            Section 16-107.5 of this Act on the effective date
17            of this amendatory Act of the 99th General Assembly
18            may elect to either continue to take such service
19            pursuant to the terms of such program as in effect
20            on such effective date for the useful life of the
21            customer's eligible renewable electric generating
22            facility as defined in such Section, or file an
23            application to receive a rebate pursuant to the
24            terms of this Section, provided that such
25            application must be submitted within 6 months
26            after the effective date of the tariff approved

 

 

09900SB1585sam002- 199 -LRB099 09533 EGJ 48253 a

1            under this subsection (c) and the inverter
2            associated with such customer's distributed
3            generation need not be a smart inverter.
4                (ii) Residential customers that begin taking
5            service pursuant to a net metering program offered
6            by an electricity provider under the terms of
7            Section 16-107.5 of this Act after the effective
8            date of this amendatory Act of the 99th General
9            Assembly may elect to either continue to take such
10            service pursuant to the terms of such program as in
11            effect on such effective date until December 31,
12            2021, or file an application to receive a rebate
13            pursuant to the terms of this Section, provided,
14            however, that the inverter associated with the
15            customer's distributed generation must be a smart
16            inverter.
17                (iii) Non-residential customers that are
18            taking service pursuant to a net metering program
19            offered by an electricity provider under the terms
20            of Section 16-107.5 of this Act on the effective
21            date of this amendatory Act of the 99th General
22            Assembly may apply for a rebate as provided for in
23            this Section, provided that the inverter
24            associated with such customer's distributed
25            generation need not be a smart inverter.
26                (iv) Non-residential customers that begin

 

 

09900SB1585sam002- 200 -LRB099 09533 EGJ 48253 a

1            taking service pursuant to a net metering program
2            offered by an electricity provider under the terms
3            of Section 16-107.5 of this Act after the effective
4            date of this amendatory Act of the 99th General
5            Assembly may apply for a rebate as provided for in
6            this Section; however, the inverter associated
7            with the customer's distributed generation must be
8            a smart inverter.
9        Upon approval of a rebate application submitted under
10        items (i) or (ii) of this subparagraph (A), the retail
11        customer shall no longer be entitled to receive any
12        delivery service credits for the excess electricity
13        generated by its facility.
14            (B) The value of the rebates shall be:
15                (i) $1,000 per kilowatt of nameplate
16            generating capacity, measured as nominal DC power
17            output, of a residential customer's distributed
18            generation; and
19                (ii) $500 per kilowatt of nameplate generating
20            capacity, measured as nominal DC power output, of a
21            non-residential customer's distributed generation.
22        (2) After the threshold date but until no later than
23    December 31, 2021:
24            (A) Retail customers may, as applicable, make the
25        following elections:
26                (i) Residential customers that begin taking

 

 

09900SB1585sam002- 201 -LRB099 09533 EGJ 48253 a

1            service pursuant to a net metering program offered
2            by an electricity provider under the terms of
3            Section 16-107.5 of this Act after the threshold
4            date may elect to either continue to take such
5            service pursuant to the terms of such program until
6            December 31, 2021 or, within 6 months after the
7            date of the customer's first bill that reflects net
8            metering, file an application to receive a rebate
9            pursuant to the terms of this Section, provided,
10            however, that the inverter associated with such
11            customer's distributed generation must be a smart
12            inverter. Upon approval of such application, the
13            retail customer shall no longer be entitled to
14            receive any delivery service credits for the
15            excess electricity generated by its facility.
16                (ii) Non-residential customers that begin
17            taking service pursuant to a net metering program
18            offered by an electricity provider under the terms
19            of Section 16-107.5 of this Act after the threshold
20            date may apply for a rebate as provided for in this
21            Section; however, the inverter associated with the
22            customer's distributed generation must be a smart
23            inverter.
24            (B) The value of the rebates shall be:
25                (i) $750 per kilowatt of nameplate generating
26            capacity, measured as nominal DC power output, of a

 

 

09900SB1585sam002- 202 -LRB099 09533 EGJ 48253 a

1            residential customer's distributed generation; and
2                (ii) $325 per kilowatt of nameplate generating
3            capacity, measured as nominal DC power output, of a
4            non-residential customer's distributed generation.
5        (3) The value of the rebates identified in this
6    subsection (c) shall be adjusted in proportion to the
7    actual nameplate capacity of the distributed generation
8    that is the subject of a rebate application submitted
9    pursuant to this Section.
10    (d) The Commission shall review the proposed tariff
11submitted pursuant to subsections (b) and (c) of this Section
12and may make changes to the tariff that are consistent with
13this Section and with the Commission's authority under Article
14IX of this Act, subject to notice and hearing. Following notice
15and hearing, the Commission shall issue an order approving, or
16approving with modification, such tariff no later than 240 days
17after the utility files its tariff.
18    (e) No later than June 1, 2021, an electric utility that
19elected, or was required, to file a tariff pursuant to this
20Section shall file a tariff with the Commission that proposes
21an annual process and formula for calculating the value of
22rebates for the retail customers described in subsection (b) of
23this Section that submit rebate applications after December 31,
242021. The value of such rebates shall be cost-based and reflect
25the value of the distributed generation to the distribution
26system at the location at which it is interconnected. Retail

 

 

09900SB1585sam002- 203 -LRB099 09533 EGJ 48253 a

1customers who elect to submit rebate applications after
2December 31, 2021, including all retail customers who are
3taking net metering and whose delivery service credits will
4terminate after December 31, 2021, shall receive the rebate
5provided for by this Section that is in effect at the time the
6application is submitted less the total amount of delivery
7service credits that the retail customer has received under any
8net metering program. The retail customer shall then no longer
9be entitled to receive any delivery service credits for the
10excess electricity generated by its facility. The Commission
11shall review and, after notice and hearing, approve, or approve
12with modification, the utility's proposed tariff. If the
13Commission modifies such tariff, the modifications shall be
14consistent with this Section and the Commission's authority
15under Article IX of this Act.
16    (f) Notwithstanding any provision of this Act to the
17contrary, the owner, developer, or customer of a generation
18facility that is part of a meter aggregation program provided
19pursuant to subsection (i) of Section 16-107.6 of this Act
20shall also be eligible to apply for the rebate described in
21subsections (b) and (c) of this Section. A customer of the
22generation facility may apply for a rebate only if the owner or
23developer has not already submitted an application, and may be
24allowed an amount as described in subsection (c) or (e) of this
25Section applicable to such customer on the date that the
26application is submitted. If the owner or developer submits the

 

 

09900SB1585sam002- 204 -LRB099 09533 EGJ 48253 a

1application, the amount of the rebate shall be in proportion to
2the mix of customers that subscribe to the output of the
3facility on the date that an application for the rebate is
4submitted, less any rebates that have been applied for or
5provided to customers of the generation facility. An
6application for a rebate for a portion of a project described
7in this subsection (d) may be submitted at or after the time
8that a related request for net metering is made.
9    (g) No later than 180 days after the utility receives an
10application for a rebate pursuant to its tariff approved under
11subsection (b) or (c) of this Section, the utility shall issue
12a rebate to the applicant pursuant to the terms of the tariff.
13In the event the application is incomplete or the utility is
14otherwise unable to calculate the payment based on the
15information provided by the owner, the utility shall issue the
16payment no later than 180 days after the application is
17complete or all requested information is received.
18    (h) An electric utility shall recover from its retail
19customers all of the costs of the rebates made pursuant to a
20tariff or tariffs placed into effect under this Section,
21including, but not limited to, the value of the rebates and all
22costs incurred by the utility to comply with and implement this
23Section, consistent with the following provisions:
24        (1) The utility shall defer the full amount of its
25    costs incurred pursuant to this Section as a regulatory
26    asset. The total costs deferred as a regulatory asset shall

 

 

09900SB1585sam002- 205 -LRB099 09533 EGJ 48253 a

1    be amortized over a 15-year period. The unamortized balance
2    shall be recognized as of December 31 for a given year. The
3    utility shall also earn a return on the total of the
4    unamortized balance of the regulatory assets, less any
5    deferred taxes related to the unamortized balance, at an
6    annual rate equal to the utility's weighted average cost of
7    capital that includes, based on a year-end capital
8    structure, the utility's actual cost of debt for the
9    applicable calendar year and a cost of equity, which shall
10    be calculated as the sum of (i) the average for the
11    applicable calendar year of the monthly average yields of
12    30-year U.S. Treasury bonds published by the Board of
13    Governors of the Federal Reserve System in its weekly H.15
14    Statistical Release or successor publication; and (ii) 580
15    basis points, including a revenue conversion factor
16    calculated to recover or refund all additional income taxes
17    that may be payable or receivable as a result of that
18    return.
19        When an electric utility creates a regulatory asset
20    pursuant to the provisions of this Section, the costs are
21    recovered over a period during which customers also receive
22    a benefit, which is in the public interest. Accordingly, it
23    is the intent of the General Assembly that an electric
24    utility that elects to create a regulatory asset pursuant
25    to the provisions of this Section shall recover all of the
26    associated costs, including, but not limited to, its cost

 

 

09900SB1585sam002- 206 -LRB099 09533 EGJ 48253 a

1    of capital as set forth in this Section. After the
2    Commission has approved the prudence and reasonableness of
3    the costs that comprise the regulatory asset, the electric
4    utility shall be permitted to recover all such costs, and
5    the value and recoverability through rates of the
6    associated regulatory asset shall not be limited, altered,
7    impaired, or reduced.
8        (2) The utility, at its election, may recover all of
9    the costs it incurs pursuant to this Section as part of a
10    filing for a general increase in rates under Article IX of
11    this Act, as part of an annual filing to update a
12    performance-based formula rate pursuant to subsection (d)
13    of Section 16-108.5 of this Act, or through an automatic
14    adjustment clause tariff. If the utility elects to recover
15    the costs it incurs under this Section through an automatic
16    adjustment clause tariff, the utility may file its proposed
17    tariff together with the tariff it files pursuant to
18    subsection (b) of this Section or at a later time. The
19    proposed tariff shall provide for an annual
20    reconciliation, less any deferred taxes related to the
21    reconciliation, with interest at an annual rate of return
22    equal to the utility's weighted average cost of capital as
23    calculated pursuant to paragraph (1) of this subsection
24    (h), including a revenue conversion factor calculated to
25    recover or refund all additional income taxes that may be
26    payable or receivable as a result of that return, of the

 

 

09900SB1585sam002- 207 -LRB099 09533 EGJ 48253 a

1    revenue requirement reflected in rates for each calendar
2    year, beginning with the calendar year in which the utility
3    files its automatic adjustment clause tariff pursuant to
4    this subsection (h), with what the revenue requirement
5    would have been had the actual cost information for the
6    applicable calendar year been available at the filing date.
7    The Commission shall review the proposed tariff and may
8    make changes to the tariff that are consistent with this
9    Section and with the Commission's authority under Article
10    IX of this Act, subject to notice and hearing. Following
11    notice and hearing, the Commission shall issue an order
12    approving, or approving with modification, such tariff no
13    later than 240 days after the utility files its tariff.
14    (i) Within 180 days after the effective date of this
15amendatory Act of the 99th General Assembly, each electric
16utility with net metering customers on such effective date
17shall provide notice of the availability of rebates under this
18Section. Subsequent to the effective date, any entity that
19offers in the State, for sale or lease, distributed generation
20and estimates the dollar saving attributable to such
21distributed generation shall provide estimates based on both
22delivery service credits and the rebates available under this
23Section.
 
24    (220 ILCS 5/16-108)
25    Sec. 16-108. Recovery of costs associated with the

 

 

09900SB1585sam002- 208 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 209 -LRB099 09533 EGJ 48253 a

1of its customers for purposes of delivery services charges.
2Delivery services shall be priced and made available to all
3retail customers electing delivery services in each such class
4on a nondiscriminatory basis regardless of whether the retail
5customer chooses the electric utility, an affiliate of the
6electric utility, or another entity as its supplier of electric
7power and energy. Charges for delivery services shall be cost
8based, and shall allow the electric utility to recover the
9costs of providing delivery services through its charges to its
10delivery service customers that use the facilities and services
11associated with such costs. Such costs shall include the costs
12of owning, operating and maintaining transmission and
13distribution facilities. The Commission shall also be
14authorized to consider whether, and if so to what extent, the
15following costs are appropriately included in the electric
16utility's delivery services rates: (i) the costs of that
17portion of generation facilities used for the production and
18absorption of reactive power in order that retail customers
19located in the electric utility's service area can receive
20electric power and energy from suppliers other than the
21electric utility, and (ii) the costs associated with the use
22and redispatch of generation facilities to mitigate
23constraints on the transmission or distribution system in order
24that retail customers located in the electric utility's service
25area can receive electric power and energy from suppliers other
26than the electric utility. Nothing in this subsection shall be

 

 

09900SB1585sam002- 210 -LRB099 09533 EGJ 48253 a

1construed as directing the Commission to allocate any of the
2costs described in (i) or (ii) that are found to be
3appropriately included in the electric utility's delivery
4services rates to any particular customer group or geographic
5area in setting delivery services rates.
6    (d) The Commission shall establish charges, terms and
7conditions for delivery services that are just and reasonable
8and shall take into account customer impacts when establishing
9such charges. In establishing charges, terms and conditions for
10delivery services, the Commission shall take into account
11voltage level differences. A retail customer shall have the
12option to request to purchase electric service at any delivery
13service voltage reasonably and technically feasible from the
14electric facilities serving that customer's premises provided
15that there are no significant adverse impacts upon system
16reliability or system efficiency. A retail customer shall also
17have the option to request to purchase electric service at any
18point of delivery that is reasonably and technically feasible
19provided that there are no significant adverse impacts on
20system reliability or efficiency. Such requests shall not be
21unreasonably denied.
22    (e) Electric utilities shall recover the costs of
23installing, operating or maintaining facilities for the
24particular benefit of one or more delivery services customers,
25including without limitation any costs incurred in complying
26with a customer's request to be served at a different voltage

 

 

09900SB1585sam002- 211 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 212 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 213 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 214 -LRB099 09533 EGJ 48253 a

1subsection (h) of this Section. Provided, however, that an
2electric utility, other than an electric utility providing
3service to at least 1,000,000 customers in this State on
4January 1, 1999, shall be entitled to petition for entry of an
5order by the Commission authorizing the electric utility to
6implement transition charges for an additional period ending no
7later than December 31, 2008. The electric utility shall file
8its petition with supporting evidence no earlier than 16
9months, and no later than 12 months, prior to December 31,
102006. The Commission shall hold a hearing on the electric
11utility's petition and shall enter its order no later than 8
12months after the petition is filed. The Commission shall
13determine whether and to what extent the electric utility shall
14be authorized to implement transition charges for an additional
15period. The Commission may authorize the electric utility to
16implement transition charges for some or all of the additional
17period, and shall determine the mitigation factors to be used
18in implementing such transition charges; provided, that the
19Commission shall not authorize mitigation factors less than
20110% of those in effect during the 12 months ended December 31,
212006. In making its determination, the Commission shall
22consider the following factors: the necessity to implement
23transition charges for an additional period in order to
24maintain the financial integrity of the electric utility; the
25prudence of the electric utility's actions in reducing its
26costs since the effective date of this amendatory Act of 1997;

 

 

09900SB1585sam002- 215 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 216 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 217 -LRB099 09533 EGJ 48253 a

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

 

 

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1number of kilowatt-hours per year obtained from the
2cogeneration or self-generation facilities during the 3 years
3prior to the date on which the customer became eligible for
4delivery services, except as provided in subsection (f) of
5Section 16-110.
6    (k) The electric utility shall be entitled to recover
7through tariffed charges all of the costs associated with the
8purchase of zero emission credits from zero emission resources
9to meet the requirements of subsection (d-5) of Section 1-75 of
10the Illinois Power Agency Act. The costs shall be allocated
11across all retail customers through a single, uniform cents per
12kilowatt-hour charge applicable to all retail customers, which
13shall appear as a separate line item on each customer's bill.
14Beginning June 1, 2018, the electric utility shall be entitled
15to recover through tariffed charges all of the costs associated
16with the purchase of renewable energy resources to meet the
17renewable energy resource standards of subsection (c) of
18Section 1-75 of the Illinois Power Agency Act, pursuant to the
19electric utility's procurement plan as approved in accordance
20with Section 16-111.5 of this Act. The costs associated with
21the purchase of renewable energy resources shall be allocated
22across all retail customers in proportion to the amount of
23renewable energy resources the utility procures for such
24customers through a single, uniform cents per kilowatt-hour
25charge applicable to such retail customers, which shall appear
26as a separate line item on each such customer's bill.

