Illinois-2021-SB0311-Introduced

102ND GENERAL ASSEMBLY State of Illinois 2021 and 2022 SB0311

Introduced 2/19/2021, by Sen. Christopher Belt

SYNOPSIS AS INTRODUCED:

See Index

Amends the Illinois Power Agency Act. In provisions concerning the renewable portfolio standards, specifies the goals for procurement of renewable energy credits and cost-effective renewable energy resources that shall be included in the long-term renewable resources procurement plan and makes other changes concerning these procurements and provides for the calculation of the cost of equity for the purposes of recovering all reasonable and prudently incurred costs of energy efficiency measures from retail customers. Provides that savings of fuels other than electricity achieved by measures that educate about, incentivize, encourage, or otherwise support the use of electricity to power vehicles shall count towards the applicable annual incremental goal and shall not be included in determining certain limits. Amends the Public Utilities Act. Provides that an electric utility that serves less than 3,000,000 retail customers but more than 500,000 customers in this State may plan for, construct, install, control, own, manage, or operate photovoltaic electricity production facilities and any energy storage facilities that are planned for, constructed, installed, controlled, owned, managed, or operated in connection with photovoltaic electricity production facilities without obtaining a certificate of public convenience and necessity subject to specified terms and conditions. Provides that a public utility that provided electric service to at least 1,000,000 retail customers in Illinois and gas service to at least 500,000 retail customers in Illinois may elect to recover its natural gas delivery services costs through a performance-based rate. Provides that, beginning in 2022, without obtaining any approvals from the Commission or any other agency, regardless of whether any such approval would otherwise be required, a participating utility that is a combination utility shall pay $1,000,000 per year for 10 years to the energy low-income and support program. Adds provisions authorizing certain utilities to plan for, construct, install, control, own, manage, or operate electric vehicle charging infrastructure. Amends the Prevailing Wage Act to include specified facilities financed in whole or in part with renewable energy resources in the definition of "public works". Makes other changes. Effective immediately.

LRB102 15398 SPS 20761 b

A BILL FOR

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1 AN ACT concerning regulation.

2 Be it enacted by the People of the State of Illinois,

3 represented in the General Assembly:

4 Section 1. Findings.

5 (a) Over the last decade, the General Assembly has

6 empowered the State of Illinois to become a national leader in

7 the implementation of a progressive energy policy. The General

8 Assembly has enacted laws to increase investment in equitable

9 energy efficiency, clean and renewable energy, and continued

10 modernization of the electric grid. The General Assembly has

11 further encouraged and enabled investment in the clean energy

12 economy in Illinois to ensure that the State and its citizens,

13 including low-income individuals, are equipped to enjoy the

14 opportunities and benefits of a smart grid and smart metering

15 infrastructure platform, adopt and deploy cost-effective

16 distributed energy resource technologies and devices, and

17 benefit from investments in job training and job creation. To

18 ensure this progress can be sustained, the General Assembly

19 finds and declares the following:

20 (1) The State of Illinois is a geographically large

21 and diverse State and communities in central and southern

22 Illinois have different strengths and needs than those in

23 the northern region of the State.

24 (2) The changing energy marketplace is having a

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1 measurable effect on employment, economic development,

2 business growth, non-profit health, school funding, local

3 government stability, and community development in central

4 and southern Illinois, and updated policies are needed to

5 address those impacts.

6 (3) The State should accelerate the development and

7 adoption of technologies and facilities in central and

8 southern Illinois so that there are greater opportunities

9 for investment in clean energy, electric vehicles, energy

10 storage facilities, management of peak load, and grid

11 stability and reliability.

12 (4) Continuing the transparent, predictable, and

13 accountable policy that allows electric utilities to

14 undertake needed system investments and earn a fair return

15 on their investments in an efficient manner is the best

16 method for building a smart, reliable grid that is

17 equipped for the clean energy future.

18 (b) The General Assembly therefore finds that it is

19 necessary to develop an energy policy for central and southern

20 Illinois that accelerates achievement of the State's renewable

21 portfolio standard by creating new opportunities for

22 investments in solar assets, building an electric vehicle

23 charging infrastructure across hundreds of miles of roads,

24 increasing research and deployment of new clean energy

25 technology, and continuing to utilize transparent annual

26 reviews to recover costs and set reasonable rates.

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1 Section 5. The Illinois Power Agency Act is amended by

2 changing Sections 1-10 and 1-75 as follows:

3 (20 ILCS 3855/1-10)

4 Sec. 1-10. Definitions.

5 "Agency" means the Illinois Power Agency.

6 "Agency loan agreement" means any agreement pursuant to

7 which the Illinois Finance Authority agrees to loan the

8 proceeds of revenue bonds issued with respect to a project to

9 the Agency upon terms providing for loan repayment

10 installments at least sufficient to pay when due all principal

11 of, interest and premium, if any, on those revenue bonds, and

12 providing for maintenance, insurance, and other matters in

13 respect of the project.

14 "Authority" means the Illinois Finance Authority.

15 "Brownfield site photovoltaic project" means photovoltaics

16 that are:

17 (1) interconnected to an electric utility as defined

18 in this Section, a municipal utility as defined in this

19 Section, a public utility as defined in Section 3-105 of

20 the Public Utilities Act, or an electric cooperative, as

21 defined in Section 3-119 of the Public Utilities Act; and

22 (2) located at a site that is regulated by any of the

23 following entities under the following programs:

24 (A) the United States Environmental Protection

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1 Agency under the federal Comprehensive Environmental

2 Response, Compensation, and Liability Act of 1980, as

3 amended;

4 (B) the United States Environmental Protection

5 Agency under the Corrective Action Program of the

6 federal Resource Conservation and Recovery Act, as

7 amended;

8 (C) the Illinois Environmental Protection Agency

9 under the Illinois Site Remediation Program; or

10 (D) the Illinois Environmental Protection Agency

11 under the Illinois Solid Waste Program.

12 "Clean coal facility" means an electric generating

13 facility that uses primarily coal as a feedstock and that

14 captures and sequesters carbon dioxide emissions at the

15 following levels: at least 50% of the total carbon dioxide

16 emissions that the facility would otherwise emit if, at the

17 time construction commences, the facility is scheduled to

18 commence operation before 2016, at least 70% of the total

19 carbon dioxide emissions that the facility would otherwise

20 emit if, at the time construction commences, the facility is

21 scheduled to commence operation during 2016 or 2017, and at

22 least 90% of the total carbon dioxide emissions that the

23 facility would otherwise emit if, at the time construction

24 commences, the facility is scheduled to commence operation

25 after 2017. The power block of the clean coal facility shall

26 not exceed allowable emission rates for sulfur dioxide,

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1 nitrogen oxides, carbon monoxide, particulates and mercury for

2 a natural gas-fired combined-cycle facility the same size as

3 and in the same location as the clean coal facility at the time

4 the clean coal facility obtains an approved air permit. All

5 coal used by a clean coal facility shall have high volatile

6 bituminous rank and greater than 1.7 pounds of sulfur per

7 million btu content, unless the clean coal facility does not

8 use gasification technology and was operating as a

9 conventional coal-fired electric generating facility on June

10 1, 2009 (the effective date of Public Act 95-1027).

11 "Clean coal SNG brownfield facility" means a facility that

12 (1) has commenced construction by July 1, 2015 on an urban

13 brownfield site in a municipality with at least 1,000,000

14 residents; (2) uses a gasification process to produce

15 substitute natural gas; (3) uses coal as at least 50% of the

16 total feedstock over the term of any sourcing agreement with a

17 utility and the remainder of the feedstock may be either

18 petroleum coke or coal, with all such coal having a high

19 bituminous rank and greater than 1.7 pounds of sulfur per

20 million Btu content unless the facility reasonably determines

21 that it is necessary to use additional petroleum coke to

22 deliver additional consumer savings, in which case the

23 facility shall use coal for at least 35% of the total feedstock

24 over the term of any sourcing agreement; and (4) captures and

25 sequesters at least 85% of the total carbon dioxide emissions

26 that the facility would otherwise emit.

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1 "Clean coal SNG facility" means a facility that uses a

2 gasification process to produce substitute natural gas, that

3 sequesters at least 90% of the total carbon dioxide emissions

4 that the facility would otherwise emit, that uses at least 90%

5 coal as a feedstock, with all such coal having a high

6 bituminous rank and greater than 1.7 pounds of sulfur per

7 million btu content, and that has a valid and effective permit

8 to construct emission sources and air pollution control

9 equipment and approval with respect to the federal regulations

10 for Prevention of Significant Deterioration of Air Quality

11 (PSD) for the plant pursuant to the federal Clean Air Act;

12 provided, however, a clean coal SNG brownfield facility shall

13 not be a clean coal SNG facility.

14 "Commission" means the Illinois Commerce Commission.

15 "Community renewable generation project" means an electric

16 generating facility that:

17 (1) is powered by wind, solar thermal energy,

18 photovoltaic cells or panels, biodiesel, crops and

19 untreated and unadulterated organic waste biomass, tree

20 waste, and hydropower that does not involve new

21 construction or significant expansion of hydropower dams;

22 (2) is interconnected at the distribution system level

23 of an electric utility as defined in this Section, a

24 municipal utility as defined in this Section that owns or

25 operates electric distribution facilities, a public

26 utility as defined in Section 3-105 of the Public

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1 Utilities Act, or an electric cooperative, as defined in

2 Section 3-119 of the Public Utilities Act;

3 (3) credits the value of electricity generated by the

4 facility to the subscribers of the facility; and

5 (4) is limited in nameplate capacity to less than or

6 equal to 2,000 kilowatts.

7 "Costs incurred in connection with the development and

8 construction of a facility" means:

9 (1) the cost of acquisition of all real property,

10 fixtures, and improvements in connection therewith and

11 equipment, personal property, and other property, rights,

12 and easements acquired that are deemed necessary for the

13 operation and maintenance of the facility;

14 (2) financing costs with respect to bonds, notes, and

15 other evidences of indebtedness of the Agency;

16 (3) all origination, commitment, utilization,

17 facility, placement, underwriting, syndication, credit

18 enhancement, and rating agency fees;

19 (4) engineering, design, procurement, consulting,

20 legal, accounting, title insurance, survey, appraisal,

21 escrow, trustee, collateral agency, interest rate hedging,

22 interest rate swap, capitalized interest, contingency, as

23 required by lenders, and other financing costs, and other

24 expenses for professional services; and

25 (5) the costs of plans, specifications, site study and

26 investigation, installation, surveys, other Agency costs

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1 and estimates of costs, and other expenses necessary or

2 incidental to determining the feasibility of any project,

3 together with such other expenses as may be necessary or

4 incidental to the financing, insuring, acquisition, and

5 construction of a specific project and starting up,

6 commissioning, and placing that project in operation.

7 "Delivery services" has the same definition as found in

8 Section 16-102 of the Public Utilities Act.

9 "Delivery year" means the consecutive 12-month period

10 beginning June 1 of a given year and ending May 31 of the

11 following year.

12 "Department" means the Department of Commerce and Economic

13 Opportunity.

14 "Director" means the Director of the Illinois Power

15 Agency.

16 "Demand-response" means measures that decrease peak

17 electricity demand or shift demand from peak to off-peak

18 periods.

19 "Distributed renewable energy generation device" means a

20 device that is:

21 (1) powered by wind, solar thermal energy,

22 photovoltaic cells or panels, biodiesel, crops and

23 untreated and unadulterated organic waste biomass, tree

24 waste, and hydropower that does not involve new

25 construction or significant expansion of hydropower dams;

26 (2) interconnected at the distribution system level of

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1 either an electric utility as defined in this Section, a

2 municipal utility as defined in this Section that owns or

3 operates electric distribution facilities, or a rural

4 electric cooperative as defined in Section 3-119 of the

5 Public Utilities Act;

6 (3) located on the customer side of the customer's

7 electric meter and is primarily used to offset that

8 customer's electricity load; and

9 (4) limited in nameplate capacity to less than or

10 equal to 2,000 kilowatts.

11 "Energy efficiency" means measures that reduce the amount

12 of electricity or natural gas consumed in order to achieve a

13 given end use. "Energy efficiency" includes voltage

14 optimization measures that optimize the voltage at points on

15 the electric distribution voltage system and thereby reduce

16 electricity consumption by electric customers' end use

17 devices. "Energy efficiency" also includes measures that

18 reduce the total Btus of electricity, natural gas, and other

19 fuels needed to meet the end use or uses. For electric

20 utilities that serve less than 3,000,000 retail customers but

21 more than 500,000 retail customers in this State, energy

22 efficiency measures that reduce the total Btus of electricity,

23 natural gas, or other fuels needed to meet the end use or uses,

24 shall include, but are not limited to, measures that educate

25 about, incentivize, encourage, or otherwise support the use of

26 electricity to power, in whole or in part, vehicles,

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1 including, but not limited to, cars, trucks, buses, trains,

2 trolleys, boats, on-road or off-road vehicles, or other

3 equipment or methods of transporting goods or people, and such

4 measures shall include, but are not limited to, measures that

5 educate about, incentivize, encourage, or otherwise support

6 the adoption of electric vehicles by retail customers of all

7 customer classes.

8 "Electric utility" has the same definition as found in

9 Section 16-102 of the Public Utilities Act.

10 "Facility" means an electric generating unit or a

11 co-generating unit that produces electricity along with

12 related equipment necessary to connect the facility to an

13 electric transmission or distribution system.

14 "Governmental aggregator" means one or more units of local

15 government that individually or collectively procure

16 electricity to serve residential retail electrical loads

17 located within its or their jurisdiction.

18 "Local government" means a unit of local government as

19 defined in Section 1 of Article VII of the Illinois

20 Constitution.

21 "Municipality" means a city, village, or incorporated

22 town.

23 "Municipal utility" means a public utility owned and

24 operated by any subdivision or municipal corporation of this

25 State.

26 "Nameplate capacity" means the aggregate inverter

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1 nameplate capacity in kilowatts AC.

2 "Person" means any natural person, firm, partnership,

3 corporation, either domestic or foreign, company, association,

4 limited liability company, joint stock company, or association

5 and includes any trustee, receiver, assignee, or personal

6 representative thereof.

7 "Project" means the planning, bidding, and construction of

8 a facility.

9 "Public utility" has the same definition as found in

10 Section 3-105 of the Public Utilities Act.

11 "Real property" means any interest in land together with

12 all structures, fixtures, and improvements thereon, including

13 lands under water and riparian rights, any easements,

14 covenants, licenses, leases, rights-of-way, uses, and other

15 interests, together with any liens, judgments, mortgages, or

16 other claims or security interests related to real property.

17 "Renewable energy credit" means a tradable credit that

18 represents the environmental attributes of one megawatt hour

19 of energy produced from a renewable energy resource.

20 "Renewable energy resources" includes energy and its

21 associated renewable energy credit or renewable energy credits

22 from wind, solar thermal energy, photovoltaic cells and

23 panels, biodiesel, anaerobic digestion, crops and untreated

24 and unadulterated organic waste biomass, tree waste, and

25 hydropower that does not involve new construction or

26 significant expansion of hydropower dams. For purposes of this

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1 Act, landfill gas produced in the State is considered a

2 renewable energy resource. "Renewable energy resources" does

3 not include the incineration or burning of tires, garbage,

4 general household, institutional, and commercial waste,

5 industrial lunchroom or office waste, landscape waste other

6 than tree waste, railroad crossties, utility poles, or

7 construction or demolition debris, other than untreated and

8 unadulterated waste wood.

9 "Retail customer" has the same definition as found in

10 Section 16-102 of the Public Utilities Act.

11 "Revenue bond" means any bond, note, or other evidence of

12 indebtedness issued by the Authority, the principal and

13 interest of which is payable solely from revenues or income

14 derived from any project or activity of the Agency.

15 "Sequester" means permanent storage of carbon dioxide by

16 injecting it into a saline aquifer, a depleted gas reservoir,

17 or an oil reservoir, directly or through an enhanced oil

18 recovery process that may involve intermediate storage,

19 regardless of whether these activities are conducted by a

20 clean coal facility, a clean coal SNG facility, a clean coal

21 SNG brownfield facility, or a party with which a clean coal

22 facility, clean coal SNG facility, or clean coal SNG

23 brownfield facility has contracted for such purposes.

24 "Service area" has the same definition as found in Section

25 16-102 of the Public Utilities Act.

26 "Sourcing agreement" means (i) in the case of an electric

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1 utility, an agreement between the owner of a clean coal

2 facility and such electric utility, which agreement shall have

3 terms and conditions meeting the requirements of paragraph (3)

4 of subsection (d) of Section 1-75, (ii) in the case of an

5 alternative retail electric supplier, an agreement between the

6 owner of a clean coal facility and such alternative retail

7 electric supplier, which agreement shall have terms and

8 conditions meeting the requirements of Section 16-115(d)(5) of

9 the Public Utilities Act, and (iii) in case of a gas utility,

10 an agreement between the owner of a clean coal SNG brownfield

11 facility and the gas utility, which agreement shall have the

12 terms and conditions meeting the requirements of subsection

13 (h-1) of Section 9-220 of the Public Utilities Act.

14 "Subscriber" means a person who (i) takes delivery service

15 from an electric utility, and (ii) has a subscription of no

16 less than 200 watts to a community renewable generation

17 project that is located in the electric utility's service

18 area. No subscriber's subscriptions may total more than 40% of

19 the nameplate capacity of an individual community renewable

20 generation project. Entities that are affiliated by virtue of

21 a common parent shall not represent multiple subscriptions

22 that total more than 40% of the nameplate capacity of an

23 individual community renewable generation project.

24 "Subscription" means an interest in a community renewable

25 generation project expressed in kilowatts, which is sized

26 primarily to offset part or all of the subscriber's

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1 electricity usage.

2 "Substitute natural gas" or "SNG" means a gas manufactured

3 by gasification of hydrocarbon feedstock, which is

4 substantially interchangeable in use and distribution with

5 conventional natural gas.

6 "Total resource cost test" or "TRC test" means a standard

7 that is met if, for an investment in energy efficiency or

8 demand-response measures, the benefit-cost ratio is greater

9 than one. The benefit-cost ratio is the ratio of the net

10 present value of the total benefits of the program to the net

11 present value of the total costs as calculated over the

12 lifetime of the measures. A total resource cost test compares

13 the sum of avoided electric utility costs, representing the

14 benefits that accrue to the system and the participant in the

15 delivery of those efficiency measures and including avoided

16 costs associated with reduced use of natural gas or other

17 fuels, avoided costs associated with reduced water

18 consumption, and avoided costs associated with reduced

19 operation and maintenance costs, as well as other quantifiable

20 societal benefits, to the sum of all incremental costs of

21 end-use measures that are implemented due to the program

22 (including both utility and participant contributions), plus

23 costs to administer, deliver, and evaluate each demand-side

24 program, to quantify the net savings obtained by substituting

25 the demand-side program for supply resources. In calculating

26 avoided costs of power and energy that an electric utility

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1 would otherwise have had to acquire, reasonable estimates

2 shall be included of financial costs likely to be imposed by

3 future regulations and legislation on emissions of greenhouse

4 gases. In discounting future societal costs and benefits for

5 the purpose of calculating net present values, a societal

6 discount rate based on actual, long-term Treasury bond yields

7 should be used. Notwithstanding anything to the contrary, the

8 TRC test shall not include or take into account a calculation

9 of market price suppression effects or demand reduction

10 induced price effects.

11 "Utility-scale solar project" means an electric generating

12 facility that:

13 (1) generates electricity using photovoltaic cells;

14 and

15 (2) has a nameplate capacity that is greater than

16 2,000 kilowatts.

17 "Utility-scale wind project" means an electric generating

18 facility that:

19 (1) generates electricity using wind; and

20 (2) has a nameplate capacity that is greater than

21 2,000 kilowatts.

22 "Zero emission credit" means a tradable credit that

23 represents the environmental attributes of one megawatt hour

24 of energy produced from a zero emission facility.

25 "Zero emission facility" means a facility that: (1) is

26 fueled by nuclear power; and (2) is interconnected with PJM

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1 Interconnection, LLC or the Midcontinent Independent System

2 Operator, Inc., or their successors.

3 (Source: P.A. 98-90, eff. 7-15-13; 99-906, eff. 6-1-17.)

4 (20 ILCS 3855/1-75)

5 Sec. 1-75. Planning and Procurement Bureau. The Planning

6 and Procurement Bureau has the following duties and

7 responsibilities:

8 (a) The Planning and Procurement Bureau shall each year,

9 beginning in 2008, develop procurement plans and conduct

10 competitive procurement processes in accordance with the

11 requirements of Section 16-111.5 of the Public Utilities Act

12 for the eligible retail customers of electric utilities that

13 on December 31, 2005 provided electric service to at least

14 100,000 customers in Illinois. Beginning with the delivery

15 year commencing on June 1, 2017, the Planning and Procurement

16 Bureau shall develop plans and processes for the procurement

17 of zero emission credits from zero emission facilities in

18 accordance with the requirements of subsection (d-5) of this

19 Section. The Planning and Procurement Bureau shall also

20 develop procurement plans and conduct competitive procurement

21 processes in accordance with the requirements of Section

22 16-111.5 of the Public Utilities Act for the eligible retail

23 customers of small multi-jurisdictional electric utilities

24 that (i) on December 31, 2005 served less than 100,000

25 customers in Illinois and (ii) request a procurement plan for

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1 their Illinois jurisdictional load. This Section shall not

2 apply to a small multi-jurisdictional utility until such time

3 as a small multi-jurisdictional utility requests the Agency to

4 prepare a procurement plan for their Illinois jurisdictional

5 load. For the purposes of this Section, the term "eligible

6 retail customers" has the same definition as found in Section

7 16-111.5(a) of the Public Utilities Act.

8 Beginning with the plan or plans to be implemented in the

9 2017 delivery year, the Agency shall no longer include the

10 procurement of renewable energy resources in the annual

11 procurement plans required by this subsection (a), except as

12 provided in subsection (q) of Section 16-111.5 of the Public

13 Utilities Act, and shall instead develop a long-term renewable

14 resources procurement plan in accordance with subsection (c)

15 of this Section and Section 16-111.5 of the Public Utilities

16 Act.

17 (1) The Agency shall each year, beginning in 2008, as

18 needed, issue a request for qualifications for experts or

19 expert consulting firms to develop the procurement plans

20 in accordance with Section 16-111.5 of the Public

21 Utilities Act. In order to qualify an expert or expert

22 consulting firm must have:

23 (A) direct previous experience assembling

24 large-scale power supply plans or portfolios for

25 end-use customers;

26 (B) an advanced degree in economics, mathematics,

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1 engineering, risk management, or a related area of

2 study;

3 (C) 10 years of experience in the electricity

4 sector, including managing supply risk;

5 (D) expertise in wholesale electricity market

6 rules, including those established by the Federal

7 Energy Regulatory Commission and regional transmission

8 organizations;

9 (E) expertise in credit protocols and familiarity

10 with contract protocols;

11 (F) adequate resources to perform and fulfill the

12 required functions and responsibilities; and

13 (G) the absence of a conflict of interest and

14 inappropriate bias for or against potential bidders or

15 the affected electric utilities.

16 (2) The Agency shall each year, as needed, issue a

17 request for qualifications for a procurement administrator

18 to conduct the competitive procurement processes in

19 accordance with Section 16-111.5 of the Public Utilities

20 Act. In order to qualify an expert or expert consulting

21 firm must have:

22 (A) direct previous experience administering a

23 large-scale competitive procurement process;

24 (B) an advanced degree in economics, mathematics,

25 engineering, or a related area of study;

26 (C) 10 years of experience in the electricity

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1 sector, including risk management experience;

2 (D) expertise in wholesale electricity market

3 rules, including those established by the Federal

4 Energy Regulatory Commission and regional transmission

5 organizations;

6 (E) expertise in credit and contract protocols;

7 (F) adequate resources to perform and fulfill the

8 required functions and responsibilities; and

9 (G) the absence of a conflict of interest and

10 inappropriate bias for or against potential bidders or

11 the affected electric utilities.

12 (3) The Agency shall provide affected utilities and

13 other interested parties with the lists of qualified

14 experts or expert consulting firms identified through the

15 request for qualifications processes that are under

16 consideration to develop the procurement plans and to

17 serve as the procurement administrator. The Agency shall

18 also provide each qualified expert's or expert consulting

19 firm's response to the request for qualifications. All

20 information provided under this subparagraph shall also be

21 provided to the Commission. The Agency may provide by rule

22 for fees associated with supplying the information to

23 utilities and other interested parties. These parties

24 shall, within 5 business days, notify the Agency in

25 writing if they object to any experts or expert consulting

26 firms on the lists. Objections shall be based on:

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1 (A) failure to satisfy qualification criteria;

2 (B) identification of a conflict of interest; or

3 (C) evidence of inappropriate bias for or against

4 potential bidders or the affected utilities.

5 The Agency shall remove experts or expert consulting

6 firms from the lists within 10 days if there is a

7 reasonable basis for an objection and provide the updated

8 lists to the affected utilities and other interested

9 parties. If the Agency fails to remove an expert or expert

10 consulting firm from a list, an objecting party may seek

11 review by the Commission within 5 days thereafter by

12 filing a petition, and the Commission shall render a

13 ruling on the petition within 10 days. There is no right of

14 appeal of the Commission's ruling.

15 (4) The Agency shall issue requests for proposals to

16 the qualified experts or expert consulting firms to

17 develop a procurement plan for the affected utilities and

18 to serve as procurement administrator.

19 (5) The Agency shall select an expert or expert

20 consulting firm to develop procurement plans based on the

21 proposals submitted and shall award contracts of up to 5

22 years to those selected.

23 (6) The Agency shall select an expert or expert

24 consulting firm, with approval of the Commission, to serve

25 as procurement administrator based on the proposals

26 submitted. If the Commission rejects, within 5 days, the

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1 Agency's selection, the Agency shall submit another

2 recommendation within 3 days based on the proposals

3 submitted. The Agency shall award a 5-year contract to the

4 expert or expert consulting firm so selected with

5 Commission approval.

6 (b) The experts or expert consulting firms retained by the

7 Agency shall, as appropriate, prepare procurement plans, and

8 conduct a competitive procurement process as prescribed in

9 Section 16-111.5 of the Public Utilities Act, to ensure

10 adequate, reliable, affordable, efficient, and environmentally

11 sustainable electric service at the lowest total cost over

12 time, taking into account any benefits of price stability, for

13 eligible retail customers of electric utilities that on

14 December 31, 2005 provided electric service to at least

15 100,000 customers in the State of Illinois, and for eligible

16 Illinois retail customers of small multi-jurisdictional

17 electric utilities that (i) on December 31, 2005 served less

18 than 100,000 customers in Illinois and (ii) request a

19 procurement plan for their Illinois jurisdictional load.

20 (c) Renewable portfolio standard.

21 (1)(A) The Agency shall develop a long-term renewable

22 resources procurement plan that shall include procurement

23 programs and competitive procurement events necessary to

24 meet the goals set forth in this subsection (c). The

25 initial long-term renewable resources procurement plan

26 shall be released for comment no later than 160 days after

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1 June 1, 2017 (the effective date of Public Act 99-906).

2 The Agency shall review, and may revise on an expedited

3 basis, the long-term renewable resources procurement plan

4 at least every 2 years, which shall be conducted in

5 conjunction with the procurement plan under Section

6 16-111.5 of the Public Utilities Act to the extent

7 practicable to minimize administrative expense. The

8 long-term renewable resources procurement plans shall be

9 subject to review and approval by the Commission under

10 Section 16-111.5 of the Public Utilities Act.

11 (B) Subject to subparagraph (F) of this paragraph (1),

12 for electric utilities that serve more than 3,000,000

13 retail customers in this State or less than 500,000 retail

14 customers in this State, the long-term renewable resources

15 procurement plan shall include the goals for procurement

16 of renewable energy credits to meet at least the following

17 overall percentages: 13% by the 2017 delivery year;

18 increasing by at least 1.5% each delivery year thereafter

19 to at least 25% by the 2025 delivery year; and continuing

20 at no less than 25% for each delivery year thereafter and

21 for electric utilities that serve less than 3,000,000

22 retail customers but more than 500,000 retail customers in

23 this State, the long-term renewable resources procurement

24 plan shall include the goals for procurement of renewable

25 energy credits to meet at least the following overall

26 percentages: 13% by the 2017 delivery year; increasing by

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1 at least 1.5% each delivery year thereafter to at least

2 25% by the 2025 delivery year, and by at least 1.5% every

3 year thereafter to at least 32.5% by the 2030 delivery

4 year; and continuing at no less than 32.5% for each

5 delivery year thereafter. In the event of a conflict

6 between these goals and the new wind and new photovoltaic

7 procurement requirements described in items (i) through

8 (iii) of subparagraph (C) of this paragraph (1), the

9 long-term plan shall prioritize compliance with the new

10 wind and new photovoltaic procurement requirements

11 described in items (i) through (iii) of subparagraph (C)

12 of this paragraph (1) over the annual percentage targets

13 described in this subparagraph (B).

14 For the delivery year beginning June 1, 2017, the

15 procurement plan shall include cost-effective renewable

16 energy resources equal to at least 13% of each utility's

17 load for eligible retail customers and 13% of the

18 applicable portion of each utility's load for retail

19 customers who are not eligible retail customers, which

20 applicable portion shall equal 50% of the utility's load

21 for retail customers who are not eligible retail customers

22 on February 28, 2017.

23 For the delivery year beginning June 1, 2018, the

24 procurement plan shall include cost-effective renewable

25 energy resources equal to at least 14.5% of each utility's

26 load for eligible retail customers and 14.5% of the

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1 applicable portion of each utility's load for retail

2 customers who are not eligible retail customers, which

3 applicable portion shall equal 75% of the utility's load

4 for retail customers who are not eligible retail customers

5 on February 28, 2017.

6 For the delivery year beginning June 1, 2019, and for

7 each year thereafter, the procurement plans shall include

8 cost-effective renewable energy resources equal to a

9 minimum percentage of each utility's load for all retail

10 customers as follows: for electric utilities that serve

11 more than 3,000,000 retail customers in this State or less

12 than 500,000 retail customers in this State, 16% by June

13 1, 2019; increasing by 1.5% each year thereafter to 25% by

14 June 1, 2025; and 25% by June 1, 2026 and each year

15 thereafter and for electric utilities that serve less than

16 3,000,000 retail customers but more than 500,000 retail

17 customers in this State, 16% by June 1, 2019; increasing

18 by 1.5% each year thereafter to 32.5% by June 1, 2030; and

19 32.5% by June 1, 2031 and each year thereafter.

20 For each delivery year, the Agency shall first

21 recognize each utility's obligations for that delivery

22 year under existing contracts. Any renewable energy

23 credits under existing contracts, including renewable

24 energy credits as part of renewable energy resources,

25 shall be used to meet the goals set forth in this

26 subsection (c) for the delivery year.

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1 (C) Of the renewable energy credits procured under

2 this subsection (c), at least 75% shall come from wind and

3 photovoltaic projects. The long-term renewable resources

4 procurement plan described in subparagraph (A) of this

5 paragraph (1) shall include the procurement of renewable

6 energy credits in amounts equal to at least the following:

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

8 At least 2,000,000 renewable energy credits

9 for each delivery year shall come from new wind

10 projects; and

11 At least 2,000,000 renewable energy credits

12 for each delivery year shall come from new

13 photovoltaic projects; of that amount, to the

14 extent possible, the Agency shall procure: at

15 least 50% from solar photovoltaic projects using

16 the program outlined in subparagraph (K) of this

17 paragraph (1) from distributed renewable energy

18 generation devices or community renewable

19 generation projects; at least 40% from

20 utility-scale solar projects; at least 2% from

21 brownfield site photovoltaic projects that are not

22 community renewable generation projects; and the

23 remainder shall be determined through the

24 long-term planning process described in

25 subparagraph (A) of this paragraph (1); however,

26 if the long-term renewable resources procurement

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1 plan includes the procurement of more than

2 2,000,000 renewable energy credits from new

3 photovoltaic projects, then the foregoing

4 allocations of renewable energy credits from the

5 program outlined in subparagraph (K) of this

6 paragraph (1), utility-scale solar projects, and

7 brownfield site photovoltaic projects that are not

8 community renewable generation projects shall not

9 apply to the portion of the renewable energy

10 credits procured in excess of the 2,000,000

11 renewable energy credits procured on behalf of

12 electric utilities that serve less than 3,000,000

13 retail customers but more than 500,000 retail

14 customers in this State and the allocation of such

15 procurement on behalf of electric utilities that

16 serve less than 3,000,000 retail customers but

17 more than 500,000 retail customers in this State

18 shall instead be based on the mix that produces

19 the lowest cost for the renewable energy credits

20 procured.