 

 

09900SB1585sam002- 219 -LRB099 09533 EGJ 48253 a

1    The electric utility shall be entitled to recover all costs
2associated with the purchase of renewable energy resources and
3zero emission credits from zero emission resources through an
4automatic adjustment clause tariff applicable to all of the
5utility's retail customers that allows the electric utility to
6adjust its tariffed charges on a quarterly basis for changes in
7its costs incurred to purchase such resources and credits, if
8any, without the need to file a general delivery services rate
9case. The electric utility's collections pursuant to such an
10automatic adjustment clause tariff shall be subject to annual
11review, reconciliation, and true-up against actual costs by the
12Commission pursuant to a procedure that shall be specified in
13the electric utility's automatic adjustment clause tariff and
14that shall be approved by the Commission in connection with its
15approval of such tariff. The procedure shall provide that any
16difference between the electric utility's collection pursuant
17to the automatic adjustment charge for an annual period and the
18electric utility's actual costs of renewable energy resources
19and zero emission credits from zero emission resources for that
20same annual period shall be refunded to or collected from, as
21applicable, the electric utility's retail customers in
22subsequent periods.
23    Nothing in this subsection (k) is intended to affect,
24limit, or change the right of the electric utility to recover
25the costs associated with the procurement of renewable energy
26resources for periods commencing before, on, or after June 1,

 

 

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12018, as otherwise provided in the Illinois Power Agency Act.
2(Source: P.A. 91-50, eff. 6-30-99; 92-690, eff. 7-18-02.)
 
3    (220 ILCS 5/16-108.9 new)
4    Sec. 16-108.9. Microgrid pilot.
5    (a) The General Assembly finds that the electric industry
6is undergoing rapid transformation, including fundamental
7changes regarding how electricity is generated, procured, and
8delivered and how customers are choosing to participate in the
9supply and delivery of electricity to and from the electric
10grid. Building upon the State's goals to increase the
11procurement of electricity from renewable energy resources and
12distributed generation, the General Assembly finds that it is
13now necessary to study how the electric grid could be enhanced
14through reliance on the diverse supply options being connected
15to the grid by traditional suppliers and new market
16participants, such as the utility's customers. Specifically,
17the General Assembly finds that these developments present
18unprecedented opportunities to strengthen the resilience and
19security of the electric grid, particularly with respect to the
20grid's support of the State's critical infrastructure
21dedicated to public safety and health purposes. The General
22Assembly therefore finds that it is beneficial to undertake the
23microgrid pilot described in this Section to explore a variety
24of objectives, including, but not limited to, (i) alternatives
25to upgrading the conventional electric grid, (ii) ways to

 

 

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1improve electric grid resiliency, security, and outage
2management for critical facilities and customers and thus
3reduce the frequency, duration, and cost of major outages, and
4(iii) how to improve the safety and security of critical
5electric infrastructure, including cyber security, for the
6benefit of the public.
7    (b) An electric utility serving more than 3,000,000 retail
8customers in Illinois may invest an estimated $250,000,000 to
9develop, construct, and install up to 5 microgrids in its
10service territory over a 5-year period that commences upon the
11date of the Commission's approval of the plan, or approval of
12the plan on rehearing, whichever is later, submitted pursuant
13to subsection (d) of this Section. Notwithstanding such
14investment amount, a utility that elects to undertake the
15investment described in this subsection (b) shall also be
16authorized to study, operate, and maintain such microgrids.
17    An electric utility serving 3,000,000 or less retail
18customers but more than 500,000 retail customers in Illinois
19may invest a maximum of $60,000,000 to develop, construct, and
20install one or more microgrids, as determined in the utility's
21sole discretion, in its service territory over a 5-year period
22that commences upon the date of the Commission's approval of
23the plan, or approval of the plan on rehearing, whichever is
24later, submitted pursuant to subsection (d) of this Section.
25Notwithstanding such investment amount, a utility that elects
26to undertake the investment described in this subsection (b)

 

 

09900SB1585sam002- 222 -LRB099 09533 EGJ 48253 a

1shall also be authorized to study, operate, and maintain such
2microgrids.
3    For purposes of this Section, "microgrid" means a group of
4interconnected loads and distributed energy resources with
5clearly defined electrical boundaries that acts as a single
6controllable entity with respect to the grid and can connect
7and disconnect from the grid to enable it to operate in both
8grid-connected or island modes.
9        (1) The locations selected to be served by the
10    microgrids shall include critical public health and safety
11    facilities and critical infrastructure and transportation
12    facilities that provide opportunities to study the
13    operation and benefits of the microgrid. Facilities and
14    locations may include, but are not limited to, the
15    following: military; fire fighting; police; aviation;
16    medical and health; HazMat; civil defense and public safety
17    warning services; communications; radiological, chemical
18    and other special weapons defense; water pumping and
19    treatment facilities; and energy delivery. Nothing in this
20    Section shall be interpreted to limit the utility's ability
21    to coordinate with governmental agencies regarding the
22    selection of locations and facilities to be served.
23    Consistent with the provisions of this paragraph (1), an
24    electric utility serving more than 3,000,000 retail
25    customers in Illinois that elects to undertake the
26    investment described in this Section may develop,

 

 

09900SB1585sam002- 223 -LRB099 09533 EGJ 48253 a

1    construct, operate, maintain, and study microgrids located
2    at or within the following sites in its service territory:
3            (A) the Bronzeville community of Chicago, whose
4        boundaries are approximately Pershing Road, 31st
5        Street, King Drive and the Dan Ryan Expressway;
6            (B) the Illinois Medical District as defined by
7        Section 1 of the Illinois Medical District Act;
8            (C) an airport, as that term is defined by the
9        Illinois Aeronautics Act, that is located in Winnebago
10        County;
11            (D) a county emergency and disaster services
12        facility; and
13            (E) the water pumping and treatment facilities
14        located in the city of Chicago Heights.
15        In the event one or more of the sites approved by the
16    Commission pursuant to subsection (d) of this Section
17    becomes unsuitable or unavailable to accommodate a
18    microgrid project, the electric utility may select an
19    alternative site or sites consistent with the provisions of
20    this paragraph (1). If the utility selects an alternative
21    site or sites, the utility shall submit an informational
22    filing to the Commission that identifies the alternative
23    site or sites within 90 days after such selection.
24        (2) Notwithstanding any law, rule, or order to the
25    contrary, an electric utility that undertakes the
26    investment authorized by this subsection (b):

 

 

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1            (A) shall study electric generating plant and
2        facilities and electric storage plant and facilities
3        that are part of the microgrids, which may include, but
4        not be limited to, the construction, installation,
5        leasing, or ownership of the following technologies:
6        (i) solar photovoltaic facilities; (ii) fuel cells;
7        (iii) natural gas generation, including generation
8        that utilizes combined heat and power; (iv) an
9        electricity storage plant and facilities; (v)
10        geothermal technologies; and (vi) wind turbines;
11            (B) shall be permitted to use the plant or
12        facilities described in subparagraph (A) of this
13        paragraph (2) as follows: (i) for distribution system
14        purposes, (ii) as a source of power, energy, and
15        ancillary services for retail customers located within
16        the boundaries of the microgrid during interruptions
17        of services on the distribution system serving the
18        microgrid or such customers, provided that the use of
19        the plant and facilities during these periods and the
20        delivery of electric power and energy that they produce
21        shall be considered and treated as a distribution
22        system reliability function and not as a retail sale of
23        power, and (iii) for sales of energy, power, heat,
24        ancillary services, and other related products and
25        services into any available markets, including, but
26        not limited to, wholesale markets, provided that such

 

 

09900SB1585sam002- 225 -LRB099 09533 EGJ 48253 a

1        sales do not compromise operation of the microgrid; a
2        utility's decision to make or refrain from making such
3        sales in order to maintain the integrity of the
4        microgrid shall not be an unreasonable or imprudent
5        decision;
6            (C) may upgrade the delivery facilities in and
7        supporting the areas served by and in the vicinity of
8        the microgrid, including, but not limited to,
9        constructing, installing, operating, and maintaining
10        (i) multiple feeders to provide service within and to
11        the microgrid, (ii) distribution automation and other
12        smart grid facilities, which shall be incremental to
13        the investment amounts set forth in Section 16-108.5 of
14        this Act, and (iii) placing underground distribution
15        facilities within and providing service to the
16        microgrid; and
17            (D) shall not be required to obtain any
18        certificates of public convenience and necessity under
19        Section 8-406 of this Act or any approvals under
20        Sections 9-212, 9-213, or 16-111.5 of this Act.
21    (c) An electric utility that elects to undertake the
22investment described in subsection (b) of this Section may, at
23its election, recover the costs of such investment through an
24automatic adjustment clause tariff or through a delivery
25services charge regardless of how the costs are classified on
26the utility's books and records of account. Regardless of which

 

 

09900SB1585sam002- 226 -LRB099 09533 EGJ 48253 a

1cost recovery mechanism the electric utility elects, the
2utility shall earn a return on the balance of the related plant
3investment as of December 31 for a given year, less any related
4accumulated depreciation and any related deferred taxes, at an
5annual rate equal to the utility's weighted average cost of
6capital that includes, based on a year-end capital structure,
7the utility's actual cost of debt for the applicable calendar
8year and a cost of equity, which shall be calculated as the sum
9of the (i) the average for the applicable calendar year of the
10monthly average yields of 30-year U.S. Treasury bonds published
11by the Board of Governors of the Federal Reserve System in its
12weekly H.15 Statistical Release or successor publication and
13(ii) 580 basis points, including a revenue conversion factor
14calculated to recover or refund all additional income taxes
15that may be payable or receivable as a result of that return.
16    In the event the utility elects to file an automatic
17adjustment clause tariff, such tariff may be filed and
18established outside the context of a general rate case filing
19or a filing under subsection (c) or (d) of Section 16-108.5 of
20this Act. The Commission shall review and, after notice and
21hearing, by order approve or approve with modification the
22proposed tariff no later than 90 days after the filing of the
23tariff. A utility may elect to reflect the charges recovered
24through the tariff as a separate line item on customers' bills,
25but shall not be required to do so. A tariff approved and
26placed into effect pursuant to this Section shall remain in

 

 

09900SB1585sam002- 227 -LRB099 09533 EGJ 48253 a

1effect at the discretion of the utility, and the utility may
2elect to withdraw the tariff at any time. At such time as the
3tariff ceases to be in effect, the utility shall recover its
4costs incurred pursuant to this Section through a delivery
5services charge regardless of how the costs are categorized or
6classified on the utility's books and records of account.
7    An electric utility that elects to undertake the investment
8described in subsection (b) of this Section shall also recover
9the costs it incurs to study, operate, and maintain the
10microgrid projects pursuant to this Section and may, at its
11election, recover such costs through an automatic adjustment
12clause tariff placed into effect pursuant to this Section, if
13applicable, or through its delivery services charges.
14    (d) If an electric utility elects to undertake the
15investment authorized by subsection (b) of this Section, then
16the utility shall submit to the Commission the utility's plan
17for developing, constructing, operating, and analyzing
18microgrids in its service territory for the 5-year period
19commencing upon the plan's approval, or approval of the plan on
20rehearing, whichever is later. Such plan shall describe:
21        (1) the utility's current projections for scope,
22    microgrid locations and boundaries, schedule,
23    expenditures, and staffing;
24        (2) the utility's projections regarding the sale into
25    wholesale markets of power generated pursuant to the plant
26    or facilities described in subparagraph (A) of paragraph

 

 

09900SB1585sam002- 228 -LRB099 09533 EGJ 48253 a

1    (2) of subsection (b) of this Section, including how such
2    sales will be executed and revenues applied to offset the
3    costs of the microgrid pilot; and
4        (3) the criteria, including specific performance
5    metrics, for evaluating the extent to which the microgrids
6    developed under this Section achieved the objectives set
7    out in subsection (a) of this Section.
8    Within 90 days after the utility files its plan pursuant to
9this subsection (d), the Commission shall review and, after
10notice and hearing, enter an order approving the plan if it
11finds that the plan conforms to the requirements of this
12Section or, if the Commission finds that the plan does not
13conform to the requirements of this Section, the Commission
14must enter an order describing in detail the reasons for not
15approving the plan. The utility may resubmit its plan to
16address the Commission's concerns, and the Commission shall
17expeditiously review and by order approve the revised plan if
18it finds that the plan conforms to the requirements of this
19Section, provided that such order shall be entered no later
20than 90 days after the utility resubmits its plan.
21    No later than 90 days after the close of each plan year,
22the utility shall submit a report to the Commission that
23includes any updates to the plan, a schedule for the
24development of any proposed microgrids for the next plan year,
25the expenditures made for the prior plan year and cumulatively,
26an evaluation of the extent to which the objectives of this

 

 

09900SB1585sam002- 229 -LRB099 09533 EGJ 48253 a

1microgrid pilot are being achieved, and the number of full-time
2equivalent jobs created for the prior plan year and
3cumulatively. Within 60 days after the utility files its annual
4report, the Commission may enter into an investigation of the
5report. If the Commission commences an investigation, it must,
6after notice and hearing, enter an order approving the report
7or approving the report with modification necessary to bring it
8into compliance with this Section no later than 180 days after
9the utility files such report. If the Commission does not
10initiate an investigation within 60 days after the utility
11files its annual report, then the filing shall be deemed
12accepted by the Commission.
13    The utility may continue operating, maintaining, and
14studying the microgrids developed and constructed pursuant to
15this Section following the end of the 5-year plan period, and
16the costs incurred by the utility regarding such continued
17operation, maintenance and studying and to comply with the
18requirements of this Section shall continue to be recoverable
19following the end of the 5-year plan period through the
20automatic adjustment clause tariff authorized by this Section
21or other cost recovery mechanism elected by the utility.
22However, any generating or storage facility that becomes
23inoperable after the initial 5-year period may not be replaced
24without the approval of the Commission unless the facility will
25be used solely for the purposes described in subparagraph (B)
26of paragraph (2) of subsection (b) of this Section.

 

 

09900SB1585sam002- 230 -LRB099 09533 EGJ 48253 a

1    To the extent feasible and consistent with State and
2federal law, the investments made pursuant to this Section
3should provide employment opportunities for all segments of the
4population and workforce, including minority-owned and
5female-owned business enterprises, and shall not, consistent
6with State and federal law, discriminate based on race or
7socioeconomic status.
8    (e) No later than 365 days following the end of the 5-year
9plan period, the electric utility shall submit its final report
10to the Commission evaluating the extent to which the objectives
11of this microgrid pilot have been achieved, reporting on its
12performance under the metrics established in the plan, and
13proposing any additional study or action required to continue
14the further development of microgrids in the electric utility's
15service territory. Thereafter, the Commission may convene a
16workshop or workshops to discuss the results of the evaluation
17reflected in the final report. In addition, an electric utility
18that serves more than 3,000,000 retail customers in the State
19shall demonstrate that it created an average of 50 full-time
20equivalent jobs in Illinois, per microgrid project, during the
21construction and operation of the microgrids over a 5-year
22period. The jobs shall include direct jobs, contractor
23positions, and induced jobs. If the Commission enters an order
24finding, after notice and hearing, that the utility did not
25satisfy its job commitment described in this subsection (e) for
26reasons that are reasonably within its control, then the

 

 

09900SB1585sam002- 231 -LRB099 09533 EGJ 48253 a

1Commission shall also determine, after consideration of the
2evidence, including, but not limited to, evidence submitted by
3the Department of Commerce and Economic Opportunity and the
4utility, the deficiency in the number of full-time equivalent
5jobs due to such failure. The Commission shall notify the
6Department of any proceeding that is initiated pursuant to this
7subsection (e). For each full-time equivalent job deficiency
8that the Commission finds as set forth in this subsection (e),
9the utility shall, within 30 days after the entry of the
10Commission's order, pay $6,000 to a fund for training grants
11administered under Section 605-800 of the Department of
12Commerce and Economic Opportunity Law, which shall not be a
13recoverable expense.
14    No later than 365 days following the date on which the
15utility submits its final report pursuant to this subsection
16(e), the Commission shall submit a report to the General
17Assembly evaluating the extent to which the objectives of the
18microgrid pilot have been achieved, reporting on the utility's
19performance under the metrics established in its plan, and
20proposing any additional study or action required to continue
21the further development of microgrids in the utility's service
22territory.
23    (f) In no event, absent General Assembly approval, shall
24the capital investment costs incurred by an electric utility
25pursuant to this Section exceed $300,000,000 for a utility that
26serves more than 3,000,000 retail customers in the State. If

 

 

09900SB1585sam002- 232 -LRB099 09533 EGJ 48253 a

1the utility's updated cost estimates for implementing its plan
2exceed the limitation imposed by this subsection (f), then it
3shall submit 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 utility
8files the report, report to the General Assembly its findings
9regarding the utility's report. If the General Assembly does
10not amend the limitation imposed by this subsection (f), then
11the utility may modify its plan so as not to exceed the
12limitation imposed by this subsection (f) and may propose
13corresponding changes in its plan, and the Commission may
14modify the metrics established pursuant to this Section
15accordingly.
16    (g) All facilities and equipment installed pursuant to this
17Section shall be considered and functionalized for ratemaking
18purposes as distribution facilities and equipment for purposes
19of Articles IX and XVI of this Act, and the expense of
20operating, maintaining, and studying such facilities shall be
21considered and functionalized for ratemaking purposes as
22distribution expense regardless of how the facilities,
23equipment, and costs are categorized or classified on the
24utility's books and records of account.
25    (h) Nothing in this Section is intended to limit or expand
26the ability of any other entity to develop, construct, or

 

 

09900SB1585sam002- 233 -LRB099 09533 EGJ 48253 a

1install a microgrid. In addition, nothing in this Section is
2intended to limit, expand, or alter otherwise applicable
3interconnection requirements.
 
4    (220 ILCS 5/16-108.10 new)
5    Sec. 16-108.10. Energy low-income and support program.
6Beginning in 2017, without obtaining any approvals from the
7Commission or any other agency, regardless of whether any such
8approval would otherwise be required, a participating utility
9that is not a combination utility, as defined by Section
1016-108.5 of this Act, shall contribute $10,000,000 per year for
115 years to the energy low-income and support program, which is
12intended to fund customer assistance programs with the primary
13purpose being avoidance of imminent disconnection and
14reconnecting customers who have been disconnected for
15non-payment. Such programs may include:
16        (1) a residential hardship program that may partner
17    with community-based organizations, including senior
18    citizen organizations, and provides grants to low-income
19    residential customers, including low-income senior
20    citizens, who demonstrate a hardship;
21        (2) a program that provides grants and other bill
22    payment concessions to disabled veterans who demonstrate a
23    hardship and members of the armed services or reserve
24    forces of the United States or members of the Illinois
25    National Guard who are on active duty pursuant to an

 

 

09900SB1585sam002- 234 -LRB099 09533 EGJ 48253 a

1    executive order of the President of the United States, an
2    act of the Congress of the United States, or an order of
3    the Governor and who demonstrate a hardship;
4        (3) a budget assistance program that provides tools and
5    education to low-income senior citizens to assist them with
6    obtaining information regarding energy usage and effective
7    means of managing energy costs;
8        (4) a non-residential special hardship program that
9    provides grants to non-residential customers, such as
10    small businesses and non-profit organizations, that
11    demonstrate a hardship, including those providing services
12    to senior citizen and low-income customers; and
13        (5) a performance-based assistance program that
14    provides grants to encourage residential customers to make
15    on-time payments by matching a portion of the customer's
16    payments or providing credits towards arrearages.
17    The payments made by a participating utility pursuant to
18this Section shall not be a recoverable expense. A
19participating utility may elect to fund either new or existing
20customer assistance programs, including, but not limited to,
21those that are administered by the utility.
22    Programs that use funds that are provided by an electric
23utility to reduce utility bills may be implemented through
24tariffs that are filed with and reviewed by the Commission. If
25a utility elects to file tariffs with the Commission to
26implement all or a portion of the programs, those tariffs

 

 

09900SB1585sam002- 235 -LRB099 09533 EGJ 48253 a

1shall, regardless of the date actually filed, be deemed
2accepted and approved and shall become effective on the first
3business day after they are filed. The electric utilities whose
4customers benefit from the funds that are disbursed as
5contemplated in this Section shall file annual reports
6documenting the disbursement of those funds with the
7Commission. The Commission may audit disbursement of the funds
8to ensure they were disbursed consistently with this Section.
9    If the Commission finds that a participating utility is no
10longer eligible to update the performance-based formula rate
11tariff pursuant to subsection (d) of Section 16-108.5 of this
12Act or the performance-based formula rate is otherwise
13terminated, then the participating utility's obligations under
14this Section shall immediately terminate.
 
15    (220 ILCS 5/16-111.5)
16    Sec. 16-111.5. Provisions relating to procurement.
17    (a) An electric utility that on December 31, 2005 served at
18least 100,000 customers in Illinois shall procure power and
19energy for its eligible retail customers in accordance with the
20applicable provisions set forth in Section 1-75 of the Illinois
21Power Agency Act and this Section. Beginning with the planning
22year commencing on June 1, 2017, such electric utility shall
23also procure zero emission credits from zero emission resources
24for all retail customers in its service territory in accordance
25with the applicable provisions set forth in Section 1-75 of the

 

 

09900SB1585sam002- 236 -LRB099 09533 EGJ 48253 a

1Illinois Power Agency Act, and, for years beginning on or after
2June 1, 2018, the utility shall procure renewable energy
3resources for all of the utility's retail customers in its
4service territory in accordance with the applicable provisions
5set forth in Section 1-75 of the Illinois Power Agency Act and
6this Section. A small multi-jurisdictional electric utility
7that on December 31, 2005 served less than 100,000 customers in
8Illinois may elect to procure power and energy for all or a
9portion of its eligible Illinois retail customers in accordance
10with the applicable provisions set forth in this Section and
11Section 1-75 of the Illinois Power Agency Act. This Section
12shall not apply to a small multi-jurisdictional utility until
13such time as a small multi-jurisdictional utility requests the
14Illinois Power Agency to prepare a procurement plan for its
15eligible retail customers. "Eligible retail customers" for the
16purposes of this Section means those retail customers that
17purchase power and energy from the electric utility under
18fixed-price bundled service tariffs, other than those retail
19customers whose service is declared or deemed competitive under
20Section 16-113 and those other customer groups specified in
21this Section, including self-generating customers, customers
22electing hourly pricing, or those customers who are otherwise
23ineligible for fixed-price bundled tariff service. For those
24Those customers that are excluded from the definition of
25"eligible retail customers" shall not be included in the
26procurement plan's electric supply service plan load

 

 

09900SB1585sam002- 237 -LRB099 09533 EGJ 48253 a

1requirements, and the utility shall procure any supply
2requirements, including capacity, ancillary services, and
3hourly priced energy, in the applicable markets as needed to
4serve those customers, provided that the utility may include in
5its procurement plan load requirements for the load that is
6associated with those retail customers whose service has been
7declared or deemed competitive pursuant to Section 16-113 of
8this Act to the extent that those customers are purchasing
9power and energy during one of the transition periods
10identified in subsection (b) of Section 16-113 of this Act.
11    (b) A procurement plan shall be prepared for each electric
12utility consistent with the applicable requirements of the
13Illinois Power Agency Act and this Section. For purposes of
14this Section, Illinois electric utilities that are affiliated
15by virtue of a common parent company are considered to be a
16single electric utility. Small multi-jurisdictional utilities
17may request a procurement plan for a portion of or all of its
18Illinois load. Each procurement plan shall analyze the
19projected balance of supply and demand for those retail
20customers to be included in the plan's electric supply service
21requirements, eligible retail customers over a 5-year period,
22with the first planning year beginning on June 1 of the year
23following the year in which the plan is filed. The plan shall
24specifically identify the wholesale products to be procured
25following plan approval, and shall follow all the requirements
26set forth in the Public Utilities Act and all applicable State

 

 

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1and federal laws, statutes, rules, or regulations, as well as
2Commission orders. Nothing in this Section precludes
3consideration of contracts longer than 5 years and related
4forecast data. Unless specified otherwise in this Section, in
5the procurement plan or in the implementing tariff, any
6procurement occurring in accordance with this plan shall be
7competitively bid through a request for proposals process.
8Approval and implementation of the procurement plan shall be
9subject to review and approval by the Commission according to
10the provisions set forth in this Section. A procurement plan
11shall include each of the following components:
12        (1) Hourly load analysis. This analysis shall include:
13            (i) multi-year historical analysis of hourly
14        loads;
15            (ii) switching trends and competitive retail
16        market analysis;
17            (iii) known or projected changes to future loads;
18        and
19            (iv) growth forecasts by customer class.
20        (2) Analysis of the impact of any demand side and
21    renewable energy initiatives. This analysis shall include:
22            (i) the impact of demand response programs and
23        energy efficiency programs, both current and
24        projected; for small multi-jurisdictional utilities,
25        the impact of demand response and energy efficiency
26        programs approved pursuant to Section 8-408 of this

 

 

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1        Act, both current and projected; and
2            (ii) supply side needs that are projected to be
3        offset by purchases of renewable energy resources, if
4        any.
5        (3) A plan for meeting the expected load requirements
6    that will not be met through preexisting contracts. This
7    plan shall include:
8            (i) definitions of the different Illinois retail
9        customer classes for which supply is being purchased;
10            (ii) the proposed mix of demand-response products
11        for which contracts will be executed during the next
12        year. For small multi-jurisdictional electric
13        utilities that on December 31, 2005 served fewer than
14        100,000 customers in Illinois, these shall be defined
15        as demand-response products offered in an energy
16        efficiency plan approved pursuant to Section 8-408 of
17        this Act. The cost-effective demand-response measures
18        shall be procured whenever the cost is lower than
19        procuring comparable capacity products, provided that
20        such products shall:
21                (A) be procured by a demand-response provider
22            from those eligible retail customers included in
23            the plan's electric supply service requirements;
24                (B) at least satisfy the demand-response
25            requirements of the regional transmission
26            organization market in which the utility's service

 

 

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1            territory is located, including, but not limited
2            to, any applicable capacity or dispatch
3            requirements;
4                (C) provide for customers' participation in
5            the stream of benefits produced by the
6            demand-response products;
7                (D) provide for reimbursement by the
8            demand-response provider of the utility for any
9            costs incurred as a result of the failure of the
10            supplier of such products to perform its
11            obligations thereunder; and
12                (E) meet the same credit requirements as apply
13            to suppliers of capacity, in the applicable
14            regional transmission organization market;
15            (iii) monthly forecasted system supply
16        requirements, including expected minimum, maximum, and
17        average values for the planning period;
18            (iv) the proposed mix and selection of standard
19        wholesale products for which contracts will be
20        executed during the next year, separately or in
21        combination, to meet that portion of its load
22        requirements not met through pre-existing contracts,
23        including but not limited to monthly 5 x 16 peak period
24        block energy, monthly off-peak wrap energy, monthly 7 x
25        24 energy, annual 5 x 16 energy, annual off-peak wrap
26        energy, annual 7 x 24 energy, monthly capacity, annual

 

 

09900SB1585sam002- 241 -LRB099 09533 EGJ 48253 a

1        capacity, peak load capacity obligations, capacity
2        purchase plan, and ancillary services;
3            (v) proposed term structures for each wholesale
4        product type included in the proposed procurement plan
5        portfolio of products; and
6            (vi) an assessment of the price risk, load
7        uncertainty, and other factors that are associated
8        with the proposed procurement plan; this assessment,
9        to the extent possible, shall include an analysis of
10        the following factors: contract terms, time frames for
11        securing products or services, fuel costs, weather
12        patterns, transmission costs, market conditions, and
13        the governmental regulatory environment; the proposed
14        procurement plan shall also identify alternatives for
15        those portfolio measures that are identified as having
16        significant price risk.
17        (4) Proposed procedures for balancing loads. The
18    procurement plan shall include, for load requirements
19    included in the procurement plan, the process for (i)
20    hourly balancing of supply and demand and (ii) the criteria
21    for portfolio re-balancing in the event of significant
22    shifts in load.
23        (5) Renewable energy resources plan. The procurement
24    plan shall include a renewable energy resources plan that
25    shall ensure adequate, reliable, affordable, efficient,
26    and environmentally sustainable renewable energy resources

 

 

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1    at the lowest total cost over time, taking into account any
2    benefits of price stability. The renewable energy
3    resources plan shall include:
4            (i) a description of the renewable energy
5        resources, including renewable energy credits proposed
6        to be procured pursuant to Section 1-56 and subsection
7        (c) of Section 1-75 of the Illinois Power Agency Act;
8            (ii) a planning horizon and a comparison of the
9        projected costs and benefits of procuring renewable
10        resources for various contract terms based on market
11        evidence; and
12            (iii) an explanation of how the Illinois Power
13        Agency plans to utilize available funds for its planned
14        renewable energy procurement, identifying specifically
15        the source of funds to be used, including the Illinois
16        Power Agency Renewable Energy Resources Fund, moneys
17        accumulated by the electric utility in respect of
18        service to customers under hourly pricing tariffs
19        pursuant to paragraph (5) of subsection (c) of Section
20        1-75 of the Illinois Power Agency Act, alternative
21        compliance payments remitted to the electric utility
22        pursuant to Section 16-115D of the Public Utilities
23        Act, and any other moneys to be collected by the
24        electric utility for procurements conducted pursuant
25        to paragraph (1) of subsection (c) of Section 1-75 of
26        the Illinois Power Agency Act. Available funds shall be

 

 

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1        prioritized as follows: new long-term contracts for
2        renewable energy resources procured from photovoltaic
3        distribution generation resources; new long-term
4        contracts for renewable energy resources procured from
5        brownfield site projects or utility scale photovoltaic
6        projects; and other one-year contracts for wind and
7        other renewable energy resources.
8    (c) The procurement process set forth in Section 1-75 of
9the Illinois Power Agency Act and subsection (e) of this
10Section shall be administered by a procurement administrator
11and monitored by a procurement monitor.
12        (1) The procurement administrator shall:
13            (i) design the final procurement process in
14        accordance with Section 1-75 of the Illinois Power
15        Agency Act and subsection (e) of this Section following
16        Commission approval of the procurement plan;
17            (ii) develop benchmarks in accordance with
18        subsection (e)(3) to be used to evaluate bids; these
19        benchmarks shall be submitted to the Commission for
20        review and approval on a confidential basis prior to
21        the procurement event;
22            (iii) serve as the interface between the electric
23        utility and suppliers;
24            (iv) manage the bidder pre-qualification and
25        registration process;
26            (v) obtain the electric utilities' agreement to