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

22 At least 3,000,000 renewable energy credits

23 for each delivery year shall come from new wind

24 projects; and

25 At least 3,000,000 renewable energy credits

26 for each delivery year shall come from new

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1 photovoltaic projects; of that amount, to the

2 extent possible, the Agency shall procure: at

3 least 50% from solar photovoltaic projects using

4 the program outlined in subparagraph (K) of this

5 paragraph (1) from distributed renewable energy

6 devices or community renewable generation

7 projects; at least 40% from utility-scale solar

8 projects; at least 2% from brownfield site

9 photovoltaic projects that are not community

10 renewable generation projects; and the remainder

11 shall be determined through the long-term planning

12 process described in subparagraph (A) of this

13 paragraph (1); however, if the long-term renewable

14 resources procurement plan includes the

15 procurement of more than 3,000,000 renewable

16 energy credits from new photovoltaic projects,

17 then the foregoing allocations of renewable energy

18 credits from the program outlined in subparagraph

19 (K) of this paragraph (1), utility-scale solar

20 projects, and brownfield site photovoltaic

21 projects that are not community renewable

22 generation projects shall not apply to the portion

23 of the renewable energy credits procured in excess

24 of the 3,000,000 renewable energy credits procured

25 on behalf of electric utilities that serve less

26 than 3,000,000 retail customers but more than

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1 500,000 retail customers in this State and the

2 allocation of such procurement on behalf of

3 electric utilities that serve less than 3,000,000

4 retail customers but more than 500,000 retail

5 customers in this State shall instead be based on

6 the mix that produced the lowest cost for the

7 renewable energy credits procured.

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

9 At least 4,000,000 renewable energy credits

10 for each delivery year shall come from new wind

11 projects; and

12 At least 4,000,000 renewable energy credits

13 for each delivery year shall come from new

14 photovoltaic projects; of that amount, to the

15 extent possible, the Agency shall procure: at

16 least 50% from solar photovoltaic projects using

17 the program outlined in subparagraph (K) of this

18 paragraph (1) from distributed renewable energy

19 devices or community renewable generation

20 projects; at least 40% from utility-scale solar

21 projects; at least 2% from brownfield site

22 photovoltaic projects that are not community

23 renewable generation projects; and the remainder

24 shall be determined through the long-term planning

25 process described in subparagraph (A) of this

26 paragraph (1); however, if the long-term renewable

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1 resources procurement plan includes the

2 procurement of more than 4,000,000 renewable

3 energy credits from new photovoltaic projects,

4 then the foregoing allocations of renewable energy

5 credits from the program outlined in subparagraph

6 (K) of this paragraph (1), utility-scale solar

7 projects, and brownfield site photovoltaic

8 projects that are not community renewable

9 generation projects shall not apply to the portion

10 of the renewable energy credits procured in excess

11 of the 4,000,000 renewable energy credits procured

12 on behalf of electric utilities that serve less

13 than 3,000,000 retail customers but more than

14 500,000 retail customers in this State and the

15 allocation of such procurement on behalf of

16 electric utilities that serve less than 3,000,000

17 retail customers but more than 500,000 retail

18 customers in this State shall instead be based on

19 the mix that produced the lowest cost for the

20 renewable energy credits procured.

21 For purposes of this Section:

22 "New wind projects" means wind renewable

23 energy facilities that are energized after June 1,

24 2017 for the delivery year commencing June 1, 2017

25 or within 3 years after the date the Commission

26 approves contracts for subsequent delivery years.

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1 "New photovoltaic projects" means photovoltaic

2 renewable energy facilities that are energized

3 after June 1, 2017. Photovoltaic projects

4 developed under Section 1-56 of this Act shall not

5 apply towards the new photovoltaic project

6 requirements in this subparagraph (C).

7 (D) Renewable energy credits shall be cost effective.

8 For purposes of this subsection (c), "cost effective"

9 means that the costs of procuring renewable energy

10 resources do not cause the limit stated in subparagraph

11 (E) of this paragraph (1) to be exceeded and, for

12 renewable energy credits procured through a competitive

13 procurement event, do not exceed benchmarks based on

14 market prices for like products in the region. For

15 purposes of this subsection (c), "like products" means

16 contracts for renewable energy credits from the same or

17 substantially similar technology, same or substantially

18 similar vintage (new or existing), the same or

19 substantially similar quantity, and the same or

20 substantially similar contract length and structure.

21 Benchmarks shall be developed by the procurement

22 administrator, in consultation with the Commission staff,

23 Agency staff, and the procurement monitor and shall be

24 subject to Commission review and approval. If price

25 benchmarks for like products in the region are not

26 available, the procurement administrator shall establish

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1 price benchmarks based on publicly available data on

2 regional technology costs and expected current and future

3 regional energy prices. The benchmarks in this Section

4 shall not be used to curtail or otherwise reduce

5 contractual obligations entered into by or through the

6 Agency prior to June 1, 2017 (the effective date of Public

7 Act 99-906).

8 (E) For purposes of this subsection (c), the required

9 procurement of cost-effective renewable energy resources

10 for a particular year commencing prior to June 1, 2017

11 shall be measured as a percentage of the actual amount of

12 electricity (megawatt-hours) supplied by the electric

13 utility to eligible retail customers in the delivery year

14 ending immediately prior to the procurement, and, for

15 delivery years commencing on and after June 1, 2017, the

16 required procurement of cost-effective renewable energy

17 resources for a particular year shall be measured as a

18 percentage of the actual amount of electricity

19 (megawatt-hours) delivered by the electric utility in the

20 delivery year ending immediately prior to the procurement,

21 to all retail customers in its service territory. For

22 purposes of this subsection (c), the amount paid per

23 kilowatthour means the total amount paid for electric

24 service expressed on a per kilowatthour basis. For

25 purposes of this subsection (c), the total amount paid for

26 electric service includes without limitation amounts paid

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1 for supply, transmission, distribution, surcharges, and

2 add-on taxes.

3 Notwithstanding the requirements of this subsection

4 (c), the total of renewable energy resources procured

5 under the procurement plan for any single year shall be

6 subject to the limitations of this subparagraph (E). Such

7 procurement shall be reduced for all retail customers

8 based on the amount necessary to limit the annual

9 estimated average net increase due to the costs of these

10 resources included in the amounts paid by eligible retail

11 customers in connection with electric service to no more

12 than the greater of 2.015% of the amount paid per

13 kilowatthour by those customers during the year ending May

14 31, 2007 or the incremental amount per kilowatthour paid

15 for these resources in 2011; however, procurements that

16 occur for procurement periods that begin on or after June

17 1, 2026 shall be reduced for all retail customers of

18 electric utilities that serve less than 3,000,000 retail

19 customers but more than 500,000 retail customers in this

20 State only by an amount necessary to limit the annual

21 estimated average net increase due to the costs of these

22 resources included in the amounts paid by eligible retail

23 customers in connection with electric service to no more

24 than the greater of 2.515% of the amount paid per

25 kilowatthour by those customers during the year ending May

26 31, 2007 or the incremental amount per kilowatthour paid

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1 for these resources in 2011. To arrive at a maximum dollar

2 amount of renewable energy resources to be procured for

3 the particular delivery year, the resulting per

4 kilowatthour amount shall be applied to the actual amount

5 of kilowatthours of electricity delivered, or applicable

6 portion of such amount as specified in paragraph (1) of

7 this subsection (c), as applicable, by the electric

8 utility in the delivery year immediately prior to the

9 procurement to all retail customers in its service

10 territory. The calculations required by this subparagraph

11 (E) shall be made only once for each delivery year at the

12 time that the renewable energy resources are procured.

13 Once the determination as to the amount of renewable

14 energy resources to procure is made based on the

15 calculations set forth in this subparagraph (E) and the

16 contracts procuring those amounts are executed, no

17 subsequent rate impact determinations shall be made and no

18 adjustments to those contract amounts shall be allowed.

19 All costs incurred under such contracts shall be fully

20 recoverable by the electric utility as provided in this

21 Section.

22 (F) If the limitation on the amount of renewable

23 energy resources procured in subparagraph (E) of this

24 paragraph (1) prevents the Agency from meeting all of the

25 goals in this subsection (c), the Agency's long-term plan

26 shall prioritize compliance with the requirements of this

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1 subsection (c) regarding renewable energy credits in the

2 following order:

3 (i) renewable energy credits under existing

4 contractual obligations;

5 (i-5) funding for the Illinois Solar for All

6 Program, as described in subparagraph (O) of this

7 paragraph (1);

8 (ii) renewable energy credits necessary to comply

9 with the new wind and new photovoltaic procurement

10 requirements described in items (i) through (iii) of

11 subparagraph (C) of this paragraph (1); and

12 (iii) renewable energy credits necessary to meet

13 the remaining requirements of this subsection (c).

14 (G) The following provisions shall apply to the

15 Agency's procurement of renewable energy credits under

16 this subsection (c):

17 (i) Notwithstanding whether a long-term renewable

18 resources procurement plan has been approved, the

19 Agency shall conduct an initial forward procurement

20 for renewable energy credits from new utility-scale

21 wind projects within 160 days after June 1, 2017 (the

22 effective date of Public Act 99-906). For the purposes

23 of this initial forward procurement, the Agency shall

24 solicit 15-year contracts for delivery of 1,000,000

25 renewable energy credits delivered annually from new

26 utility-scale wind projects to begin delivery on June

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1 1, 2019, if available, but not later than June 1, 2021,

2 unless the project has delays in the establishment of

3 an operating interconnection with the applicable

4 transmission or distribution system as a result of the

5 actions or inactions of the transmission or

6 distribution provider, or other causes for force

7 majeure as outlined in the procurement contract, in

8 which case, not later than June 1, 2022. Payments to

9 suppliers of renewable energy credits shall commence

10 upon delivery. Renewable energy credits procured under

11 this initial procurement shall be included in the

12 Agency's long-term plan and shall apply to all

13 renewable energy goals in this subsection (c).

14 (ii) Notwithstanding whether a long-term renewable

15 resources procurement plan has been approved, the

16 Agency shall conduct an initial forward procurement

17 for renewable energy credits from new utility-scale

18 solar projects and brownfield site photovoltaic

19 projects within one year after June 1, 2017 (the

20 effective date of Public Act 99-906). For the purposes

21 of this initial forward procurement, the Agency shall

22 solicit 15-year contracts for delivery of 1,000,000

23 renewable energy credits delivered annually from new

24 utility-scale solar projects and brownfield site

25 photovoltaic projects to begin delivery on June 1,

26 2019, if available, but not later than June 1, 2021,

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1 unless the project has delays in the establishment of

2 an operating interconnection with the applicable

3 transmission or distribution system as a result of the

4 actions or inactions of the transmission or

5 distribution provider, or other causes for force

6 majeure as outlined in the procurement contract, in

7 which case, not later than June 1, 2022. The Agency may

8 structure this initial procurement in one or more

9 discrete procurement events. Payments to suppliers of

10 renewable energy credits shall commence upon delivery.

11 Renewable energy credits procured under this initial

12 procurement shall be included in the Agency's

13 long-term plan and shall apply to all renewable energy

14 goals in this subsection (c).

15 (iii) Subsequent forward procurements for

16 utility-scale wind projects shall solicit at least

17 1,000,000 renewable energy credits delivered annually

18 per procurement event and shall be planned, scheduled,

19 and designed such that the cumulative amount of

20 renewable energy credits delivered from all new wind

21 projects in each delivery year shall not exceed the

22 Agency's projection of the cumulative amount of

23 renewable energy credits that will be delivered from

24 all new photovoltaic projects, including utility-scale

25 and distributed photovoltaic devices, in the same

26 delivery year at the time scheduled for wind contract

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1 delivery.

2 (iv) If, at any time after the time set for

3 delivery of renewable energy credits pursuant to the

4 initial procurements in items (i) and (ii) of this

5 subparagraph (G), the cumulative amount of renewable

6 energy credits projected to be delivered from all new

7 wind projects in a given delivery year exceeds the

8 cumulative amount of renewable energy credits

9 projected to be delivered from all new photovoltaic

10 projects in that delivery year by 200,000 or more

11 renewable energy credits, then the Agency shall within

12 60 days adjust the procurement programs in the

13 long-term renewable resources procurement plan to

14 ensure that the projected cumulative amount of

15 renewable energy credits to be delivered from all new

16 wind projects does not exceed the projected cumulative

17 amount of renewable energy credits to be delivered

18 from all new photovoltaic projects by 200,000 or more

19 renewable energy credits, provided that nothing in

20 this Section shall preclude the projected cumulative

21 amount of renewable energy credits to be delivered

22 from all new photovoltaic projects from exceeding the

23 projected cumulative amount of renewable energy

24 credits to be delivered from all new wind projects in

25 each delivery year and provided further that nothing

26 in this item (iv) shall require the curtailment of an

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1 executed contract. The Agency shall update, on a

2 quarterly basis, its projection of the renewable

3 energy credits to be delivered from all projects in

4 each delivery year. Notwithstanding anything to the

5 contrary, the Agency may adjust the timing of

6 procurement events conducted under this subparagraph

7 (G). The long-term renewable resources procurement

8 plan shall set forth the process by which the

9 adjustments may be made.

10 (v) All procurements under this subparagraph (G)

11 shall comply with the geographic requirements in

12 subparagraph (I) of this paragraph (1) and shall

13 follow the procurement processes and procedures

14 described in this Section and Section 16-111.5 of the

15 Public Utilities Act to the extent practicable, and

16 these processes and procedures may be expedited to

17 accommodate the schedule established by this

18 subparagraph (G).

19 (H) The procurement of renewable energy resources for

20 a given delivery year shall be reduced as described in

21 this subparagraph (H) if an alternative retail electric

22 supplier meets the requirements described in this

23 subparagraph (H).

24 (i) Within 45 days after June 1, 2017 (the

25 effective date of Public Act 99-906), an alternative

26 retail electric supplier or its successor shall submit

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1 an informational filing to the Illinois Commerce

2 Commission certifying that, as of December 31, 2015,

3 the alternative retail electric supplier owned one or

4 more electric generating facilities that generates

5 renewable energy resources as defined in Section 1-10

6 of this Act, provided that such facilities are not

7 powered by wind or photovoltaics, and the facilities

8 generate one renewable energy credit for each

9 megawatthour of energy produced from the facility.

10 The informational filing shall identify each

11 facility that was eligible to satisfy the alternative

12 retail electric supplier's obligations under Section

13 16-115D of the Public Utilities Act as described in

14 this item (i).

15 (ii) For a given delivery year, the alternative

16 retail electric supplier may elect to supply its

17 retail customers with renewable energy credits from

18 the facility or facilities described in item (i) of

19 this subparagraph (H) that continue to be owned by the

20 alternative retail electric supplier.

21 (iii) The alternative retail electric supplier

22 shall notify the Agency and the applicable utility, no

23 later than February 28 of the year preceding the

24 applicable delivery year or 15 days after June 1, 2017

25 (the effective date of Public Act 99-906), whichever

26 is later, of its election under item (ii) of this

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1 subparagraph (H) to supply renewable energy credits to

2 retail customers of the utility. Such election shall

3 identify the amount of renewable energy credits to be

4 supplied by the alternative retail electric supplier

5 to the utility's retail customers and the source of

6 the renewable energy credits identified in the

7 informational filing as described in item (i) of this

8 subparagraph (H), subject to the following

9 limitations:

10 For the delivery year beginning June 1, 2018,

11 the maximum amount of renewable energy credits to

12 be supplied by an alternative retail electric

13 supplier under this subparagraph (H) shall be 68%

14 multiplied by 25% multiplied by 14.5% multiplied

15 by the amount of metered electricity

16 (megawatt-hours) delivered by the alternative

17 retail electric supplier to Illinois retail

18 customers during the delivery year ending May 31,

19 2016.

20 For delivery years beginning June 1, 2019 and

21 each year thereafter, the maximum amount of

22 renewable energy credits to be supplied by an

23 alternative retail electric supplier under this

24 subparagraph (H) shall be 68% multiplied by 50%

25 multiplied by 16% multiplied by the amount of

26 metered electricity (megawatt-hours) delivered by

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1 the alternative retail electric supplier to

2 Illinois retail customers during the delivery year

3 ending May 31, 2016, provided that the 16% value

4 shall increase by 1.5% each delivery year

5 thereafter to 25% by the delivery year beginning

6 June 1, 2025, and thereafter the 25% value shall

7 apply to each delivery year.

8 For each delivery year, the total amount of

9 renewable energy credits supplied by all alternative

10 retail electric suppliers under this subparagraph (H)

11 shall not exceed 9% of the Illinois target renewable

12 energy credit quantity. The Illinois target renewable

13 energy credit quantity for the delivery year beginning

14 June 1, 2018 is 14.5% multiplied by the total amount of

15 metered electricity (megawatt-hours) delivered in the

16 delivery year immediately preceding that delivery

17 year, provided that the 14.5% shall increase by 1.5%

18 each delivery year thereafter to 25% by the delivery

19 year beginning June 1, 2025, and thereafter the 25%

20 value shall apply to each delivery year.

21 If the requirements set forth in items (i) through

22 (iii) of this subparagraph (H) are met, the charges

23 that would otherwise be applicable to the retail

24 customers of the alternative retail electric supplier

25 under paragraph (6) of this subsection (c) for the

26 applicable delivery year shall be reduced by the ratio

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1 of the quantity of renewable energy credits supplied

2 by the alternative retail electric supplier compared

3 to that supplier's target renewable energy credit

4 quantity. The supplier's target renewable energy

5 credit quantity for the delivery year beginning June

6 1, 2018 is 14.5% multiplied by the total amount of

7 metered electricity (megawatt-hours) delivered by the

8 alternative retail supplier in that delivery year,

9 provided that the 14.5% shall increase by 1.5% each

10 delivery year thereafter to 25% by the delivery year

11 beginning June 1, 2025, and thereafter the 25% value

12 shall apply to each delivery year.

13 On or before April 1 of each year, the Agency shall

14 annually publish a report on its website that

15 identifies the aggregate amount of renewable energy

16 credits supplied by alternative retail electric

17 suppliers under this subparagraph (H).

18 (I) The Agency shall design its long-term renewable

19 energy procurement plan to maximize the State's interest

20 in the health, safety, and welfare of its residents,

21 including but not limited to minimizing sulfur dioxide,

22 nitrogen oxide, particulate matter and other pollution

23 that adversely affects public health in this State,

24 increasing fuel and resource diversity in this State,

25 enhancing the reliability and resiliency of the

26 electricity distribution system in this State, meeting

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1 goals to limit carbon dioxide emissions under federal or

2 State law, and contributing to a cleaner and healthier

3 environment for the citizens of this State, while

4 balancing these goals with the requirement to minimize the

5 cost to customers attributable to the procurement of

6 renewable energy credits set forth in subparagraph (C) of

7 paragraph (1) of this subsection (c). In order to further

8 these legislative purposes, renewable energy credits shall

9 be eligible to be counted toward the renewable energy

10 requirements of this subsection (c) if they are generated

11 from facilities located in this State. The Agency may

12 qualify renewable energy credits from facilities located

13 in states adjacent to Illinois if the generator

14 demonstrates and the Agency determines that the operation

15 of such facility or facilities will help promote the

16 State's interest in the health, safety, and welfare of its

17 residents based on the public interest criteria described

18 above. To ensure that the public interest criteria are

19 applied to the procurement and given full effect, the

20 Agency's long-term procurement plan shall describe in

21 detail how each public interest factor shall be considered

22 and weighted for facilities located in states adjacent to

23 Illinois.

24 (J) In order to promote the competitive development of

25 renewable energy resources in furtherance of the State's

26 interest in the health, safety, and welfare of its

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1 residents, renewable energy credits shall not be eligible

2 to be counted toward the renewable energy requirements of

3 this subsection (c) if they are sourced from a generating

4 unit whose costs were being recovered through rates

5 regulated by this State or any other state or states on or

6 after January 1, 2017. Each contract executed to purchase

7 renewable energy credits under this subsection (c) shall

8 provide for the contract's termination if the costs of the

9 generating unit supplying the renewable energy credits

10 subsequently begin to be recovered through rates regulated

11 by this State or any other state or states; and each

12 contract shall further provide that, in that event, the

13 supplier of the credits must return 110% of all payments

14 received under the contract. Amounts returned under the

15 requirements of this subparagraph (J) shall be retained by

16 the utility and all of these amounts shall be used for the

17 procurement of additional renewable energy credits from

18 new wind or new photovoltaic resources as defined in this

19 subsection (c). The long-term plan shall provide that

20 these renewable energy credits shall be procured in the

21 next procurement event.

22 Notwithstanding the limitations of this subparagraph

23 (J), renewable energy credits sourced from generating

24 units that are constructed, purchased, owned, or leased by

25 an electric utility as part of an approved project,

26 program, or pilot under Section 1-56 of this Act shall be

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1 eligible to be counted toward the renewable energy

2 requirements of this subsection (c), regardless of how the

3 costs of these units are recovered.

4 (K) The long-term renewable resources procurement plan

5 developed by the Agency in accordance with subparagraph

6 (A) of this paragraph (1) shall include an Adjustable

7 Block program for the procurement of renewable energy

8 credits from new photovoltaic projects that are

9 distributed renewable energy generation devices or new

10 photovoltaic community renewable generation projects on

11 behalf of electric utilities that serve more than

12 3,000,000 retail customers or less than 500,000 retail

13 customers in this State and a competitive procurement

14 process for the procurement of new photovoltaic community

15 renewable generation projects on behalf of electric

16 utilities that serve less than 3,000,000 retail customers

17 but more than 500,000 retail customers in this State. The

18 Adjustable Block program shall be designed to provide a

19 transparent schedule of prices and quantities to enable

20 the photovoltaic market to scale up and for renewable

21 energy credit prices to adjust at a predictable rate over

22 time. The prices set by the Adjustable Block program can

23 be reflected as a set value or as the product of a formula.

24 The Adjustable Block program shall include for each

25 category of eligible projects: a schedule of standard

26 block purchase prices to be offered; a series of steps,

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1 with associated nameplate capacity and purchase prices

2 that adjust from step to step; and automatic opening of

3 the next step as soon as the nameplate capacity and

4 available purchase prices for an open step are fully

5 committed or reserved. Only projects energized on or after

6 June 1, 2017 shall be eligible for the Adjustable Block

7 program. For each block group the Agency shall determine

8 the number of blocks, the amount of generation capacity in

9 each block, and the purchase price for each block,

10 provided that the purchase price provided and the total

11 amount of generation in all blocks for all block groups

12 shall be sufficient to meet the goals in this subsection

13 (c). The Agency may periodically review its prior

14 decisions establishing the number of blocks, the amount of

15 generation capacity in each block, and the purchase price

16 for each block, and may propose, on an expedited basis,

17 changes to these previously set values, including but not

18 limited to redistributing these amounts and the available

19 funds as necessary and appropriate, subject to Commission

20 approval as part of the periodic plan revision process

21 described in Section 16-111.5 of the Public Utilities Act.

22 The Agency may define different block sizes, purchase

23 prices, or other distinct terms and conditions for

24 projects located in different utility service territories

25 if the Agency deems it necessary to meet the goals in this

26 subsection (c); however, if, for any block to be procured

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1 on behalf of electric utilities that serve less than

2 3,000,000 retail customers but more than 500,000 retail

3 customers in this State, the quantity of renewable energy

4 credits sought by eligible projects exceeds the quantity

5 of renewable energy credits defined by the Agency for the

6 block, the Agency shall lower the price applicable to the

7 block and require eligible projects to affirm the

8 commitment to the quantity of renewable energy credits

9 sought. The Agency shall employ a stepped process of

10 lowering the price applicable to the block so as to

11 identify a price at which the quantity of renewable energy

12 credits sought by eligible projects balances with the

13 renewable energy credits sought by the Agency for the

14 block.

15 The competitive procurement process used for the

16 procurement of new photovoltaic community renewable

17 generation projects on behalf of electric utilities that

18 serve less than 3,000,000 retail customers but more than

19 500,000 retail customers in this State shall define the

20 quantity of renewable energy credits to be procured and

21 allow bidders to submit price offers to the Agency. The

22 Agency shall conduct the competitive procurement process

23 in a manner that results in the lowest cost for the

24 renewable energy credits procured.

25 The Adjustable Block program and competitive

26 procurement process shall include at least the following

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1 block groups in at least the following amounts, which may

2 be adjusted upon review by the Agency and approval by the

3 Commission as described in this subparagraph (K):

4 (i) At least 25% from distributed renewable energy

5 generation devices with a nameplate capacity of no

6 more than 10 kilowatts.

7 (ii) At least 25% from distributed renewable

8 energy generation devices with a nameplate capacity of

9 more than 10 kilowatts and no more than 2,000

10 kilowatts. The Agency may create sub-categories within

11 this category to account for the differences between

12 projects for small commercial customers, large

13 commercial customers, and public or non-profit

14 customers.

15 (iii) At least 25% from photovoltaic community

16 renewable generation projects.

17 (iv) The remaining 25% shall be allocated as

18 specified by the Agency in the long-term renewable

19 resources procurement plan.

20 The Adjustable Block program shall be designed to

21 ensure that renewable energy credits are procured from

22 photovoltaic distributed renewable energy generation

23 devices and new photovoltaic community renewable energy

24 generation projects in diverse locations and are not

25 concentrated in a few geographic areas.

26 (L) The procurement of photovoltaic renewable energy

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1 credits under items (i) through (iv) of subparagraph (K)

2 of this paragraph (1) shall be subject to the following

3 contract and payment terms:

4 (i) The Agency shall procure contracts of at least

5 15 years in length.

6 (ii) For those renewable energy credits that

7 qualify and are procured under item (i) of

8 subparagraph (K) of this paragraph (1), the renewable

9 energy credit purchase price shall be paid in full by

10 the contracting utilities at the time that the

11 facility producing the renewable energy credits is

12 interconnected at the distribution system level of the

13 utility and energized. The electric utility shall

14 receive and retire all renewable energy credits

15 generated by the project for the first 15 years of

16 operation.

17 (iii) For those renewable energy credits that

18 qualify and are procured under item (ii) and (iii) of

19 subparagraph (K) of this paragraph (1) and any

20 additional categories of distributed generation

21 included in the long-term renewable resources

22 procurement plan and approved by the Commission, 20

23 percent of the renewable energy credit purchase price

24 shall be paid by the contracting utilities at the time

25 that the facility producing the renewable energy

26 credits is interconnected at the distribution system

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1 level of the utility and energized. The remaining

2 portion shall be paid ratably over the subsequent

3 4-year period. The electric utility shall receive and

4 retire all renewable energy credits generated by the

5 project for the first 15 years of operation.

6 (iv) Each contract shall include provisions to

7 ensure the delivery of the renewable energy credits

8 for the full term of the contract.

9 (v) The utility shall be the counterparty to the

10 contracts executed under this subparagraph (L) that

11 are approved by the Commission under the process

12 described in Section 16-111.5 of the Public Utilities

13 Act. No contract shall be executed for an amount that

14 is less than one renewable energy credit per year.

15 (vi) If, at any time, approved applications for

16 the Adjustable Block program exceed funds collected by

17 the electric utility or would cause the Agency to

18 exceed the limitation described in subparagraph (E) of

19 this paragraph (1) on the amount of renewable energy

20 resources that may be procured, then the Agency shall

21 consider future uncommitted funds to be reserved for

22 these contracts on a first-come, first-served basis,

23 with the delivery of renewable energy credits required

24 beginning at the time that the reserved funds become

25 available.

26 (vii) Nothing in this Section shall require the

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1 utility to advance any payment or pay any amounts that

2 exceed the actual amount of revenues collected by the

3 utility under paragraph (6) of this subsection (c) and

4 subsection (k) of Section 16-108 of the Public

5 Utilities Act, and contracts executed under this

6 Section shall expressly incorporate this limitation.

7 (M) The Agency shall be authorized to retain one or

8 more experts or expert consulting firms to develop,

9 administer, implement, operate, and evaluate the

10 Adjustable Block program described in subparagraph (K) of

11 this paragraph (1), and the Agency shall retain the

12 consultant or consultants in the same manner, to the

13 extent practicable, as the Agency retains others to

14 administer provisions of this Act, including, but not

15 limited to, the procurement administrator. The selection

16 of experts and expert consulting firms and the procurement

17 process described in this subparagraph (M) are exempt from

18 the requirements of Section 20-10 of the Illinois

19 Procurement Code, under Section 20-10 of that Code. The

20 Agency shall strive to minimize administrative expenses in

21 the implementation of the Adjustable Block program.

22 The Agency and its consultant or consultants shall

23 monitor block activity, share program activity with

24 stakeholders and conduct regularly scheduled meetings to

25 discuss program activity and market conditions. If

26 necessary, the Agency may make prospective administrative

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1 adjustments to the Adjustable Block program design, such

2 as redistributing available funds or making adjustments to

3 purchase prices as necessary to achieve the goals of this

4 subsection (c). Program modifications to any price,

5 capacity block, or other program element that do not

6 deviate from the Commission's approved value by more than

7 25% shall take effect immediately and are not subject to

8 Commission review and approval. Program modifications to

9 any price, capacity block, or other program element that

10 deviate more than 25% from the Commission's approved value

11 must be approved by the Commission as a long-term plan

12 amendment under Section 16-111.5 of the Public Utilities

13 Act. The Agency shall consider stakeholder feedback when

14 making adjustments to the Adjustable Block design and

15 shall notify stakeholders in advance of any planned

16 changes.

17 (N) The long-term renewable resources procurement plan

18 required by this subsection (c) shall include a community

19 renewable generation program. The Agency shall establish

20 the terms, conditions, and program requirements for

21 community renewable generation projects with a goal to

22 expand renewable energy generating facility access to a

23 broader group of energy consumers, to ensure robust

24 participation opportunities for residential and small

25 commercial customers and those who cannot install

26 renewable energy on their own properties. Any plan

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1 approved by the Commission shall allow subscriptions to

2 community renewable generation projects to be portable and

3 transferable. For purposes of this subparagraph (N),

4 "portable" means that subscriptions may be retained by the

5 subscriber even if the subscriber relocates or changes its

6 address within the same utility service territory; and

7 "transferable" means that a subscriber may assign or sell

8 subscriptions to another person within the same utility

9 service territory.

10 Electric utilities shall provide a monetary credit to

11 a subscriber's subsequent bill for service for the

12 proportional output of a community renewable generation

13 project attributable to that subscriber as specified in

14 Section 16-107.5 of the Public Utilities Act.

15 The Agency shall purchase renewable energy credits

16 from subscribed shares of photovoltaic community renewable

17 generation projects through the Adjustable Block program

18 and the competitive procurement process described in

19 subparagraph (K) of this paragraph (1) or through the

20 Illinois Solar for All Program described in Section 1-56

21 of this Act. The electric utility shall purchase any

22 unsubscribed energy from community renewable generation

23 projects that are Qualifying Facilities ("QF") under the

24 electric utility's tariff for purchasing the output from

25 QFs under Public Utilities Regulatory Policies Act of

26 1978.

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1 The owners of and any subscribers to a community

2 renewable generation project shall not be considered

3 public utilities or alternative retail electricity

4 suppliers under the Public Utilities Act solely as a

5 result of their interest in or subscription to a community

6 renewable generation project and shall not be required to

7 become an alternative retail electric supplier by

8 participating in a community renewable generation project

9 with a public utility.

10 (O) For the delivery year beginning June 1, 2018, the

11 long-term renewable resources procurement plan required by

12 this subsection (c) shall provide for the Agency to

13 procure contracts to continue offering the Illinois Solar

14 for All Program described in subsection (b) of Section

15 1-56 of this Act, and the contracts approved by the

16 Commission shall be executed by the utilities that are

17 subject to this subsection (c). The long-term renewable

18 resources procurement plan shall allocate 5% of the funds

19 available under the plan for the applicable delivery year,

20 or $10,000,000 per delivery year, whichever is greater, to

21 fund the programs, and the plan shall determine the amount

22 of funding to be apportioned to the programs identified in

23 subsection (b) of Section 1-56 of this Act; provided that

24 for the delivery years beginning June 1, 2017, June 1,

25 2021, and June 1, 2025, the long-term renewable resources

26 procurement plan shall allocate 10% of the funds available

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1 under the plan for the applicable delivery year, or

2 $20,000,000 per delivery year, whichever is greater, and

3 $10,000,000 of such funds in such year shall be used by an

4 electric utility that serves more than 3,000,000 retail

5 customers in the State to implement a Commission-approved

6 plan under Section 16-108.12 of the Public Utilities Act.