 

 

09900SB1585sam002- 244 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 245 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 246 -LRB099 09533 EGJ 48253 a

1process shall be conducted as follows:
2        (1) Beginning in 2008, each Illinois utility procuring
3    power pursuant to this Section shall annually provide a
4    range of load forecasts to the Illinois Power Agency by
5    July 15 of each year, or such other date as may be required
6    by the Commission or Agency. The load forecasts shall cover
7    the 5-year procurement planning period for the next
8    procurement plan and shall include hourly data
9    representing a high-load, low-load and expected-load
10    scenario for the load of those the eligible retail
11    customers included in the plan's electric supply service
12    requirements. The utility shall provide supporting data
13    and assumptions for each of the scenarios.
14        (2) Beginning in 2008, the Illinois Power Agency shall
15    prepare a procurement plan by August 15th of each year, or
16    such other date as may be required by the Commission. The
17    procurement plan shall identify the portfolio of
18    demand-response and power and energy products to be
19    procured. Cost-effective demand-response measures shall be
20    procured as set forth in item (iii) of subsection (b) of
21    this Section. Copies of the procurement plan shall be
22    posted and made publicly available on the Agency's and
23    Commission's websites, and copies shall also be provided to
24    each affected electric utility. An affected utility shall
25    have 30 days following the date of posting to provide
26    comment to the Agency on the procurement plan. Other

 

 

09900SB1585sam002- 247 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 248 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 249 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 250 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 251 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 252 -LRB099 09533 EGJ 48253 a

1        procurement monitor, and the Commission staff shall
2        meet within 10 days to analyze potential causes of low
3        supplier interest or causes for the Commission
4        decision. If changes are identified that would likely
5        result in increased supplier participation, or that
6        would address concerns causing the Commission to
7        reject the results of the prior procurement event, the
8        procurement administrator may implement those changes
9        and rerun the request for proposals process according
10        to a schedule determined by those parties and
11        consistent with Section 1-75 of the Illinois Power
12        Agency Act and this subsection. In any event, a new
13        request for proposals process shall be implemented by
14        the procurement administrator within 90 days after the
15        determination that the procurement process has failed
16        to fully meet the expected load requirement.
17            (iii) In all cases where there is insufficient
18        supply provided under contracts awarded through the
19        procurement process to fully meet the electric
20        utility's load requirement, the utility shall meet the
21        load requirement by procuring power and energy from the
22        applicable regional transmission organization market,
23        including ancillary services, capacity, and day-ahead
24        or real time energy or both; provided, however, that if
25        a needed product is not available through the regional
26        transmission organization market it shall be purchased

 

 

09900SB1585sam002- 253 -LRB099 09533 EGJ 48253 a

1        from the wholesale market.
2        (6) The procurement process described in this
3    subsection is exempt from the requirements of the Illinois
4    Procurement Code, pursuant to Section 20-10 of that Code.
5    (f) Within 2 business days after opening the sealed bids,
6the procurement administrator shall submit a confidential
7report to the Commission. The report shall contain the results
8of the bidding for each of the products along with the
9procurement administrator's recommendation for the acceptance
10and rejection of bids based on the price benchmark criteria and
11other factors observed in the process. The procurement monitor
12also shall submit a confidential report to the Commission
13within 2 business days after opening the sealed bids. The
14report shall contain the procurement monitor's assessment of
15bidder behavior in the process as well as an assessment of the
16procurement administrator's compliance with the procurement
17process and rules. The Commission shall review the confidential
18reports submitted by the procurement administrator and
19procurement monitor, and shall accept or reject the
20recommendations of the procurement administrator within 2
21business days after receipt of the reports.
22    (g) Within 3 business days after the Commission decision
23approving the results of a procurement event, the utility shall
24enter into binding contractual arrangements with the winning
25suppliers using the standard form contracts; except that the
26utility shall not be required either directly or indirectly to

 

 

09900SB1585sam002- 254 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 255 -LRB099 09533 EGJ 48253 a

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

 

 

09900SB1585sam002- 256 -LRB099 09533 EGJ 48253 a

1    electric utility's plan shall be specific, supported by
2    data or other detailed analyses. The electric utility may
3    file a response to any objections to its procurement plan
4    within 7 days after the date objections are due to be
5    filed. Within 7 days after the date the utility's response
6    is due, the Commission shall determine whether a hearing is
7    necessary. If it determines that a hearing is necessary, it
8    shall require the hearing to be completed and issue an
9    order on the procurement plan within 60 days after the
10    filing of the procurement plan by the electric utility.
11        (ii) The order shall approve or modify the procurement
12    plan, approve an independent procurement administrator,
13    and approve or modify the electric utility's tariffs that
14    are proposed with the initial procurement plan. The
15    Commission shall approve the procurement plan if the
16    Commission determines that it will ensure 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    (k) In order to promote price stability for residential and
21small commercial customers during the transition to
22competition in Illinois, and notwithstanding any other
23provision of this Act, each electric utility subject to this
24Section shall enter into one or more multi-year financial swap
25contracts that become effective on the effective date of this
26amendatory Act. These contracts may be executed with generators

 

 

09900SB1585sam002- 257 -LRB099 09533 EGJ 48253 a

1and power marketers, including affiliated interests of the
2electric utility. These contracts shall be for a term of no
3more than 5 years and shall, for each respective utility or for
4any Illinois electric utilities that are affiliated by virtue
5of a common parent company and that are thereby considered a
6single electric utility for purposes of this subsection (k),
7not exceed in the aggregate 3,000 megawatts for any hour of the
8year. The contracts shall be financial contracts and not energy
9sales contracts. The contracts shall be executed as
10transactions under a negotiated master agreement based on the
11form of master agreement for financial swap contracts sponsored
12by the International Swaps and Derivatives Association, Inc.
13and shall be considered pre-existing contracts in the
14utilities' procurement plans for residential and small
15commercial customers. Costs incurred pursuant to a contract
16authorized by this subsection (k) shall be deemed prudently
17incurred and reasonable in amount and the electric utility
18shall be entitled to full cost recovery pursuant to the tariffs
19filed with the Commission.
20    (k-5) In order to promote price stability for residential
21and small commercial customers during the infrastructure
22investment program described in subsection (b) of Section
2316-108.5 of this Act, and notwithstanding any other provision
24of this Act or the Illinois Power Agency Act, for each electric
25utility that serves more than one million retail customers in
26Illinois, the Illinois Power Agency shall conduct a procurement

 

 

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1event within 120 days after October 26, 2011 (the effective
2date of Public Act 97-616) and may procure contracts for energy
3and renewable energy credits for the period June 1, 2013
4through December 31, 2017 that satisfy the requirements of this
5subsection (k-5), including the benchmarks described in this
6subsection. These contracts shall be entered into as the result
7of a competitive procurement event, and, to the extent that any
8provisions of this Section or the Illinois Power Agency Act do
9not conflict with this subsection (k-5), such provisions shall
10apply to the procurement event. The energy contracts shall be
11for 24 hour by 7 day supply over a term that runs from the first
12delivery year through December 31, 2017. For a utility that
13serves over 2 million customers, the energy contracts shall be
14multi-year with pricing escalating at 2.5% per annum. The
15energy contracts may be designed as financial swaps or may
16require physical delivery.
17    Within 30 days of October 26, 2011 (the effective date of
18Public Act 97-616), each such utility shall submit to the
19Agency updated load forecasts for the period June 1, 2013
20through December 31, 2017. The megawatt volume of the contracts
21shall be based on the updated load forecasts of the minimum
22monthly on-peak or off-peak average load requirements shown in
23the forecasts, taking into account any existing energy
24contracts in effect as well as the expected migration of the
25utility's customers to alternative retail electric suppliers.
26The renewable energy credit volume shall be based on the number

 

 

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1of credits that would satisfy the requirements of subsection
2(c) of Section 1-75 of the Illinois Power Agency Act, subject
3to the rate impact caps and other provisions of subsection (c)
4of Section 1-75 of the Illinois Power Agency Act. The
5evaluation of contract bids in the competitive procurement
6events for energy and for renewable energy credits shall
7incorporate price benchmarks set collaboratively by the
8Agency, the procurement administrator, the staff of the
9Commission, and the procurement monitor. If the contracts are
10swap contracts, then they shall be executed as transactions
11under a negotiated master agreement based on the form of master
12agreement for financial swap contracts sponsored by the
13International Swaps and Derivatives Association, Inc. Costs
14incurred pursuant to a contract authorized by this subsection
15(k-5) shall be deemed prudently incurred and reasonable in
16amount and the electric utility shall be entitled to full cost
17recovery pursuant to the tariffs filed with the Commission.
18    The cost of administering the procurement event described
19in this subsection (k-5) shall be paid by the winning supplier
20or suppliers to the procurement administrator through a
21supplier fee. In the event that there is no winning supplier
22for a particular utility, such utility will pay the procurement
23administrator for the costs associated with the procurement
24event, and those costs shall not be a recoverable expense.
25Nothing in this subsection (k-5) is intended to alter the
26recovery of costs for any other procurement event.

 

 

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

 

 

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1costs of procuring electric supply for which it contracted
2before the effective date of this Section in conjunction with
3the provision of full requirements service under fixed-price
4bundled service tariffs subsequent to December 31, 2006. All
5such costs shall be deemed to have been prudently incurred. The
6pass-through tariffs that are filed and approved pursuant to
7this Section shall not be subject to review under, or in any
8way limited by, Section 16-111(i) of this Act. All of the costs
9incurred by the electric utility associated with the purchase
10of zero emission credits in accordance with subsection (d-5) of
11Section 1-75 of the Illinois Power Agency Act and, beginning
12June 1, 2018, all of the costs incurred by the electric utility
13associated with the purchase of renewable energy resources in
14accordance with subsection (c) of Section 1-75 of the Illinois
15Power Agency Act, shall be recovered through the electric
16utility's tariffed charges applicable to all of the retail
17customers in its service territory, as specified in subsection
18(k) of Section 16-108 of this Act, and shall not be recovered
19through the electric utility's tariffed charges for electric
20power and energy supply to its eligible retail customers.
21    (m) The Commission has the authority to adopt rules to
22carry out the provisions of this Section. For the public
23interest, safety, and welfare, the Commission also has
24authority to adopt rules to carry out the provisions of this
25Section on an emergency basis immediately following the
26effective date of this amendatory Act.

 

 

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

 

 

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1pre-existing contract under subsection (b) of this Section. The
2Commission shall in any order approving a proposal under this
3subsection specify how the utility will recover the prudently
4incurred costs of investing in, leasing, owning, or operating
5such generation facility through just and reasonable rates
6charged to those eligible retail customers included in the
7plan's electric supply service requirements. Cost recovery for
8facilities included in the utility's procurement plan pursuant
9to this subsection shall not be subject to review under or in
10any way limited by the provisions of Section 16-111(i) of this
11Act. Nothing in this Section is intended to prohibit a utility
12from filing for a fuel adjustment clause as is otherwise
13permitted under Section 9-220 of this Act.
14(Source: P.A. 97-325, eff. 8-12-11; 97-616, eff. 10-26-11;
1597-813, eff. 7-13-12.)
 
16    (220 ILCS 5/16-111.5B)
17    Sec. 16-111.5B. Provisions relating to energy efficiency
18procurement.
19    (a) Procurement Beginning in 2012, procurement plans
20prepared and filed pursuant to Section 16-111.5 of this Act
21during the years 2012 through 2015 shall be subject to the
22following additional requirements:
23        (1) The analysis included pursuant to paragraph (2) of
24    subsection (b) of Section 16-111.5 shall also include the
25    impact of energy efficiency building codes or appliance

 

 

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1    standards, both current and projected.
2        (2) The procurement plan components described in
3    subsection (b) of Section 16-111.5 shall also include an
4    assessment of opportunities to expand the programs
5    promoting energy efficiency measures that have been
6    offered under plans approved pursuant to Section 8-103 of
7    this Act or to implement additional cost-effective energy
8    efficiency programs or measures.
9        (3) In addition to the information provided pursuant to
10    paragraph (1) of subsection (d) of Section 16-111.5 of this
11    Act, each Illinois utility procuring power pursuant to that
12    Section shall annually provide to the Illinois Power Agency
13    by July 15 of each year, or such other date as may be
14    required by the Commission or Agency, an assessment of
15    cost-effective energy efficiency programs or measures that
16    could be included in the procurement plan. The assessment
17    shall include the following:
18            (A) A comprehensive energy efficiency potential
19        study for the utility's service territory that was
20        completed within the past 3 years.
21            (B) Beginning in 2014, the most recent analysis
22        submitted pursuant to Section 8-103A of this Act and
23        approved by the Commission under subsection (f) of
24        Section 8-103 of this Act.
25            (C) Identification of new or expanded
26        cost-effective energy efficiency programs or measures

 

 

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1        that are incremental to those included in energy
2        efficiency and demand-response plans approved by the
3        Commission pursuant to Section 8-103 of this Act and
4        that would be offered to all retail customers whose
5        electric service has not been declared competitive
6        under Section 16-113 of this Act and who are eligible
7        to purchase power and energy from the utility under
8        fixed-price bundled service tariffs, regardless of
9        whether such customers actually do purchase such power
10        and energy from the utility.
11            (D) Analysis showing that the new or expanded
12        cost-effective energy efficiency programs or measures
13        would lead to a reduction in the overall cost of
14        electric service.
15            (E) Analysis of how the cost of procuring
16        additional cost-effective energy efficiency measures
17        compares over the life of the measures to the
18        prevailing cost of comparable supply.
19            (F) An energy savings goal, expressed in
20        megawatt-hours, for the year in which the measures will
21        be implemented.
22            (G) For each expanded or new program, the estimated
23        amount that the program may reduce the agency's need to
24        procure supply.
25        In preparing such assessments, a utility shall conduct
26    an annual solicitation process for purposes of requesting

 

 

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1    proposals from third-party vendors, the results of which
2    shall be provided to the Agency as part of the assessment,
3    including documentation of all bids received. The utility
4    shall develop requests for proposals consistent with the
5    manner in which it develops requests for proposals under
6    plans approved pursuant to Section 8-103 of this Act, which
7    considers input from the Agency and interested
8    stakeholders.
9        (4) The Illinois Power Agency shall include in the
10    procurement plan prepared pursuant to paragraph (2) of
11    subsection (d) of Section 16-111.5 of this Act energy
12    efficiency programs and measures it determines are
13    cost-effective and the associated annual energy savings
14    goal included in the annual solicitation process and
15    assessment submitted pursuant to paragraph (3) of this
16    subsection (a).
17        (5) Pursuant to paragraph (4) of subsection (d) of
18    Section 16-111.5 of this Act, the Commission shall also
19    approve the energy efficiency programs and measures
20    included in the procurement plan, including the annual
21    energy savings goal, if the Commission determines they
22    fully capture the potential for all achievable
23    cost-effective savings, to the extent practicable, and
24    otherwise satisfy the requirements of Section 8-103 of this
25    Act.
26        In the event the Commission approves the procurement of

 

 

09900SB1585sam002- 267 -LRB099 09533 EGJ 48253 a

1    additional energy efficiency, it shall reduce the amount of
2    power to be procured under the procurement plan to reflect
3    the additional energy efficiency and shall direct the
4    utility to undertake the procurement of such energy
5    efficiency, which shall not be subject to the requirements
6    of subsection (e) of Section 16-111.5 of this Act. The
7    utility shall consider input from the Agency and interested
8    stakeholders on the procurement and administration
9    process. The requirements set forth in paragraphs (1)
10    through (5) of this subsection (a) shall terminate after
11    the filing of the procurement plan in 2015, and no energy
12    efficiency shall be procured by the Agency thereafter.
13    Energy efficiency programs approved previously pursuant to
14    this Section shall terminate no later than December 31,
15    2017.
16        (6) An electric utility shall recover its costs
17    incurred under this Section related to the implementation
18    of energy efficiency programs and measures approved by the
19    Commission in its order approving the procurement plan
20    under Section 16-111.5 of this Act, including, but not
21    limited to, all costs associated with complying with this
22    Section and all start-up and administrative costs and the
23    costs for any evaluation, measurement, and verification of
24    the measures, from all retail customers whose electric
25    service has not been declared competitive under Section
26    16-113 of this Act and who are eligible to purchase power

 

 

09900SB1585sam002- 268 -LRB099 09533 EGJ 48253 a

1    and energy from the utility under fixed-price bundled
2    service tariffs, regardless of whether such customers
3    actually do purchase such power and energy from the utility
4    through the automatic adjustment clause tariff established
5    pursuant to Section 8-103 of this Act, provided, however,
6    that the limitations described in subsection (d) of that
7    Section shall not apply to the costs incurred pursuant to
8    this Section or Section 16-111.7 of this Act.
9    (b) For purposes of this Section, the term "energy
10efficiency" shall have the meaning set forth in Section 1-10 of
11the Illinois Power Agency Act, and the term "cost-effective"
12shall have the meaning set forth in subsection (a) of Section
138-103 of this Act.
14    (c) The changes to this Section made by this amendatory Act
15of the 99th General Assembly shall not interfere with existing
16contracts executed pursuant to a Commission order entered under
17this Section.
18(Source: P.A. 97-616, eff. 10-26-11; 97-824, eff. 7-18-12.)
 
19    (220 ILCS 5/16-111.7)
20    Sec. 16-111.7. On-bill financing program; electric
21utilities.
22    (a) The Illinois General Assembly finds that Illinois homes
23and businesses have the potential to save energy through
24conservation and cost-effective energy efficiency measures.
25Programs created pursuant to this Section will allow utility

 

 

09900SB1585sam002- 269 -LRB099 09533 EGJ 48253 a

1customers to purchase cost-effective energy efficiency
2measures, including measures set forth in a
3Commission-approved energy efficiency and demand-response plan
4under Section 8-103 or 8-103B of this Act, with no required
5initial upfront payment, and to pay the cost of those products
6and services over time on their utility bill.
7    (b) Notwithstanding any other provision of this Act, an
8electric utility serving more than 100,000 customers on January
91, 2009 shall offer a Commission-approved on-bill financing
10program ("program") that allows its eligible retail customers,
11as that term is defined in Section 16-111.5 of this Act, who
12own a residential single family home, duplex, or other
13residential building with 4 or less units, or condominium at
14which the electric service is being provided (i) to borrow
15funds from a third party lender in order to purchase electric
16energy efficiency measures approved under the program for
17installation in such home or condominium without any required
18upfront payment and (ii) to pay back such funds over time
19through the electric utility's bill. Based upon the process
20described in subsection (b-5) of this Section, small commercial
21customers who own the premises at which electric service is
22being provided may be included in such program. After receiving
23a request from an electric utility for approval of a proposed
24program and tariffs pursuant to this Section, the Commission
25shall render its decision within 120 days. If no decision is
26rendered within 120 days, then the request shall be deemed to

 

 

09900SB1585sam002- 270 -LRB099 09533 EGJ 48253 a

1be approved.
2    Beginning no later than December 31, 2013, an electric
3utility subject to this subsection (b) shall also offer its
4program to eligible retail customers that own multifamily
5residential or mixed-use buildings with no more than 50
6residential units, provided, however, that such customers must
7either be a residential customer or small commercial customer
8and may not use the program in such a way that repayment of the
9cost of energy efficiency measures is made through tenants'
10utility bills. An electric utility may impose a per site loan
11limit not to exceed $150,000. The program, and loans issued
12thereunder, shall only be offered to customers of the utility
13that meet the requirements of this Section and that also have
14an electric service account at the premises where the energy
15efficiency measures being financed shall be installed.
16Beginning no later than 2 years after the effective date of
17this amendatory Act of the 99th General Assembly, the 50
18residential unit limitation described in this paragraph shall
19no longer apply, and the utility shall replace the per site
20loan limit of $150,000 with a loan limit that correlates to a
21maximum monthly payment that does not exceed 50% of the
22customer's average utility bill over the prior 12-month period.
23    Beginning no later than 2 years after the effective date of
24this amendatory Act of the 99th General Assembly, an electric
25utility subject to this subsection (b) shall also offer its
26program to eligible retail customers that are Unit Owners'

 

 

09900SB1585sam002- 271 -LRB099 09533 EGJ 48253 a

1Associations, as defined in subsection (o) of Section 2 of the
2Condominium Property Act, or Master Associations, as defined in
3subsection (u) of the Condominium Property Act. However, such
4customers must either be residential customers or small
5commercial customers and may not use the program in such a way
6that repayment of the cost of energy efficiency measures is
7made through unit owners' utility bills. The program and loans
8issued under the program shall only be offered to customers of
9the utility that meet the requirements of this Section and that
10also have an electric service account at the premises where the
11energy efficiency measures being financed shall be installed.
12    For purposes of this Section, "small commercial customer"
13means, for an electric utility serving more than 3,000,000
14retail customers, those customers having peak demand of less
15than 100 kilowatts, and, for an electric utility serving less
16than 3,000,000 retail customers, those customers having peak
17demand of less than 150 kilowatts; provided, however, that in
18the event the Commission, after the effective date of this
19amendatory Act of the 98th General Assembly, approves changes
20to a utility's tariffs that reflects new or revised demand
21criteria for the utility's customer rate classifications, then
22the utility may file a petition with the Commission to revise
23the applicable definition of a small commercial customer to
24reflect the new or revised demand criteria for the purposes of
25this Section. After notice and hearing, the Commission shall
26enter an order approving, or approving with modification, the

 

 

09900SB1585sam002- 272 -LRB099 09533 EGJ 48253 a

1revised definition within 60 days after the utility files the
2petition.
3    (b-5) Within 30 days after the effective date of this
4amendatory Act of the 96th General Assembly, the Commission
5shall convene a workshop process during which interested
6participants may discuss issues related to the program,
7including program design, eligible electric energy efficiency
8measures, vendor qualifications, and a methodology for
9ensuring ongoing compliance with such qualifications,
10financing, sample documents such as request for proposals,
11contracts and agreements, dispute resolution, pre-installment
12and post-installment verification, and evaluation. The
13workshop process shall be completed within 150 days after the
14effective date of this amendatory Act of the 96th General
15Assembly.
16    (c) Not later than 60 days following completion of the
17workshop process described in subsection (b-5) of this Section,
18each electric utility subject to subsection (b) of this Section
19shall submit a proposed program to the Commission that contains
20the following components:
21        (1) A list of recommended electric energy efficiency
22    measures that will be eligible for on-bill financing. An
23    eligible electric energy efficiency measure ("measure")
24    shall be a product or service for which one or more of the
25    following is true:
26            (A) (blank);

 

 

09900SB1585sam002- 273 -LRB099 09533 EGJ 48253 a

1            (B) the projected electricity savings (determined
2        by rates in effect at the time of purchase) are
3        sufficient to cover the costs of implementing the
4        measures, including finance charges and any program
5        fees not recovered pursuant to subsection (f) of this
6        Section; or
7            (C) the product or service is included in a
8        Commission-approved energy efficiency and
9        demand-response plan under Section 8-103 or 8-103B of
10        this Act.
11        (1.5) Beginning no later than 2 years after the
12    effective date of this amendatory Act of the 99th General
13    Assembly, an eligible electric energy efficiency measure
14    (measure) shall be a product or service that qualifies
15    under subparagraph (B) or (C) of paragraph (1) of this
16    subsection (c) or for which one or more of the following is
17    true:
18            (A) a building energy assessment, performed by an
19        energy auditor who is certified by the Building
20        Performance Institute or who holds a similar
21        certification, has recommended the product or service
22        as likely to be cost effective over the course of its
23        installed life for the building in which the measure is
24        to be installed; or
25            (B) the product or service is necessary to safely
26        or correctly install to code or industry standard an

 

 

09900SB1585sam002- 274 -LRB099 09533 EGJ 48253 a

1        efficiency measure, including, but not limited to,
2        installation work; changes needed to plumbing or
3        electrical connections; upgrades to wiring or
4        fixtures; removal of hazardous materials; correction
5        of leaks; changes to thermostats, controls, or similar
6        devices; and changes to venting or exhaust
7        necessitated by the measure. However, the costs of the
8        product or service described in this subparagraph (B)
9        shall not exceed 25% of the total cost of installing
10        the measure.
11        (2) The electric utility shall issue a request for
12    proposals ("RFP") to lenders for purposes of providing
13    financing to participants to pay for approved measures. The
14    RFP criteria shall include, but not be limited to, the
15    interest rate, origination fees, and credit terms. The
16    utility shall select the winning bidders based on its
17    evaluation of these criteria, with a preference for those
18    bids containing the rates, fees, and terms most favorable
19    to participants;
20        (3) The utility shall work with the lenders selected
21    pursuant to the RFP process, and with vendors, to establish
22    the terms and processes pursuant to which a participant can
23    purchase eligible electric energy efficiency measures
24    using the financing obtained from the lender. The vendor
25    shall explain and offer the approved financing packaging to
26    those customers identified in subsection (b) of this

 

 

09900SB1585sam002- 275 -LRB099 09533 EGJ 48253 a

1    Section and shall assist customers in applying for
2    financing. As part of the process, vendors shall also
3    provide to participants information about any other
4    incentives that may be available for the measures.
5        (4) The lender shall conduct credit checks or undertake
6    other appropriate measures to limit credit risk, and shall
7    review and approve or deny financing applications
8    submitted by customers identified in subsection (b) of this
9    Section. Following the lender's approval of financing and
10    the participant's purchase of the measure or measures, the
11    lender shall forward payment information to the electric
12    utility, and the utility shall add as a separate line item
13    on the participant's utility bill a charge showing the
14    amount due under the program each month.
15        (5) A loan issued to a participant pursuant to the
16    program shall be the sole responsibility of the
17    participant, and any dispute that may arise concerning the
18    loan's terms, conditions, or charges shall be resolved
19    between the participant and lender. Upon transfer of the
20    property title for the premises at which the participant
21    receives electric service from the utility or the
22    participant's request to terminate service at such
23    premises, the participant shall pay in full its electric
24    utility bill, including all amounts due under the program,
25    provided that this obligation may be modified as provided
26    in subsection (g) of this Section. Amounts due under the

 

 

09900SB1585sam002- 276 -LRB099 09533 EGJ 48253 a

1    program shall be deemed amounts owed for residential and,
2    as appropriate, small commercial electric service.
3        (6) The electric utility shall remit payment in full to
4    the lender each month on behalf of the participant. In the
5    event a participant defaults on payment of its electric
6    utility bill, the electric utility shall continue to remit
7    all payments due under the program to the lender, and the
8    utility shall be entitled to recover all costs related to a
9    participant's nonpayment through the automatic adjustment
10    clause tariff established pursuant to Section 16-111.8 of
11    this Act. In addition, the electric utility shall retain a
12    security interest in the measure or measures purchased
13    under the program, and the utility retains its right to
14    disconnect a participant that defaults on the payment of
15    its utility bill.
16        (7) The total outstanding amount financed under the
17    program in this subsection and subsection (c-5) of this
18    Section shall not exceed $2.5 million for an electric
19    utility or electric utilities under a single holding
20    company, provided that the electric utility or electric
21    utilities may petition the Commission for an increase in
22    such amount. Beginning after the effective date of this
23    amendatory Act of the 99th General Assembly, the total
24    maximum outstanding amount financed under the program in
25    this subsection and subsections (c-5) and (c-10) of this
26    Section shall increase by $2,500,000 per year until such

 

 

09900SB1585sam002- 277 -LRB099 09533 EGJ 48253 a

1    time as the total maximum outstanding amount financed
2    reaches $20,000,000.
3    (c-5) Within 120 days after the effective date of this
4amendatory Act of the 98th General Assembly, each electric
5utility subject to the requirements of this Section shall
6submit an informational filing to the Commission that describes
7its plan for implementing the provisions of this amendatory Act
8of the 98th General Assembly on or before December 31, 2013.
9Such filing shall also describe how the electric utility shall
10coordinate its program with any gas utility or utilities that
11provide gas service to buildings within the electric utility's
12service territory so that it is practical and feasible for the
13owner of a multifamily building to make a single application to
14access loans for both gas and electric energy efficiency
15measures in any individual building.
16    (c-10) No later than 365 days after the effective date of
17this amendatory Act of the 99th General Assembly, each electric
18utility subject to the requirements of this Section shall
19submit an informational filing to the Commission that describes
20its plan for implementing the provisions of this amendatory Act
21of the 99th General Assembly that were incorporated into this
22Section. Such filing shall also include the criteria to be used
23by the program for determining if measures to be financed are
24eligible electric energy efficiency measures, as defined by
25paragraph (1.5) of subsection (c) of this Section.
26    (d) A program approved by the Commission shall also include

 

 

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1the following criteria and guidelines for such program:
2        (1) guidelines for financing of measures installed
3    under a program, including, but not limited to, RFP
4    criteria and limits on both individual loan amounts and the
5    duration of the loans;
6        (2) criteria and standards for identifying and
7    approving measures;
8        (3) qualifications of vendors that will market or
9    install measures, as well as a methodology for ensuring
10    ongoing compliance with such qualifications;
11        (4) sample contracts and agreements necessary to
12    implement the measures and program; and
13        (5) the types of data and information that utilities
14    and vendors participating in the program shall collect for
15    purposes of preparing the reports required under
16    subsection (g) of this Section.
17    (e) The proposed program submitted by each electric utility
18shall be consistent with the provisions of this Section that
19define operational, financial and billing arrangements between
20and among program participants, vendors, lenders, and the
21electric utility.
22    (f) An electric utility shall recover all of the prudently
23incurred costs of offering a program approved by the Commission
24pursuant to this Section, including, but not limited to, all
25start-up and administrative costs and the costs for program
26evaluation. All prudently incurred costs under this Section

 

 

09900SB1585sam002- 279 -LRB099 09533 EGJ 48253 a

1shall be recovered from the residential and small commercial
2retail customer classes eligible to participate in the program
3through the automatic adjustment clause tariff established
4pursuant to Section 8-103 or 8-103B of this Act.
5    (g) An independent evaluation of a program shall be
6conducted after 3 years of the program's operation. The
7electric utility shall retain an independent evaluator who
8shall evaluate the effects of the measures installed under the
9program and the overall operation of the program, including,
10but not limited to, customer eligibility criteria and whether
11the payment obligation for permanent electric energy
12efficiency measures that will continue to provide benefits of
13energy savings should attach to the meter location. As part of
14the evaluation process, the evaluator shall also solicit
15feedback from participants and interested stakeholders. The
16evaluator shall issue a report to the Commission on its
17findings no later than 4 years after the date on which the
18program commenced, and the Commission shall issue a report to
19the Governor and General Assembly including a summary of the
20information described in this Section as well as its
21recommendations as to whether the program should be
22discontinued, continued with modification or modifications or
23continued without modification, provided that any recommended
24modifications shall only apply prospectively and to measures
25not yet installed or financed.
26    (h) An electric utility offering a Commission-approved

 

 

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1program pursuant to this Section shall not be required to
2comply with any other statute, order, rule, or regulation of
3this State that may relate to the offering of such program,
4provided that nothing in this Section is intended to limit the
5electric utility's obligation to comply with this Act and the
6Commission's orders, rules, and regulations, including Part
7280 of Title 83 of the Illinois Administrative Code.
8    (i) The source of a utility customer's electric supply
9shall not disqualify a customer from participation in the
10utility's on-bill financing program. Customers of alternative
11retail electric suppliers may participate in the program under
12the same terms and conditions applicable to the utility's
13supply customers.
14(Source: P.A. 97-616, eff. 10-26-11; 98-586, eff. 8-27-13.)
 