7 In making the determinations required under this

8 subparagraph (O), the Commission shall consider the

9 experience and performance under the programs and any

10 evaluation reports. The Commission shall also provide for

11 an independent evaluation of those programs on a periodic

12 basis that are funded under this subparagraph (O).

13 (2) (Blank).

14 (3) (Blank).

15 (4) The electric utility shall retire all renewable

16 energy credits used to comply with the standard.

17 (5) Beginning with the 2010 delivery year and ending

18 June 1, 2017, an electric utility subject to this

19 subsection (c) shall apply the lesser of the maximum

20 alternative compliance payment rate or the most recent

21 estimated alternative compliance payment rate for its

22 service territory for the corresponding compliance period,

23 established pursuant to subsection (d) of Section 16-115D

24 of the Public Utilities Act to its retail customers that

25 take service pursuant to the electric utility's hourly

26 pricing tariff or tariffs. The electric utility shall

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1 retain all amounts collected as a result of the

2 application of the alternative compliance payment rate or

3 rates to such customers, and, beginning in 2011, the

4 utility shall include in the information provided under

5 item (1) of subsection (d) of Section 16-111.5 of the

6 Public Utilities Act the amounts collected under the

7 alternative compliance payment rate or rates for the prior

8 year ending May 31. Notwithstanding any limitation on the

9 procurement of renewable energy resources imposed by item

10 (2) of this subsection (c), the Agency shall increase its

11 spending on the purchase of renewable energy resources to

12 be procured by the electric utility for the next plan year

13 by an amount equal to the amounts collected by the utility

14 under the alternative compliance payment rate or rates in

15 the prior year ending May 31.

16 (6) The electric utility shall be entitled to recover

17 all of its costs associated with the procurement of

18 renewable energy credits under plans approved under this

19 Section and Section 16-111.5 of the Public Utilities Act.

20 These costs shall include associated reasonable expenses

21 for implementing the procurement programs, including, but

22 not limited to, the costs of administering and evaluating

23 the Adjustable Block program, through an automatic

24 adjustment clause tariff in accordance with subsection (k)

25 of Section 16-108 of the Public Utilities Act.

26 (7) Renewable energy credits procured from new

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1 photovoltaic projects or new distributed renewable energy

2 generation devices under this Section after June 1, 2017

3 (the effective date of Public Act 99-906) must be procured

4 from devices installed by a qualified person in compliance

5 with the requirements of Section 16-128A of the Public

6 Utilities Act and any rules or regulations adopted

7 thereunder.

8 In meeting the renewable energy requirements of this

9 subsection (c), to the extent feasible and consistent with

10 State and federal law, the renewable energy credit

11 procurements, Adjustable Block solar program, and

12 community renewable generation program shall provide

13 employment opportunities for all segments of the

14 population and workforce, including minority-owned and

15 woman-owned ~~female-owned~~ business enterprises, and shall

16 not, consistent with State and federal law, discriminate

17 based on race or socioeconomic status.

18 As part of any renewable resources procurement plan

19 required by this subsection (c), the Agency will compile

20 and publish a list of any seller of renewable energy

21 resources procured by the Agency that is not, as of

22 January 1 of the calendar year in which the procurement

23 plan will be filed for approval with the Commission, in

24 compliance with the reporting obligations of Section 5-117

25 of the Public Utilities Act, and the Agency shall not

26 procure any renewable energy resources from any entity not

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1 in compliance with the reporting obligations of Section

2 5-117 of the Public Utilities Act in the procurement plan.

3 Any entity that submits a bid to provide renewable

4 energy resources in any procurement event conducted

5 pursuant to this Section occurring after the effective

6 date of this amendatory Act of the 102nd General Assembly

7 shall certify that not less than the prevailing wage, as

8 determined pursuant to the Prevailing Wage Act, was or

9 will be paid to employees who are engaged in construction

10 activities associated with the renewable energy resources,

11 and the Agency shall not procure any renewable resources

12 from any entity not providing such a certification. Every

13 contract for the procurement of renewable energy resources

14 pursuant to this Section shall provide that failure to

15 comply with the terms of such certification shall

16 constitute an event of default, subject to termination of

17 the contract.

18 (d) Clean coal portfolio standard.

19 (1) The procurement plans shall include electricity

20 generated using clean coal. Each utility shall enter into

21 one or more sourcing agreements with the initial clean

22 coal facility, as provided in paragraph (3) of this

23 subsection (d), covering electricity generated by the

24 initial clean coal facility representing at least 5% of

25 each utility's total supply to serve the load of eligible

26 retail customers in 2015 and each year thereafter, as

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1 described in paragraph (3) of this subsection (d), subject

2 to the limits specified in paragraph (2) of this

3 subsection (d). It is the goal of the State that by January

4 1, 2025, 25% of the electricity used in the State shall be

5 generated by cost-effective clean coal facilities. For

6 purposes of this subsection (d), "cost-effective" means

7 that the expenditures pursuant to such sourcing agreements

8 do not cause the limit stated in paragraph (2) of this

9 subsection (d) to be exceeded and do not exceed cost-based

10 benchmarks, which shall be developed to assess all

11 expenditures pursuant to such sourcing agreements covering

12 electricity generated by clean coal facilities, other than

13 the initial clean coal facility, by the procurement

14 administrator, in consultation with the Commission staff,

15 Agency staff, and the procurement monitor and shall be

16 subject to Commission review and approval.

17 A utility party to a sourcing agreement shall

18 immediately retire any emission credits that it receives

19 in connection with the electricity covered by such

20 agreement.

21 Utilities shall maintain adequate records documenting

22 the purchases under the sourcing agreement to comply with

23 this subsection (d) and shall file an accounting with the

24 load forecast that must be filed with the Agency by July 15

25 of each year, in accordance with subsection (d) of Section

26 16-111.5 of the Public Utilities Act.

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1 A utility shall be deemed to have complied with the

2 clean coal portfolio standard specified in this subsection

3 (d) if the utility enters into a sourcing agreement as

4 required by this subsection (d).

5 (2) For purposes of this subsection (d), the required

6 execution of sourcing agreements with the initial clean

7 coal facility for a particular year shall be measured as a

8 percentage of the actual amount of electricity

9 (megawatt-hours) supplied by the electric utility to

10 eligible retail customers in the planning year ending

11 immediately prior to the agreement's execution. For

12 purposes of this subsection (d), the amount paid per

13 kilowatthour means the total amount paid for electric

14 service expressed on a per kilowatthour basis. For

15 purposes of this subsection (d), the total amount paid for

16 electric service includes without limitation amounts paid

17 for supply, transmission, distribution, surcharges and

18 add-on taxes.

19 Notwithstanding the requirements of this subsection

20 (d), the total amount paid under sourcing agreements with

21 clean coal facilities pursuant to the procurement plan for

22 any given year shall be reduced by an amount necessary to

23 limit the annual estimated average net increase due to the

24 costs of these resources included in the amounts paid by

25 eligible retail customers in connection with electric

26 service to:

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1 (A) in 2010, no more than 0.5% of the amount paid

2 per kilowatthour by those customers during the year

3 ending May 31, 2009;

4 (B) in 2011, the greater of an additional 0.5% of

5 the amount paid per kilowatthour by those customers

6 during the year ending May 31, 2010 or 1% of the amount

7 paid per kilowatthour by those customers during the

8 year ending May 31, 2009;

9 (C) in 2012, the greater of an additional 0.5% of

10 the amount paid per kilowatthour by those customers

11 during the year ending May 31, 2011 or 1.5% of the

12 amount paid per kilowatthour by those customers during

13 the year ending May 31, 2009;

14 (D) in 2013, the greater of an additional 0.5% of

15 the amount paid per kilowatthour by those customers

16 during the year ending May 31, 2012 or 2% of the amount

17 paid per kilowatthour by those customers during the

18 year ending May 31, 2009; and

19 (E) thereafter, the total amount paid under

20 sourcing agreements with clean coal facilities

21 pursuant to the procurement plan for any single year

22 shall be reduced by an amount necessary to limit the

23 estimated average net increase due to the cost of

24 these resources included in the amounts paid by

25 eligible retail customers in connection with electric

26 service to no more than the greater of (i) 2.015% of

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1 the amount paid per kilowatthour by those customers

2 during the year ending May 31, 2009 or (ii) the

3 incremental amount per kilowatthour paid for these

4 resources in 2013. These requirements may be altered

5 only as provided by statute.

6 No later than June 30, 2015, the Commission shall

7 review the limitation on the total amount paid under

8 sourcing agreements, if any, with clean coal facilities

9 pursuant to this subsection (d) and report to the General

10 Assembly its findings as to whether that limitation unduly

11 constrains the amount of electricity generated by

12 cost-effective clean coal facilities that is covered by

13 sourcing agreements.

14 (3) Initial clean coal facility. In order to promote

15 development of clean coal facilities in Illinois, each

16 electric utility subject to this Section shall execute a

17 sourcing agreement to source electricity from a proposed

18 clean coal facility in Illinois (the "initial clean coal

19 facility") that will have a nameplate capacity of at least

20 500 MW when commercial operation commences, that has a

21 final Clean Air Act permit on June 1, 2009 (the effective

22 date of Public Act 95-1027), and that will meet the

23 definition of clean coal facility in Section 1-10 of this

24 Act when commercial operation commences. The sourcing

25 agreements with this initial clean coal facility shall be

26 subject to both approval of the initial clean coal

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1 facility by the General Assembly and satisfaction of the

2 requirements of paragraph (4) of this subsection (d) and

3 shall be executed within 90 days after any such approval

4 by the General Assembly. The Agency and the Commission

5 shall have authority to inspect all books and records

6 associated with the initial clean coal facility during the

7 term of such a sourcing agreement. A utility's sourcing

8 agreement for electricity produced by the initial clean

9 coal facility shall include:

10 (A) a formula contractual price (the "contract

11 price") approved pursuant to paragraph (4) of this

12 subsection (d), which shall:

13 (i) be determined using a cost of service

14 methodology employing either a level or deferred

15 capital recovery component, based on a capital

16 structure consisting of 45% equity and 55% debt,

17 and a return on equity as may be approved by the

18 Federal Energy Regulatory Commission, which in any

19 case may not exceed the lower of 11.5% or the rate

20 of return approved by the General Assembly

21 pursuant to paragraph (4) of this subsection (d);

22 and

23 (ii) provide that all miscellaneous net

24 revenue, including but not limited to net revenue

25 from the sale of emission allowances, if any,

26 substitute natural gas, if any, grants or other

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1 support provided by the State of Illinois or the

2 United States Government, firm transmission

3 rights, if any, by-products produced by the

4 facility, energy or capacity derived from the

5 facility and not covered by a sourcing agreement

6 pursuant to paragraph (3) of this subsection (d)

7 or item (5) of subsection (d) of Section 16-115 of

8 the Public Utilities Act, whether generated from

9 the synthesis gas derived from coal, from SNG, or

10 from natural gas, shall be credited against the

11 revenue requirement for this initial clean coal

12 facility;

13 (B) power purchase provisions, which shall:

14 (i) provide that the utility party to such

15 sourcing agreement shall pay the contract price

16 for electricity delivered under such sourcing

17 agreement;

18 (ii) require delivery of electricity to the

19 regional transmission organization market of the

20 utility that is party to such sourcing agreement;

21 (iii) require the utility party to such

22 sourcing agreement to buy from the initial clean

23 coal facility in each hour an amount of energy

24 equal to all clean coal energy made available from

25 the initial clean coal facility during such hour

26 times a fraction, the numerator of which is such

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1 utility's retail market sales of electricity

2 (expressed in kilowatthours sold) in the State

3 during the prior calendar month and the

4 denominator of which is the total retail market

5 sales of electricity (expressed in kilowatthours

6 sold) in the State by utilities during such prior

7 month and the sales of electricity (expressed in

8 kilowatthours sold) in the State by alternative

9 retail electric suppliers during such prior month

10 that are subject to the requirements of this

11 subsection (d) and paragraph (5) of subsection (d)

12 of Section 16-115 of the Public Utilities Act,

13 provided that the amount purchased by the utility

14 in any year will be limited by paragraph (2) of

15 this subsection (d); and

16 (iv) be considered pre-existing contracts in

17 such utility's procurement plans for eligible

18 retail customers;

19 (C) contract for differences provisions, which

20 shall:

21 (i) require the utility party to such sourcing

22 agreement to contract with the initial clean coal

23 facility in each hour with respect to an amount of

24 energy equal to all clean coal energy made

25 available from the initial clean coal facility

26 during such hour times a fraction, the numerator

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1 of which is such utility's retail market sales of

2 electricity (expressed in kilowatthours sold) in

3 the utility's service territory in the State

4 during the prior calendar month and the

5 denominator of which is the total retail market

6 sales of electricity (expressed in kilowatthours

7 sold) in the State by utilities during such prior

8 month and the sales of electricity (expressed in

9 kilowatthours sold) in the State by alternative

10 retail electric suppliers during such prior month

11 that are subject to the requirements of this

12 subsection (d) and paragraph (5) of subsection (d)

13 of Section 16-115 of the Public Utilities Act,

14 provided that the amount paid by the utility in

15 any year will be limited by paragraph (2) of this

16 subsection (d);

17 (ii) provide that the utility's payment

18 obligation in respect of the quantity of

19 electricity determined pursuant to the preceding

20 clause (i) shall be limited to an amount equal to

21 (1) the difference between the contract price

22 determined pursuant to subparagraph (A) of

23 paragraph (3) of this subsection (d) and the

24 day-ahead price for electricity delivered to the

25 regional transmission organization market of the

26 utility that is party to such sourcing agreement

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1 (or any successor delivery point at which such

2 utility's supply obligations are financially

3 settled on an hourly basis) (the "reference

4 price") on the day preceding the day on which the

5 electricity is delivered to the initial clean coal

6 facility busbar, multiplied by (2) the quantity of

7 electricity determined pursuant to the preceding

8 clause (i); and

9 (iii) not require the utility to take physical

10 delivery of the electricity produced by the

11 facility;

12 (D) general provisions, which shall:

13 (i) specify a term of no more than 30 years,

14 commencing on the commercial operation date of the

15 facility;

16 (ii) provide that utilities shall maintain

17 adequate records documenting purchases under the

18 sourcing agreements entered into to comply with

19 this subsection (d) and shall file an accounting

20 with the load forecast that must be filed with the

21 Agency by July 15 of each year, in accordance with

22 subsection (d) of Section 16-111.5 of the Public

23 Utilities Act;

24 (iii) provide that all costs associated with

25 the initial clean coal facility will be

26 periodically reported to the Federal Energy

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1 Regulatory Commission and to purchasers in

2 accordance with applicable laws governing

3 cost-based wholesale power contracts;

4 (iv) permit the Illinois Power Agency to

5 assume ownership of the initial clean coal

6 facility, without monetary consideration and

7 otherwise on reasonable terms acceptable to the

8 Agency, if the Agency so requests no less than 3

9 years prior to the end of the stated contract

10 term;

11 (v) require the owner of the initial clean

12 coal facility to provide documentation to the

13 Commission each year, starting in the facility's

14 first year of commercial operation, accurately

15 reporting the quantity of carbon emissions from

16 the facility that have been captured and

17 sequestered and report any quantities of carbon

18 released from the site or sites at which carbon

19 emissions were sequestered in prior years, based

20 on continuous monitoring of such sites. If, in any

21 year after the first year of commercial operation,

22 the owner of the facility fails to demonstrate

23 that the initial clean coal facility captured and

24 sequestered at least 50% of the total carbon

25 emissions that the facility would otherwise emit

26 or that sequestration of emissions from prior

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1 years has failed, resulting in the release of

2 carbon dioxide into the atmosphere, the owner of

3 the facility must offset excess emissions. Any

4 such carbon offsets must be permanent, additional,

5 verifiable, real, located within the State of

6 Illinois, and legally and practicably enforceable.

7 The cost of such offsets for the facility that are

8 not recoverable shall not exceed $15 million in

9 any given year. No costs of any such purchases of

10 carbon offsets may be recovered from a utility or

11 its customers. All carbon offsets purchased for

12 this purpose and any carbon emission credits

13 associated with sequestration of carbon from the

14 facility must be permanently retired. The initial

15 clean coal facility shall not forfeit its

16 designation as a clean coal facility if the

17 facility fails to fully comply with the applicable

18 carbon sequestration requirements in any given

19 year, provided the requisite offsets are

20 purchased. However, the Attorney General, on

21 behalf of the People of the State of Illinois, may

22 specifically enforce the facility's sequestration

23 requirement and the other terms of this contract

24 provision. Compliance with the sequestration

25 requirements and offset purchase requirements

26 specified in paragraph (3) of this subsection (d)

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1 shall be reviewed annually by an independent

2 expert retained by the owner of the initial clean

3 coal facility, with the advance written approval

4 of the Attorney General. The Commission may, in

5 the course of the review specified in item (vii),

6 reduce the allowable return on equity for the

7 facility if the facility willfully fails to comply

8 with the carbon capture and sequestration

9 requirements set forth in this item (v);

10 (vi) include limits on, and accordingly

11 provide for modification of, the amount the

12 utility is required to source under the sourcing

13 agreement consistent with paragraph (2) of this

14 subsection (d);

15 (vii) require Commission review: (1) to

16 determine the justness, reasonableness, and

17 prudence of the inputs to the formula referenced

18 in subparagraphs (A)(i) through (A)(iii) of

19 paragraph (3) of this subsection (d), prior to an

20 adjustment in those inputs including, without

21 limitation, the capital structure and return on

22 equity, fuel costs, and other operations and

23 maintenance costs and (2) to approve the costs to

24 be passed through to customers under the sourcing

25 agreement by which the utility satisfies its

26 statutory obligations. Commission review shall

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1 occur no less than every 3 years, regardless of

2 whether any adjustments have been proposed, and

3 shall be completed within 9 months;

4 (viii) limit the utility's obligation to such

5 amount as the utility is allowed to recover

6 through tariffs filed with the Commission,

7 provided that neither the clean coal facility nor

8 the utility waives any right to assert federal

9 pre-emption or any other argument in response to a

10 purported disallowance of recovery costs;

11 (ix) limit the utility's or alternative retail

12 electric supplier's obligation to incur any

13 liability until such time as the facility is in

14 commercial operation and generating power and

15 energy and such power and energy is being

16 delivered to the facility busbar;

17 (x) provide that the owner or owners of the

18 initial clean coal facility, which is the

19 counterparty to such sourcing agreement, shall

20 have the right from time to time to elect whether

21 the obligations of the utility party thereto shall

22 be governed by the power purchase provisions or

23 the contract for differences provisions;

24 (xi) append documentation showing that the

25 formula rate and contract, insofar as they relate

26 to the power purchase provisions, have been

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1 approved by the Federal Energy Regulatory

2 Commission pursuant to Section 205 of the Federal

3 Power Act;

4 (xii) provide that any changes to the terms of

5 the contract, insofar as such changes relate to

6 the power purchase provisions, are subject to

7 review under the public interest standard applied

8 by the Federal Energy Regulatory Commission

9 pursuant to Sections 205 and 206 of the Federal

10 Power Act; and

11 (xiii) conform with customary lender

12 requirements in power purchase agreements used as

13 the basis for financing non-utility generators.

14 (4) Effective date of sourcing agreements with the

15 initial clean coal facility. Any proposed sourcing

16 agreement with the initial clean coal facility shall not

17 become effective unless the following reports are prepared

18 and submitted and authorizations and approvals obtained:

19 (i) Facility cost report. The owner of the initial

20 clean coal facility shall submit to the Commission,

21 the Agency, and the General Assembly a front-end

22 engineering and design study, a facility cost report,

23 method of financing (including but not limited to

24 structure and associated costs), and an operating and

25 maintenance cost quote for the facility (collectively

26 "facility cost report"), which shall be prepared in

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1 accordance with the requirements of this paragraph (4)

2 of subsection (d) of this Section, and shall provide

3 the Commission and the Agency access to the work

4 papers, relied upon documents, and any other backup

5 documentation related to the facility cost report.

6 (ii) Commission report. Within 6 months following

7 receipt of the facility cost report, the Commission,

8 in consultation with the Agency, shall submit a report

9 to the General Assembly setting forth its analysis of

10 the facility cost report. Such report shall include,

11 but not be limited to, a comparison of the costs

12 associated with electricity generated by the initial

13 clean coal facility to the costs associated with

14 electricity generated by other types of generation

15 facilities, an analysis of the rate impacts on

16 residential and small business customers over the life

17 of the sourcing agreements, and an analysis of the

18 likelihood that the initial clean coal facility will

19 commence commercial operation by and be delivering

20 power to the facility's busbar by 2016. To assist in

21 the preparation of its report, the Commission, in

22 consultation with the Agency, may hire one or more

23 experts or consultants, the costs of which shall be

24 paid for by the owner of the initial clean coal

25 facility. The Commission and Agency may begin the

26 process of selecting such experts or consultants prior

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1 to receipt of the facility cost report.

2 (iii) General Assembly approval. The proposed

3 sourcing agreements shall not take effect unless,

4 based on the facility cost report and the Commission's

5 report, the General Assembly enacts authorizing

6 legislation approving (A) the projected price, stated

7 in cents per kilowatthour, to be charged for

8 electricity generated by the initial clean coal

9 facility, (B) the projected impact on residential and

10 small business customers' bills over the life of the

11 sourcing agreements, and (C) the maximum allowable

12 return on equity for the project; and

13 (iv) Commission review. If the General Assembly

14 enacts authorizing legislation pursuant to

15 subparagraph (iii) approving a sourcing agreement, the

16 Commission shall, within 90 days of such enactment,

17 complete a review of such sourcing agreement. During

18 such time period, the Commission shall implement any

19 directive of the General Assembly, resolve any

20 disputes between the parties to the sourcing agreement

21 concerning the terms of such agreement, approve the

22 form of such agreement, and issue an order finding

23 that the sourcing agreement is prudent and reasonable.

24 The facility cost report shall be prepared as follows:

25 (A) The facility cost report shall be prepared by

26 duly licensed engineering and construction firms

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1 detailing the estimated capital costs payable to one

2 or more contractors or suppliers for the engineering,

3 procurement and construction of the components

4 comprising the initial clean coal facility and the

5 estimated costs of operation and maintenance of the

6 facility. The facility cost report shall include:

7 (i) an estimate of the capital cost of the

8 core plant based on one or more front end

9 engineering and design studies for the

10 gasification island and related facilities. The

11 core plant shall include all civil, structural,

12 mechanical, electrical, control, and safety

13 systems.

14 (ii) an estimate of the capital cost of the

15 balance of the plant, including any capital costs

16 associated with sequestration of carbon dioxide

17 emissions and all interconnects and interfaces

18 required to operate the facility, such as

19 transmission of electricity, construction or

20 backfeed power supply, pipelines to transport

21 substitute natural gas or carbon dioxide, potable

22 water supply, natural gas supply, water supply,

23 water discharge, landfill, access roads, and coal

24 delivery.

25 The quoted construction costs shall be expressed

26 in nominal dollars as of the date that the quote is

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1 prepared and shall include capitalized financing costs

2 during construction, taxes, insurance, and other

3 owner's costs, and an assumed escalation in materials

4 and labor beyond the date as of which the construction

5 cost quote is expressed.

6 (B) The front end engineering and design study for

7 the gasification island and the cost study for the

8 balance of plant shall include sufficient design work

9 to permit quantification of major categories of

10 materials, commodities and labor hours, and receipt of

11 quotes from vendors of major equipment required to

12 construct and operate the clean coal facility.

13 (C) The facility cost report shall also include an

14 operating and maintenance cost quote that will provide

15 the estimated cost of delivered fuel, personnel,

16 maintenance contracts, chemicals, catalysts,

17 consumables, spares, and other fixed and variable

18 operations and maintenance costs. The delivered fuel

19 cost estimate will be provided by a recognized third

20 party expert or experts in the fuel and transportation

21 industries. The balance of the operating and

22 maintenance cost quote, excluding delivered fuel

23 costs, will be developed based on the inputs provided

24 by duly licensed engineering and construction firms

25 performing the construction cost quote, potential

26 vendors under long-term service agreements and plant

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1 operating agreements, or recognized third party plant

2 operator or operators.

3 The operating and maintenance cost quote

4 (including the cost of the front end engineering and

5 design study) shall be expressed in nominal dollars as

6 of the date that the quote is prepared and shall

7 include taxes, insurance, and other owner's costs, and

8 an assumed escalation in materials and labor beyond

9 the date as of which the operating and maintenance

10 cost quote is expressed.

11 (D) The facility cost report shall also include an

12 analysis of the initial clean coal facility's ability

13 to deliver power and energy into the applicable

14 regional transmission organization markets and an

15 analysis of the expected capacity factor for the

16 initial clean coal facility.

17 (E) Amounts paid to third parties unrelated to the

18 owner or owners of the initial clean coal facility to

19 prepare the core plant construction cost quote,

20 including the front end engineering and design study,

21 and the operating and maintenance cost quote will be

22 reimbursed through Coal Development Bonds.

23 (5) Re-powering and retrofitting coal-fired power

24 plants previously owned by Illinois utilities to qualify

25 as clean coal facilities. During the 2009 procurement

26 planning process and thereafter, the Agency and the

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1 Commission shall consider sourcing agreements covering

2 electricity generated by power plants that were previously

3 owned by Illinois utilities and that have been or will be

4 converted into clean coal facilities, as defined by

5 Section 1-10 of this Act. Pursuant to such procurement

6 planning process, the owners of such facilities may

7 propose to the Agency sourcing agreements with utilities

8 and alternative retail electric suppliers required to

9 comply with subsection (d) of this Section and item (5) of

10 subsection (d) of Section 16-115 of the Public Utilities

11 Act, covering electricity generated by such facilities. In

12 the case of sourcing agreements that are power purchase

13 agreements, the contract price for electricity sales shall

14 be established on a cost of service basis. In the case of

15 sourcing agreements that are contracts for differences,

16 the contract price from which the reference price is

17 subtracted shall be established on a cost of service

18 basis. The Agency and the Commission may approve any such

19 utility sourcing agreements that do not exceed cost-based

20 benchmarks developed by the procurement administrator, in

21 consultation with the Commission staff, Agency staff and

22 the procurement monitor, subject to Commission review and

23 approval. The Commission shall have authority to inspect

24 all books and records associated with these clean coal

25 facilities during the term of any such contract.

26 (6) Costs incurred under this subsection (d) or

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1 pursuant to a contract entered into under this subsection

2 (d) shall be deemed prudently incurred and reasonable in

3 amount and the electric utility shall be entitled to full

4 cost recovery pursuant to the tariffs filed with the

5 Commission.

6 (d-5) Zero emission standard.

7 (1) Beginning with the delivery year commencing on

8 June 1, 2017, the Agency shall, for electric utilities

9 that serve at least 100,000 retail customers in this

10 State, procure contracts with zero emission facilities

11 that are reasonably capable of generating cost-effective

12 zero emission credits in an amount approximately equal to

13 16% of the actual amount of electricity delivered by each

14 electric utility to retail customers in the State during

15 calendar year 2014. For an electric utility serving fewer

16 than 100,000 retail customers in this State that

17 requested, under Section 16-111.5 of the Public Utilities

18 Act, that the Agency procure power and energy for all or a

19 portion of the utility's Illinois load for the delivery

20 year commencing June 1, 2016, the Agency shall procure

21 contracts with zero emission facilities that are

22 reasonably capable of generating cost-effective zero

23 emission credits in an amount approximately equal to 16%

24 of the portion of power and energy to be procured by the

25 Agency for the utility. The duration of the contracts

26 procured under this subsection (d-5) shall be for a term

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1 of 10 years ending May 31, 2027. The quantity of zero

2 emission credits to be procured under the contracts shall

3 be all of the zero emission credits generated by the zero

4 emission facility in each delivery year; however, if the

5 zero emission facility is owned by more than one entity,

6 then the quantity of zero emission credits to be procured

7 under the contracts shall be the amount of zero emission

8 credits that are generated from the portion of the zero

9 emission facility that is owned by the winning supplier.

10 The 16% value identified in this paragraph (1) is the

11 average of the percentage targets in subparagraph (B) of

12 paragraph (1) of subsection (c) of this Section for the 5

13 delivery years beginning June 1, 2017.

14 The procurement process shall be subject to the

15 following provisions:

16 (A) Those zero emission facilities that intend to

17 participate in the procurement shall submit to the

18 Agency the following eligibility information for each

19 zero emission facility on or before the date

20 established by the Agency:

21 (i) the in-service date and remaining useful

22 life of the zero emission facility;

23 (ii) the amount of power generated annually

24 for each of the years 2005 through 2015, and the

25 projected zero emission credits to be generated

26 over the remaining useful life of the zero

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1 emission facility, which shall be used to

2 determine the capability of each facility;

3 (iii) the annual zero emission facility cost

4 projections, expressed on a per megawatthour

5 basis, over the next 6 delivery years, which shall

6 include the following: operation and maintenance

7 expenses; fully allocated overhead costs, which

8 shall be allocated using the methodology developed

9 by the Institute for Nuclear Power Operations;

10 fuel expenditures; non-fuel capital expenditures;

11 spent fuel expenditures; a return on working

12 capital; the cost of operational and market risks

13 that could be avoided by ceasing operation; and

14 any other costs necessary for continued

15 operations, provided that "necessary" means, for

16 purposes of this item (iii), that the costs could

17 reasonably be avoided only by ceasing operations

18 of the zero emission facility; and

19 (iv) a commitment to continue operating, for

20 the duration of the contract or contracts executed

21 under the procurement held under this subsection

22 (d-5), the zero emission facility that produces

23 the zero emission credits to be procured in the

24 procurement.

25 The information described in item (iii) of this

26 subparagraph (A) may be submitted on a confidential

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1 basis and shall be treated and maintained by the

2 Agency, the procurement administrator, and the

3 Commission as confidential and proprietary and exempt

4 from disclosure under subparagraphs (a) and (g) of

5 paragraph (1) of Section 7 of the Freedom of

6 Information Act. The Office of Attorney General shall

7 have access to, and maintain the confidentiality of,

8 such information pursuant to Section 6.5 of the

9 Attorney General Act.

10 (B) The price for each zero emission credit

11 procured under this subsection (d-5) for each delivery

12 year shall be in an amount that equals the Social Cost

13 of Carbon, expressed on a price per megawatthour

14 basis. However, to ensure that the procurement remains

15 affordable to retail customers in this State if

16 electricity prices increase, the price in an

17 applicable delivery year shall be reduced below the

18 Social Cost of Carbon by the amount ("Price

19 Adjustment") by which the market price index for the

20 applicable delivery year exceeds the baseline market

21 price index for the consecutive 12-month period ending

22 May 31, 2016. If the Price Adjustment is greater than

23 or equal to the Social Cost of Carbon in an applicable

24 delivery year, then no payments shall be due in that

25 delivery year. The components of this calculation are

26 defined as follows:

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1 (i) Social Cost of Carbon: The Social Cost of

2 Carbon is $16.50 per megawatthour, which is based

3 on the U.S. Interagency Working Group on Social

4 Cost of Carbon's price in the August 2016

5 Technical Update using a 3% discount rate,

6 adjusted for inflation for each year of the

7 program. Beginning with the delivery year

8 commencing June 1, 2023, the price per

9 megawatthour shall increase by $1 per

10 megawatthour, and continue to increase by an

11 additional $1 per megawatthour each delivery year

12 thereafter.

13 (ii) Baseline market price index: The baseline

14 market price index for the consecutive 12-month

15 period ending May 31, 2016 is $31.40 per

16 megawatthour, which is based on the sum of (aa)

17 the average day-ahead energy price across all

18 hours of such 12-month period at the PJM

19 Interconnection LLC Northern Illinois Hub, (bb)

20 50% multiplied by the Base Residual Auction, or

21 its successor, capacity price for the rest of the

22 RTO zone group determined by PJM Interconnection

23 LLC, divided by 24 hours per day, and (cc) 50%

24 multiplied by the Planning Resource Auction, or

25 its successor, capacity price for Zone 4

26 determined by the Midcontinent Independent System

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1 Operator, Inc., divided by 24 hours per day.

2 (iii) Market price index: The market price

3 index for a delivery year shall be the sum of

4 projected energy prices and projected capacity

5 prices determined as follows:

6 (aa) Projected energy prices: the

7 projected energy prices for the applicable

8 delivery year shall be calculated once for the

9 year using the forward market price for the

10 PJM Interconnection, LLC Northern Illinois

11 Hub. The forward market price shall be

12 calculated as follows: the energy forward

13 prices for each month of the applicable

14 delivery year averaged for each trade date

15 during the calendar year immediately preceding

16 that delivery year to produce a single energy

17 forward price for the delivery year. The

18 forward market price calculation shall use

19 data published by the Intercontinental

20 Exchange, or its successor.

21 (bb) Projected capacity prices:

22 (I) For the delivery years commencing

23 June 1, 2017, June 1, 2018, and June 1,

24 2019, the projected capacity price shall

25 be equal to the sum of (1) 50% multiplied

26 by the Base Residual Auction, or its

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1 successor, price for the rest of the RTO

2 zone group as determined by PJM

3 Interconnection LLC, divided by 24 hours

4 per day and, (2) 50% multiplied by the

5 resource auction price determined in the

6 resource auction administered by the

7 Midcontinent Independent System Operator,

8 Inc., in which the largest percentage of

9 load cleared for Local Resource Zone 4,

10 divided by 24 hours per day, and where

11 such price is determined by the

12 Midcontinent Independent System Operator,

13 Inc.

14 (II) For the delivery year commencing

15 June 1, 2020, and each year thereafter,

16 the projected capacity price shall be

17 equal to the sum of (1) 50% multiplied by

18 the Base Residual Auction, or its

19 successor, price for the ComEd zone as

20 determined by PJM Interconnection LLC,

21 divided by 24 hours per day, and (2) 50%

22 multiplied by the resource auction price

23 determined in the resource auction

24 administered by the Midcontinent

25 Independent System Operator, Inc., in

26 which the largest percentage of load

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1 cleared for Local Resource Zone 4, divided

2 by 24 hours per day, and where such price

3 is determined by the Midcontinent

4 Independent System Operator, Inc.

5 For purposes of this subsection (d-5):

6 "Rest of the RTO" and "ComEd Zone" shall have

7 the meaning ascribed to them by PJM

8 Interconnection, LLC.

9 "RTO" means regional transmission

10 organization.

11 (C) No later than 45 days after June 1, 2017 (the

12 effective date of Public Act 99-906), the Agency shall

13 publish its proposed zero emission standard

14 procurement plan. The plan shall be consistent with

15 the provisions of this paragraph (1) and shall provide

16 that winning bids shall be selected based on public

17 interest criteria that include, but are not limited

18 to, minimizing carbon dioxide emissions that result

19 from electricity consumed in Illinois and minimizing

20 sulfur dioxide, nitrogen oxide, and particulate matter

21 emissions that adversely affect the citizens of this

22 State. In particular, the selection of winning bids

23 shall take into account the incremental environmental

24 benefits resulting from the procurement, such as any

25 existing environmental benefits that are preserved by

26 the procurements held under Public Act 99-906 and

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1 would cease to exist if the procurements were not

2 held, including the preservation of zero emission

3 facilities. The plan shall also describe in detail how

4 each public interest factor shall be considered and

5 weighted in the bid selection process to ensure that

6 the public interest criteria are applied to the

7 procurement and given full effect.

8 For purposes of developing the plan, the Agency

9 shall consider any reports issued by a State agency,

10 board, or commission under House Resolution 1146 of

11 the 98th General Assembly and paragraph (4) of

12 subsection (d) of this Section, as well as publicly

13 available analyses and studies performed by or for

14 regional transmission organizations that serve the

15 State and their independent market monitors.

16 Upon publishing of the zero emission standard

17 procurement plan, copies of the plan shall be posted

18 and made publicly available on the Agency's website.

19 All interested parties shall have 10 days following

20 the date of posting to provide comment to the Agency on

21 the plan. All comments shall be posted to the Agency's

22 website. Following the end of the comment period, but

23 no more than 60 days later than June 1, 2017 (the

24 effective date of Public Act 99-906), the Agency shall

25 revise the plan as necessary based on the comments

26 received and file its zero emission standard

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1 procurement plan with the Commission.

2 If the Commission determines that the plan will

3 result in the procurement of cost-effective zero

4 emission credits, then the Commission shall, after

5 notice and hearing, but no later than 45 days after the

6 Agency filed the plan, approve the plan or approve

7 with modification. For purposes of this subsection

8 (d-5), "cost effective" means the projected costs of

9 procuring zero emission credits from zero emission

10 facilities do not cause the limit stated in paragraph

11 (2) of this subsection to be exceeded.

12 (C-5) As part of the Commission's review and

13 acceptance or rejection of the procurement results,

14 the Commission shall, in its public notice of

15 successful bidders:

16 (i) identify how the winning bids satisfy the

17 public interest criteria described in subparagraph

18 (C) of this paragraph (1) of minimizing carbon

19 dioxide emissions that result from electricity

20 consumed in Illinois and minimizing sulfur

21 dioxide, nitrogen oxide, and particulate matter

22 emissions that adversely affect the citizens of

23 this State;

24 (ii) specifically address how the selection of

25 winning bids takes into account the incremental

26 environmental benefits resulting from the

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1 procurement, including any existing environmental

2 benefits that are preserved by the procurements

3 held under Public Act 99-906 and would have ceased

4 to exist if the procurements had not been held,

5 such as the preservation of zero emission

6 facilities;

7 (iii) quantify the environmental benefit of

8 preserving the resources identified in item (ii)

9 of this subparagraph (C-5), including the

10 following:

11 (aa) the value of avoided greenhouse gas

12 emissions measured as the product of the zero

13 emission facilities' output over the contract

14 term multiplied by the U.S. Environmental

15 Protection Agency eGrid subregion carbon

16 dioxide emission rate and the U.S. Interagency

17 Working Group on Social Cost of Carbon's price

18 in the August 2016 Technical Update using a 3%

19 discount rate, adjusted for inflation for each

20 delivery year; and

21 (bb) the costs of replacement with other

22 zero carbon dioxide resources, including wind

23 and photovoltaic, based upon the simple

24 average of the following:

25 (I) the price, or if there is more

26 than one price, the average of the prices,

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1 paid for renewable energy credits from new

2 utility-scale wind projects in the

3 procurement events specified in item (i)

4 of subparagraph (G) of paragraph (1) of

5 subsection (c) of this Section; and

6 (II) the price, or if there is more

7 than one price, the average of the prices,

8 paid for renewable energy credits from new

9 utility-scale solar projects and

10 brownfield site photovoltaic projects in

11 the procurement events specified in item

12 (ii) of subparagraph (G) of paragraph (1)

13 of subsection (c) of this Section and,

14 after January 1, 2015, renewable energy

15 credits from photovoltaic distributed

16 generation projects in procurement events

17 held under subsection (c) of this Section.

18 Each utility shall enter into binding contractual

19 arrangements with the winning suppliers.

20 The procurement described in this subsection

21 (d-5), including, but not limited to, the execution of

22 all contracts procured, shall be completed no later

23 than May 10, 2017. Based on the effective date of

24 Public Act 99-906, the Agency and Commission may, as

25 appropriate, modify the various dates and timelines

26 under this subparagraph and subparagraphs (C) and (D)

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1 of this paragraph (1). The procurement and plan

2 approval processes required by this subsection (d-5)

3 shall be conducted in conjunction with the procurement

4 and plan approval processes required by subsection (c)

5 of this Section and Section 16-111.5 of the Public

6 Utilities Act, to the extent practicable.

7 Notwithstanding whether a procurement event is

8 conducted under Section 16-111.5 of the Public

9 Utilities Act, the Agency shall immediately initiate a

10 procurement process on June 1, 2017 (the effective

11 date of Public Act 99-906).

12 (D) Following the procurement event described in

13 this paragraph (1) and consistent with subparagraph

14 (B) of this paragraph (1), the Agency shall calculate

15 the payments to be made under each contract for the

16 next delivery year based on the market price index for

17 that delivery year. The Agency shall publish the

18 payment calculations no later than May 25, 2017 and

19 every May 25 thereafter.

20 (E) Notwithstanding the requirements of this

21 subsection (d-5), the contracts executed under this

22 subsection (d-5) shall provide that the zero emission

23 facility may, as applicable, suspend or terminate

24 performance under the contracts in the following

25 instances:

26 (i) A zero emission facility shall be excused

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1 from its performance under the contract for any

2 cause beyond the control of the resource,

3 including, but not restricted to, acts of God,

4 flood, drought, earthquake, storm, fire,

5 lightning, epidemic, war, riot, civil disturbance

6 or disobedience, labor dispute, labor or material

7 shortage, sabotage, acts of public enemy,

8 explosions, orders, regulations or restrictions

9 imposed by governmental, military, or lawfully

10 established civilian authorities, which, in any of

11 the foregoing cases, by exercise of commercially

12 reasonable efforts the zero emission facility

13 could not reasonably have been expected to avoid,

14 and which, by the exercise of commercially

15 reasonable efforts, it has been unable to

16 overcome. In such event, the zero emission

17 facility shall be excused from performance for the

18 duration of the event, including, but not limited

19 to, delivery of zero emission credits, and no

20 payment shall be due to the zero emission facility

21 during the duration of the event.

22 (ii) A zero emission facility shall be

23 permitted to terminate the contract if legislation

24 is enacted into law by the General Assembly that

25 imposes or authorizes a new tax, special

26 assessment, or fee on the generation of

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1 electricity, the ownership or leasehold of a

2 generating unit, or the privilege or occupation of

3 such generation, ownership, or leasehold of

4 generation units by a zero emission facility.

5 However, the provisions of this item (ii) do not

6 apply to any generally applicable tax, special

7 assessment or fee, or requirements imposed by

8 federal law.

9 (iii) A zero emission facility shall be

10 permitted to terminate the contract in the event

11 that the resource requires capital expenditures in

12 excess of $40,000,000 that were neither known nor

13 reasonably foreseeable at the time it executed the

14 contract and that a prudent owner or operator of

15 such resource would not undertake.

16 (iv) A zero emission facility shall be

17 permitted to terminate the contract in the event

18 the Nuclear Regulatory Commission terminates the

19 resource's license.

20 (F) If the zero emission facility elects to

21 terminate a contract under subparagraph (E) of this

22 paragraph (1), then the Commission shall reopen the

23 docket in which the Commission approved the zero

24 emission standard procurement plan under subparagraph

25 (C) of this paragraph (1) and, after notice and

26 hearing, enter an order acknowledging the contract

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1 termination election if such termination is consistent

2 with the provisions of this subsection (d-5).

3 (2) For purposes of this subsection (d-5), the amount

4 paid per kilowatthour means the total amount paid for

5 electric service expressed on a per kilowatthour basis.

6 For purposes of this subsection (d-5), the total amount

7 paid for electric service includes, without limitation,

8 amounts paid for supply, transmission, distribution,

9 surcharges, and add-on taxes.

10 Notwithstanding the requirements of this subsection

11 (d-5), the contracts executed under this subsection (d-5)

12 shall provide that the total of zero emission credits

13 procured under a procurement plan shall be subject to the

14 limitations of this paragraph (2). For each delivery year,

15 the contractual volume receiving payments in such year

16 shall be reduced for all retail customers based on the

17 amount necessary to limit the net increase that delivery

18 year to the costs of those credits included in the amounts

19 paid by eligible retail customers in connection with

20 electric service to no more than 1.65% of the amount paid

21 per kilowatthour by eligible retail customers during the

22 year ending May 31, 2009. The result of this computation

23 shall apply to and reduce the procurement for all retail

24 customers, and all those customers shall pay the same

25 single, uniform cents per kilowatthour charge under

26 subsection (k) of Section 16-108 of the Public Utilities

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1 Act. To arrive at a maximum dollar amount of zero emission

2 credits to be paid for the particular delivery year, the

3 resulting per kilowatthour amount shall be applied to the

4 actual amount of kilowatthours of electricity delivered by

5 the electric utility in the delivery year immediately

6 prior to the procurement, to all retail customers in its

7 service territory. Unpaid contractual volume for any

8 delivery year shall be paid in any subsequent delivery

9 year in which such payments can be made without exceeding

10 the amount specified in this paragraph (2). The

11 calculations required by this paragraph (2) shall be made

12 only once for each procurement plan year. Once the

13 determination as to the amount of zero emission credits to

14 be paid is made based on the calculations set forth in this

15 paragraph (2), no subsequent rate impact determinations

16 shall be made and no adjustments to those contract amounts

17 shall be allowed. All costs incurred under those contracts

18 and in implementing this subsection (d-5) shall be

19 recovered by the electric utility as provided in this

20 Section.

21 No later than June 30, 2019, the Commission shall

22 review the limitation on the amount of zero emission

23 credits procured under this subsection (d-5) and report to

24 the General Assembly its findings as to whether that

25 limitation unduly constrains the procurement of

26 cost-effective zero emission credits.

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1 (3) Six years after the execution of a contract under

2 this subsection (d-5), the Agency shall determine whether

3 the actual zero emission credit payments received by the

4 supplier over the 6-year period exceed the Average ZEC

5 Payment. In addition, at the end of the term of a contract

6 executed under this subsection (d-5), or at the time, if

7 any, a zero emission facility's contract is terminated

8 under subparagraph (E) of paragraph (1) of this subsection

9 (d-5), then the Agency shall determine whether the actual

10 zero emission credit payments received by the supplier

11 over the term of the contract exceed the Average ZEC

12 Payment, after taking into account any amounts previously

13 credited back to the utility under this paragraph (3). If

14 the Agency determines that the actual zero emission credit

15 payments received by the supplier over the relevant period

16 exceed the Average ZEC Payment, then the supplier shall

17 credit the difference back to the utility. The amount of

18 the credit shall be remitted to the applicable electric

19 utility no later than 120 days after the Agency's

20 determination, which the utility shall reflect as a credit

21 on its retail customer bills as soon as practicable;

22 however, the credit remitted to the utility shall not

23 exceed the total amount of payments received by the

24 facility under its contract.

25 For purposes of this Section, the Average ZEC Payment

26 shall be calculated by multiplying the quantity of zero

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1 emission credits delivered under the contract times the

2 average contract price. The average contract price shall

3 be determined by subtracting the amount calculated under

4 subparagraph (B) of this paragraph (3) from the amount

5 calculated under subparagraph (A) of this paragraph (3),

6 as follows:

7 (A) The average of the Social Cost of Carbon, as

8 defined in subparagraph (B) of paragraph (1) of this

9 subsection (d-5), during the term of the contract.

10 (B) The average of the market price indices, as

11 defined in subparagraph (B) of paragraph (1) of this

12 subsection (d-5), during the term of the contract,

13 minus the baseline market price index, as defined in

14 subparagraph (B) of paragraph (1) of this subsection

15 (d-5).

16 If the subtraction yields a negative number, then the

17 Average ZEC Payment shall be zero.

18 (4) Cost-effective zero emission credits procured from

19 zero emission facilities shall satisfy the applicable

20 definitions set forth in Section 1-10 of this Act.

21 (5) The electric utility shall retire all zero

22 emission credits used to comply with the requirements of

23 this subsection (d-5).

24 (6) Electric utilities shall be entitled to recover

25 all of the costs associated with the procurement of zero

26 emission credits through an automatic adjustment clause

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1 tariff in accordance with subsection (k) and (m) of

2 Section 16-108 of the Public Utilities Act, and the

3 contracts executed under this subsection (d-5) shall

4 provide that the utilities' payment obligations under such

5 contracts shall be reduced if an adjustment is required

6 under subsection (m) of Section 16-108 of the Public

7 Utilities Act.

8 (7) This subsection (d-5) shall become inoperative on

9 January 1, 2028.

10 (e) The draft procurement plans are subject to public

11 comment, as required by Section 16-111.5 of the Public

12 Utilities Act.

13 (f) The Agency shall submit the final procurement plan to

14 the Commission. The Agency shall revise a procurement plan if

15 the Commission determines that it does not meet the standards

16 set forth in Section 16-111.5 of the Public Utilities Act.

17 (g) The Agency shall assess fees to each affected utility

18 to recover the costs incurred in preparation of the annual

19 procurement plan for the utility.

20 (h) The Agency shall assess fees to each bidder to recover

21 the costs incurred in connection with a competitive

22 procurement process.

23 (i) A renewable energy credit, carbon emission credit, or

24 zero emission credit can only be used once to comply with a

25 single portfolio or other standard as set forth in subsection

26 (c), subsection (d), or subsection (d-5) of this Section,

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1 respectively. A renewable energy credit, carbon emission

2 credit, or zero emission credit cannot be used to satisfy the

3 requirements of more than one standard. If more than one type

4 of credit is issued for the same megawatt hour of energy, only

5 one credit can be used to satisfy the requirements of a single

6 standard. After such use, the credit must be retired together

7 with any other credits issued for the same megawatt hour of

8 energy.

9 (Source: P.A. 100-863, eff. 8-14-18; 101-81, eff. 7-12-19;

10 101-113, eff. 1-1-20.)

11 Section 10. The Public Utilities Act is amended by

12 changing Sections 5-117, 8-103B, 16-102, 16-107.6, 16-108.5,

13 16-111.5, and 16-128A and by adding Sections 8-218, 9-244.5,

14 16-108.19 and 16-108.20 as follows:

15 (220 ILCS 5/5-117)

16 Sec. 5-117. Supplier diversity goals.

17 (a) The public policy of this State is to collaboratively

18 work with companies that serve Illinois residents to improve

19 their supplier diversity in a non-antagonistic manner.

20 (b) The Commission shall require all gas, electric, and

21 water companies with at least 100,000 customers under its

22 authority, as well as suppliers of wind energy, solar energy,

23 hydroelectricity, nuclear energy, and any other supplier of

24 energy within this State, including, but not limited to, any

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1 party selling renewable energy resources procured by the

2 Illinois Power Agency pursuant to Section 16-111.5 of this Act

3 and Section 1-75 of the Illinois Power Agency Act, to submit an

4 annual report by April 15, 2015 and every April 15 thereafter,

5 in a searchable Adobe PDF format, on all procurement goals and

6 actual spending for woman-owned ~~female-owned~~, minority-owned,

7 veteran-owned, and small business enterprises in the previous

8 calendar year. These goals shall be expressed as a percentage

9 of the total work performed by the entity submitting the

10 report, and the actual spending for all woman-owned

11 ~~female-owned~~, minority-owned, veteran-owned, and small

12 business enterprises shall also be expressed as a percentage

13 of the total work performed by the entity submitting the

14 report. Nothing in this subsection (b) shall require any

15 entity that was not required to file a report pursuant to this

16 subsection (b) prior to the effective date of this amendatory

17 Act of the 102nd General Assembly to file reports for calendar

18 years prior to 2021.

19 (c) Each participating company in its annual report shall

20 include the following information:

21 (1) an explanation of the plan for the next year to

22 increase participation;

23 (2) an explanation of the plan to increase the goals;

24 (3) the areas of procurement each company shall be

25 actively seeking more participation in ~~in~~ the next year;

26 (4) an outline of the plan to alert and encourage

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1 potential vendors in that area to seek business from the

2 company;

3 (5) an explanation of the challenges faced in finding

4 quality vendors and offer any suggestions for what the

5 Commission could do to be helpful to identify those

6 vendors;

7 (6) a list of the certifications the company

8 recognizes;

9 (7) the point of contact for any potential vendor who

10 wishes to do business with the company and explain the

11 process for a vendor to enroll with the company as a

12 minority-owned, women-owned, or veteran-owned company; and

13 (8) any particular success stories to encourage other

14 companies to emulate best practices.

15 (d) Each annual report shall include as much

16 State-specific data as possible. If the submitting entity does

17 not submit State-specific data, then the company shall include

18 any national data it does have and explain why it could not

19 submit State-specific data and how it intends to do so in

20 future reports, if possible.

21 (e) Each annual report shall include the rules,

22 regulations, and definitions used for the procurement goals in

23 the company's annual report.

24 (f) The Commission and all participating entities shall

25 hold an annual workshop open to the public in 2015 and every

26 year thereafter on the state of supplier diversity to

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1 collaboratively seek solutions to structural impediments to

2 achieving stated goals, including testimony from each

3 participating entity as well as subject matter experts and

4 advocates. The Commission shall publish a database on its

5 website of the point of contact for each participating entity

6 for supplier diversity, along with a list of certifications

7 each company recognizes from the information submitted in each

8 annual report. The Commission shall publish each annual report

9 on its website and shall maintain each annual report for at

10 least 5 years.

11 (Source: P.A. 98-1056, eff. 8-26-14; 99-906, eff. 6-1-17;

12 revised 7-22-19.)

13 (220 ILCS 5/8-103B)

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

15 measures.

16 (a) It is the policy of the State that electric utilities

17 are required to use cost-effective energy efficiency and

18 demand-response measures to reduce the total Btus of

19 electricity, natural gas, or other fuels needed to meet the

20 end use or uses for all retail customers ~~delivery load~~.

21 Requiring investment in cost-effective energy efficiency and

22 demand-response measures will reduce direct and indirect costs

23 to consumers by decreasing environmental impacts and by

24 avoiding or delaying the need for new generation,

25 transmission, and distribution infrastructure. It serves the

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1 public interest to allow electric utilities to recover costs

2 for reasonably and prudently incurred expenditures for energy

3 efficiency and demand-response measures. As used in this

4 Section, "cost-effective" means that the measures satisfy the

5 total resource cost test. The low-income measures described in

6 subsection (c) of this Section shall not be required to meet

7 the total resource cost test. For purposes of this Section,

8 the terms "energy-efficiency", "demand-response", "electric

9 utility", and "total resource cost test" have the meanings set

10 forth in the Illinois Power Agency Act.

11 (a-5) This Section applies to electric utilities serving

12 more than 500,000 retail customers in the State for those

13 multi-year plans commencing after December 31, 2017.

14 (b) For purposes of this Section, electric utilities

15 subject to this Section that serve more than 3,000,000 retail

16 customers in the State shall be deemed to have achieved a

17 cumulative persisting annual savings of 6.6% from energy

18 efficiency measures and programs implemented during the period

19 beginning January 1, 2012 and ending December 31, 2017, which

20 percent is based on the deemed average weather normalized

21 sales of electric power and energy during calendar years 2014,

22 2015, and 2016 of 88,000,000 MWhs. For the purposes of this

23 subsection (b) and subsection (b-5), the 88,000,000 MWhs of

24 deemed electric power and energy sales shall be reduced by the

25 number of MWhs equal to the sum of the annual consumption of

26 customers that are exempt from subsections (a) through (j) of

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1 this Section under subsection (l) of this Section, as averaged

2 across the calendar years 2014, 2015, and 2016. After 2017,

3 the deemed value of cumulative persisting annual savings from

4 energy efficiency measures and programs implemented during the

5 period beginning January 1, 2012 and ending December 31, 2017,

6 shall be reduced each year, as follows, and the applicable

7 value shall be applied to and count toward the utility's

8 achievement of the cumulative persisting annual savings goals

9 set forth in subsection (b-5):

10 (1) 5.8% deemed cumulative persisting annual savings

11 for the year ending December 31, 2018;

12 (2) 5.2% deemed cumulative persisting annual savings

13 for the year ending December 31, 2019;

14 (3) 4.5% deemed cumulative persisting annual savings

15 for the year ending December 31, 2020;

16 (4) 4.0% deemed cumulative persisting annual savings

17 for the year ending December 31, 2021;

18 (5) 3.5% deemed cumulative persisting annual savings

19 for the year ending December 31, 2022;

20 (6) 3.1% deemed cumulative persisting annual savings

21 for the year ending December 31, 2023;

22 (7) 2.8% deemed cumulative persisting annual savings

23 for the year ending December 31, 2024;

24 (8) 2.5% deemed cumulative persisting annual savings

25 for the year ending December 31, 2025;

26 (9) 2.3% deemed cumulative persisting annual savings

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1 for the year ending December 31, 2026;

2 (10) 2.1% deemed cumulative persisting annual savings

3 for the year ending December 31, 2027;

4 (11) 1.8% deemed cumulative persisting annual savings

5 for the year ending December 31, 2028;

6 (12) 1.7% deemed cumulative persisting annual savings

7 for the year ending December 31, 2029; and

8 (13) 1.5% deemed cumulative persisting annual savings

9 for the year ending December 31, 2030.

10 For purposes of this Section, "cumulative persisting

11 annual savings" means the total electric energy savings in a

12 given year from measures installed in that year or in previous

13 years, but no earlier than January 1, 2012, that are still

14 operational and providing savings in that year because the

15 measures have not yet reached the end of their useful lives.

16 (b-5) Beginning in 2018, electric utilities subject to

17 this Section that serve more than 3,000,000 retail customers

18 in the State shall achieve the following cumulative persisting

19 annual savings goals, as modified by subsection (f) of this

20 Section and as compared to the deemed baseline of 88,000,000

21 MWhs of electric power and energy sales set forth in

22 subsection (b), as reduced by the number of MWhs equal to the

23 sum of the annual consumption of customers that are exempt

24 from subsections (a) through (j) of this Section under

25 subsection (l) of this Section as averaged across the calendar

26 years 2014, 2015, and 2016, through the implementation of

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1 energy efficiency measures during the applicable year and in

2 prior years, but no earlier than January 1, 2012:

3 (1) 7.8% cumulative persisting annual savings for the

4 year ending December 31, 2018;

5 (2) 9.1% cumulative persisting annual savings for the

6 year ending December 31, 2019;

7 (3) 10.4% cumulative persisting annual savings for the

8 year ending December 31, 2020;

9 (4) 11.8% cumulative persisting annual savings for the

10 year ending December 31, 2021;

11 (5) 13.1% cumulative persisting annual savings for the

12 year ending December 31, 2022;

13 (6) 14.4% cumulative persisting annual savings for the

14 year ending December 31, 2023;

15 (7) 15.7% cumulative persisting annual savings for the

16 year ending December 31, 2024;

17 (8) 17% cumulative persisting annual savings for the

18 year ending December 31, 2025;

19 (9) 17.9% cumulative persisting annual savings for the

20 year ending December 31, 2026;

21 (10) 18.8% cumulative persisting annual savings for

22 the year ending December 31, 2027;

23 (11) 19.7% cumulative persisting annual savings for

24 the year ending December 31, 2028;

25 (12) 20.6% cumulative persisting annual savings for

26 the year ending December 31, 2029; and

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1 (13) 21.5% cumulative persisting annual savings for

2 the year ending December 31, 2030.

3 (b-10) For purposes of this Section, electric utilities

4 subject to this Section that serve less than 3,000,000 retail

5 customers but more than 500,000 retail customers in the State

6 shall be deemed to have achieved a cumulative persisting

7 annual savings of 6.6% from energy efficiency measures and

8 programs implemented during the period beginning January 1,

9 2012 and ending December 31, 2017, which is based on the deemed

10 average weather normalized sales of electric power and energy

11 during calendar years 2014, 2015, and 2016 of 36,900,000 MWhs.

12 For the purposes of this subsection (b-10) and subsection

13 (b-15), the 36,900,000 MWhs of deemed electric power and

14 energy sales shall be reduced by the number of MWhs equal to

15 the sum of the annual consumption of customers that are exempt

16 from subsections (a) through (j) of this Section under

17 subsection (l) of this Section, as averaged across the

18 calendar years 2014, 2015, and 2016. After 2017, the deemed

19 value of cumulative persisting annual savings from energy

20 efficiency measures and programs implemented during the period

21 beginning January 1, 2012 and ending December 31, 2017, shall

22 be reduced each year, as follows, and the applicable value

23 shall be applied to and count toward the utility's achievement

24 of the cumulative persisting annual savings goals set forth in

25 subsection (b-15):

26 (1) 5.8% deemed cumulative persisting annual savings

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1 for the year ending December 31, 2018;

2 (2) 5.2% deemed cumulative persisting annual savings

3 for the year ending December 31, 2019;

4 (3) 4.5% deemed cumulative persisting annual savings

5 for the year ending December 31, 2020;

6 (4) 4.0% deemed cumulative persisting annual savings

7 for the year ending December 31, 2021;

8 (5) 3.5% deemed cumulative persisting annual savings

9 for the year ending December 31, 2022;

10 (6) 3.1% deemed cumulative persisting annual savings

11 for the year ending December 31, 2023;

12 (7) 2.8% deemed cumulative persisting annual savings

13 for the year ending December 31, 2024;

14 (8) 2.5% deemed cumulative persisting annual savings

15 for the year ending December 31, 2025;

16 (9) 2.3% deemed cumulative persisting annual savings

17 for the year ending December 31, 2026;

18 (10) 2.1% deemed cumulative persisting annual savings

19 for the year ending December 31, 2027;

20 (11) 1.8% deemed cumulative persisting annual savings

21 for the year ending December 31, 2028;

22 (12) 1.7% deemed cumulative persisting annual savings

23 for the year ending December 31, 2029; and

24 (13) 1.5% deemed cumulative persisting annual savings

25 for the year ending December 31, 2030.

26 (b-15) Beginning in 2018, electric utilities subject to

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1 this Section that serve less than 3,000,000 retail customers

2 but more than 500,000 retail customers in the State shall

3 achieve the following cumulative persisting annual savings

4 goals, as modified by subsection (b-20) and subsection (f) of

5 this Section and as compared to the deemed baseline as reduced

6 by the number of MWhs equal to the sum of the annual

7 consumption of customers that are exempt from subsections (a)

8 through (j) of this Section under subsection (l) of this

9 Section as averaged across the calendar years 2014, 2015, and

10 2016, through the implementation of energy efficiency measures

11 during the applicable year and in prior years, but no earlier

12 than January 1, 2012:

13 (1) 7.4% cumulative persisting annual savings for the

14 year ending December 31, 2018;

15 (2) 8.2% cumulative persisting annual savings for the

16 year ending December 31, 2019;

17 (3) 9.0% cumulative persisting annual savings for the

18 year ending December 31, 2020;

19 (4) 9.8% cumulative persisting annual savings for the

20 year ending December 31, 2021;

21 (5) 10.6% cumulative persisting annual savings for the

22 year ending December 31, 2022;

23 (6) 11.4% cumulative persisting annual savings for the

24 year ending December 31, 2023;

25 (7) 12.2% cumulative persisting annual savings for the

26 year ending December 31, 2024;

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1 (8) 13% cumulative persisting annual savings for the

2 year ending December 31, 2025;

3 (9) 13.6% cumulative persisting annual savings for the

4 year ending December 31, 2026;

5 (10) 14.2% cumulative persisting annual savings for

6 the year ending December 31, 2027;

7 (11) 14.8% cumulative persisting annual savings for

8 the year ending December 31, 2028;

9 (12) 15.4% cumulative persisting annual savings for

10 the year ending December 31, 2029; and

11 (13) 16% cumulative persisting annual savings for the

12 year ending December 31, 2030.

13 The difference between the cumulative persisting annual

14 savings goal for the applicable calendar year and the

15 cumulative persisting annual savings goal for the immediately

16 preceding calendar year is 0.8% for the period of January 1,

17 2018 through December 31, 2025 and 0.6% for the period of

18 January 1, 2026 through December 31, 2030.

19 (b-20) Each electric utility subject to this Section may

20 include cost-effective voltage optimization measures in its

21 plans submitted under subsections (f) and (g) of this Section,

22 and the costs incurred by a utility to implement the measures

23 under a Commission-approved plan shall be recovered under the

24 provisions of Article IX or Section 16-108.5 of this Act. For

25 purposes of this Section, the measure life of voltage

26 optimization measures shall be 15 years. The measure life

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1 period is independent of the depreciation rate of the voltage

2 optimization assets deployed.

3 Within 270 days after June 1, 2017 (the effective date of

4 Public Act 99-906), an electric utility that serves less than

5 3,000,000 retail customers but more than 500,000 retail

6 customers in the State shall file a plan with the Commission

7 that identifies the cost-effective voltage optimization

8 investment the electric utility plans to undertake through

9 December 31, 2024. The Commission, after notice and hearing,

10 shall approve or approve with modification the plan within 120

11 days after the plan's filing and, in the order approving or

12 approving with modification the plan, the Commission shall

13 adjust the applicable cumulative persisting annual savings

14 goals set forth in subsection (b-15) to reflect any amount of

15 cost-effective energy savings approved by the Commission that

16 is greater than or less than the following cumulative

17 persisting annual savings values attributable to voltage

18 optimization for the applicable year:

19 (1) 0.0% of cumulative persisting annual savings for

20 the year ending December 31, 2018;

21 (2) 0.17% of cumulative persisting annual savings for

22 the year ending December 31, 2019;

23 (3) 0.17% of cumulative persisting annual savings for

24 the year ending December 31, 2020;

25 (4) 0.33% of cumulative persisting annual savings for

26 the year ending December 31, 2021;

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1 (5) 0.5% of cumulative persisting annual savings for

2 the year ending December 31, 2022;

3 (6) 0.67% of cumulative persisting annual savings for

4 the year ending December 31, 2023;

5 (7) 0.83% of cumulative persisting annual savings for

6 the year ending December 31, 2024; and

7 (8) 1.0% of cumulative persisting annual savings for

8 the year ending December 31, 2025.