15    (220 ILCS 5/16-115D)
16    Sec. 16-115D. Renewable portfolio standard for alternative
17retail electric suppliers and electric utilities operating
18outside their service territories.
19    (a) An alternative retail electric supplier shall be
20responsible for procuring cost-effective renewable energy
21resources as required under item (5) of subsection (d) of
22Section 16-115 of this Act as outlined herein:
23        (1) The definition of renewable energy resources
24    contained in Section 1-10 of the Illinois Power Agency Act
25    applies to all renewable energy resources required to be

 

 

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1    procured by alternative retail electric suppliers.
2        (2) Through May 31, 2018, the The quantity of renewable
3    energy resources shall be measured as a percentage of the
4    actual amount of metered electricity (megawatt-hours)
5    delivered by the alternative retail electric supplier to
6    Illinois retail customers during the 12-month period June 1
7    through May 31, commencing June 1, 2009, and the comparable
8    12-month period in each year thereafter except as provided
9    in item (6) of this subsection (a). Beginning with the
10    planning year commencing June 1, 2018 and each year
11    thereafter, the quantity of renewable energy resources
12    shall be measured as the uncovered portion of the actual
13    amount of metered electricity (megawatt-hours) delivered
14    by the alternative retail electric supplier during the
15    12-month period to Illinois retail customers whose
16    electric service has been declared competitive pursuant to
17    Section 16-113 of the Public Utilities Act. For purposes of
18    this Section, "uncovered portion" means the percentage
19    difference between 100% minus the applicable portion
20    determined by paragraph (1) of subsection (c) of Section
21    1-75 of the Illinois Power Agency Act.
22        (3) Through May 31, 2018, the The quantity of renewable
23    energy resources shall be in amounts at least equal to the
24    annual percentages set forth in item (1) of subsection (c)
25    of Section 1-75 of the Illinois Power Agency Act. At least
26    60% of the renewable energy resources procured pursuant to

 

 

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1    items (1) and through (3) of subsection (b) of this Section
2    shall come from wind generation and, starting June 1, 2015,
3    at least 6% of the renewable energy resources procured
4    pursuant to items (1) and through (3) of subsection (b) of
5    this Section shall come from solar photovoltaics. If, in
6    any given year, an alternative retail electric supplier
7    does not purchase at least these levels of renewable energy
8    resources, then the alternative retail electric supplier
9    shall make alternative compliance payments, as described
10    in subsection (d) of this Section.
11        (3.5) Beginning with the planning year commencing June
12    1, 2018, the quantity of renewable energy resources shall
13    be at least 14.5% and increase by 1.5% each year thereafter
14    to at least 25% by June 1, 2025. At least 60% of the
15    renewable energy resources procured pursuant this
16    paragraph (3.5) shall come from wind generation.
17        (4) The quantity and source of renewable energy
18    resources shall be independently verified through the PJM
19    Environmental Information System Generation Attribute
20    Tracking System (PJM-GATS) or the Midwest Renewable Energy
21    Tracking System (M-RETS), which shall document the
22    location of generation, resource type, month, and year of
23    generation for all qualifying renewable energy resources
24    that an alternative retail electric supplier uses to comply
25    with this Section. No later than June 1, 2009, the Illinois
26    Power Agency shall provide PJM-GATS, M-RETS, and

 

 

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1    alternative retail electric suppliers with all information
2    necessary to identify resources located in Illinois,
3    within states that adjoin Illinois or within portions of
4    the PJM and MISO footprint in the United States that
5    qualify under the definition of renewable energy resources
6    in Section 1-10 of the Illinois Power Agency Act for
7    compliance with this Section 16-115D. Alternative retail
8    electric suppliers shall not be subject to the requirements
9    in item (3) of subsection (c) of Section 1-75 of the
10    Illinois Power Agency Act.
11        (5) All renewable energy credits used to comply with
12    this Section shall be permanently retired.
13        (6) The required procurement of renewable energy
14    resources by an alternative retail electric supplier shall
15    apply to all metered electricity delivered to Illinois
16    retail customers by the alternative retail electric
17    supplier pursuant to contracts executed or extended after
18    March 15, 2009.
19    (b) Compliance obligations.
20        (1) Through May 31, 2018, an An alternative retail
21    electric supplier shall comply with the renewable energy
22    portfolio standards by making an alternative compliance
23    payment, as described in subsection (d) of this Section, to
24    cover at least one-half of the alternative retail electric
25    supplier's compliance obligation for the period prior to
26    May 31, 2018.

 

 

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1        (2) Beginning on June 1, 2018, an alternative retail
2    electric supplier need not make any alternative compliance
3    payment to meet any portion of its compliance obligation,
4    as set forth in paragraph (3.5) of subsection (a) of this
5    Section, with respect to its metered electricity supplied
6    to its Illinois retail customers that, on January 1, 2015,
7    had their electric service declared competitive pursuant
8    to Section 16-113 of this Act.
9        (3) An alternative retail electric supplier shall use
10    and any one or combination of the following means to cover
11    the remainder of the alternative retail electric
12    supplier's compliance obligation, as set forth in
13    paragraphs (3) and (3.5) of subsection (a) of this Section,
14    not covered by an alternative compliance payment made under
15    paragraphs (1) and (2) of this subsection (b):
16            (A) (1) Generating electricity using renewable
17        energy resources identified pursuant to item (4) of
18        subsection (a) of this Section.
19            (B) (2) Purchasing electricity generated using
20        renewable energy resources identified pursuant to item
21        (4) of subsection (a) of this Section through an energy
22        contract.
23            (C) (3) Purchasing renewable energy credits from
24        renewable energy resources identified pursuant to item
25        (4) of subsection (a) of this Section.
26            (D) (4) Making an alternative compliance payment

 

 

09900SB1585sam002- 285 -LRB099 09533 EGJ 48253 a

1        as described in subsection (d) of this Section.
2    (c) Use of renewable energy credits.
3        (1) Renewable energy credits that are not used by an
4    alternative retail electric supplier to comply with a
5    renewable portfolio standard in a compliance year may be
6    banked and carried forward up to 2 12-month compliance
7    periods after the compliance period in which the credit was
8    generated for the purpose of complying with a renewable
9    portfolio standard in those 2 subsequent compliance
10    periods. For the 2009-2010 and 2010-2011 compliance
11    periods, an alternative retail electric supplier may use
12    renewable credits generated after December 31, 2008 and
13    before June 1, 2009 to comply with this Section.
14        (2) An alternative retail electric supplier is
15    responsible for demonstrating that a renewable energy
16    credit used to comply with a renewable portfolio standard
17    is derived from a renewable energy resource and that the
18    alternative retail electric supplier has not used, traded,
19    sold, or otherwise transferred the credit.
20        (3) The same renewable energy credit may be used by an
21    alternative retail electric supplier to comply with a
22    federal renewable portfolio standard and a renewable
23    portfolio standard established under this Act. An
24    alternative retail electric supplier that uses a renewable
25    energy credit to comply with a renewable portfolio standard
26    imposed by any other state may not use the same credit to

 

 

09900SB1585sam002- 286 -LRB099 09533 EGJ 48253 a

1    comply with a renewable portfolio standard established
2    under this Act.
3    (d) Alternative compliance payments.
4        (1) The Commission shall establish and post on its
5    website, within 5 business days after entering an order
6    approving a procurement plan pursuant to Section 1-75 of
7    the Illinois Power Agency Act, maximum alternative
8    compliance payment rates, expressed on a per kilowatt-hour
9    basis, that will be applicable in the first compliance
10    period following the plan approval. A separate maximum
11    alternative compliance payment rate shall be established
12    for the service territory of each electric utility that is
13    subject to subsection (c) of Section 1-75 of the Illinois
14    Power Agency Act. Each maximum alternative compliance
15    payment rate shall be equal to the maximum allowable annual
16    estimated average net increase due to the costs of the
17    utility's purchase of renewable energy resources included
18    in the amounts paid by eligible retail customers in
19    connection with electric service, as described in item (2)
20    of subsection (c) of Section 1-75 of the Illinois Power
21    Agency Act for the compliance period, and as established in
22    the approved procurement plan. Following each procurement
23    event through which renewable energy resources are
24    purchased for one or more of these utilities for the
25    compliance period, the Commission shall establish and post
26    on its website estimates of the alternative compliance

 

 

09900SB1585sam002- 287 -LRB099 09533 EGJ 48253 a

1    payment rates, expressed on a per kilowatt-hour basis, that
2    shall apply for that compliance period. Posting of the
3    estimates shall occur no later than 10 business days
4    following the procurement event, however, the Commission
5    shall not be required to establish and post such estimates
6    more often than once per calendar month. By July 1 of each
7    year, the Commission shall establish and post on its
8    website the actual alternative compliance payment rates
9    for the preceding compliance year. The Commission shall
10    make available to alternative retail electric suppliers
11    subject to this Section the average cost and quantity for
12    the compliance year, the estimated average cost for each
13    subsequent compliance year, and the anticipated quantity
14    for each subsequent compliance year for the duration of
15    such executed renewable energy contracts which will impact
16    the alternative compliance payment. For compliance years
17    beginning prior to June 1, 2014, each alternative
18    compliance payment rate shall be equal to the total amount
19    of dollars that the utility contracted to spend on
20    renewable resources, excepting the additional incremental
21    cost attributable to solar resources, for the compliance
22    period divided by the forecasted load of eligible retail
23    customers, at the customers' meters, as previously
24    established in the Commission-approved procurement plan
25    for that compliance year. For compliance years commencing
26    on or after June 1, 2014, each alternative compliance

 

 

09900SB1585sam002- 288 -LRB099 09533 EGJ 48253 a

1    payment rate shall be equal to the total amount of dollars
2    that the utility contracted to spend on all renewable
3    resources for the compliance period divided by the
4    forecasted load of eligible retail customers for which the
5    utility is procuring renewable energy resources in a given
6    planning year, at the customers' meters, as previously
7    established in the Commission-approved procurement plan
8    for that compliance year. The actual alternative
9    compliance payment rates may not exceed the maximum
10    alternative compliance payment rates established for the
11    compliance period. For purposes of this subsection (d), the
12    term "eligible retail customers" has the same meaning as
13    found in Section 16-111.5 of this Act.
14        (2) In any given compliance year, an alternative retail
15    electric supplier may elect to use alternative compliance
16    payments to comply with all or a part of the applicable
17    renewable portfolio standard. In the event that an
18    alternative retail electric supplier elects to make
19    alternative compliance payments to comply with all or a
20    part of the applicable renewable portfolio standard, such
21    payments shall be made by September 1, 2010 for the period
22    of June 1, 2009 to May 1, 2010 and by September 1 of each
23    year thereafter for the subsequent compliance period, in
24    the manner and form as determined by the Commission. Any
25    election by an alternative retail electric supplier to use
26    alternative compliance payments is subject to review by the

 

 

09900SB1585sam002- 289 -LRB099 09533 EGJ 48253 a

1    Commission under subsection (e) of this Section.
2        (3) An alternative retail electric supplier's
3    alternative compliance payments shall be computed
4    separately for each electric utility's service territory
5    within which the alternative retail electric supplier
6    provided retail service during the compliance period,
7    provided that the electric utility was subject to
8    subsection (c) of Section 1-75 of the Illinois Power Agency
9    Act. For each service territory, the alternative retail
10    electric supplier's alternative compliance payment shall
11    be equal to (i) the actual alternative compliance payment
12    rate established in item (1) of this subsection (d),
13    multiplied by (ii) the actual amount of metered electricity
14    delivered by the alternative retail electric supplier to
15    retail customers for which the supplier has a compliance
16    obligation within the service territory during the
17    compliance period, multiplied by (iii) the result of one
18    minus the ratios of the quantity of renewable energy
19    resources used by the alternative retail electric supplier
20    to comply with the requirements of this Section within the
21    service territory to the product of the percentage of
22    renewable energy resources required under item (3) of
23    subsection (a) of this Section and the actual amount of
24    metered electricity delivered by the alternative retail
25    electric supplier to retail customers for which the
26    supplier has a compliance obligation within the service

 

 

09900SB1585sam002- 290 -LRB099 09533 EGJ 48253 a

1    territory during the compliance period.
2        (4) Through May 31, 2018, all All alternative
3    compliance payments by alternative retail electric
4    suppliers shall be deposited in the Illinois Power Agency
5    Renewable Energy Resources Fund and used to purchase
6    renewable energy credits, in accordance with Section 1-56
7    of the Illinois Power Agency Act. Beginning April 1, 2012
8    and by April 1 of each year thereafter, the Illinois Power
9    Agency shall submit an annual report to the General
10    Assembly, the Commission, and alternative retail electric
11    suppliers that shall include, but not be limited to:
12            (A) the total amount of alternative compliance
13        payments received in aggregate from alternative retail
14        electric suppliers by planning year for all previous
15        planning years in which the alternative compliance
16        payment was in effect;
17            (B) the amount of those payments utilized to
18        purchased renewable energy credits itemized by the
19        date of each procurement in which the payments were
20        utilized; and
21            (C) the unused and remaining balance in the Agency
22        Renewable Energy Resources Fund attributable to those
23        payments.
24        (4.5) Beginning with the planning year commencing June
25    1, 2018, all alternative compliance payments by
26    alternative retail electric suppliers shall be remitted to

 

 

09900SB1585sam002- 291 -LRB099 09533 EGJ 48253 a

1    the applicable electric utility. To facilitate this
2    remittance, each electric utility shall file a tariff with
3    the Commission no later than 30 days following the
4    effective date of this amendatory Act of the 99th General
5    Assembly, which the Commission shall approve, after notice
6    and hearing, no later than 45 days after its filing. The
7    Illinois Power Agency shall use such payments to increase
8    the amount of renewable energy resources otherwise to be
9    procured under subsection (c) of Section 1-75 of the
10    Illinois Power Agency Act.
11        (5) The Commission, in consultation with the Illinois
12    Power Agency, shall establish a process or proceeding to
13    consider the impact of a federal renewable portfolio
14    standard, if enacted, on the operation of the alternative
15    compliance mechanism, which shall include, but not be
16    limited to, developing, to the extent permitted by the
17    applicable federal statute, an appropriate methodology to
18    apportion renewable energy credits retired as a result of
19    alternative compliance payments made in accordance with
20    this Section. The Commission shall commence any such
21    process or proceeding within 35 days after enactment of a
22    federal renewable portfolio standard.
23    (e) Each alternative retail electric supplier shall, by
24September 1, 2010 and by September 1 of each year thereafter,
25prepare and submit to the Commission a report, in a format to
26be specified by the Commission on or before December 31, 2009,

 

 