9 (b-25) In the event an electric utility jointly offers an

10 energy efficiency measure or program with a gas utility under

11 plans approved under this Section and Section 8-104 of this

12 Act, the electric utility may continue offering the program,

13 including the gas energy efficiency measures, in the event the

14 gas utility discontinues funding the program. In that event,

15 the energy savings value associated with such other fuels

16 shall be converted to electric energy savings on an equivalent

17 Btu basis for the premises. However, the electric utility

18 shall prioritize programs for low-income residential customers

19 to the extent practicable. An electric utility may recover the

20 costs of offering the gas energy efficiency measures under

21 this subsection (b-25).

22 For those energy efficiency measures or programs that save

23 both electricity and other fuels but are not jointly offered

24 with a gas utility under plans approved under this Section and

25 Section 8-104 or not offered with an affiliated gas utility

26 under paragraph (6) of subsection (f) of Section 8-104 of this

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1 Act, or for those energy efficiency measures that achieve

2 savings of fuels other than electricity, an ~~the~~ electric

3 utility may count savings of fuels other than electricity

4 toward the achievement of its annual savings goal, and the

5 energy savings value associated with such other fuels shall be

6 converted to electric energy savings on an equivalent Btu

7 basis at the premises.

8 In no event shall more than 10% of each year's applicable

9 annual incremental goal as defined in paragraph (7) of

10 subsection (g) of this Section be met through savings of fuels

11 other than electricity; however, savings of fuels other than

12 electricity achieved by measures that educate about,

13 incentivize, encourage, or otherwise support the use of

14 electricity to power, in whole or in part, vehicles,

15 including, but not limited to, cars, trucks, buses, trains,

16 trolleys, boats, on-road or off-road vehicles, or other

17 equipment or methods of transporting goods or people, shall

18 count towards the applicable annual incremental goal and shall

19 not be included in the 10% limit set forth in this subsection

20 (b-25). Such measures shall include, but are not limited to,

21 measures that educate about, incentivize, encourage, or

22 otherwise support the adoption of electric vehicles by retail

23 customers of all customer classes.

24 (c) Electric utilities shall be responsible for overseeing

25 the design, development, and filing of energy efficiency plans

26 with the Commission and may, as part of that implementation,

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1 outsource various aspects of program development and

2 implementation. A minimum of 10%, for electric utilities that

3 serve more than 3,000,000 retail customers in the State, and a

4 minimum of 7%, for electric utilities that serve less than

5 3,000,000 retail customers but more than 500,000 retail

6 customers in the State, of the utility's entire portfolio

7 funding level for a given year shall be used to procure

8 cost-effective energy efficiency measures from units of local

9 government, municipal corporations, school districts, public

10 housing, and community college districts, provided that a

11 minimum percentage of available funds shall be used to procure

12 energy efficiency from public housing, which percentage shall

13 be equal to public housing's share of public building energy

14 consumption.

15 The utilities shall also implement energy efficiency

16 measures targeted at low-income households, which, for

17 purposes of this Section, shall be defined as households at or

18 below 80% of area median income, and expenditures to implement

19 the measures shall be no less than $25,000,000 per year for

20 electric utilities that serve more than 3,000,000 retail

21 customers in the State and no less than $8,350,000 per year for

22 electric utilities that serve less than 3,000,000 retail

23 customers but more than 500,000 retail customers in the State.

24 Each electric utility shall assess opportunities to

25 implement cost-effective energy efficiency measures and

26 programs through a public housing authority or authorities

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1 located in its service territory. If such opportunities are

2 identified, the utility shall propose such measures and

3 programs to address the opportunities. Expenditures to address

4 such opportunities shall be credited toward the minimum

5 procurement and expenditure requirements set forth in this

6 subsection (c).

7 Implementation of energy efficiency measures and programs

8 targeted at low-income households should be contracted, when

9 it is practicable, to independent third parties that have

10 demonstrated capabilities to serve such households, with a

11 preference for not-for-profit entities and government agencies

12 that have existing relationships with or experience serving

13 low-income communities in the State.

14 Each electric utility shall develop and implement

15 reporting procedures that address and assist in determining

16 the amount of energy savings that can be applied to the

17 low-income procurement and expenditure requirements set forth

18 in this subsection (c).

19 The electric utilities shall also convene a low-income

20 energy efficiency advisory committee to assist in the design

21 and evaluation of the low-income energy efficiency programs.

22 The committee shall be comprised of the electric utilities

23 subject to the requirements of this Section, the gas utilities

24 subject to the requirements of Section 8-104 of this Act, the

25 utilities' low-income energy efficiency implementation

26 contractors, and representatives of community-based

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1 organizations.

2 (d) Notwithstanding any other provision of law to the

3 contrary, a utility providing approved energy efficiency

4 measures and, if applicable, demand-response measures in the

5 State shall be permitted to recover all reasonable and

6 prudently incurred costs of those measures from all retail

7 customers, except as provided in subsection (l) of this

8 Section, as follows, provided that nothing in this subsection

9 (d) permits the double recovery of such costs from customers:

10 (1) The utility may recover its costs through an

11 automatic adjustment clause tariff filed with and approved

12 by the Commission. The tariff shall be established outside

13 the context of a general rate case. Each year the

14 Commission shall initiate a review to reconcile any

15 amounts collected with the actual costs and to determine

16 the required adjustment to the annual tariff factor to

17 match annual expenditures. To enable the financing of the

18 incremental capital expenditures, including regulatory

19 assets, for electric utilities that serve less than

20 3,000,000 retail customers but more than 500,000 retail

21 customers in the State, the utility's actual year-end

22 capital structure that includes a common equity ratio,

23 excluding goodwill, of up to and including 54% ~~50%~~ of the

24 total capital structure shall be deemed reasonable and

25 used to set rates.

26 (2) A utility may recover its costs through an energy

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1 efficiency formula rate approved by the Commission under a

2 filing under subsections (f) and (g) of this Section,

3 which shall specify the cost components that form the

4 basis of the rate charged to customers with sufficient

5 specificity to operate in a standardized manner and be

6 updated annually with transparent information that

7 reflects the utility's actual costs to be recovered during

8 the applicable rate year, which is the period beginning

9 with the first billing day of January and extending

10 through the last billing day of the following December.

11 The energy efficiency formula rate shall be implemented

12 through a tariff filed with the Commission under

13 subsections (f) and (g) of this Section that is consistent

14 with the provisions of this paragraph (2) and that shall

15 be applicable to all delivery services customers. The

16 Commission shall conduct an investigation of the tariff in

17 a manner consistent with the provisions of this paragraph

18 (2), subsections (f) and (g) of this Section, and the

19 provisions of Article IX of this Act to the extent they do

20 not conflict with this paragraph (2). The energy

21 efficiency formula rate approved by the Commission shall

22 remain in effect at the discretion of the utility and

23 shall do the following:

24 (A) Provide for the recovery of the utility's

25 actual costs incurred under this Section that are

26 prudently incurred and reasonable in amount consistent

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1 with Commission practice and law. The sole fact that a

2 cost differs from that incurred in a prior calendar

3 year or that an investment is different from that made

4 in a prior calendar year shall not imply the

5 imprudence or unreasonableness of that cost or

6 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. To enable the financing of the incremental

12 capital expenditures, including regulatory assets, for

13 electric utilities that serve less than 3,000,000

14 retail customers but more than 500,000 retail

15 customers in the State, a participating electric

16 utility's actual year-end capital structure that

17 includes a common equity ratio, excluding goodwill, of

18 up to and including 54% ~~50%~~ of the total capital

19 structure shall be deemed reasonable and used to set

20 rates.

21 (C) Include a cost of equity, which in all

22 calendar years for electric utilities that serve

23 3,000,000 or more retail customers in this State, and

24 in each calendar year commencing before January 1,

25 2021 for electric utilities that serve less than

26 3,000,000 retail customers but more than 500,000

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1 retail customers in this State, shall be calculated as

2 the sum of the following:

3 (i) the average for the applicable calendar

4 year of the monthly average yields of 30-year U.S.

5 Treasury bonds published by the Board of Governors

6 of the Federal Reserve System in its weekly H.15

7 Statistical Release or successor publication; and

8 (ii) 580 basis points.

9 For electric utilities that serve less than

10 3,000,000 retail customers but more than 500,000

11 retail customers in this State, for each calendar year

12 commencing after December 31, 2020, the cost of equity

13 shall be equal to the national average cost of equity

14 as calculated under this subparagraph (C) of this

15 paragraph (2). For purposes of this subparagraph (C)

16 of this paragraph (2), the national average cost of

17 equity for an applicable calendar year shall be the

18 simple average of the cost of equity specified and

19 approved in each order of a state regulatory

20 commission, other than the Commission, issued during

21 such calendar year that is applicable to base rates

22 for retail electric service provided by an

23 investor-owned public utility company operating in the

24 United States. No order shall be excluded from the

25 national average cost of equity calculated under this

26 subparagraph (C) of this paragraph (2) on the grounds

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1 that it was arrived at by stipulation or agreement or

2 is subject to rehearing or appeal. In its final order

3 in the proceeding, occurring pursuant to subsection

4 (d) of this Section during calendar year 2021, the

5 Commission shall set the cost of equity using the

6 method applicable to calendar years commencing prior

7 to January 1, 2021. In its final orders in the

8 proceedings, occurring pursuant to subsection (d) of

9 this Section in years subsequent to calendar year

10 2021, including the reconciliation of the 2021 rate

11 year, the Commission shall set the cost of equity

12 using the method applicable to calendar years

13 commencing after December 31, 2020. If, for any

14 calendar year, there are fewer than 15 applicable

15 orders of state regulatory commissions with which to

16 compute the average cost of equity under this

17 subparagraph (C) of this paragraph (2), the Commission

18 shall include in the calculation of the national

19 average the number of state regulatory orders from the

20 year or years immediately preceding such calendar year

21 necessary to reach a total of 15, beginning with the

22 most recently issued and proceeding in reverse

23 chronological order.

24 At such time as the Board of Governors of the

25 Federal Reserve System ceases to include the monthly

26 average yields of 30-year U.S. Treasury bonds in its

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1 weekly H.15 Statistical Release or successor

2 publication, the monthly average yields of the U.S.

3 Treasury bonds then having the longest duration

4 published by the Board of Governors in its weekly H.15

5 Statistical Release or successor publication shall

6 instead be used for purposes of this paragraph (2).

7 (D) Permit and set forth protocols, subject to a

8 determination of prudence and reasonableness

9 consistent with Commission practice and law, for the

10 following:

11 (i) recovery of incentive compensation expense

12 that is based on the achievement of operational

13 metrics, including metrics related to budget

14 controls, outage duration and frequency, safety,

15 customer service, efficiency and productivity, and

16 environmental compliance; however, this protocol

17 shall not apply if such expense related to costs

18 incurred under this Section is recovered under

19 Article IX or Section 16-108.5 of this Act;

20 incentive compensation expense that is based on

21 net income or an affiliate's earnings per share

22 shall not be recoverable under the energy

23 efficiency formula rate;

24 (ii) recovery of pension and other

25 post-employment benefits expense, provided that

26 such costs are supported by an actuarial study;

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1 however, this protocol shall not apply if such

2 expense related to costs incurred under this

3 Section is recovered under Article IX or Section

4 16-108.5 of this Act;

5 (iii) recovery of existing regulatory assets

6 over the periods previously authorized by the

7 Commission;

8 (iv) as described in subsection (e),

9 amortization of costs incurred under this Section;

10 and

11 (v) projected, weather normalized billing

12 determinants for the applicable rate year.

13 (E) Provide for an annual reconciliation, as

14 described in paragraph (3) of this subsection (d),

15 less any deferred taxes related to the reconciliation,

16 with interest at an annual rate of return equal to the

17 utility's weighted average cost of capital, including

18 a revenue conversion factor calculated to recover or

19 refund all additional income taxes that may be payable

20 or receivable as a result of that return, of the energy

21 efficiency revenue requirement reflected in rates for

22 each calendar year, beginning with the calendar year

23 in which the utility files its energy efficiency

24 formula rate tariff under this paragraph (2), with

25 what the revenue requirement would have been had the

26 actual cost information for the applicable calendar

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1 year been available at the filing date.

2 The utility shall file, together with its tariff, the

3 projected costs to be incurred by the utility during the

4 rate year under the utility's multi-year plan approved

5 under subsections (f) and (g) of this Section, including,

6 but not limited to, the projected capital investment costs

7 and projected regulatory asset balances with

8 correspondingly updated depreciation and amortization

9 reserves and expense, that shall populate the energy

10 efficiency formula rate and set the initial rates under

11 the formula.

12 The Commission shall review the proposed tariff in

13 conjunction with its review of a proposed multi-year plan,

14 as specified in paragraph (5) of subsection (g) of this

15 Section. The review shall be based on the same evidentiary

16 standards, including, but not limited to, those concerning

17 the prudence and reasonableness of the costs incurred by

18 the utility, the Commission applies in a hearing to review

19 a filing for a general increase in rates under Article IX

20 of this Act. The initial rates shall take effect beginning

21 with the January monthly billing period following the

22 Commission's approval.

23 The tariff's rate design and cost allocation across

24 customer classes shall be consistent with the utility's

25 automatic adjustment clause tariff in effect on June 1,

26 2017 (the effective date of Public Act 99-906); however,

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1 the Commission may revise the tariff's rate design and

2 cost allocation in subsequent proceedings under paragraph

3 (3) of this subsection (d).

4 If the energy efficiency formula rate is terminated,

5 the then current rates shall remain in effect until such

6 time as the energy efficiency costs are incorporated into

7 new rates that are set under this subsection (d) or

8 Article IX of this Act, subject to retroactive rate

9 adjustment, with interest, to reconcile rates charged with

10 actual costs.

11 (3) The provisions of this paragraph (3) shall only

12 apply to an electric utility that has elected to file an

13 energy efficiency formula rate under paragraph (2) of this

14 subsection (d). Subsequent to the Commission's issuance of

15 an order approving the utility's energy efficiency formula

16 rate structure and protocols, and initial rates under

17 paragraph (2) of this subsection (d), the utility shall

18 file, on or before June 1 of each year, with the Chief

19 Clerk of the Commission its updated cost inputs to the

20 energy efficiency formula rate for the applicable rate

21 year and the corresponding new charges, as well as the

22 information described in paragraph (9) of subsection (g)

23 of this Section. Each such filing shall conform to the

24 following requirements and include the following

25 information:

26 (A) The inputs to the energy efficiency formula

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1 rate for the applicable rate year shall be based on the

2 projected costs to be incurred by the utility during

3 the rate year under the utility's multi-year plan

4 approved under subsections (f) and (g) of this

5 Section, including, but not limited to, projected

6 capital investment costs and projected regulatory

7 asset balances with correspondingly updated

8 depreciation and amortization reserves and expense.

9 The filing shall also include a reconciliation of the

10 energy efficiency revenue requirement that was in

11 effect for the prior rate year (as set by the cost

12 inputs for the prior rate year) with the actual

13 revenue requirement for the prior rate year

14 (determined using a year-end rate base) that uses

15 amounts reflected in the applicable FERC Form 1 that

16 reports the actual costs for the prior rate year. Any

17 over-collection or under-collection indicated by such

18 reconciliation shall be reflected as a credit against,

19 or recovered as an additional charge to, respectively,

20 with interest calculated at a rate equal to the

21 utility's weighted average cost of capital approved by

22 the Commission for the prior rate year, the charges

23 for the applicable rate year. Such over-collection or

24 under-collection shall be adjusted to remove any

25 deferred taxes related to the reconciliation, for

26 purposes of calculating interest at an annual rate of

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1 return equal to the utility's weighted average cost of

2 capital approved by the Commission for the prior rate

3 year, including a revenue conversion factor calculated

4 to recover or refund all additional income taxes that

5 may be payable or receivable as a result of that

6 return. Each reconciliation shall be certified by the

7 participating utility in the same manner that FERC

8 Form 1 is certified. The filing shall also include the

9 charge or credit, if any, resulting from the

10 calculation required by subparagraph (E) of paragraph

11 (2) of this subsection (d).

12 Notwithstanding any other provision of law to the

13 contrary, the intent of the reconciliation is to

14 ultimately reconcile both the revenue requirement

15 reflected in rates for each calendar year, beginning

16 with the calendar year in which the utility files its

17 energy efficiency formula rate tariff under paragraph

18 (2) of this subsection (d), with what the revenue

19 requirement determined using a year-end rate base for

20 the applicable calendar year would have been had the

21 actual cost information for the applicable calendar

22 year been available at the filing date.

23 For purposes of this Section, "FERC Form 1" means

24 the Annual Report of Major Electric Utilities,

25 Licensees and Others that electric utilities are

26 required to file with the Federal Energy Regulatory

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1 Commission under the Federal Power Act, Sections 3,

2 4(a), 304 and 209, modified as necessary to be

3 consistent with 83 Ill. Admin. Code Part 415 as of May

4 1, 2011. Nothing in this Section is intended to allow

5 costs that are not otherwise recoverable to be

6 recoverable by virtue of inclusion in FERC Form 1.

7 (B) The new charges shall take effect beginning on

8 the first billing day of the following January billing

9 period and remain in effect through the last billing

10 day of the next December billing period regardless of

11 whether the Commission enters upon a hearing under

12 this paragraph (3).

13 (C) The filing shall include relevant and

14 necessary data and documentation for the applicable

15 rate year. Normalization adjustments shall not be

16 required.

17 Within 45 days after the utility files its annual

18 update of cost inputs to the energy efficiency formula

19 rate, the Commission shall with reasonable notice,

20 initiate a proceeding concerning whether the projected

21 costs to be incurred by the utility and recovered during

22 the applicable rate year, and that are reflected in the

23 inputs to the energy efficiency formula rate, are

24 consistent with the utility's approved multi-year plan

25 under subsections (f) and (g) of this Section and whether

26 the costs incurred by the utility during the prior rate

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1 year were prudent and reasonable. The Commission shall

2 also have the authority to investigate the information and

3 data described in paragraph (9) of subsection (g) of this

4 Section, including the proposed adjustment to the

5 utility's return on equity component of its weighted

6 average cost of capital. During the course of the

7 proceeding, each objection shall be stated with

8 particularity and evidence provided in support thereof,

9 after which the utility shall have the opportunity to

10 rebut the evidence. Discovery shall be allowed consistent

11 with the Commission's Rules of Practice, which Rules of

12 Practice shall be enforced by the Commission or the

13 assigned administrative law judge. The Commission shall

14 apply the same evidentiary standards, including, but not

15 limited to, those concerning the prudence and

16 reasonableness of the costs incurred by the utility,

17 during the proceeding as it would apply in a proceeding to

18 review a filing for a general increase in rates under

19 Article IX of this Act. The Commission shall not, however,

20 have the authority in a proceeding under this paragraph

21 (3) to consider or order any changes to the structure or

22 protocols of the energy efficiency formula rate approved

23 under paragraph (2) of this subsection (d). In a

24 proceeding under this paragraph (3), the Commission shall

25 enter its order no later than the earlier of 195 days after

26 the utility's filing of its annual update of cost inputs

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1 to the energy efficiency formula rate or December 15. The

2 utility's proposed return on equity calculation, as

3 described in paragraphs (7) through (9) of subsection (g)

4 of this Section, shall be deemed the final, approved

5 calculation on December 15 of the year in which it is filed

6 unless the Commission enters an order on or before

7 December 15, after notice and hearing, that modifies such

8 calculation consistent with this Section. The Commission's

9 determinations of the prudence and reasonableness of the

10 costs incurred, and determination of such return on equity

11 calculation, for the applicable calendar year shall be

12 final upon entry of the Commission's order and shall not

13 be subject to reopening, reexamination, or collateral

14 attack in any other Commission proceeding, case, docket,

15 order, rule, or regulation; however, nothing in this

16 paragraph (3) shall prohibit a party from petitioning the

17 Commission to rehear or appeal to the courts the order

18 under the provisions of this Act.

19 (e) Beginning on June 1, 2017 (the effective date of

20 Public Act 99-906), a utility subject to the requirements of

21 this Section may elect to defer, as a regulatory asset, up to

22 the full amount of its expenditures incurred under this

23 Section for each annual period, including, but not limited to,

24 any expenditures incurred above the funding level set by

25 subsection (f) of this Section for a given year. The total

26 expenditures deferred as a regulatory asset in a given year

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1 shall be amortized and recovered over a period that is equal to

2 the weighted average of the energy efficiency measure lives

3 implemented for that year that are reflected in the regulatory

4 asset. The unamortized balance shall be recognized as of

5 December 31 for a given year. The utility shall also earn a

6 return on the total of the unamortized balances of all of the

7 energy efficiency regulatory assets, less any deferred taxes

8 related to those unamortized balances, at an annual rate equal

9 to the utility's weighted average cost of capital that

10 includes, based on a year-end capital structure, the utility's

11 actual cost of debt for the applicable calendar year and a cost

12 of equity, which shall be calculated in accordance with the

13 calculations set forth in subparagraph (C) of paragraph (2) of

14 subsection (d) of this Section ~~as the sum of the (i) the~~

15 ~~average for the applicable calendar year of the monthly~~

16 ~~average yields of 30-year U.S. Treasury bonds published by the~~

17 ~~Board of Governors of the Federal Reserve System in its weekly~~

18 ~~H.15 Statistical Release or successor publication; and (ii)~~

19 ~~580 basis points~~, including a revenue conversion factor

20 calculated to recover or refund all additional income taxes

21 that may be payable or receivable as a result of that return.

22 Capital investment costs shall be depreciated and recovered

23 over their useful lives consistent with generally accepted

24 accounting principles. The weighted average cost of capital

25 shall be applied to the capital investment cost balance, less

26 any accumulated depreciation and accumulated deferred income

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1 taxes, as of December 31 for a given year.

2 When an electric utility creates a regulatory asset under

3 the provisions of this Section, the costs are recovered over a

4 period during which customers also receive a benefit which is

5 in the public interest. Accordingly, it is the intent of the

6 General Assembly that an electric utility that elects to

7 create a regulatory asset under the provisions of this Section

8 shall recover all of the associated costs as set forth in this

9 Section. After the Commission has approved the prudence and

10 reasonableness of the costs that comprise the regulatory

11 asset, the electric utility shall be permitted to recover all

12 such costs, and the value and recoverability through rates of

13 the associated regulatory asset shall not be limited, altered,

14 impaired, or reduced.

15 (f) Beginning in 2017, each electric utility shall file an

16 energy efficiency plan with the Commission to meet the energy

17 efficiency standards for the next applicable multi-year period

18 beginning January 1 of the year following the filing,

19 according to the schedule set forth in paragraphs (1) through

20 (3) of this subsection (f). If a utility does not file such a

21 plan on or before the applicable filing deadline for the plan,

22 it shall face a penalty of $100,000 per day until the plan is

23 filed.

24 (1) No later than 30 days after June 1, 2017 (the

25 effective date of Public Act 99-906), each electric

26 utility shall file a 4-year energy efficiency plan

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1 commencing on January 1, 2018 that is designed to achieve

2 the cumulative persisting annual savings goals specified

3 in paragraphs (1) through (4) of subsection (b-5) of this

4 Section or in paragraphs (1) through (4) of subsection

5 (b-15) of this Section, as applicable, through

6 implementation of energy efficiency measures; however, the

7 goals may be reduced if the utility's expenditures are

8 limited pursuant to subsection (m) of this Section or, for

9 a utility that serves less than 3,000,000 retail

10 customers, if each of the following conditions are met:

11 (A) the plan's analysis and forecasts of the utility's

12 ability to acquire energy savings demonstrate that

13 achievement of such goals is not cost effective; and (B)

14 the amount of energy savings achieved by the utility as

15 determined by the independent evaluator for the most

16 recent year for which savings have been evaluated

17 preceding the plan filing was less than the average annual

18 amount of savings required to achieve the goals for the

19 applicable 4-year plan period. Except as provided in

20 subsection (m) of this Section, annual increases in

21 cumulative persisting annual savings goals during the

22 applicable 4-year plan period shall not be reduced to

23 amounts that are less than the maximum amount of

24 cumulative persisting annual savings that is forecast to

25 be cost-effectively achievable during the 4-year plan

26 period. The Commission shall review any proposed goal

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1 reduction as part of its review and approval of the

2 utility's proposed plan.

3 (2) No later than March 1, 2021, each electric utility

4 shall file a 4-year energy efficiency plan commencing on

5 January 1, 2022 that is designed to achieve the cumulative

6 persisting annual savings goals specified in paragraphs

7 (5) through (8) of subsection (b-5) of this Section or in

8 paragraphs (5) through (8) of subsection (b-15) of this

9 Section, as applicable, through implementation of energy

10 efficiency measures; however, the goals may be reduced if

11 the utility's expenditures are limited pursuant to

12 subsection (m) of this Section or, each of the following

13 conditions are met: (A) the plan's analysis and forecasts

14 of the utility's ability to acquire energy savings

15 demonstrate that achievement of such goals is not cost

16 effective; and (B) the amount of energy savings achieved

17 by the utility as determined by the independent evaluator

18 for the most recent year for which savings have been

19 evaluated preceding the plan filing was less than the

20 average annual amount of savings required to achieve the

21 goals for the applicable 4-year plan period. Except as

22 provided in subsection (m) of this Section, annual

23 increases in cumulative persisting annual savings goals

24 during the applicable 4-year plan period shall not be

25 reduced to amounts that are less than the maximum amount

26 of cumulative persisting annual savings that is forecast

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1 to be cost-effectively achievable during the 4-year plan

2 period. The Commission shall review any proposed goal

3 reduction as part of its review and approval of the

4 utility's proposed plan.

5 (3) No later than March 1, 2025, each electric utility

6 shall file a 5-year energy efficiency plan commencing on

7 January 1, 2026 that is designed to achieve the cumulative

8 persisting annual savings goals specified in paragraphs

9 (9) through (13) of subsection (b-5) of this Section or in

10 paragraphs (9) through (13) of subsection (b-15) of this

11 Section, as applicable, through implementation of energy

12 efficiency measures; however, the goals may be reduced if

13 the utility's expenditures are limited pursuant to

14 subsection (m) of this Section or, each of the following

15 conditions are met: (A) the plan's analysis and forecasts

16 of the utility's ability to acquire energy savings

17 demonstrate that achievement of such goals is not cost

18 effective; and (B) the amount of energy savings achieved

19 by the utility as determined by the independent evaluator

20 for the most recent year for which savings have been

21 evaluated preceding the plan filing was less than the

22 average annual amount of savings required to achieve the

23 goals for the applicable 5-year plan period. Except as

24 provided in subsection (m) of this Section, annual

25 increases in cumulative persisting annual savings goals

26 during the applicable 5-year plan period shall not be

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1 reduced to amounts that are less than the maximum amount

2 of cumulative persisting annual savings that is forecast

3 to be cost-effectively achievable during the 5-year plan

4 period. The Commission shall review any proposed goal

5 reduction as part of its review and approval of the

6 utility's proposed plan.

7 Each utility's plan shall set forth the utility's

8 proposals to meet the energy efficiency standards identified

9 in subsection (b-5) or (b-15), as applicable and as such

10 standards may have been modified under this subsection (f),

11 taking into account the unique circumstances of the utility's

12 service territory. For those plans commencing on January 1,

13 2018, the Commission shall seek public comment on the

14 utility's plan and shall issue an order approving or

15 disapproving each plan no later than 105 days after June 1,

16 2017 (the effective date of Public Act 99-906). For those

17 plans commencing after December 31, 2021, the Commission shall

18 seek public comment on the utility's plan and shall issue an

19 order approving or disapproving each plan within 6 months

20 after its submission. If the Commission disapproves a plan,

21 the Commission shall, within 30 days, describe in detail the

22 reasons for the disapproval and describe a path by which the

23 utility may file a revised draft of the plan to address the

24 Commission's concerns satisfactorily. If the utility does not

25 refile with the Commission within 60 days, the utility shall

26 be subject to penalties at a rate of $100,000 per day until the

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1 plan is filed. This process shall continue, and penalties

2 shall accrue, until the utility has successfully filed a

3 portfolio of energy efficiency and demand-response measures.

4 Penalties shall be deposited into the Energy Efficiency Trust

5 Fund.

6 (g) In submitting proposed plans and funding levels under

7 subsection (f) of this Section to meet the savings goals

8 identified in subsection (b-5) or (b-15) of this Section, as

9 applicable, the utility shall:

10 (1) Demonstrate that its proposed energy efficiency

11 measures will achieve the applicable requirements that are

12 identified in subsection (b-5) or (b-15) of this Section,

13 as modified by subsection (f) of this Section.

14 (2) Present specific proposals to implement new

15 building and appliance standards that have been placed

16 into effect.

17 (3) Demonstrate that its overall portfolio of

18 measures, not including low-income programs described in

19 subsection (c) of this Section, is cost-effective using

20 the total resource cost test or complies with paragraphs

21 (1) through (3) of subsection (f) of this Section and

22 represents a diverse cross-section of opportunities for

23 customers of all rate classes, other than those customers

24 described in subsection (l) of this Section, to

25 participate in the programs. Individual measures need not

26 be cost effective.

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1 (4) Present a third-party energy efficiency

2 implementation program subject to the following

3 requirements:

4 (A) beginning with the year commencing January 1,

5 2019, electric utilities that serve more than

6 3,000,000 retail customers in the State shall fund

7 third-party energy efficiency programs in an amount

8 that is no less than $25,000,000 per year, and

9 electric utilities that serve less than 3,000,000

10 retail customers but more than 500,000 retail

11 customers in the State shall fund third-party energy

12 efficiency programs in an amount that is no less than

13 $8,350,000 per year;

14 (B) during 2018, the utility shall conduct a

15 solicitation process for purposes of requesting

16 proposals from third-party vendors for those

17 third-party energy efficiency programs to be offered

18 during one or more of the years commencing January 1,

19 2019, January 1, 2020, and January 1, 2021; for those

20 multi-year plans commencing on January 1, 2022 and

21 January 1, 2026, the utility shall conduct a

22 solicitation process during 2021 and 2025,

23 respectively, for purposes of requesting proposals

24 from third-party vendors for those third-party energy

25 efficiency programs to be offered during one or more

26 years of the respective multi-year plan period; for

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1 each solicitation process, the utility shall identify

2 the sector, technology, or geographical area for which

3 it is seeking requests for proposals;

4 (C) the utility shall propose the bidder

5 qualifications, performance measurement process, and

6 contract structure, which must include a performance

7 payment mechanism and general terms and conditions;

8 the proposed qualifications, process, and structure

9 shall be subject to Commission approval; and

10 (D) the utility shall retain an independent third

11 party to score the proposals received through the

12 solicitation process described in this paragraph (4),

13 rank them according to their cost per lifetime

14 kilowatt-hours saved, and assemble the portfolio of

15 third-party programs.

16 The electric utility shall recover all costs

17 associated with Commission-approved, third-party

18 administered programs regardless of the success of those

19 programs.

20 (4.5) Implement cost-effective demand-response

21 measures to reduce peak demand by 0.1% over the prior year

22 for eligible retail customers, as defined in Section

23 16-111.5 of this Act, and for customers that elect hourly

24 service from the utility pursuant to Section 16-107 of

25 this Act, provided those customers have not been declared

26 competitive. This requirement continues until December 31,

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1 2026.

2 (5) Include a proposed or revised cost-recovery tariff

3 mechanism, as provided for under subsection (d) of this

4 Section, to fund the proposed energy efficiency and

5 demand-response measures and to ensure the recovery of the

6 prudently and reasonably incurred costs of

7 Commission-approved programs.

8 (6) Provide for an annual independent evaluation of

9 the performance of the cost-effectiveness of the utility's

10 portfolio of measures, as well as a full review of the

11 multi-year plan results of the broader net program impacts

12 and, to the extent practical, for adjustment of the

13 measures on a going-forward basis as a result of the

14 evaluations. For purposes of evaluating the

15 cost-effectiveness of measures that incentivize,

16 encourage, or otherwise support the purchase of vehicles

17 that use electricity for power, in whole or in part,

18 including, but not limited to, cars, trucks, buses,

19 trains, trolleys, boats, on-road or off-road vehicles, or

20 other equipment or methods of transporting goods or

21 people, including, but not limited to, measures that

22 incentivize, encourage, or otherwise support the adoption

23 of electric vehicles by retail customers of all customer

24 classes, the independent evaluation shall include

25 valuation and consideration of the reduction of carbon

26 emissions and avoided costs associated with the reduction

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1 in fossil fuel consumption associated with the measures.

2 The resources dedicated to evaluation shall not exceed 3%

3 of portfolio resources in any given year.

4 (7) For electric utilities that serve more than

5 3,000,000 retail customers in the State:

6 (A) Through December 31, 2025, provide for an

7 adjustment to the return on equity component of the

8 utility's weighted average cost of capital calculated

9 under subsection (d) of this Section:

10 (i) If the independent evaluator determines

11 that the utility achieved a cumulative persisting

12 annual savings that is less than the applicable

13 annual incremental goal, then the return on equity

14 component shall be reduced by a maximum of 200

15 basis points in the event that the utility

16 achieved no more than 75% of such goal. If the

17 utility achieved more than 75% of the applicable

18 annual incremental goal but less than 100% of such

19 goal, then the return on equity component shall be

20 reduced by 8 basis points for each percent by

21 which the utility failed to achieve the goal.

22 (ii) If the independent evaluator determines

23 that the utility achieved a cumulative persisting

24 annual savings that is more than the applicable

25 annual incremental goal, then the return on equity

26 component shall be increased by a maximum of 200

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1 basis points in the event that the utility

2 achieved at least 125% of such goal. If the

3 utility achieved more than 100% of the applicable

4 annual incremental goal but less than 125% of such

5 goal, then the return on equity component shall be

6 increased by 8 basis points for each percent by

7 which the utility achieved above the goal. If the

8 applicable annual incremental goal was reduced

9 under paragraphs (1) or (2) of subsection (f) of

10 this Section, then the following adjustments shall

11 be made to the calculations described in this item

12 (ii):

13 (aa) the calculation for determining

14 achievement that is at least 125% of the

15 applicable annual incremental goal shall use

16 the unreduced applicable annual incremental

17 goal to set the value; and

18 (bb) the calculation for determining

19 achievement that is less than 125% but more

20 than 100% of the applicable annual incremental

21 goal shall use the reduced applicable annual

22 incremental goal to set the value for 100%

23 achievement of the goal and shall use the

24 unreduced goal to set the value for 125%

25 achievement. The 8 basis point value shall

26 also be modified, as necessary, so that the

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1 200 basis points are evenly apportioned among

2 each percentage point value between 100% and

3 125% achievement.

4 (B) For the period January 1, 2026 through

5 December 31, 2030, provide for an adjustment to the

6 return on equity component of the utility's weighted

7 average cost of capital calculated under subsection

8 (d) of this Section:

9 (i) If the independent evaluator determines

10 that the utility achieved a cumulative persisting

11 annual savings that is less than the applicable

12 annual incremental goal, then the return on equity

13 component shall be reduced by a maximum of 200

14 basis points in the event that the utility

15 achieved no more than 66% of such goal. If the

16 utility achieved more than 66% of the applicable

17 annual incremental goal but less than 100% of such

18 goal, then the return on equity component shall be

19 reduced by 6 basis points for each percent by

20 which the utility failed to achieve the goal.

21 (ii) If the independent evaluator determines

22 that the utility achieved a cumulative persisting

23 annual savings that is more than the applicable

24 annual incremental goal, then the return on equity

25 component shall be increased by a maximum of 200

26 basis points in the event that the utility

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1 achieved at least 134% of such goal. If the

2 utility achieved more than 100% of the applicable

3 annual incremental goal but less than 134% of such

4 goal, then the return on equity component shall be

5 increased by 6 basis points for each percent by

6 which the utility achieved above the goal. If the

7 applicable annual incremental goal was reduced

8 under paragraph (3) of subsection (f) of this

9 Section, then the following adjustments shall be

10 made to the calculations described in this item

11 (ii):

12 (aa) the calculation for determining

13 achievement that is at least 134% of the

14 applicable annual incremental goal shall use

15 the unreduced applicable annual incremental

16 goal to set the value; and

17 (bb) the calculation for determining

18 achievement that is less than 134% but more

19 than 100% of the applicable annual incremental

20 goal shall use the reduced applicable annual

21 incremental goal to set the value for 100%

22 achievement of the goal and shall use the

23 unreduced goal to set the value for 134%

24 achievement. The 6 basis point value shall

25 also be modified, as necessary, so that the

26 200 basis points are evenly apportioned among

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1 each percentage point value between 100% and

2 134% achievement.

3 (7.5) For purposes of this Section, the term

4 "applicable annual incremental goal" means the difference

5 between the cumulative persisting annual savings goal for

6 the calendar year that is the subject of the independent

7 evaluator's determination and the cumulative persisting

8 annual savings goal for the immediately preceding calendar

9 year, as such goals are defined in subsections (b-5) and

10 (b-15) of this Section and as these goals may have been

11 modified as provided for under subsection (b-20) and

12 paragraphs (1) through (3) of subsection (f) of this

13 Section. Under subsections (b), (b-5), (b-10), and (b-15)

14 of this Section, a utility must first replace energy

15 savings from measures that have reached the end of their

16 measure lives and would otherwise have to be replaced to

17 meet the applicable savings goals identified in subsection

18 (b-5) or (b-15) of this Section before any progress

19 towards achievement of its applicable annual incremental

20 goal may be counted. Notwithstanding anything else set

21 forth in this Section, the difference between the actual

22 annual incremental savings achieved in any given year,

23 including the replacement of energy savings from measures

24 that have expired, and the applicable annual incremental

25 goal shall not affect adjustments to the return on equity

26 for subsequent calendar years under this subsection (g).

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1 (8) For electric utilities that serve less than

2 3,000,000 retail customers but more than 500,000 retail

3 customers in the State:

4 (A) Through December 31, 2025, the applicable

5 annual incremental goal shall be compared to the

6 annual incremental savings as determined by the

7 independent evaluator.

8 (i) The return on equity component shall be

9 reduced by 8 basis points for each percent by

10 which the utility did not achieve 84.4% of the

11 applicable annual incremental goal.

12 (ii) The return on equity component shall be

13 increased by 8 basis points for each percent by

14 which the utility exceeded 100% of the applicable

15 annual incremental goal.

16 (iii) The return on equity component shall not

17 be increased or decreased if the annual

18 incremental savings as determined by the

19 independent evaluator is greater than 84.4% of the

20 applicable annual incremental goal and less than

21 100% of the applicable annual incremental goal.

22 (iv) The return on equity component shall not

23 be increased or decreased by an amount greater

24 than 200 basis points pursuant to this

25 subparagraph (A).

26 (B) For the period of January 1, 2026 through

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1 December 31, 2030, the applicable annual incremental

2 goal shall be compared to the annual incremental

3 savings as determined by the independent evaluator.

4 (i) The return on equity component shall be

5 reduced by 6 basis points for each percent by

6 which the utility did not achieve 100% of the

7 applicable annual incremental goal.

8 (ii) The return on equity component shall be

9 increased by 6 basis points for each percent by

10 which the utility exceeded 100% of the applicable

11 annual incremental goal.

12 (iii) The return on equity component shall not

13 be increased or decreased by an amount greater

14 than 200 basis points pursuant to this

15 subparagraph (B).

16 (C) If the applicable annual incremental goal was

17 reduced under paragraphs (1), (2) or (3) of subsection

18 (f) of this Section, then the following adjustments

19 shall be made to the calculations described in

20 subparagraphs (A) and (B) of this paragraph (8):

21 (i) The calculation for determining

22 achievement that is at least 125% or 134%, as

23 applicable, of the applicable annual incremental

24 goal shall use the unreduced applicable annual

25 incremental goal to set the value.

26 (ii) For the period through December 31, 2025,

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1 the calculation for determining achievement that

2 is less than 125% but more than 100% of the

3 applicable annual incremental goal shall use the

4 reduced applicable annual incremental goal to set

5 the value for 100% achievement of the goal and

6 shall use the unreduced goal to set the value for

7 125% achievement. The 8 basis point value shall

8 also be modified, as necessary, so that the 200

9 basis points are evenly apportioned among each

10 percentage point value between 100% and 125%

11 achievement.

12 (iii) For the period of January 1, 2026

13 through December 31, 2030, the calculation for

14 determining achievement that is less than 134% but

15 more than 100% of the applicable annual

16 incremental goal shall use the reduced applicable

17 annual incremental goal to set the value for 100%

18 achievement of the goal and shall use the

19 unreduced goal to set the value for 125%

20 achievement. The 6 basis point value shall also be

21 modified, as necessary, so that the 200 basis

22 points are evenly apportioned among each

23 percentage point value between 100% and 134%

24 achievement.

25 (8.5) Electric utilities that serve less than

26 3,000,000 retail customers but more than 500,000 retail

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1 customers in this State may identify, at the electric

2 utility's sole discretion, cost-effective measures that

3 educate about, incentivize, encourage, or otherwise

4 support the use of electricity to power, in whole or in

5 part, vehicles, including, but not limited to, cars,

6 trucks, buses, trains, trolleys, boats, on-road or

7 off-road vehicles, or other equipment or methods of

8 transporting goods or people. Such measures may include,

9 but are not limited to, measures that educate about,

10 incentivize, encourage, or otherwise support the adoption

11 of electric vehicles by retail customers of all rate

12 classes.

13 (9) The utility shall submit the energy savings data

14 to the independent evaluator no later than 30 days after

15 the close of the plan year. The independent evaluator

16 shall determine the cumulative persisting annual savings

17 for a given plan year no later than 120 days after the

18 close of the plan year. The utility shall submit an

19 informational filing to the Commission no later than 160

20 days after the close of the plan year that attaches the

21 independent evaluator's final report identifying the

22 cumulative persisting annual savings for the year and

23 calculates, under paragraph (7) or (8) of this subsection

24 (g), as applicable, any resulting change to the utility's

25 return on equity component of the weighted average cost of

26 capital applicable to the next plan year beginning with

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1 the January monthly billing period and extending through

2 the December monthly billing period. However, if the

3 utility recovers the costs incurred under this Section

4 under paragraphs (2) and (3) of subsection (d) of this

5 Section, then the utility shall not be required to submit

6 such informational filing, and shall instead submit the

7 information that would otherwise be included in the

8 informational filing as part of its filing under paragraph

9 (3) of such subsection (d) that is due on or before June 1

10 of each year.

11 For those utilities that must submit the informational

12 filing, the Commission may, on its own motion or by

13 petition, initiate an investigation of such filing,

14 provided, however, that the utility's proposed return on

15 equity calculation shall be deemed the final, approved

16 calculation on December 15 of the year in which it is filed

17 unless the Commission enters an order on or before

18 December 15, after notice and hearing, that modifies such

19 calculation consistent with this Section.

20 The adjustments to the return on equity component

21 described in paragraphs (7) and (8) of this subsection (g)

22 shall be applied as described in such paragraphs through a

23 separate tariff mechanism, which shall be filed by the

24 utility under subsections (f) and (g) of this Section.

25 (h) Other than measures authorized by subsection (n) of

26 this Section or identified pursuant to paragraph (8.5) of

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1 subsection (g) of this Section, no ~~No~~ more than 6% of energy

2 efficiency and demand-response program revenue may be

3 allocated for research, development, or pilot deployment of

4 new equipment or measures.

5 (i) When practicable, electric utilities shall incorporate

6 advanced metering infrastructure data into the planning,

7 implementation, and evaluation of energy efficiency measures

8 and programs, subject to the data privacy and confidentiality

9 protections of applicable law.

10 (j) The independent evaluator shall follow the guidelines

11 and use the savings set forth in Commission-approved energy

12 efficiency policy manuals and technical reference manuals, as

13 each may be updated from time to time. Until such time as

14 measure life values for energy efficiency measures implemented

15 for low-income households under subsection (c) of this Section

16 are incorporated into such Commission-approved manuals, the

17 low-income measures shall have the same measure life values

18 that are established for same measures implemented in

19 households that are not low-income households.

20 Commencing on the effective date of this amendatory Act of

21 the 102nd General Assembly, the following provisions shall

22 apply to electric utilities that serve less than 3,000,000

23 retail customers but more than 500,000 retail customers in

24 this State:

25 (1) Starting in the year in which this amendatory Act

26 of the 102nd General Assembly takes effect and continuing

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1 for a period of 5 calendar years thereafter, the savings

2 achieved by energy efficiency measures authorized by

3 subsection (n) of this Section or identified pursuant to

4 paragraph (8.5) of subsection (g) of this Section, shall

5 be evaluated using the following parameters:

6 (A) the evaluation shall use a factor of 1.50

7 pounds of carbon dioxide emitted per kilowatt hour of

8 electric energy used for vehicle operation, adjusted

9 each year starting with the year in which this

10 amendatory Act of the 102nd General Assembly takes

11 effect to reflect the annual increase of renewable

12 resource procurement as set forth in subsection (c) of

13 Section 1-75 of the Illinois Power Agency Act;

14 (B) the evaluation shall use a heat rate of fossil

15 fuel electric generating units of 7,939 Btu per

16 kilowatt hour, adjusted each year starting with the

17 year in which this amendatory Act of the 102nd General

18 Assembly takes effect to reflect the annual increase

19 of renewable resource procurement as set forth in

20 subsection (c) of Section 1-75 of the Illinois Power

21 Agency Act;

22 (C) the evaluation shall include any netting of

23 electricity used by the electric vehicle, as

24 calculated using the parameters provided for in

25 paragraph (2) of this subsection (j);

26 (D) the evaluation shall use a net to gross ratio

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1 of 1.0 for each measure evaluated; and

2 (E) all savings achieved by the measures evaluated

3 shall persist for the life of the measure, without

4 degradation.

5 (2) Starting in the year in which this amendatory Act

6 of the 102nd General Assembly takes effect and continuing

7 for a period of 5 calendar years thereafter, the savings

8 achieved by energy efficiency measures authorized by

9 subsection (n) of this Section or identified pursuant to

10 paragraph (8.5) of subsection (g) of this Section that are

11 applicable to passenger vehicles shall, in addition to the

12 parameters identified in paragraph (1) of this subsection

13 (j), be evaluated using the following parameters:

14 (A) the measure life of measures that incentivize

15 or otherwise encourage the purchase of electric

16 vehicles shall be 13 years from the date of original

17 purchase by the customer;

18 (B) the evaluation shall use a value of 11,500

19 vehicle miles traveled for annual vehicle operation;

20 (C) the evaluation shall use a fossil fuel vehicle

21 economy value equal to 28 miles per gallon of fossil

22 fuel used for vehicle operation;

23 (D) the evaluation shall use a conversion factor

24 of 120,429 Btus per gallon of fossil fuel used for

25 vehicle operation;

26 (E) the evaluation shall use a factor of 161

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1 pounds of carbon dioxide emitted per million Btu of

2 fossil fuel used for vehicle operation;

3 (F) the evaluation shall use a factor of 8.78

4 kilograms of carbon dioxide emitted per gallon of

5 fossil fuel used for vehicle operation;

6 (G) the evaluation shall use an annual value of

7 fossil fuel saved of 50 MMBtu; and

8 (H) the evaluation shall use an electric vehicle

9 efficiency value of 30 kilowatt hours per 100 miles

10 traveled for vehicle operation.

11 (3) Any additional evaluation criteria not identified

12 in paragraph (1) or (2) of this subsection (j) used to

13 evaluate savings achieved by energy efficiency measures

14 authorized by subsection (n) of this Section or identified

15 pursuant to paragraph (8.5) of subsection (g) of this

16 Section shall follow the guidelines and use the savings

17 set forth in Commission-approved energy efficiency policy

18 manuals and technical reference manuals, as each may be

19 updated from time to time.

20 (k) Notwithstanding any provision of law to the contrary,

21 an electric utility subject to the requirements of this

22 Section may file a tariff cancelling an automatic adjustment

23 clause tariff in effect under this Section or Section 8-103,

24 which shall take effect no later than one business day after

25 the date such tariff is filed. Thereafter, the utility shall

26 be authorized to defer and recover its expenditures incurred

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1 under this Section through a new tariff authorized under

2 subsection (d) of this Section or in the utility's next rate

3 case under Article IX or Section 16-108.5 of this Act, with

4 interest at an annual rate equal to the utility's weighted

5 average cost of capital as approved by the Commission in such

6 case. If the utility elects to file a new tariff under

7 subsection (d) of this Section, the utility may file the

8 tariff within 10 days after June 1, 2017 (the effective date of

9 Public Act 99-906), and the cost inputs to such tariff shall be

10 based on the projected costs to be incurred by the utility

11 during the calendar year in which the new tariff is filed and

12 that were not recovered under the tariff that was cancelled as

13 provided for in this subsection. Such costs shall include

14 those incurred or to be incurred by the utility under its

15 multi-year plan approved under subsections (f) and (g) of this

16 Section, including, but not limited to, projected capital

17 investment costs and projected regulatory asset balances with

18 correspondingly updated depreciation and amortization reserves

19 and expense. The Commission shall, after notice and hearing,

20 approve, or approve with modification, such tariff and cost

21 inputs no later than 75 days after the utility filed the

22 tariff, provided that such approval, or approval with

23 modification, shall be consistent with the provisions of this

24 Section to the extent they do not conflict with this

25 subsection (k). The tariff approved by the Commission shall

26 take effect no later than 5 days after the Commission enters

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1 its order approving the tariff.

2 No later than 60 days after the effective date of the

3 tariff cancelling the utility's automatic adjustment clause

4 tariff, the utility shall file a reconciliation that

5 reconciles the moneys collected under its automatic adjustment

6 clause tariff with the costs incurred during the period

7 beginning June 1, 2016 and ending on the date that the electric

8 utility's automatic adjustment clause tariff was cancelled. In

9 the event the reconciliation reflects an under-collection, the

10 utility shall recover the costs as specified in this

11 subsection (k). If the reconciliation reflects an

12 over-collection, the utility shall apply the amount of such

13 over-collection as a one-time credit to retail customers'

14 bills.

15 (l) For the calendar years covered by a multi-year plan

16 commencing after December 31, 2017, subsections (a) through

17 (j) of this Section do not apply to any retail customers of an

18 electric utility that serves more than 3,000,000 retail

19 customers in the State and whose total highest 30 minute

20 demand was more than 10,000 kilowatts, or any retail customers

21 of an electric utility that serves less than 3,000,000 retail

22 customers but more than 500,000 retail customers in the State

23 and whose total highest 15 minute demand was more than 10,000

24 kilowatts. For purposes of this subsection (l), "retail

25 customer" has the meaning set forth in Section 16-102 of this

26 Act. A determination of whether this subsection is applicable

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1 to a customer shall be made for each multi-year plan beginning

2 after December 31, 2017. The criteria for determining whether

3 this subsection (l) is applicable to a retail customer shall

4 be based on the 12 consecutive billing periods prior to the

5 start of the first year of each such multi-year plan.

6 (m) Notwithstanding the requirements of this Section, as

7 part of a proceeding to approve a multi-year plan under

8 subsections (f) and (g) of this Section, the Commission shall

9 reduce the amount of energy efficiency measures implemented

10 for any single year, and whose costs are recovered under

11 subsection (d) of this Section, by an amount necessary to

12 limit the estimated average net increase due to the cost of the

13 measures to no more than

14 (1) 3.5% for each of the 4 years beginning January 1,

15 2018,

16 (2) 3.75% for each of the 4 years beginning January 1,

17 2022, and

18 (3) 4% for each of the 5 years beginning January 1,

19 2026,

20 of the average amount paid per kilowatthour by residential

21 eligible retail customers during calendar year 2015. To

22 determine the total amount that may be spent by an electric

23 utility in any single year, the applicable percentage of the

24 average amount paid per kilowatthour shall be multiplied by

25 the total amount of energy delivered by such electric utility

26 in the calendar year 2015, adjusted to reflect the proportion

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1 of the utility's load attributable to customers who are exempt

2 from subsections (a) through (j) of this Section under

3 subsection (l) of this Section. For purposes of this

4 subsection (m), the amount paid per kilowatthour includes,

5 without limitation, estimated amounts paid for supply,

6 transmission, distribution, surcharges, and add-on taxes. For

7 purposes of this Section, "eligible retail customers" shall

8 have the meaning set forth in Section 16-111.5 of this Act.

9 Once the Commission has approved a plan under subsections (f)

10 and (g) of this Section, no subsequent rate impact

11 determinations shall be made.

12 (n) Starting on the effective date of this amendatory Act

13 of the 102nd General Assembly, electric utilities that serve

14 less than 3,000,000 retail customers but more than 500,000

15 retail customers in this State may administer programs and

16 implement cost-effective measures that educate about,

17 incentivize, encourage, or otherwise support the use of

18 electricity to power, in whole or in part, vehicles,

19 including, but not limited to, cars, trucks, buses, trains,

20 trolleys, boats, on-road or off-road vehicles, or other

21 equipment or methods of transporting goods or people. Such

22 programs and measures may be implemented as part of a plan

23 approved pursuant to subsection (f) of this Section and may

24 include, but are not limited to, measures that educate about,

25 incentivize, encourage, or otherwise support the adoption of

26 electric vehicles by retail customers of all customer classes.

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1 Programs and measures authorized by this subsection (n) and

2 identified pursuant to paragraph (8.5) of subsection (g) shall

3 not be prohibited by the Commission as promotional practices

4 under any rules or policies of the Commission, including, but

5 not limited to, 83 Ill. Adm. Code Part 275.

6 (Source: P.A. 100-840, eff. 8-13-18; 101-81, eff. 7-12-19.)

7 (220 ILCS 5/8-218 new)

8 Sec. 8-218. Electric photovoltaic generating facilities.

9 (a) The General Assembly finds and declares that the

10 citizens and businesses of the State of Illinois would be

11 well-served by the development of photovoltaic electricity

12 production facilities in this State, which would both bring

13 economic benefits and environmental benefits to the State and

14 further expand access to renewable energy resources at an

15 affordable cost to Illinois residents, particularly in those

16 areas of the State that have been significantly and adversely

17 affected by the retirement of coal-fired electric generating

18 plants. To that end, the General Assembly seeks to encourage

19 further development of photovoltaic electric production

20 facilities of all scales in an efficient and cost-effective

21 manner. Accordingly, the General Assembly finds that,

22 notwithstanding other provisions of this Act to the contrary,

23 it would be both prudent and reasonable for electric utilities

24 in this State to plan for, construct, install, control, own,

25 manage, or operate photovoltaic electricity production

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1 facilities pursuant to the provisions of this Section.

2 (b) An electric utility that serves less than 3,000,000

3 retail customers but more than 500,000 customers in this

4 State, may plan for, construct, install, control, own, manage,

5 or operate photovoltaic electricity production facilities and

6 any energy storage facilities as authorized under Section

7 16-108.20 of this Act that are planned for, constructed,

8 installed, controlled, owned, managed, or operated in

9 connection with photovoltaic electricity production facilities

10 authorized under this Section without obtaining a certificate

11 of public convenience and necessity pursuant to Section 8-406

12 of this Act, subject to the following terms and conditions:

13 (1) the electric utility may plan for, construct,

14 install, control, own, manage, or operate photovoltaic

15 electricity production facilities of any type or scale,

16 including, but not limited to, large scale (greater than 2

17 MW), small scale (less than or equal to 2 MW), and

18 community solar projects; for purposes of this Section,

19 "community solar projects" includes community solar

20 facilities with a nameplate capacity up to and including

21 10,000 kilowatts that are connected to either the

22 distribution system or transmission system of the electric

23 utility;

24 (2) photovoltaic electricity production facilities

25 authorized pursuant to this Section shall be deemed for

26 all purposes under this Act as prudent and used and

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1 useful, including under the provisions of Section 9-212 of

2 this Act, and, subject to the provisions set forth in this

3 Section, the Commission may not limit recovery of any

4 portion of the reasonable costs of the photovoltaic

5 electricity production facilities authorized pursuant to

6 this Section on the grounds that the facilities are not

7 prudent or used and useful;

8 (3) the electric utility's costs of planning for,

9 constructing, installing, controlling, owning, managing,

10 or operating the photovoltaic electricity production

11 facilities shall be recovered, on a kilowatt hour basis,

12 in the electric utility's rates for delivery service

13 established pursuant to Article XVI or Article IX of this

14 Act, and for purposes of cost recovery the photovoltaic

15 electricity production facilities, shall be treated as

16 distribution assets, provided: (1) the Commission shall

17 have the authority to determine the reasonableness of the

18 costs of the facilities, (2) any monetary value of power

19 and energy from the facilities shall be credited against

20 the delivery services revenue requirement, and (3) all

21 renewable energy credits associated with the photovoltaic

22 electricity production facilities shall be retired on

23 behalf of the electric utility's distribution customers

24 and may not be sold or used for any other purposes by the

25 electric utility other than satisfying the electric

26 utility's requirements under subsection (c) of Section

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1 1-75 of the Illinois Power Agency Act;

2 (4) the annual quantity of renewable energy credits

3 generated from the photovoltaic electricity production

4 facilities placed in service by an electric utility

5 pursuant to this Section after the effective date of this

6 amendatory Act of the 102nd General Assembly shall not

7 exceed 20% of the electric utility's requirements under

8 subsection (c) of Section 1-75 of the Illinois Power

9 Agency Act; and

10 (5) the electric utility shall certify that not less

11 than the prevailing wage, as determined pursuant to the

12 Prevailing Wage Act, was or will be paid to employees who

13 are engaged in construction activities associated with the

14 photovoltaic electric production facilities authorized

15 under this Section.

16 If an electric utility requires approval under Section

17 7-101 or 7-102 of this Act in connection with the

18 construction, installation, control, ownership, management, or

19 operation of photovoltaic electricity production facilities

20 pursuant to this Section, the Commission shall issue its Order

21 granting or denying such approval within 150 days after a

22 petition for such approval is filed.

23 For purposes of this Section, "electric utility" has the

24 meaning set forth in Section 16-102 of this Act.

25 (c) Notwithstanding anything to the contrary in the

26 Illinois Power Agency Act or this Act, the Illinois Power

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1 Agency shall apply any renewable energy credits associated

2 with photovoltaic electricity production facilities meeting

3 the criteria set forth in subsection (b) of this Section to the

4 electric utility's requirements under subsection (c) of

5 Section 1-75 of the Illinois Power Agency Act. No cost

6 associated with facilities placed in service pursuant to this

7 Section shall be included when calculating the limitation

8 under subparagraph (E) of paragraph (1) of subsection (c) of

9 Section 1-75 of the Illinois Power Agency Act.

10 (220 ILCS 5/9-244.5 new)

11 Sec. 9-244.5. Natural gas investment and modernization;

12 regulatory reform.

13 (a) The General Assembly finds that regulatory reform

14 measures that increase predictability, stability, and

15 transparency in the ratemaking process are needed to promote

16 prudent, long-term infrastructure investment and to mutually

17 benefit the State's natural gas utilities and their customers,

18 regulators, and investors.

19 (b) For purposes of this Section, "participating gas

20 utility" means a public utility that, as of January 1, 2020,

21 provided electric service to at least 1,000,000 retail

22 customers in Illinois and gas service to at least 500,000

23 retail customers in Illinois.

24 (c) A participating gas utility may elect to recover its

25 natural gas delivery services costs through a

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1 performance-based rate, which shall be approved by the

2 Commission and which shall specify the cost components that

3 form the basis of the rate charged to customers with

4 sufficient specificity to operate in a standardized manner and

5 be updated annually with transparent information that reflects

6 the participating gas utility's actual costs to be recovered

7 during the applicable year, which is the period beginning with

8 the first billing day of January and extending through the

9 last billing day of the following December. In the event the

10 participating gas utility recovers a portion of its costs

11 through automatic adjustment clause tariffs on the effective

12 date of the Act, other than a surcharge tariff under paragraph

13 (3) of subsection (a) of Section 9-220.3, the participating

14 gas utility may elect to continue to recover these costs

15 through such tariffs, but such costs shall not be recovered

16 through the performance based rate as long as the

17 participating gas utility elects to recover such costs through

18 such automatic adjustment clause tariffs.

19 The performance-based rate shall be implemented through a

20 tariff filed with the Commission consistent with the

21 provisions of this subsection (c) that shall be applicable to

22 all natural gas delivery services customers. The Commission

23 shall initiate and conduct an investigation of the tariff in a

24 manner consistent with the provisions of this subsection (c)

25 and the provisions of Article IX of this Act to the extent they

26 do not conflict with this subsection (c). The

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1 performance-based rate shall remain in effect at the

2 discretion of the participating gas utility.

3 The performance-based rate approved by the Commission

4 shall do the following:

5 (1) Provide for the recovery of the participating gas

6 utility's actual costs of natural gas delivery services

7 that are prudently incurred and reasonable in amount

8 consistent with Commission practice and law. The sole fact

9 that a cost differs from that incurred in a prior calendar

10 year or that an investment is different from that made in a

11 prior calendar year shall not imply the imprudence or

12 unreasonableness of that cost or investment.

13 (2) Reflect the utility's actual year-end capital

14 structure for the applicable calendar year, excluding

15 goodwill, subject to a determination of prudence and

16 reasonableness consistent with Commission practice and

17 law. To enable the financing of the incremental capital

18 expenditures, including regulatory assets, a participating

19 gas utility's actual year-end capital structure that

20 includes a common equity ratio, excluding goodwill, of up

21 to and including 54% of the total capital structure shall

22 be deemed reasonable and used to set rates.

23 (3) Include a cost of equity equal to the national

24 average cost of equity. For purposes of this paragraph (3)

25 of this subsection (c), the national average cost of

26 equity applicable to a calendar year shall be the simple

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1 average of the cost of equity specified and approved in

2 each order of a state regulatory commission, other than

3 the Commission, issued during such calendar year that is

4 applicable to base rates for retail natural gas delivery

5 service provided by an investor-owned public utility

6 company operating in the United States. No order shall be

7 excluded from the national average cost of equity

8 calculated under this paragraph (3) on the grounds that it

9 was arrived at by stipulation or agreement or is subject

10 to rehearing or appeal. If, for any calendar year, there

11 are fewer than 15 applicable orders of state regulatory

12 commissions with which to compute the average cost of

13 equity, the Commission shall include in the calculation of

14 the national average the number of state regulatory orders

15 from the year or years immediately preceding such calendar

16 year necessary to reach a total of 15, beginning with the

17 most recently issued and proceeding in reverse

18 chronological order.

19 (4) Permit and set forth protocols, subject to a

20 determination of prudence and reasonableness consistent

21 with Commission practice and law, for the following:

22 (A) irrespective of the form of award, recovery of

23 expense of incentive compensation that is awarded

24 based on non-financial criteria such as the

25 achievement of operational metrics, including metrics

26 related to budget controls, safety, customer service,

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1 efficiency and productivity, and environmental

2 compliance. The expense of incentive compensation

3 expense that is awarded based on net income or an

4 affiliate's earnings per share shall not be

5 recoverable under the performance-based rate;

6 (B) recovery of pension and other post-employment

7 benefits expense, provided that such costs are

8 supported by an actuarial study;

9 (C) recovery of severance costs, provided that if

10 the amount is over $2,500,000, then the full amount

11 shall be amortized consistent with subparagraph (F) of

12 this paragraph (4);

13 (D) investment return at a rate equal to the

14 participating gas utility's weighted average cost of

15 long-term debt on the pension assets as, and in the

16 amount, reported in Account 182.3 and 186 (or in such

17 other Account or Accounts as such asset may

18 subsequently be recorded) of the utility's most

19 recently filed ICC Form 21, FERC Form 1, or FERC Form

20 2, as applicable, net of deferred tax benefits;

21 (E) recovery of the expenses related to the

22 Commission proceeding under this subsection (c) to

23 approve this performance-based rate and initial rates

24 or to subsequent proceedings related to the formula,

25 provided that the recovery shall be amortized over a

26 3-year period; recovery of expenses related to the

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1 annual Commission proceedings under subsection (e) of

2 this Section to review the inputs to the

3 performance-based rate shall be expensed and recovered

4 through the performance-based rate;

5 (F) amortization over a 5-year period of the full

6 amount of each charge or credit that exceeds the

7 amount specified in subparagraph (C) of this paragraph

8 (4) and that relates to a workforce reduction

9 program's severance costs, changes in accounting

10 rules, changes in law, compliance with any

11 Commission-initiated audit, or other extraordinary

12 expense, provided that any unamortized balance shall

13 be reflected in rate base. For purposes of this

14 subparagraph (F), changes in law include any

15 enactment, repeal, or amendment in a law, ordinance,

16 rule, regulation, interpretation, permit, license,

17 consent, or order, including those relating to taxes,

18 accounting, or to environmental matters, or in the

19 interpretation or application thereof by any

20 governmental authority occurring after the effective

21 date of the Act;

22 (G) recovery of existing regulatory assets over

23 the periods previously authorized by the Commission;

24 (H) historical weather normalized billing

25 determinants; and

26 (I) allocation methods for common costs.