09900SB1585sam002- 292 -LRB099 09533 EGJ 48253 a

1that provides information certifying:
2        (1) compliance by the alternative retail electric
3    supplier with this Section, including copies of all
4    PJM-GATS and M-RETS reports;
5        (2) , and documentation relating to banking and ,
6    retiring renewable energy credits; ,
7        (3) the type and the amounts of renewable energy
8    credits the alternative retail electric supplier is using
9    to satisfy the alternative retail electric supplier's
10    compliance obligation for the applicable compliance year;
11        (4) the states in which the facilities supplying the
12    renewable energy credits purchased by the alternative
13    retail electric supplier to satisfy the alternative retail
14    electric supplier's compliance obligation for the
15    applicable compliance year are located;
16        (5) the vintage of all renewable energy credits
17    purchased by the alternative retail electric supplier;
18        (6) the percent, if any, of the alternative retail
19    electric supplier's compliance obligation that it intends
20    to meet through making an alternative compliance payment
21    pursuant to subsection (b) of this Section; and
22        (7) and any other information that the Commission
23    determines necessary to ensure compliance with this
24    Section.
25    However, the information required by paragraphs (3)
26through (6) of this subsection (e) shall not be required to be

 

 

09900SB1585sam002- 293 -LRB099 09533 EGJ 48253 a

1included in reports submitted on or before September 1, 2018.
2    An alternative retail electric supplier may file
3commercially or financially sensitive information or trade
4secrets with the Commission as provided under the rules of the
5Commission. To be filed confidentially, the information shall
6be accompanied by an affidavit that sets forth both the reasons
7for the confidentiality and a public synopsis of the
8information.
9    The Commission shall provide an analysis of the information
10provided by the alternative retail electric suppliers pursuant
11to this subsection (e) and a description of the manner in which
12alternative retail electric suppliers have met their
13obligations. The information in the Commission's annual report
14shall be presented in a way that protects the confidentiality
15of the information provided by the alternative retail electric
16suppliers. The Commission's annual report shall be posted on
17its website and cover the period from June 1, 2018 through May
1831, 2019 and each annual period thereafter.
19    (f) The Commission may initiate a contested case to review
20allegations that the alternative retail electric supplier has
21violated this Section, including an order issued or rule
22promulgated under this Section. In any such proceeding, the
23alternative retail electric supplier shall have the burden of
24proof. If the Commission finds, after notice and hearing, that
25an alternative retail electric supplier has violated this
26Section, then the Commission shall issue an order requiring the

 

 

09900SB1585sam002- 294 -LRB099 09533 EGJ 48253 a

1alternative retail electric supplier to:
2        (1) immediately comply with this Section; and
3        (2) if the violation involves a failure to procure the
4    requisite quantity of renewable energy resources or pay the
5    applicable alternative compliance payment by the annual
6    deadline, the Commission shall require the alternative
7    retail electric supplier to double the applicable
8    alternative compliance payment that would otherwise be
9    required to bring the alternative retail electric supplier
10    into compliance with this Section.
11    If an alternative retail electric supplier fails to comply
12with the renewable energy resource portfolio requirement in
13this Section more than once in a 5-year period, then the
14Commission shall revoke the alternative electric supplier's
15certificate of service authority. The Commission shall not
16accept an application for a certificate of service authority
17from an alternative retail electric supplier that has lost
18certification under this subsection (f), or any corporate
19affiliate thereof, for at least one year after the date of
20revocation.
21    (g) All of the provisions of this Section apply to electric
22utilities operating outside their service area except under
23item (2) of subsection (a) of this Section the quantity of
24renewable energy resources shall be measured as a percentage of
25the actual amount of electricity (megawatt-hours) supplied in
26the State outside of the utility's service territory during the

 

 

09900SB1585sam002- 295 -LRB099 09533 EGJ 48253 a

112-month period June 1 through May 31, commencing June 1, 2009,
2and the comparable 12-month period in each year thereafter
3except as provided in item (6) of subsection (a) of this
4Section.
5    If any such utility fails to procure the requisite quantity
6of renewable energy resources by the annual deadline, then the
7Commission shall require the utility to double the alternative
8compliance payment that would otherwise be required to bring
9the utility into compliance with this Section.
10    If any such utility fails to comply with the renewable
11energy resource portfolio requirement in this Section more than
12once in a 5-year period, then the Commission shall order the
13utility to cease all sales outside of the utility's service
14territory for a period of at least one year.
15    (h) The provisions of this Section and the provisions of
16subsection (d) of Section 16-115 of this Act relating to
17procurement of renewable energy resources shall not apply to an
18alternative retail electric supplier that operates a combined
19heat and power system in this State or that has a corporate
20affiliate that operates such a combined heat and power system
21in this State that supplies electricity primarily to or for the
22benefit of: (i) facilities owned by the supplier, its
23subsidiary, or other corporate affiliate; (ii) facilities
24electrically integrated with the electrical system of
25facilities owned by the supplier, its subsidiary, or other
26corporate affiliate; or (iii) facilities that are adjacent to

 

 

09900SB1585sam002- 296 -LRB099 09533 EGJ 48253 a

1the site on which the combined heat and power system is
2located.
3    (i) The obligations of alternative retail electric
4suppliers and electric utilities operating outside their
5service territories to procure renewable energy resources,
6make alternative compliance payments, and file annual reports,
7and the obligations of the Commission to determine and post
8alternative compliance payment rates, shall terminate
9effective on the date that electric utilities begin procuring
10renewable energy resources for 100% of the actual load of
11retail customers whose electric service has been declared
12competitive pursuant to Section 16-113 of this Act, as
13determined by paragraph (1) of subsection (c) of Section 1-75
14of the Illinois Power Agency Act, provided that alternative
15retail electric suppliers and electric utilities operative
16outside their service territories shall be obligated to make
17all alternative compliance payments that they were obligated to
18pay for periods through and including that date, but were not
19paid as of that date. The Commission shall continue to enforce
20the payment of unpaid alternative compliance payments after
21that date in accordance with subsections (f) and (g) of this
22Section. All alternative compliance payments made after that
23date shall be remitted to the applicable electric utility and
24used to purchase renewable energy credits, in accordance with
25Section 1-75 of the Illinois Power Agency Act.
26(Source: P.A. 96-33, eff. 7-10-09; 96-159, eff. 8-10-09;

 

 

09900SB1585sam002- 297 -LRB099 09533 EGJ 48253 a

196-1437, eff. 8-17-10; 97-658, eff. 1-13-12.)
 
2    (220 ILCS 5/16-127)
3    Sec. 16-127. Environmental disclosure.
4    (a) Effective January 1, 2013, every electric utility and
5alternative retail electric supplier shall provide the
6following information, to the maximum extent practicable, to
7its customers on a quarterly basis:
8        (i) the known sources of electricity supplied,
9    broken-out by percentages, of biomass power, coal-fired
10    power, hydro power, natural gas-fired power, nuclear
11    power, oil-fired power, solar power, wind power and other
12    resources, respectively;
13        (ii) a pie chart pie-chart that graphically depicts the
14    percentages of the sources of the electricity supplied as
15    set forth in subparagraph (i) of this subsection; and
16        (iii) a pie chart pie-chart that graphically depicts
17    the quantity of renewable energy resources procured
18    pursuant to Section 1-75 of the Illinois Power Agency Act
19    as a percentage of electricity supplied to serve eligible
20    retail customers as defined in Section 16-111.5(a) of this
21    Act; and .
22        (iv) after May, 31, 2017, a pie chart that graphically
23    depicts the quantity of zero emission credits from zero
24    emission resources procured pursuant to Section 1-75 of the
25    Illinois Power Agency Act as a percentage of the actual

 

 

09900SB1585sam002- 298 -LRB099 09533 EGJ 48253 a

1    load of retail customers within its service area.
2    (b) In addition, every electric utility and alternative
3retail electric supplier shall provide, to the maximum extent
4practicable, to its customers on a quarterly basis, a
5standardized chart in a format to be determined by the
6Commission in a rule following notice and hearings which
7provides the amounts of carbon dioxide, nitrogen oxides and
8sulfur dioxide emissions and nuclear waste attributable to the
9known sources of electricity supplied as set forth in
10subparagraph (i) of subsection (a) of this Section.
11    (c) The electric utilities and alternative retail electric
12suppliers may provide their customers with such other
13information as they believe relevant to the information
14required in subsections (a) and (b) of this Section. All of the
15information required in subsections (a) and (b) of this Section
16shall be made available by the electric utilities or
17alternative retail electric suppliers either in an electronic
18medium, such as on a website or by electronic mail, or through
19the U.S. Postal Service.
20    (d) For the purposes of subsection (a) of this Section,
21"biomass" means dedicated crops grown for energy production and
22organic wastes.
23    (e) All of the information provided in subsections (a) and
24(b) of this Section shall be presented to the Commission for
25inclusion in its World Wide Web Site.
26(Source: P.A. 97-1092, eff. 1-1-13.)
 

 

 

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1    Section 20. The Energy Assistance Act is amended by
2changing Sections 13 and 18 as follows:
 
3    (305 ILCS 20/13)
4    (Section scheduled to be repealed on December 31, 2018)
5    Sec. 13. Supplemental Low-Income Energy Assistance Fund.
6    (a) The Supplemental Low-Income Energy Assistance Fund is
7hereby created as a special fund in the State Treasury. The
8Supplemental Low-Income Energy Assistance Fund is authorized
9to receive moneys from voluntary donations from individuals,
10foundations, corporations, and other sources, moneys received
11pursuant to Section 17, and, by statutory deposit, the moneys
12collected pursuant to this Section. The Fund is also authorized
13to receive voluntary donations from individuals, foundations,
14corporations, and other sources, as well as contributions made
15in accordance with Section 507MM of the Illinois Income Tax
16Act. Subject to appropriation, the Department shall use moneys
17from the Supplemental Low-Income Energy Assistance Fund for
18payments to electric or gas public utilities, municipal
19electric or gas utilities, and electric cooperatives on behalf
20of their customers who are participants in the program
21authorized by Sections 4 and 18 of this Act, for the provision
22of weatherization services and for administration of the
23Supplemental Low-Income Energy Assistance Fund. The yearly
24expenditures for weatherization may not exceed 10% of the

 

 

09900SB1585sam002- 300 -LRB099 09533 EGJ 48253 a

1amount collected during the year pursuant to this Section. The
2yearly administrative expenses of the Supplemental Low-Income
3Energy Assistance Fund may not exceed 10% of the amount
4collected during that year pursuant to this Section, except
5when unspent funds from the Supplemental Low-Income Energy
6Assistance Fund are reallocated from a previous year; any
7unspent balance of the 10% administrative allowance may be
8utilized for administrative expenses in the year they are
9reallocated.
10    (b) Notwithstanding the provisions of Section 16-111 of the
11Public Utilities Act but subject to subsection (k) of this
12Section, each public utility, electric cooperative, as defined
13in Section 3.4 of the Electric Supplier Act, and municipal
14utility, as referenced in Section 3-105 of the Public Utilities
15Act, that is engaged in the delivery of electricity or the
16distribution of natural gas within the State of Illinois shall,
17effective January 1, 1998, assess each of its customer accounts
18a monthly Energy Assistance Charge for the Supplemental
19Low-Income Energy Assistance Fund. The delivering public
20utility, municipal electric or gas utility, or electric or gas
21cooperative for a self-assessing purchaser remains subject to
22the collection of the fee imposed by this Section. The monthly
23charge shall be as follows:
24        (1) $0.48 per month on each account for residential
25    electric service; provided that beginning January 1, 2019,
26    the monthly charge for residential electric service shall

 

 

09900SB1585sam002- 301 -LRB099 09533 EGJ 48253 a

1    change to $0.72 for a period of 5 years; after the 5-year
2    period, the charge shall be reduced to $0.48 per month;
3        (2) $0.48 per month on each account for residential gas
4    service;
5        (3) $4.80 per month on each account for non-residential
6    electric service which had less than 10 megawatts of peak
7    demand during the previous calendar year;
8        (4) $4.80 per month on each account for non-residential
9    gas service which had distributed to it less than 4,000,000
10    therms of gas during the previous calendar year;
11        (5) $360 per month on each account for non-residential
12    electric service which had 10 megawatts or greater of peak
13    demand during the previous calendar year; and
14        (6) $360 per month on each account for non-residential
15    gas service which had 4,000,000 or more therms of gas
16    distributed to it during the previous calendar year.
17    The incremental change to such charges imposed by this
18amendatory Act of the 96th General Assembly shall not (i) be
19used for any purpose other than to directly assist customers
20and (ii) be applicable to utilities serving less than 100,000
21customers in Illinois on January 1, 2009. Moreover, the
22incremental change to such charges imposed by this amendatory
23Act of the 99th General Assembly is intended to assist
24low-income customers, including, but not limited to, those who
25may have their monthly electric bills increase because of a
26transition to demand-based rates under Section 9-105 of the

 

 

09900SB1585sam002- 302 -LRB099 09533 EGJ 48253 a

1Public Utilities Act, and such incremental change shall not (i)
2be used for any purpose other than to fund the Percentage of
3Income Payment Plan program, Arrearage Reduction program, and
4Supplemental Arrearage Reduction program under Section 18 of
5this Act or (ii) be applicable to utilities serving less than
6100,000 customers in Illinois on January 1, 2009.
7    In addition, electric and gas utilities have committed, and
8shall contribute, a one-time payment of $22 million to the
9Fund, within 10 days after the effective date of the tariffs
10established pursuant to Sections 16-111.8 and 19-145 of the
11Public Utilities Act to be used for the Department's cost of
12implementing the programs described in Section 18 of this
13amendatory Act of the 96th General Assembly, the Arrearage
14Reduction Program described in Section 18, and the programs
15described in Section 8-105 of the Public Utilities Act. If a
16utility elects not to file a rider within 90 days after the
17effective date of this amendatory Act of the 96th General
18Assembly, then the contribution from such utility shall be made
19no later than February 1, 2010.
20    (c) For purposes of this Section:
21        (1) "residential electric service" means electric
22    utility service for household purposes delivered to a
23    dwelling of 2 or fewer units which is billed under a
24    residential rate, or electric utility service for
25    household purposes delivered to a dwelling unit or units
26    which is billed under a residential rate and is registered

 

 

09900SB1585sam002- 303 -LRB099 09533 EGJ 48253 a

1    by a separate meter for each dwelling unit;
2        (2) "residential gas service" means gas utility
3    service for household purposes distributed to a dwelling of
4    2 or fewer units which is billed under a residential rate,
5    or gas utility service for household purposes distributed
6    to a dwelling unit or units which is billed under a
7    residential rate and is registered by a separate meter for
8    each dwelling unit;
9        (3) "non-residential electric service" means electric
10    utility service which is not residential electric service;
11    and
12        (4) "non-residential gas service" means gas utility
13    service which is not residential gas service.
14    (d) Within 30 days after the effective date of this
15amendatory Act of the 96th General Assembly, each public
16utility engaged in the delivery of electricity or the
17distribution of natural gas shall file with the Illinois
18Commerce Commission tariffs incorporating the Energy
19Assistance Charge in other charges stated in such tariffs,
20which shall become effective no later than the beginning of the
21first billing cycle following such filing.
22    (e) The Energy Assistance Charge assessed by electric and
23gas public utilities shall be considered a charge for public
24utility service.
25    (f) By the 20th day of the month following the month in
26which the charges imposed by the Section were collected, each

 

 

09900SB1585sam002- 304 -LRB099 09533 EGJ 48253 a

1public utility, municipal utility, and electric cooperative
2shall remit to the Department of Revenue all moneys received as
3payment of the Energy Assistance Charge on a return prescribed
4and furnished by the Department of Revenue showing such
5information as the Department of Revenue may reasonably
6require; provided, however, that a utility offering an
7Arrearage Reduction Program or Supplemental Arrearage
8Reduction Program pursuant to Section 18 of this Act shall be
9entitled to net those amounts necessary to fund and recover the
10costs of such Program as authorized by that Section that is no
11more than the incremental change in such Energy Assistance
12Charge authorized by this amendatory Act of the 96th General
13Assembly and this amendatory Act of the 99th General Assembly.
14If a customer makes a partial payment, a public utility,
15municipal utility, or electric cooperative may elect either:
16(i) to apply such partial payments first to amounts owed to the
17utility or cooperative for its services and then to payment for
18the Energy Assistance Charge or (ii) to apply such partial
19payments on a pro-rata basis between amounts owed to the
20utility or cooperative for its services and to payment for the
21Energy Assistance Charge.
22    (g) The Department of Revenue shall deposit into the
23Supplemental Low-Income Energy Assistance Fund all moneys
24remitted to it in accordance with subsection (f) of this
25Section; provided, however, that the amounts remitted by each
26utility shall be used to provide assistance to that utility's