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1 (5) Provide that if the participating gas utility's

2 earned rate of return on common equity related to the

3 provision of natural gas delivery services for the prior

4 rate year (calculated using costs and capital structure

5 approved by the Commission as provided in subparagraphs

6 (2) and (3) of this subsection (c), consistent with this

7 Section, in accordance with Commission rules and orders,

8 including, but not limited to, adjustments for goodwill,

9 and after any Commission-ordered disallowances and taxes)

10 is higher than the rate of return on common equity

11 calculated pursuant to paragraph (3) of this subsection

12 (c) (after any adjustments to the rate of return on common

13 equity applied pursuant to the performance metrics

14 provision of subsection (g) or (h) of this Section, as

15 applicable), then the participating gas utility shall

16 apply a credit through the performance-based rate that

17 reflects an amount equal to the value of that portion of

18 the earned rate of return on common equity that is higher

19 than the rate of return on common equity calculated

20 pursuant to paragraph (3) of this subsection (c) (after

21 any adjustments to the rate of return on common equity

22 applied pursuant to the performance metrics provision of

23 subsection (g) or (h) of this Section, as applicable) for

24 the prior rate year, adjusted for taxes. If the

25 participating gas utility's earned rate of return on

26 common equity related to the provision of natural gas

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1 delivery services for the prior rate year (calculated

2 using costs and capital structure approved by the

3 Commission as provided in paragraphs (2) and (3) of this

4 subsection (c), consistent with this Section, in

5 accordance with Commission rules and orders, including,

6 but not limited to, adjustments for goodwill, and after

7 any Commission-ordered disallowances and taxes) is less

8 than the return on common equity calculated pursuant to

9 paragraph (3) of this subsection (c) (after any

10 adjustments to the rate of return on common equity applied

11 pursuant to the performance metrics provision of

12 subsections (g) or (h) of this Section, as applicable),

13 then the participating gas utility shall apply a charge

14 through the performance-based rate that reflects an amount

15 equal to the value of that portion of the earned rate of

16 return on common equity that is less than the rate of

17 return on common equity calculated pursuant to paragraph

18 (3) of this subsection (c) (after any adjustments to the

19 rate of return on common equity applied pursuant to the

20 performance metrics provision of subsections (g) or (h) of

21 this Section, as applicable) for the prior rate year,

22 adjusted for taxes.

23 (6) Provide for annual reconciliations, as described

24 in subsection (e) of this Section, with interest, of the

25 revenue requirement reflected in rates for each calendar

26 year, beginning with the calendar year in which the

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1 participating gas utility files its performance-based rate

2 tariff pursuant to subsection (c) of this Section, with

3 what the revenue requirement would have been had the

4 actual cost information for the applicable calendar year

5 been available at the filing date.

6 (7) Any surcharge tariff of a participating gas

7 utility authorized by paragraph (3) of subsection (a) of

8 Section 9-220.3 of the Act that is in effect as of the

9 effective date of the performance-based rate tariff

10 approved by the Commission for that utility pursuant to

11 the provisions of this Section will be suspended by

12 operation of law as of the effective date of that

13 performance-based rate tariff. Notwithstanding anything in

14 paragraph (4) of subsection (a) and paragraph (2) of

15 subsection (e) of Section 9-220.3, a participating gas

16 utility shall not file a petition to initiate a final

17 reconciliation of amounts collected under such a surcharge

18 tariff on account of qualifying infrastructure investment

19 (as that term is defined in Section 9-220.3(b)) that

20 occurred during any calendar year for which a

21 reconciliation will be made under subsection (c), and no

22 adjustment to the participating gas utility's initial

23 rates as calculated under paragraph (1) of subsection (c)

24 shall be made based on the fact that the utility had such a

25 tariff in effect or recovered any portion of its revenue

26 requirement through such a tariff.

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1 The participating gas utility shall file, together with

2 its tariff, final data based on its most recently filed ICC

3 Form 21, FERC Form 1, or FERC Form 2, as applicable, subject to

4 the adjustments specified in subsection (c), plus projected

5 plant additions and correspondingly updated depreciation

6 reserve and expense for the calendar year in which the tariff

7 and data are filed, that shall populate the performance-based

8 rate and set the initial gas delivery services rates under the

9 formula. For purposes of this Section, "ICC Form 21" means the

10 "Annual Report of Electric Utilities and/or Natural Gas

11 Utilities" or any successor to that report that natural gas

12 utilities are required to file with the Commission under

13 Section 5-109 of this Act. Nothing in this Section is intended

14 to allow costs that are not otherwise recoverable to be

15 recoverable by virtue of inclusion in ICC Form 21, FERC Form 1,

16 or FERC Form 2.

17 After the participating gas utility files its proposed

18 performance-based rate structure and protocols and initial

19 rates, the Commission shall initiate a docket to review the

20 filing. The Commission shall enter an order approving, or

21 approving as modified, the performance-based rate, including

22 the initial rates, as just and reasonable within 270 days

23 after the date on which the tariff was filed. Such review shall

24 be based on the same evidentiary standards, including, but not

25 limited to, those concerning the prudence and reasonableness

26 of the costs incurred by the utility, the Commission applies

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1 in a hearing to review a filing for a general increase in rates

2 under Article IX of this Act. The initial rates shall take

3 effect within 30 days after the Commission's order approving

4 the performance-based rate tariff.

5 Until the Commission approves a different rate design and

6 cost allocation pursuant to subsection (f) of this Section,

7 rate design and cost allocation across customer classes shall

8 be consistent with the Commission's most recent order

9 regarding the participating gas utility's request for a

10 general increase in its delivery services rates.

11 Subsequent changes to the performance-based rate structure

12 or protocols shall be made as set forth in Section 9-201 of

13 this Act, but nothing in this subsection (c) is intended to

14 limit the Commission's authority under Article IX and other

15 provisions of this Act to initiate an investigation of a

16 participating gas utility's performance-based rate tariff,

17 provided that any such changes shall be consistent with

18 paragraphs (1) through (7) of this subsection (c). Any change

19 ordered by the Commission shall be made at the same time new

20 rates take effect following the Commission's next order

21 pursuant to subsection (e) of this Section, provided that the

22 new rates take effect no less than 30 days after the date on

23 which the Commission issues an order adopting the change.

24 In the event the performance-based rate is terminated, the

25 then current rates shall remain in effect until such time as

26 new rates are set pursuant to Article IX of this Act, subject

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1 to retroactive rate adjustment, with interest, to reconcile

2 rates charged with actual costs.

3 (d) Beginning in the first calendar year following the

4 year in which this reporting requirement becomes effective, a

5 participating gas utility shall, within 45 days after the

6 close of each of the participating gas utility's fiscal

7 quarters, submit to the Commission a report that summarizes

8 the additions to utility plant that were placed into service

9 during the prior quarter, which for purposes of the report

10 shall be the most recently closed fiscal quarter, as well as

11 what utility plant the participating gas utility projects will

12 place into service through the end of the calendar year in

13 which the report is filed. The quarterly report provided will

14 be used for informational purposes only, and any estimates

15 therein shall not bind or limit the participating gas

16 utility's future decisions to invest in any utility plant or

17 other projects and may not be used in any Commission

18 proceeding to support any finding as to imprudence,

19 unreasonableness, or lack of use or usefulness of any

20 individual or aggregate level of utility plant or other

21 investment. Within 7 days of receiving a quarterly report, the

22 Commission shall make such report available to the public.

23 Each quarterly report shall include the following detail:

24 (1) the total dollar value of the additions to utility

25 plant placed in service during the prior quarter;

26 (2) a list of standing work orders for utility plant

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1 placed in service during the prior quarter, including the

2 total dollar amount for the work reflected in each

3 standing work order as of the last day of the quarterly

4 reporting period, and a summary description of the

5 standing work order;

6 (3) a list of specific work orders for utility plant

7 placed in service during the prior quarter for utility

8 plant placed in service with a total dollar value as of the

9 last day of the quarterly reporting period that is equal

10 to or greater than $500,000, inclusive of the dollar

11 amount reflected in each specific work order, and a

12 summary description of the specific work order;

13 (4) the estimated total dollar value of the additions

14 to utility plant projected to be placed in service through

15 the end of the calendar year in which the report is filed;

16 (5) a list of standing work orders for utility plant

17 projected to be placed in service through the end of the

18 calendar year in which the report is filed, including the

19 estimated dollar amount for the work reflected in each

20 standing work order, and a summary description of the

21 standing work order; and

22 (6) a list of specific work orders for utility plant

23 projected to be placed in service through the end of the

24 calendar year in which the report is filed with an

25 estimated dollar value that is equal to or greater than

26 $500,000, inclusive of the estimated dollar amount for the

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1 work reflected in each specific work order, and a summary

2 description of the specific work order.

3 (e) Subsequent to the Commission's issuance of an order

4 approving the participating gas utility's performance-based

5 rate structure and protocols, and initial rates under

6 subsection (c) of this Section, the utility shall file, on or

7 before May 1 of each year, with the Chief Clerk of the

8 Commission its updated cost inputs to the performance-based

9 rate for the applicable rate year and the corresponding new

10 charges. Each such filing shall conform to the following

11 requirements and include the following information:

12 (1) The inputs to the performance-based rate for the

13 applicable rate year shall be based on final historical

14 data reflected in the participating gas utility's most

15 recently filed annual ICC Form 21, or FERC Form 1, or FERC

16 Form 2, as applicable, subject to adjustments specified in

17 subsection (c) of this Section, plus projected plant

18 additions and correspondingly updated depreciation reserve

19 and expense for the calendar year in which the inputs are

20 filed. The filing shall also include a reconciliation of

21 the revenue requirement that was in effect for the prior

22 rate year (as set by the cost inputs for the prior rate

23 year) with the actual revenue requirement for the prior

24 rate year (determined using a year-end rate base) that

25 uses amounts reflected in the applicable ICC Form 21, FERC

26 Form 1, or FERC Form 2, that reports the actual costs for

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1 the prior rate year. Any over-collection or

2 under-collection indicated by such reconciliation shall be

3 reflected as a credit against, or recovered as an

4 additional charge to, respectively, with interest

5 calculated at a rate equal to the participating gas

6 utility's weighted average cost of capital approved by the

7 Commission for the prior rate year, the charges for the

8 applicable rate year. Provided, however, that the first

9 such reconciliation shall be for the calendar year in

10 which the participating gas utility files its

11 performance-based rate tariff pursuant to subsection (c)

12 of this Section and shall reconcile (i) the revenue

13 requirement or revenue requirements established by the

14 rate order or rate orders in effect from time to time

15 during such calendar year (weighted, as applicable),

16 including any surcharge tariff authorized for the

17 participating gas utility pursuant to paragraph (3) of

18 subsection (a) of Section 9-220.3 of the Act with (ii) the

19 revenue requirement determined using a year-end rate base

20 for that calendar year calculated pursuant to the

21 performance-based rate using actual costs for that year as

22 reflected in the applicable ICC Form 21, FERC Form 1, or

23 FERC Form 2, as applicable, subject to adjustments

24 specified in subsection (c) of this Section. The first

25 such reconciliation is not intended to provide for the

26 recovery of costs previously excluded from rates based on

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1 a prior Commission order finding of imprudence or

2 unreasonableness. Each reconciliation shall be certified

3 by the participating gas utility in the same manner that

4 ICC Form 21 is certified. The filing shall also include

5 the charge or credit, if any, resulting from the

6 calculation required by paragraph (6) of subsection (c) of

7 this Section.

8 Notwithstanding anything that may be to the contrary,

9 the intent of the reconciliations is to ultimately

10 reconcile the revenue requirement reflected in rates for

11 such calendar year, beginning with the calendar year in

12 which the participating gas utility files its

13 performance-based rate tariff pursuant to subsection (c)

14 of this Section, with what the revenue requirement

15 determined using a year-end rate base for the applicable

16 calendar year would have been had actual cost information

17 for the applicable calendar year been available at the

18 filing date.

19 (2) The new charges shall take effect beginning on the

20 first billing day of the following January billing period

21 and remain in effect through the last billing day of the

22 next December billing period regardless of whether the

23 Commission enters upon a hearing pursuant to this

24 subsection (e).

25 (3) The filing shall include relevant and necessary

26 data and documentation for the applicable rate year that

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1 is consistent with the Commission's rules applicable to a

2 filing for a general increase in rates or any rules

3 adopted by the Commission to implement this Section.

4 Normalization adjustments shall not be required.

5 Notwithstanding any other provision of this Section or Act

6 or any rule or other requirement adopted by the

7 Commission, a participating gas utility with more than one

8 rate zone shall not be required to file a separate set of

9 such data and documentation for each rate zone and may

10 combine such data and documentation into a single set of

11 schedules.

12 Within 45 days after the participating gas utility files

13 its annual update of cost inputs to the performance-based

14 rate, the Commission shall have the authority, either upon

15 complaint or its own initiative, but with reasonable notice,

16 to enter upon a hearing concerning the prudence and

17 reasonableness of the costs incurred by the participating gas

18 utility to be recovered during the applicable rate year that

19 are reflected in the inputs to the performance-based rate

20 derived from the participating gas utility's ICC Form 21, FERC

21 Form 1, or FERC Form 2. During the course of the hearing, each

22 objection shall be stated with particularity and evidence

23 provided in support thereof, after which the utility shall

24 have the opportunity to rebut the evidence. Discovery shall be

25 allowed consistent with the Commission's Rules of Practice,

26 which Rules shall be enforced by the Commission or the

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1 assigned administrative law judge. The Commission shall apply

2 the same evidentiary standards, including, but not limited to,

3 those concerning the prudence and reasonableness of the costs

4 incurred by the participating gas utility, in the hearing as

5 it would apply in a hearing to review a filing for a general

6 increase in rates under Article IX of this Act. The Commission

7 shall not, however, have the authority in a proceeding under

8 this subsection (e) to consider or order any changes to the

9 structure or protocols of the performance-based rate approved

10 pursuant to subsection (c) of this Section. In a proceeding

11 under this subsection (e), the Commission shall enter its

12 order no later than the earlier of 240 days after the utility's

13 filing of its annual update of cost inputs to the

14 performance-based rate or December 31. The Commission's

15 determinations of the prudence and reasonableness of the costs

16 incurred for the applicable calendar year shall be final upon

17 entry of the Commission's order and shall not be subject to

18 reopening, reexamination, or collateral attack in any other

19 Commission proceeding, case, docket, order, rule, or

20 regulation, provided, however, that nothing in this subsection

21 (e) shall prohibit a party from petitioning the Commission to

22 rehear or appeal to the courts the order pursuant to the

23 provisions of this Act.

24 In the event the Commission does not, either upon

25 complaint or its own initiative, enter upon a hearing within

26 45 days after the participating gas utility files the annual

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1 update of cost inputs to its performance-based rate, then the

2 costs incurred for the applicable calendar year shall be

3 deemed prudent and reasonable, and the filed charges shall not

4 be subject to reopening, reexamination, or collateral attack

5 in any other proceeding, case, docket, order, rule, or

6 regulation.

7 A participating gas utility's first filing of the updated

8 cost inputs, and any Commission investigation of such inputs

9 pursuant to this subsection (e) shall proceed notwithstanding

10 the fact that the Commission's investigation under subsection

11 (c) of this Section is still pending and notwithstanding any

12 other law, order, rule, or Commission practice to the

13 contrary.

14 (f) Nothing in subsections (c) or (e) of this Section

15 shall prohibit the Commission from investigating, or a

16 participating gas utility from filing, revenue-neutral tariff

17 changes related to rate design of a performance-based rate

18 that has been placed into effect for the utility. Following

19 approval of a participating gas utility's performance-based

20 rate tariff pursuant to subsection (c) of this Section, the

21 utility shall make a filing with the Commission within one

22 year after the effective date of the performance-based rate

23 tariff that proposes changes to the tariff to incorporate the

24 findings of any final rate design orders of the Commission

25 applicable to the participating gas utility and entered

26 subsequent to the Commission's approval of the tariff. The

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1 Commission shall, after notice and hearing, enter its order

2 approving, or approving with modification, the proposed

3 changes to the performance-based rate tariff within 240 days

4 after the utility's filing. Following such approval, the

5 utility shall make a filing with the Commission during each

6 subsequent 3-year period that either proposes revenue-neutral

7 tariff changes or re-files the existing tariffs without

8 change, which shall present the Commission with an opportunity

9 to suspend the tariffs and consider revenue-neutral tariff

10 changes related to rate design.

11 (g) Within 30 days after the filing of a tariff pursuant to

12 subsection (c) of this Section, each participating gas utility

13 shall develop and file with the Commission multi-year metrics.

14 For each participating gas utility, the following metrics

15 shall be designed to achieve, ratably (in equal annual

16 segments, unless otherwise specified) over a 10-year period,

17 improvement over baseline performance values as follows:

18 (1) System Integrity, Reliability, and Pipeline Safety

19 Improvement (under 49 CFR Part 192): Reduce the number of

20 outstanding, underground gas leaks on a participating gas

21 utility's gas system by 50% resulting in reduced methane

22 emissions into the environment, using a baseline of year

23 end 2020.

24 (2) System Integrity, Reliability, and Pipeline Safety

25 Improvement (under 49 CFR Part 192): Reduce the number of

26 outstanding above-ground gas leaks on a participating gas

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1 utility's gas system by 50% resulting in reduced methane

2 emissions into the environment, using a baseline of year

3 end 2020.

4 (3) System Integrity, Reliability and Pipeline Safety

5 Improvement: Reduce the known quantity of gas transmission

6 pipeline facilities (including mains and associated

7 facilities) that do not have complete records to support

8 the maximum allowable operating pressures in accordance

9 with Federal Department of Transportation pipeline safety

10 regulations by 50% using a baseline of year end 2020.

11 (4) System Integrity, Reliability, and Pipeline Safety

12 Improvement: Reduce the known quantity of mechanically

13 coupled steel gas distribution pipeline facilities

14 (including mains, services, and associated facilities)

15 that are prone to leakage by 70% using a baseline of year

16 end 2020.

17 (5) Opportunities for minority-owned, woman-owned, and

18 veteran-owned business enterprises: design a performance

19 metric regarding the creation of opportunities for

20 minority-owned, woman-owned and veteran-owned business

21 enterprises consistent with State and federal law using a

22 base performance value of the percentage of the

23 participating gas utility's capital expenditures that were

24 paid to minority-owned, woman-owned and veteran-owned

25 business enterprises in the years 2018, 2019 and 2020.

26 The metrics shall include incremental performance goals

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1 for each year of the 10-year period, which shall be designed to

2 demonstrate that the participating gas utility is on track to

3 achieve the performance goal in each category at the end of the

4 10-year period. The participating gas utility shall elect when

5 the 10-year period shall commence for the metrics set forth in

6 this subsection (g), provided that it begins no later than 14

7 months following the date on which the participating gas

8 utility files a tariff pursuant to subsection (c).

9 (h) The financial adjustments applicable to the metrics

10 described in subparagraphs (1) through (4) of subsection (g),

11 as applicable, shall be applied through an adjustment to the

12 participating gas utility's return on equity of no more than a

13 total of 40 basis points in any year, as follows:

14 (1) With respect to the incremental annual performance

15 goal established pursuant to subparagraph (1) of

16 subsection (g), for each year that a participating gas

17 utility does not achieve at least 95% of such goal, the

18 participating gas utility's return on equity shall be

19 reduced by 10 basis points; and for each year in which the

20 participating utility achieves 105% or more of such goal,

21 the participating gas utility's return on equity shall be

22 increased by 10 basis points.

23 (2) With respect to the incremental annual performance

24 goal established pursuant to subparagraph (2) of

25 subsection (g), for each year that a participating gas

26 utility does not achieve at least 95% of such goal, the

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1 participating gas utility's return on equity shall be

2 reduced by 10 basis points; and for each year that a

3 participating gas utility achieves 105% or more of such

4 goal, the participating gas utility's return on equity

5 shall be increased by 10 basis points.

6 (3) With respect to the incremental annual performance

7 goal established pursuant to subparagraph (3) of

8 subsection (g), for each year that a participating gas

9 utility does not achieve at least 95% of such goal, the

10 participating gas utility's return on equity shall be

11 reduced by 10 basis points; and for each year that a

12 participating gas utility achieves 105% or more of such

13 goal, the participating gas utility's return on equity

14 shall be increased by 10 basis points.

15 (4) With respect to the incremental annual performance

16 goals established pursuant to subparagraph (4) of

17 subsection (g), for each year that a participating gas

18 utility does not achieve at least 95% of such goal, the

19 participating gas utility's return on equity shall be

20 reduced by 10 basis points; and for each year that a

21 participating gas utility achieves 105% or more of such

22 goal, the participating gas utility's return on equity

23 shall be increased by 10 basis points.

24 (i) The financial adjustments shall be applied as

25 described in subsection (h), as applicable, for the 12-month

26 period in which they accrued through a separate tariff

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1 mechanism, which shall be filed by the participating gas

2 utility together with its metrics. In the event the

3 performance-based formula rate tariff established pursuant to

4 subsection (c) of this Section terminates, the participating

5 gas utility's obligations under subsection (g), as applicable,

6 and subsection (h), as applicable, of this Section and this

7 subsection (i) shall also terminate; provided, however, that

8 the tariff mechanism established pursuant to subsection (g) of

9 this Section and subsection (h), as applicable, and this

10 subsection (i) shall remain in effect until the remaining

11 balance of any financial adjustments at the time of such

12 termination is fully amortized.

13 The Commission shall, after notice and hearing, enter an

14 order within 120 days after the metrics are filed approving,

15 or approving with modification, a participating gas utility's

16 tariff or mechanism to satisfy the metrics set forth in

17 subsection (g), as applicable, of this Section and subsection

18 (h), as applicable, of this Section. On June 1 of each

19 subsequent year, each participating gas utility shall file a

20 report with the Commission that includes, among other things,

21 a description of how the participating gas utility performed

22 under each metric and an identification of any extraordinary

23 events that adversely impacted the participating gas utility's

24 performance. Whenever a participating gas utility's report on

25 its performance shows that a financial adjustment is warranted

26 under subsection (h) of this Section, the Commission shall,

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1 after notice and hearing, enter an order approving any

2 financial adjustments in accordance with subsection (h) of

3 this Section. The Commission-approved financial adjustments

4 shall be applied beginning with the next rate year.

5 (j) This Section, other than this subsection (j), is

6 inoperative after December 31, 2032, for every participating

7 gas utility, after which time a participating gas utility

8 shall no longer be eligible to annually update the

9 performance-based rate tariff pursuant to subsection (e) of

10 this Section. At such time, the then current rates shall

11 remain in effect until such time as new rates are set pursuant

12 to Article IX of this Act, subject to retroactive adjustment,

13 with interest, to reconcile rates charged with actual costs.

14 The fact that this Section becomes inoperative as set

15 forth in this subsection shall not be construed to mean that

16 the Commission may reexamine or otherwise reopen prudence or

17 reasonableness determinations already made.

18 (220 ILCS 5/16-102)

19 Sec. 16-102. Definitions. For the purposes of this Article

20 the following terms shall be defined as set forth in this

21 Section.

22 "Alternative retail electric supplier" means every person,

23 cooperative, corporation, municipal corporation, company,

24 association, joint stock company or association, firm,

25 partnership, individual, or other entity, their lessees,

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1 trustees, or receivers appointed by any court whatsoever, that

2 offers electric power or energy for sale, lease or in exchange

3 for other value received to one or more retail customers, or

4 that engages in the delivery or furnishing of electric power

5 or energy to such retail customers, and shall include, without

6 limitation, resellers, aggregators and power marketers, but

7 shall not include (i) electric utilities (or any agent of the

8 electric utility to the extent the electric utility provides

9 tariffed services to retail customers through that agent),

10 (ii) any electric cooperative or municipal system as defined

11 in Section 17-100 to the extent that the electric cooperative

12 or municipal system is serving retail customers within any

13 area in which it is or would be entitled to provide service

14 under the law in effect immediately prior to the effective

15 date of this amendatory Act of 1997, (iii) a public utility

16 that is owned and operated by any public institution of higher

17 education of this State, or a public utility that is owned by

18 such public institution of higher education and operated by

19 any of its lessees or operating agents, within any area in

20 which it is or would be entitled to provide service under the

21 law in effect immediately prior to the effective date of this

22 amendatory Act of 1997, (iv) a retail customer to the extent

23 that customer obtains its electric power and energy from that

24 customer's own cogeneration or self-generation facilities, (v)

25 an entity that owns, operates, sells, or arranges for the

26 installation of a customer's own cogeneration or

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1 self-generation facilities, but only to the extent the entity

2 is engaged in owning, selling or arranging for the

3 installation of such facility, or operating the facility on

4 behalf of such customer, provided however that any such third

5 party owner or operator of a facility built after January 1,

6 1999, complies with the labor provisions of Section 16-128(a)

7 as though such third party were an alternative retail electric

8 supplier, or (vi) an industrial or manufacturing customer that

9 owns its own distribution facilities, to the extent that the

10 customer provides service from that distribution system to a

11 third-party contractor located on the customer's premises that

12 is integrally and predominantly engaged in the customer's

13 industrial or manufacturing process; provided, that if the

14 industrial or manufacturing customer has elected delivery

15 services, the customer shall pay transition charges applicable

16 to the electric power and energy consumed by the third-party

17 contractor unless such charges are otherwise paid by the third

18 party contractor, which shall be calculated based on the usage

19 of, and the base rates or the contract rates applicable to, the

20 third-party contractor in accordance with Section 16-102.

21 An entity that furnishes the service of charging electric

22 vehicles does not and shall not be deemed to sell electricity

23 and is not and shall not be deemed an alternative retail

24 electric supplier, and is not subject to regulation as such

25 under this Act notwithstanding the basis on which the service

26 is provided or billed. If, however, the entity is otherwise

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1 deemed an alternative retail electric supplier under this Act,

2 or is otherwise subject to regulation under this Act, then

3 that entity is not exempt from and remains subject to the

4 otherwise applicable provisions of this Act. The installation,

5 maintenance, and repair of an electric vehicle charging

6 station shall comply with the requirements of subsection (a)

7 of Section 16-128 and Section 16-128A of this Act.

8 ~~For purposes of this Section, the term "electric vehicles"~~

9 ~~has the meaning ascribed to that term in Section 10 of the~~

10 ~~Electric Vehicle Act.~~

11 "Base rates" means the rates for those tariffed services

12 that the electric utility is required to offer pursuant to

13 subsection (a) of Section 16-103 and that were identified in a

14 rate order for collection of the electric utility's base rate

15 revenue requirement, excluding (i) separate automatic rate

16 adjustment riders then in effect, (ii) special or negotiated

17 contract rates, (iii) delivery services tariffs filed pursuant

18 to Section 16-108, (iv) real-time pricing, or (v) tariffs that

19 were in effect prior to October 1, 1996 and that based charges

20 for services on an index or average of other utilities'

21 charges, but including (vi) any subsequent redesign of such

22 rates for tariffed services that is authorized by the

23 Commission after notice and hearing.

24 "Competitive service" includes (i) any service that has

25 been declared to be competitive pursuant to Section 16-113 of

26 this Act, (ii) contract service, and (iii) services, other

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1 than tariffed services, that are related to, but not necessary

2 for, the provision of electric power and energy or delivery

3 services.

4 "Contract service" means (1) services, including the

5 provision of electric power and energy or other services, that

6 are provided by mutual agreement between an electric utility

7 and a retail customer that is located in the electric

8 utility's service area, provided that, delivery services shall

9 not be a contract service until such services are declared

10 competitive pursuant to Section 16-113; and also means (2) the

11 provision of electric power and energy by an electric utility

12 to retail customers outside the electric utility's service

13 area pursuant to Section 16-116. Provided, however, contract

14 service does not include electric utility services provided

15 pursuant to (i) contracts that retail customers are required

16 to execute as a condition of receiving tariffed services, or

17 (ii) special or negotiated rate contracts for electric utility

18 services that were entered into between an electric utility

19 and a retail customer prior to the effective date of this

20 amendatory Act of 1997 and filed with the Commission.

21 "Delivery services" means those services provided by the

22 electric utility that are necessary in order for the

23 transmission and distribution systems to function so that

24 retail customers located in the electric utility's service

25 area can receive electric power and energy from suppliers

26 other than the electric utility, and shall include, without

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1 limitation, standard metering and billing services.

2 "Electric utility" means a public utility, as defined in

3 Section 3-105 of this Act, that has a franchise, license,

4 permit or right to furnish or sell electricity to retail

5 customers within a service area.

6 "Electric vehicle" means: (i) a battery-powered vehicle

7 operated solely by electricity that can be recharged from an

8 external source; or (ii) a plug-in hybrid electric vehicle

9 that operates on electricity and another fuel and has a

10 battery that can be recharged from an external source.

11 "Electric vehicle charging station" means any facility,

12 infrastructure, or equipment that is used to charge a battery

13 or other energy storage device of an electric vehicle.

14 "Energy storage" or "storage" means any infrastructure,

15 facility, technology, or device used to store energy for use

16 on an electric distribution or transmission system and shall

17 not include or be considered energy generation.

18 "Mandatory transition period" means the period from the

19 effective date of this amendatory Act of 1997 through January

20 1, 2007.

21 "Municipal system" shall have the meaning set forth in

22 Section 17-100.

23 "Real-time pricing" means tariffed retail charges for

24 delivered electric power and energy that vary hour-to-hour and

25 are determined from wholesale market prices using a

26 methodology approved by the Illinois Commerce Commission.

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1 "Retail customer" means a single entity using electric

2 power or energy at a single premises and that (A) either (i) is

3 receiving or is eligible to receive tariffed services from an

4 electric utility, or (ii) that is served by a municipal system

5 or electric cooperative within any area in which the municipal

6 system or electric cooperative is or would be entitled to

7 provide service under the law in effect immediately prior to

8 the effective date of this amendatory Act of 1997, or (B) an

9 entity which on the effective date of this Act was receiving

10 electric service from a public utility and (i) was engaged in

11 the practice of resale and redistribution of such electricity

12 within a building prior to January 2, 1957, or (ii) was

13 providing lighting services to tenants in a multi-occupancy

14 building, but only to the extent such resale, redistribution

15 or lighting service is authorized by the electric utility's

16 tariffs that were on file with the Commission on the effective

17 date of this Act.

18 "Service area" means (i) the geographic area within which

19 an electric utility was lawfully entitled to provide electric

20 power and energy to retail customers as of the effective date

21 of this amendatory Act of 1997, and includes (ii) the location

22 of any retail customer to which the electric utility was

23 lawfully providing electric utility services on such effective

24 date.

25 "Small commercial retail customer" means those

26 nonresidential retail customers of an electric utility

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1 consuming 15,000 kilowatt-hours or less of electricity

2 annually in its service area.