 

 

09900SB1585sam002- 305 -LRB099 09533 EGJ 48253 a

1customers. The utilities shall coordinate with the Department
2to establish an equitable and practical methodology for
3implementing this subsection (g) beginning with the 2010
4program year.
5    (h) On or before December 31, 2002, the Department shall
6prepare a report for the General Assembly on the expenditure of
7funds appropriated from the Low-Income Energy Assistance Block
8Grant Fund for the program authorized under Section 4 of this
9Act.
10    (i) The Department of Revenue may establish such rules as
11it deems necessary to implement this Section.
12    (j) The Department of Commerce and Economic Opportunity may
13establish such rules as it deems necessary to implement this
14Section.
15    (k) The charges imposed by this Section shall only apply to
16customers of municipal electric or gas utilities and electric
17or gas cooperatives if the municipal electric or gas utility or
18electric or gas cooperative makes an affirmative decision to
19impose the charge. If a municipal electric or gas utility or an
20electric cooperative makes an affirmative decision to impose
21the charge provided by this Section, the municipal electric or
22gas utility or electric cooperative shall inform the Department
23of Revenue in writing of such decision when it begins to impose
24the charge. If a municipal electric or gas utility or electric
25or gas cooperative does not assess this charge, the Department
26may not use funds from the Supplemental Low-Income Energy

 

 

09900SB1585sam002- 306 -LRB099 09533 EGJ 48253 a

1Assistance Fund to provide benefits to its customers under the
2program authorized by Section 4 of this Act.
3    In its use of federal funds under this Act, the Department
4may not cause a disproportionate share of those federal funds
5to benefit customers of systems which do not assess the charge
6provided by this Section.
7    This Section is repealed effective December 31, 2018 unless
8renewed by action of the General Assembly. The General Assembly
9shall consider the results of the evaluations described in
10Section 8 in its deliberations.
11(Source: P.A. 98-429, eff. 8-16-13; 99-457, eff. 1-1-16.)
 
12    (305 ILCS 20/18)
13    Sec. 18. Financial assistance; payment plans.
14    (a) The Percentage of Income Payment Plan (PIPP or PIP
15Plan) is hereby created as a mandatory bill payment assistance
16program for low-income residential customers of utilities
17serving more than 100,000 retail customers as of January 1,
182009. The PIP Plan will:
19        (1) bring participants' gas and electric bills into the
20    range of affordability;
21        (2) provide incentives for participants to make timely
22    payments;
23        (3) encourage participants to reduce usage and
24    participate in conservation and energy efficiency measures
25    that reduce the customer's bill and payment requirements;

 

 

09900SB1585sam002- 307 -LRB099 09533 EGJ 48253 a

1    and
2        (4) identify participants whose homes are most in need
3    of weatherization.
4    (b) For purposes of this Section:
5        (1) "LIHEAP" means the energy assistance program
6    established under the Illinois Energy Assistance Act and
7    the Low-Income Home Energy Assistance Act of 1981.
8        (2) "Plan participant" is an eligible participant who
9    is also eligible for the PIPP and who will receive either a
10    percentage of income payment credit under the PIPP criteria
11    set forth in this Act or a benefit pursuant to Section 4 of
12    this Act. Plan participants are a subset of eligible
13    participants.
14        (3) "Pre-program arrears" means the amount a plan
15    participant owes for gas or electric service at the time
16    the participant is determined to be eligible for the PIPP
17    or the program set forth in Section 4 of this Act.
18        (4) "Eligible participant" means any person who has
19    applied for, been accepted and is receiving residential
20    service from a gas or electric utility and who is also
21    eligible for LIHEAP.
22    (c) The PIP Plan shall be administered as follows:
23        (1) The Department shall coordinate with Local
24    Administrative Agencies (LAAs), to determine eligibility
25    for the Illinois Low Income Home Energy Assistance Program
26    (LIHEAP) pursuant to the Energy Assistance Act, provided

 

 

09900SB1585sam002- 308 -LRB099 09533 EGJ 48253 a

1    that eligible income shall be no more than 150% of the
2    poverty level. Applicants will be screened to determine
3    whether the applicant's projected payments for electric
4    service or natural gas service over a 12-month period
5    exceed the criteria established in this Section. To
6    maintain the financial integrity of the program, the
7    Department may limit eligibility to households with income
8    below 125% of the poverty level.
9        (2) The Department shall establish the percentage of
10    income formula to determine the amount of a monthly credit,
11    not to exceed $150 per month per household, not to exceed
12    $1,800 annually, that will be applied to PIP Plan
13    participants' utility bills based on the portion of the
14    bill that is the responsibility of the participant provided
15    that the percentage shall be no more than a total of 6% of
16    the relevant income for gas and electric utility bills
17    combined, but in any event no less than $10 per month,
18    unless the household does not pay directly for heat, in
19    which case its payment shall be 2.4% of income but in any
20    event no less than $5 per month. The Department may
21    establish a minimum credit amount based on the cost of
22    administering the program and may deny credits to otherwise
23    eligible participants if the cost of administering the
24    credit exceeds the actual amount of any monthly credit to a
25    participant. If the participant takes both gas and electric
26    service, 66.67% of the credit shall be allocated to the

 

 

09900SB1585sam002- 309 -LRB099 09533 EGJ 48253 a

1    entity that provides the participant's primary energy
2    supply for heating. Each participant shall enter into a
3    levelized payment plan for, as applicable, gas and electric
4    service and such plans shall be implemented by the utility
5    so that a participant's usage and required payments are
6    reviewed and adjusted regularly, but no more frequently
7    than quarterly. Nothing in this Section is intended to
8    prohibit a customer, who is otherwise eligible for LIHEAP,
9    from participating in the program described in Section 4 of
10    this Act. Eligible participants who receive such a benefit
11    shall be considered plan participants and shall be eligible
12    to participate in the Arrearage Reduction Program
13    described in item (5) of this subsection (c).
14        (3) The Department shall remit, through the LAAs, to
15    the utility or participating alternative supplier that
16    portion of the plan participant's bill that is not the
17    responsibility of the participant. In the event that the
18    Department fails to timely remit payment to the utility,
19    the utility shall be entitled to recover all costs related
20    to such nonpayment through the automatic adjustment clause
21    tariffs established pursuant to Section 16-111.8 and
22    Section 19-145 of the Public Utilities Act. For purposes of
23    this item (3) of this subsection (c), payment is due on the
24    date specified on the participant's bill. The Department,
25    the Department of Revenue and LAAs shall adopt processes
26    that provide for the timely payment required by this item

 

 

09900SB1585sam002- 310 -LRB099 09533 EGJ 48253 a

1    (3) of this subsection (c).
2        (4) A plan participant is responsible for all actual
3    charges for utility service in excess of the PIPP credit.
4    Pre-program arrears that are included in the Arrearage
5    Reduction Program described in item (5) of this subsection
6    (c) shall not be included in the calculation of the
7    levelized payment plan. Emergency or crisis assistance
8    payments shall not affect the amount of any PIPP credit to
9    which a participant is entitled.
10        (5) Electric and gas utilities subject to this Section
11    shall implement an Arrearage Reduction Program (ARP) for
12    plan participants as follows: for each month that a plan
13    participant timely pays his or her utility bill, the
14    utility shall apply a credit to a portion of the
15    participant's pre-program arrears, if any, equal to
16    one-twelfth of such arrearage provided that the total
17    amount of arrearage credits shall equal no more than $1,000
18    annually for each participant for gas and no more than
19    $1,000 annually for each participant for electricity. In
20    the third year of the PIPP, the Department, in consultation
21    with the Policy Advisory Council established pursuant to
22    Section 5 of this Act, shall determine by rule an
23    appropriate per participant total cap on such amounts, if
24    any. Those plan participants participating in the ARP shall
25    not be subject to the imposition of any additional late
26    payment fees on pre-program arrears covered by the ARP. In

 

 

09900SB1585sam002- 311 -LRB099 09533 EGJ 48253 a

1    all other respects, the utility shall bill and collect the
2    monthly bill of a plan participant pursuant to the same
3    rules, regulations, programs and policies as applicable to
4    residential customers generally. Participation in the
5    Arrearage Reduction Program shall be limited to the maximum
6    amount of funds available as set forth in subsection (f) of
7    Section 13 of this Act. In the event any donated funds
8    under Section 13 of this Act are specifically designated
9    for the purpose of funding the ARP, the Department shall
10    remit such amounts to the utilities upon verification that
11    such funds are needed to fund the ARP. Nothing in this
12    Section shall preclude a utility from continuing to
13    implement, and apply credits under, an ARP in the event
14    that the PIPP or LIHEAP is suspended due to lack of funding
15    such that the plan participant does not receive a benefit
16    under either the PIPP or LIHEAP.
17        (5.5) In addition to the ARP described in paragraph (5)
18    of this subsection (c), utilities may also implement a
19    Supplemental Arrearage Reduction Program (SARP) for
20    eligible participants who are not able to become plan
21    participants due to PIPP timing or funding constraints. If
22    a utility elects to implement a SARP, it shall be
23    administered as follows: for each month that a SARP
24    participant timely pays his or her utility bill, the
25    utility shall apply a credit to a portion of the
26    participant's pre-program arrears, if any, equal to

 

 

09900SB1585sam002- 312 -LRB099 09533 EGJ 48253 a

1    one-twelfth of such arrearage, provided that the utility
2    may limit the total amount of arrearage credits to no more
3    than $1,000 annually for each participant for gas and no
4    more than $1,000 annually for each participant for
5    electricity. SARP participants shall not be subject to the
6    imposition of any additional late payment fees on
7    pre-program arrears covered by the ARP. In all other
8    respects, the utility shall bill and collect the monthly
9    bill of a SARP participant pursuant to the same rules,
10    regulations, programs, and policies as applicable to
11    residential customers generally. Participation in the SARP
12    shall be limited to the maximum amount of funds available
13    as set forth in subsection (f) of Section 13 of this Act.
14    In the event any donated funds under Section 13 of this Act
15    are specifically designated for the purpose of funding the
16    SARP, the Department shall remit such amounts to the
17    utilities upon verification that such funds are needed to
18    fund the SARP.
19        (6) The Department may terminate a plan participant's
20    eligibility for the PIP Plan upon notification by the
21    utility that the participant's monthly utility payment is
22    more than 45 days past due.
23        (7) The Department, in consultation with the Policy
24    Advisory Council, may adjust the number of PIP Plan
25    participants annually, if necessary, to match the
26    availability of funds from LIHEAP. Any plan participant who

 

 

09900SB1585sam002- 313 -LRB099 09533 EGJ 48253 a

1    qualifies for a PIPP credit under a utility's PIPP shall be
2    entitled to participate in and receive a credit under such
3    utility's ARP for so long as such utility has ARP funds
4    available, regardless of whether the customer's
5    participation under another utility's PIPP or ARP has been
6    curtailed or limited because of a lack of funds.
7        (8) The Department shall fully implement the PIPP at
8    the earliest possible date it is able to effectively
9    administer the PIPP. Within 90 days of the effective date
10    of this amendatory Act of the 96th General Assembly, the
11    Department shall, in consultation with utility companies,
12    participating alternative suppliers, LAAs and the Illinois
13    Commerce Commission (Commission), issue a detailed
14    implementation plan which shall include detailed testing
15    protocols and analysis of the capacity for implementation
16    by the LAAs and utilities. Such consultation process also
17    shall address how to implement the PIPP in the most
18    cost-effective and timely manner, and shall identify
19    opportunities for relying on the expertise of utilities,
20    LAAs and the Commission. Following the implementation of
21    the testing protocols, the Department shall issue a written
22    report on the feasibility of full or gradual
23    implementation. The PIPP shall be fully implemented by
24    September 1, 2011, but may be phased in prior to that date.
25        (9) As part of the screening process established under
26    item (1) of this subsection (c), the Department and LAAs

 

 

09900SB1585sam002- 314 -LRB099 09533 EGJ 48253 a

1    shall assess whether any energy efficiency or demand
2    response measures are available to the plan participant at
3    no cost, and if so, the participant shall enroll in any
4    such program for which he or she is eligible. The LAAs
5    shall assist the participant in the applicable enrollment
6    or application process.
7        (10) Each alternative retail electric and gas supplier
8    serving residential customers shall elect whether to
9    participate in the PIPP or ARP described in this Section.
10    Any such supplier electing to participate in the PIPP shall
11    provide to the Department such information as the
12    Department may require, including, without limitation,
13    information sufficient for the Department to determine the
14    proportionate allocation of credits between the
15    alternative supplier and the utility. If a utility in whose
16    service territory an alternative supplier serves customers
17    contributes money to the ARP fund which is not recovered
18    from ratepayers, then an alternative supplier which
19    participates in ARP in that utility's service territory
20    shall also contribute to the ARP fund in an amount that is
21    commensurate with the number of alternative supplier
22    customers who elect to participate in the program.
23    (d) The Department, in consultation with the Policy
24Advisory Council, shall develop and implement a program to
25educate customers about the PIP Plan and about their rights and
26responsibilities under the percentage of income component. The

 

 

09900SB1585sam002- 315 -LRB099 09533 EGJ 48253 a

1Department, in consultation with the Policy Advisory Council,
2shall establish a process that LAAs shall use to contact
3customers in jeopardy of losing eligibility due to late
4payments. The Department shall ensure that LAAs are adequately
5funded to perform all necessary educational tasks.
6    (e) The PIPP shall be administered in a manner which
7ensures that credits to plan participants will not be counted
8as income or as a resource in other means-tested assistance
9programs for low-income households or otherwise result in the
10loss of federal or State assistance dollars for low-income
11households.
12    (f) In order to ensure that implementation costs are
13minimized, the Department and utilities shall work together to
14identify cost-effective ways to transfer information
15electronically and to employ available protocols that will
16minimize their respective administrative costs as follows:
17        (1) The Commission may require utilities to provide
18    such information on customer usage and billing and payment
19    information as required by the Department to implement the
20    PIP Plan and to provide written notices and communications
21    to plan participants.
22        (2) Each utility and participating alternative
23    supplier shall file annual reports with the Department and
24    the Commission that cumulatively summarize and update
25    program information as required by the Commission's rules.
26    The reports shall track implementation costs and contain

 

 

09900SB1585sam002- 316 -LRB099 09533 EGJ 48253 a

1    such information as is necessary to evaluate the success of
2    the PIPP.
3        (3) The Department and the Commission shall have the
4    authority to promulgate rules and regulations necessary to
5    execute and administer the provisions of this Section.
6    (g) Each utility shall be entitled to recover reasonable
7administrative and operational costs incurred to comply with
8this Section from the Supplemental Low Income Energy Assistance
9Fund. The utility may net such costs against monies it would
10otherwise remit to the Funds, and each utility shall include in
11the annual report required under subsection (f) of this Section
12an accounting for the funds collected.
13(Source: P.A. 96-33, eff. 7-10-09.)
 
14    Section 97. Severability. The provisions of this Act are
15severable under Section 1.31 of the Statute on Statutes.
 
16    Section 99. Effective date. This Act takes effect upon
17becoming law.".