3 "Tariffed service" means services provided to retail

4 customers by an electric utility as defined by its rates on

5 file with the Commission pursuant to the provisions of Article

6 IX of this Act, but shall not include competitive services.

7 "Transition charge" means a charge expressed in cents per

8 kilowatt-hour that is calculated for a customer or class of

9 customers as follows for each year in which an electric

10 utility is entitled to recover transition charges as provided

11 in Section 16-108:

12 (1) the amount of revenue that an electric utility

13 would receive from the retail customer or customers if it

14 were serving such customers' electric power and energy

15 requirements as a tariffed service based on (A) all of the

16 customers' actual usage during the 3 years ending 90 days

17 prior to the date on which such customers were first

18 eligible for delivery services pursuant to Section 16-104,

19 and (B) on (i) the base rates in effect on October 1, 1996

20 (adjusted for the reductions required by subsection (b) of

21 Section 16-111, for any reduction resulting from a rate

22 decrease under Section 16-101(b), for any restatement of

23 base rates made in conjunction with an elimination of the

24 fuel adjustment clause pursuant to subsection (b), (d), or

25 (f) of Section 9-220 and for any removal of

26 decommissioning costs from base rates pursuant to Section

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1 16-114) and any separate automatic rate adjustment riders

2 (other than a decommissioning rate as defined in Section

3 16-114) under which the customers were receiving or, had

4 they been customers, would have received electric power

5 and energy from the electric utility during the year

6 immediately preceding the date on which such customers

7 were first eligible for delivery service pursuant to

8 Section 16-104, or (ii) to the extent applicable, any

9 contract rates, including contracts or rates for

10 consolidated or aggregated billing, under which such

11 customers were receiving electric power and energy from

12 the electric utility during such year;

13 (2) less the amount of revenue, other than revenue

14 from transition charges and decommissioning rates, that

15 the electric utility would receive from such retail

16 customers for delivery services provided by the electric

17 utility, assuming such customers were taking delivery

18 services for all of their usage, based on the delivery

19 services tariffs in effect during the year for which the

20 transition charge is being calculated and on the usage

21 identified in paragraph (1);

22 (3) less the market value for the electric power and

23 energy that the electric utility would have used to supply

24 all of such customers' electric power and energy

25 requirements, as a tariffed service, based on the usage

26 identified in paragraph (1), with such market value

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1 determined in accordance with Section 16-112 of this Act;

2 (4) less the following amount which represents the

3 amount to be attributed to new revenue sources and cost

4 reductions by the electric utility through the end of the

5 period for which transition costs are recovered pursuant

6 to Section 16-108, referred to in this Article XVI as a

7 "mitigation factor":

8 (A) for nonresidential retail customers, an amount

9 equal to the greater of (i) 0.5 cents per

10 kilowatt-hour during the period October 1, 1999

11 through December 31, 2004, 0.6 cents per kilowatt-hour

12 in calendar year 2005, and 0.9 cents per kilowatt-hour

13 in calendar year 2006, multiplied in each year by the

14 usage identified in paragraph (1), or (ii) an amount

15 equal to the following percentages of the amount

16 produced by applying the applicable base rates

17 (adjusted as described in subparagraph (1)(B)) or

18 contract rate to the usage identified in paragraph

19 (1): 8% for the period October 1, 1999 through

20 December 31, 2002, 10% in calendar years 2003 and

21 2004, 11% in calendar year 2005 and 12% in calendar

22 year 2006; and

23 (B) for residential retail customers, an amount

24 equal to the following percentages of the amount

25 produced by applying the base rates in effect on

26 October 1, 1996 (adjusted as described in subparagraph

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1 (1)(B)) to the usage identified in paragraph (1): (i)

2 6% from May 1, 2002 through December 31, 2002, (ii) 7%

3 in calendar years 2003 and 2004, (iii) 8% in calendar

4 year 2005, and (iv) 10% in calendar year 2006;

5 (5) divided by the usage of such customers identified

6 in paragraph (1),

7 provided that the transition charge shall never be less than

8 zero.

9 "Unbundled service" means a component or constituent part

10 of a tariffed service which the electric utility subsequently

11 offers separately to its customers.

12 (Source: P.A. 97-1128, eff. 8-28-12.)

13 (220 ILCS 5/16-107.6)

14 Sec. 16-107.6. Distributed generation rebate.

15 (a) In this Section:

16 "Smart inverter" means a device that converts direct

17 current into alternating current and can autonomously

18 contribute to grid support during excursions from normal

19 operating voltage and frequency conditions by providing each

20 of the following: dynamic reactive and real power support,

21 voltage and frequency ride-through, ramp rate controls,

22 communication systems with ability to accept external

23 commands, and other functions from the electric utility.

24 "Subscriber" has the meaning set forth in Section 1-10 of

25 the Illinois Power Agency Act.

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1 "Subscription" has the meaning set forth in Section 1-10

2 of the Illinois Power Agency Act.

3 "Threshold date" means the date on which the load of an

4 electricity provider's net metering customers equals 5% of the

5 total peak demand supplied by that electricity provider during

6 the previous year, as specified under subsection (j) of

7 Section 16-107.5 of this Act.

8 (b) An electric utility that serves more than 200,000

9 customers in the State shall file a petition with the

10 Commission requesting approval of the utility's tariff to

11 provide a rebate to a retail customer who owns or operates

12 distributed generation that meets the following criteria:

13 (1) has a nameplate generating capacity no greater

14 than 2,000 kilowatts and is primarily used to offset that

15 customer's electricity load;

16 (2) is located on the customer's premises, for the

17 customer's own use, and not for commercial use or sales,

18 including, but not limited to, wholesale sales of electric

19 power and energy;

20 (3) is located in the electric utility's service

21 territory; and

22 (4) is interconnected under rules adopted by the

23 Commission by means of the inverter or smart inverter

24 required by this Section, as applicable.

25 For purposes of this Section, "distributed generation"

26 shall satisfy the definition of distributed renewable energy

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1 generation device set forth in Section 1-10 of the Illinois

2 Power Agency Act to the extent such definition is consistent

3 with the requirements of this Section.

4 In addition, any new photovoltaic distributed generation

5 that is installed after the effective date of this amendatory

6 Act of the 99th General Assembly must be installed by a

7 qualified person, as defined by subsection (i) of Section 1-56

8 of the Illinois Power Agency Act.

9 The tariff shall provide that the utility shall be

10 permitted to operate and control the smart inverter associated

11 with the distributed generation that is the subject of the

12 rebate for the purpose of preserving reliability during

13 distribution system reliability events and shall address the

14 terms and conditions of the operation and the compensation

15 associated with the operation. Nothing in this Section shall

16 negate or supersede Institute of Electrical and Electronics

17 Engineers interconnection requirements or standards or other

18 similar standards or requirements. The tariff shall also

19 provide for additional uses of the smart inverter that shall

20 be separately compensated and which may include, but are not

21 limited to, voltage and VAR support, regulation, and other

22 grid services. As part of the proceeding described in

23 subsection (e) of this Section, the Commission shall review

24 and determine whether smart inverters can provide any

25 additional uses or services. If the Commission determines that

26 an additional use or service would be beneficial, the

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1 Commission shall determine the terms and conditions of the

2 operation and how the use or service should be separately

3 compensated.

4 (c) The proposed tariff authorized by subsection (b) of

5 this Section shall include the following participation terms

6 and formulae to calculate the value of the rebates to be

7 applied under this Section for distributed generation that

8 satisfies the criteria set forth in subsection (b) of this

9 Section:

10 (1) Until the utility files its tariff or tariffs to

11 place into effect the rebate values established by the

12 Commission under subsection (e) of this Section,

13 non-residential customers that are taking service under a

14 net metering program offered by an electricity provider

15 under the terms of Section 16-107.5 of this Act may apply

16 for a rebate as provided for in this Section. The value of

17 the rebate shall be $250 per kilowatt of nameplate

18 generating capacity, measured as nominal DC power output,

19 of a non-residential customer's distributed generation.

20 (2) After the utility's tariff or tariffs setting the

21 new rebate values established under subsection (d) of this

22 Section take effect, retail customers may, as applicable,

23 make the following elections:

24 (A) Residential customers that are taking service

25 under a net metering program offered by an electricity

26 provider under the terms of Section 16-107.5 of this

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1 Act on the threshold date may elect to either continue

2 to take such service under the terms of such program as

3 in effect on such threshold date for the useful life of

4 the customer's eligible renewable electric generating

5 facility as defined in such Section, or file an

6 application to receive a rebate under the terms of

7 this Section, provided that such application must be

8 submitted within 6 months after the effective date of

9 the tariff approved under subsection (d) of this

10 Section. The value of the rebate shall be the amount

11 established by the Commission and reflected in the

12 utility's tariff pursuant to subsection (e) of this

13 Section.

14 (B) Non-residential customers that are taking

15 service under a net metering program offered by an

16 electricity provider under the terms of Section

17 16-107.5 of this Act on the threshold date may apply

18 for a rebate as provided for in this Section. The value

19 of the rebate shall be the amount established by the

20 Commission and reflected in the utility's tariff

21 pursuant to subsection (e) of this Section.

22 (3) Upon approval of a rebate application submitted

23 under this subsection (c), the retail customer shall no

24 longer be entitled to receive any delivery service credits

25 for the excess electricity generated by its facility and

26 shall be subject to the provisions of subsection (n) of

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1 Section 16-107.5 of this Act.

2 (4) To be eligible for a rebate described in this

3 subsection (c), customers who begin taking service after

4 the effective date of this amendatory Act of the 99th

5 General Assembly under a net metering program offered by

6 an electricity provider under the terms of Section

7 16-107.5 of this Act must have a smart inverter associated

8 with the customer's distributed generation.

9 (d) The Commission shall review the proposed tariff

10 submitted under subsections (b) and (c) of this Section and

11 may make changes to the tariff that are consistent with this

12 Section and with the Commission's authority under Article IX

13 of this Act, subject to notice and hearing. Following notice

14 and hearing, the Commission shall issue an order approving, or

15 approving with modification, such tariff no later than 240

16 days after the utility files its tariff.

17 (e) When the total generating capacity of the electricity

18 provider's net metering customers is equal to 3%, the

19 Commission shall open an investigation into an annual process

20 and formula for calculating the value of rebates for the

21 retail customers described in subsections (b) and (f) of this

22 Section that submit rebate applications after the threshold

23 date for an electric utility that elected to file a tariff

24 pursuant to this Section. The investigation shall include

25 diverse sets of stakeholders, calculations for valuing

26 distributed energy resource benefits to the grid based on best

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1 practices, and assessments of present and future technological

2 capabilities of distributed energy resources. The value of

3 such rebates shall reflect the value of the distributed

4 generation to the distribution system at the location at which

5 it is interconnected, taking into account the geographic,

6 time-based, and performance-based benefits, as well as

7 technological capabilities and present and future grid needs.

8 No later than 10 days after the Commission enters its final

9 order under this subsection (e), the utility shall file its

10 tariff or tariffs in compliance with the order, and the

11 Commission shall approve, or approve with modification, the

12 tariff or tariffs within 45 days after the utility's filing.

13 For those rebate applications filed after the threshold date

14 but before the utility's tariff or tariffs filed pursuant to

15 this subsection (e) take effect, the value of the rebate shall

16 remain at the value established in subsection (c) of this

17 Section until the tariff is approved.

18 (f) Notwithstanding any provision of this Act to the

19 contrary, the owner, developer, or subscriber of a generation

20 facility that is part of a net metering program provided under

21 subsection (l) of Section 16-107.5 shall also be eligible to

22 apply for the rebate described in this Section. A subscriber

23 to the generation facility may apply for a rebate in the amount

24 of the subscriber's subscription only if the owner, developer,

25 or previous subscriber to the same panel or panels has not

26 already submitted an application, and, regardless of whether

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1 the subscriber is a residential or non-residential customer,

2 may be allowed the amount identified in paragraph (1) of

3 subsection (c) or in subsection (e) of this Section applicable

4 to such customer on the date that the application is

5 submitted. An application for a rebate for a portion of a

6 project described in this subsection (f) may be submitted at

7 or after the time that a related request for net metering is

8 made.

9 (g) No later than 60 days after the utility receives an

10 application for a rebate under its tariff approved under

11 subsection (d) or (e) of this Section, the utility shall issue

12 a rebate to the applicant under the terms of the tariff. In the

13 event the application is incomplete or the utility is

14 otherwise unable to calculate the payment based on the

15 information provided by the owner, the utility shall issue the

16 payment no later than 60 days after the application is

17 complete or all requested information is received.

18 (h) An electric utility shall recover from its retail

19 customers all of the costs of the rebates made under a tariff

20 or tariffs placed into effect under this Section, including,

21 but not limited to, the value of the rebates and all costs

22 incurred by the utility to comply with and implement this

23 Section, consistent with the following provisions:

24 (1) The utility shall defer the full amount of its

25 costs incurred under this Section as a regulatory asset.

26 The total costs deferred as a regulatory asset shall be

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1 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

7 of 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 in

10 all years for electric utilities that serve more than

11 3,000,000 retail customers in this State, and in each

12 calendar year commencing before January 1, 2021 for

13 electric utilities that serve less than 3,000,000 retail

14 customers but more than 500,000 retail customers in this

15 State, shall be calculated as the sum of (i) the average

16 for the applicable calendar year of the monthly average

17 yields of 30-year U.S. Treasury bonds published by the

18 Board of Governors of the Federal Reserve System in its

19 weekly H.15 Statistical Release or successor publication;

20 and (ii) 580 basis points, including a revenue conversion

21 factor calculated to recover or refund all additional

22 income taxes that may be payable or receivable as a result

23 of that return. For electric utilities that serve less

24 than 3,000,000 retail customers but more than 500,000

25 retail customers in this State, for each calendar year

26 commencing after December 31, 2020, the cost of equity

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1 shall be equal to the national average cost of equity as

2 calculated under this paragraph (1). For purposes of this

3 paragraph (1), the national average cost of equity for an

4 applicable calendar year shall be the simple average of

5 the cost of equity specified and approved in each order of

6 a state regulatory commission, other than the Commission,

7 issued during such calendar year that is applicable to

8 base rates for retail electric service provided by an

9 investor-owned public utility company operating in the

10 United States. No order shall be excluded from the

11 national average cost of equity calculated under this

12 paragraph (1) on the grounds that it was arrived at by

13 stipulation or agreement or is subject to rehearing or

14 appeal. In its final order in the proceeding occurring

15 pursuant to this subsection (h) of this Section during

16 calendar year 2021, the Commission shall set the cost of

17 equity using the method applicable to calendar years

18 commencing prior to January 1, 2021. In its final orders

19 in the proceedings occurring pursuant to subsection (h) of

20 this Section in years subsequent to calendar year 2021,

21 including the reconciliation of the 2021 rate year, the

22 Commission shall set the cost of equity using the method

23 applicable to calendar years commencing after December 31,

24 2020. If, for any calendar year, there are fewer than 15

25 applicable orders of state regulatory commissions with

26 which to compute the average cost of equity, the

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1 Commission shall include in the calculation of the

2 national average the number of state regulatory orders

3 from the year or years immediately preceding such calendar

4 year necessary to reach a total of 15, beginning with the

5 most recently issued and proceeding in reverse

6 chronological order.

7 When an electric utility creates a regulatory asset

8 under the provisions of this Section, the costs are

9 recovered over a period during which customers also

10 receive a benefit, which is in the public interest.

11 Accordingly, it is the intent of the General Assembly that

12 an electric utility that elects to create a regulatory

13 asset under the provisions of this Section shall recover

14 all of the associated costs, including, but not limited

15 to, its cost of capital as set forth in this Section. After

16 the Commission has approved the prudence and

17 reasonableness of the costs that comprise the regulatory

18 asset, the electric utility shall be permitted to recover

19 all such costs, and the value and recoverability through

20 rates of the associated regulatory asset shall not be

21 limited, altered, impaired, or reduced. To enable the

22 financing of the incremental capital expenditures,

23 including regulatory assets, for electric utilities that

24 serve less than 3,000,000 retail customers but more than

25 500,000 retail customers in the State, the utility's

26 actual year-end capital structure that includes a common

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1 equity ratio, excluding goodwill, of up to and including

2 54% ~~50%~~ of the total capital structure shall be deemed

3 reasonable and used to set rates.

4 (2) The utility, at its election, may recover all of

5 the costs it incurs under this Section as part of a filing

6 for a general increase in rates under Article IX of this

7 Act, as part of an annual filing to update a

8 performance-based formula rate under subsection (d) of

9 Section 16-108.5 of this Act, or through an automatic

10 adjustment clause tariff, provided that nothing in this

11 paragraph (2) permits the double recovery of such costs

12 from customers. If the utility elects to recover the costs

13 it incurs under this Section through an automatic

14 adjustment clause tariff, the utility may file its

15 proposed tariff together with the tariff it files under

16 subsection (b) of this Section or at a later time. The

17 proposed tariff shall provide for an annual

18 reconciliation, less any deferred taxes related to the

19 reconciliation, with interest at an annual rate of return

20 equal to the utility's weighted average cost of capital as

21 calculated under paragraph (1) of this subsection (h),

22 including a revenue conversion factor calculated to

23 recover or refund all additional income taxes that may be

24 payable or receivable as a result of that return, of the

25 revenue requirement reflected in rates for each calendar

26 year, beginning with the calendar year in which the

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1 utility files its automatic adjustment clause tariff under

2 this subsection (h), with what the revenue requirement

3 would have been had the actual cost information for the

4 applicable calendar year been available at the filing

5 date. The Commission shall review the proposed tariff and

6 may make changes to the tariff that are consistent with

7 this Section and with the Commission's authority under

8 Article IX of this Act, subject to notice and hearing.

9 Following notice and hearing, the Commission shall issue

10 an order approving, or approving with modification, such

11 tariff no later than 240 days after the utility files its

12 tariff.

13 (i) No later than 90 days after the Commission enters an

14 order, or order on rehearing, whichever is later, approving an

15 electric utility's proposed tariff under subsection (d) of

16 this Section, the electric utility shall provide notice of the

17 availability of rebates under this Section. Subsequent to the

18 utility's notice, any entity that offers in the State, for

19 sale or lease, distributed generation and estimates the dollar

20 saving attributable to such distributed generation shall

21 provide estimates based on both delivery service credits and

22 the rebates available under this Section.

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

24 (220 ILCS 5/16-108.5)

25 Sec. 16-108.5. Infrastructure investment and

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1 modernization; regulatory reform.

2 (a) (Blank).

3 (b) For purposes of this Section, "participating utility"

4 means an electric utility or a combination utility serving

5 more than 1,000,000 customers in Illinois that voluntarily

6 elects and commits to undertake (i) the infrastructure

7 investment program consisting of the commitments and

8 obligations described in this subsection (b) and (ii) the

9 customer assistance program consisting of the commitments and

10 obligations described in subsection (b-10) of this Section,

11 notwithstanding any other provisions of this Act and without

12 obtaining any approvals from the Commission or any other

13 agency other than as set forth in this Section, regardless of

14 whether any such approval would otherwise be required.

15 "Combination utility" means a utility that, as of January 1,

16 2011, provided electric service to at least one million retail

17 customers in Illinois and gas service to at least 500,000

18 retail customers in Illinois. A participating utility shall

19 recover the expenditures made under the infrastructure

20 investment program through the ratemaking process, including,

21 but not limited to, the performance-based formula rate and

22 process set forth in this Section.

23 During the infrastructure investment program's peak

24 program year, a participating utility other than a combination

25 utility shall create 2,000 full-time equivalent jobs in

26 Illinois, and a participating utility that is a combination

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1 utility shall create 450 full-time equivalent jobs in Illinois

2 related to the provision of electric service. These jobs shall

3 include direct jobs, contractor positions, and induced jobs,

4 but shall not include any portion of a job commitment, not

5 specifically contingent on an amendatory Act of the 97th

6 General Assembly becoming law, between a participating utility

7 and a labor union that existed on December 30, 2011 (the

8 effective date of Public Act 97-646) and that has not yet been

9 fulfilled. A portion of the full-time equivalent jobs created

10 by each participating utility shall include incremental

11 personnel hired subsequent to December 30, 2011 (the effective

12 date of Public Act 97-646). For purposes of this Section,

13 "peak program year" means the consecutive 12-month period with

14 the highest number of full-time equivalent jobs that occurs

15 between the beginning of investment year 2 and the end of

16 investment year 4.

17 A participating utility shall meet one of the following

18 commitments, as applicable:

19 (1) Beginning no later than 180 days after a

20 participating utility other than a combination utility

21 files a performance-based formula rate tariff pursuant to

22 subsection (c) of this Section, or, beginning no later

23 than January 1, 2012 if such utility files such

24 performance-based formula rate tariff within 14 days of

25 October 26, 2011 (the effective date of Public Act

26 97-616), the participating utility shall, except as

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1 provided in subsection (b-5):

2 (A) over a 5-year period, invest an estimated

3 $1,300,000,000 in electric system upgrades,

4 modernization projects, and training facilities,

5 including, but not limited to:

6 (i) distribution infrastructure improvements

7 totaling an estimated $1,000,000,000, including

8 underground residential distribution cable

9 injection and replacement and mainline cable

10 system refurbishment and replacement projects;

11 (ii) training facility construction or upgrade

12 projects totaling an estimated $10,000,000,

13 provided that, at a minimum, one such facility

14 shall be located in a municipality having a

15 population of more than 2 million residents and

16 one such facility shall be located in a

17 municipality having a population of more than

18 150,000 residents but fewer than 170,000

19 residents; any such new facility located in a

20 municipality having a population of more than 2

21 million residents must be designed for the purpose

22 of obtaining, and the owner of the facility shall

23 apply for, certification under the United States

24 Green Building Council's Leadership in Energy

25 Efficiency Design Green Building Rating System;

26 (iii) wood pole inspection, treatment, and

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1 replacement programs;

2 (iv) an estimated $200,000,000 for reducing

3 the susceptibility of certain circuits to

4 storm-related damage, including, but not limited

5 to, high winds, thunderstorms, and ice storms;

6 improvements may include, but are not limited to,

7 overhead to underground conversion and other

8 engineered outcomes for circuits; the

9 participating utility shall prioritize the

10 selection of circuits based on each circuit's

11 historical susceptibility to storm-related damage

12 and the ability to provide the greatest customer

13 benefit upon completion of the improvements; to be

14 eligible for improvement, the participating

15 utility's ability to maintain proper tree

16 clearances surrounding the overhead circuit must

17 not have been impeded by third parties; and

18 (B) over a 10-year period, invest an estimated

19 $1,300,000,000 to upgrade and modernize its

20 transmission and distribution infrastructure and in

21 Smart Grid electric system upgrades, including, but

22 not limited to:

23 (i) additional smart meters;

24 (ii) distribution automation;

25 (iii) associated cyber secure data

26 communication network; and

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1 (iv) substation micro-processor relay

2 upgrades.

3 (2) Beginning no later than 180 days after a

4 participating utility that is a combination utility files

5 a performance-based formula rate tariff pursuant to

6 subsection (c) of this Section, or, beginning no later

7 than January 1, 2012 if such utility files such

8 performance-based formula rate tariff within 14 days of

9 October 26, 2011 (the effective date of Public Act

10 97-616), the participating utility shall, except as

11 provided in subsection (b-5):

12 (A) over a 10-year period, invest an estimated

13 $265,000,000 in electric system upgrades,

14 modernization projects, and training facilities,

15 including, but not limited to:

16 (i) distribution infrastructure improvements

17 totaling an estimated $245,000,000, which may

18 include bulk supply substations, transformers,

19 reconductoring, and rebuilding overhead

20 distribution and sub-transmission lines,

21 underground residential distribution cable

22 injection and replacement and mainline cable

23 system refurbishment and replacement projects;

24 (ii) training facility construction or upgrade

25 projects totaling an estimated $1,000,000; any

26 such new facility must be designed for the purpose

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1 of obtaining, and the owner of the facility shall

2 apply for, certification under the United States

3 Green Building Council's Leadership in Energy

4 Efficiency Design Green Building Rating System;

5 and

6 (iii) wood pole inspection, treatment, and

7 replacement programs; and

8 (B) over a 10-year period, invest an estimated

9 $360,000,000 to upgrade and modernize its transmission

10 and distribution infrastructure and in Smart Grid

11 electric system upgrades, including, but not limited

12 to:

13 (i) additional smart meters;

14 (ii) distribution automation;

15 (iii) associated cyber secure data

16 communication network; and

17 (iv) substation micro-processor relay

18 upgrades.

19 For purposes of this Section, "Smart Grid electric system

20 upgrades" shall have the meaning set forth in subsection (a)

21 of Section 16-108.6 of this Act.

22 The investments in the infrastructure investment program

23 described in this subsection (b) shall be incremental to the

24 participating utility's annual capital investment program, as

25 defined by, for purposes of this subsection (b), the

26 participating utility's average capital spend for calendar

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1 years 2008, 2009, and 2010 as reported in the applicable

2 Federal Energy Regulatory Commission (FERC) Form 1; provided

3 that where one or more utilities have merged, the average

4 capital spend shall be determined using the aggregate of the

5 merged utilities' capital spend reported in FERC Form 1 for

6 the years 2008, 2009, and 2010. A participating utility may

7 add reasonable construction ramp-up and ramp-down time to the

8 investment periods specified in this subsection (b). For each

9 such investment period, the ramp-up and ramp-down time shall

10 not exceed a total of 6 months.

11 Within 60 days after filing a tariff under subsection (c)

12 of this Section, a participating utility shall submit to the

13 Commission its plan, including scope, schedule, and staffing,

14 for satisfying its infrastructure investment program

15 commitments pursuant to this subsection (b). The submitted

16 plan shall include a schedule and staffing plan for the next

17 calendar year. The plan shall also include a plan for the

18 creation, operation, and administration of a Smart Grid test

19 bed as described in subsection (c) of Section 16-108.8. The

20 plan need not allocate the work equally over the respective

21 periods, but should allocate material increments throughout

22 such periods commensurate with the work to be undertaken. No

23 later than April 1 of each subsequent year, the utility shall

24 submit to the Commission a report that includes any updates to

25 the plan, a schedule for the next calendar year, the

26 expenditures made for the prior calendar year and

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1 cumulatively, and the number of full-time equivalent jobs

2 created for the prior calendar year and cumulatively. If the

3 utility is materially deficient in satisfying a schedule or

4 staffing plan, then the report must also include a corrective

5 action plan to address the deficiency. The fact that the plan,

6 implementation of the plan, or a schedule changes shall not

7 imply the imprudence or unreasonableness of the infrastructure

8 investment program, plan, or schedule. Further, no later than

9 45 days following the last day of the first, second, and third

10 quarters of each year of the plan, a participating utility

11 shall submit to the Commission a verified quarterly report for

12 the prior quarter that includes (i) the total number of

13 full-time equivalent jobs created during the prior quarter,

14 (ii) the total number of employees as of the last day of the

15 prior quarter, (iii) the total number of full-time equivalent

16 hours in each job classification or job title, (iv) the total

17 number of incremental employees and contractors in support of

18 the investments undertaken pursuant to this subsection (b) for

19 the prior quarter, and (v) any other information that the

20 Commission may require by rule.

21 With respect to the participating utility's peak job

22 commitment, if, after considering the utility's corrective

23 action plan and compliance thereunder, the Commission enters

24 an order finding, after notice and hearing, that a

25 participating utility did not satisfy its peak job commitment

26 described in this subsection (b) for reasons that are

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1 reasonably within its control, then the Commission shall also

2 determine, after consideration of the evidence, including, but

3 not limited to, evidence submitted by the Department of

4 Commerce and Economic Opportunity and the utility, the

5 deficiency in the number of full-time equivalent jobs during

6 the peak program year due to such failure. The Commission

7 shall notify the Department of any proceeding that is

8 initiated pursuant to this paragraph. For each full-time

9 equivalent job deficiency during the peak program year that

10 the Commission finds as set forth in this paragraph, the

11 participating utility shall, within 30 days after the entry of

12 the Commission's order, pay $6,000 to a fund for training

13 grants administered under Section 605-800 of the Department of

14 Commerce and Economic Opportunity Law, which shall not be a

15 recoverable expense.

16 With respect to the participating utility's investment

17 amount commitments, if, after considering the utility's

18 corrective action plan and compliance thereunder, the

19 Commission enters an order finding, after notice and hearing,

20 that a participating utility is not satisfying its investment

21 amount commitments described in this subsection (b), then the

22 utility shall no longer be eligible to annually update the

23 performance-based formula rate tariff pursuant to subsection

24 (d) of this Section. In such event, the then current rates

25 shall remain in effect until such time as new rates are set

26 pursuant to Article IX of this Act, subject to retroactive

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1 adjustment, with interest, to reconcile rates charged with

2 actual costs.

3 If the Commission finds that a participating utility is no

4 longer eligible to update the performance-based formula rate

5 tariff pursuant to subsection (d) of this Section, or the

6 performance-based formula rate is otherwise terminated, then

7 the participating utility's voluntary commitments and

8 obligations under this subsection (b) shall immediately

9 terminate, except for the utility's obligation to pay an

10 amount already owed to the fund for training grants pursuant

11 to a Commission order.

12 In meeting the obligations of this subsection (b), to the

13 extent feasible and consistent with State and federal law, the

14 investments under the infrastructure investment program should

15 provide employment opportunities for all segments of the

16 population and workforce, including minority-owned and

17 woman-owned ~~female-owned~~ business enterprises, and shall not,

18 consistent with State and federal law, discriminate based on

19 race or socioeconomic status.

20 (b-5) Nothing in this Section shall prohibit the

21 Commission from investigating the prudence and reasonableness

22 of the expenditures made under the infrastructure investment

23 program during the annual review required by subsection (d) of

24 this Section and shall, as part of such investigation,

25 determine whether the utility's actual costs under the program

26 are prudent and reasonable. The fact that a participating

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1 utility invests more than the minimum amounts specified in

2 subsection (b) of this Section or its plan shall not imply

3 imprudence or unreasonableness.

4 If the participating utility finds that it is implementing

5 its plan for satisfying the infrastructure investment program

6 commitments described in subsection (b) of this Section at a

7 cost below the estimated amounts specified in subsection (b)

8 of this Section, then the utility may file a petition with the

9 Commission requesting that it be permitted to satisfy its

10 commitments by spending less than the estimated amounts

11 specified in subsection (b) of this Section. The Commission

12 shall, after notice and hearing, enter its order approving, or

13 approving as modified, or denying each such petition within

14 150 days after the filing of the petition.

15 In no event, absent General Assembly approval, shall the

16 capital investment costs incurred by a participating utility

17 other than a combination utility in satisfying its

18 infrastructure investment program commitments described in

19 subsection (b) of this Section exceed $3,000,000,000 or, for a

20 participating utility that is a combination utility,

21 $720,000,000. If the participating utility's updated cost

22 estimates for satisfying its infrastructure investment program

23 commitments described in subsection (b) of this Section exceed

24 the limitation imposed by this subsection (b-5), then it shall

25 submit a report to the Commission that identifies the

26 increased costs and explains the reason or reasons for the

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1 increased costs no later than the year in which the utility

2 estimates it will exceed the limitation. The Commission shall

3 review the report and shall, within 90 days after the

4 participating utility files the report, report to the General

5 Assembly its findings regarding the participating utility's

6 report. If the General Assembly does not amend the limitation

7 imposed by this subsection (b-5), then the utility may modify

8 its plan so as not to exceed the limitation imposed by this

9 subsection (b-5) and may propose corresponding changes to the

10 metrics established pursuant to subparagraphs (5) through (8)

11 of subsection (f) of this Section, and the Commission may

12 modify the metrics and incremental savings goals established

13 pursuant to subsection (f) of this Section accordingly.

14 (b-10) All participating utilities shall make

15 contributions for an energy low-income and support program in

16 accordance with this subsection. Beginning no later than 180

17 days after a participating utility files a performance-based

18 formula rate tariff pursuant to subsection (c) of this

19 Section, or beginning no later than January 1, 2012 if such

20 utility files such performance-based formula rate tariff

21 within 14 days of December 30, 2011 (the effective date of

22 Public Act 97-646), and without obtaining any approvals from

23 the Commission or any other agency other than as set forth in

24 this Section, regardless of whether any such approval would

25 otherwise be required, a participating utility other than a

26 combination utility shall pay $10,000,000 per year for 5 years

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1 and a participating utility that is a combination utility

2 shall pay $1,000,000 per year for 10 years to the energy

3 low-income and support program, which is intended to fund

4 customer assistance programs with the primary purpose being

5 avoidance of imminent disconnection. Such programs may

6 include:

7 (1) a residential hardship program that may partner

8 with community-based organizations, including senior

9 citizen organizations, and provides grants to low-income

10 residential customers, including low-income senior

11 citizens, who demonstrate a hardship;

12 (2) a program that provides grants and other bill

13 payment concessions to veterans with disabilities who

14 demonstrate a hardship and members of the armed services

15 or reserve forces of the United States or members of the

16 Illinois National Guard who are on active duty pursuant to

17 an executive order of the President of the United States,

18 an act of the Congress of the United States, or an order of

19 the Governor and who demonstrate a hardship;

20 (3) a budget assistance program that provides tools

21 and education to low-income senior citizens to assist them

22 with obtaining information regarding energy usage and

23 effective means of managing energy costs;

24 (4) a non-residential special hardship program that

25 provides grants to non-residential customers such as small

26 businesses and non-profit organizations that demonstrate a

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1 hardship, including those providing services to senior

2 citizen and low-income customers; and

3 (5) a performance-based assistance program that

4 provides grants to encourage residential customers to make

5 on-time payments by matching a portion of the customer's

6 payments or providing credits towards arrearages.

7 The payments made by a participating utility pursuant to

8 this subsection (b-10) shall not be a recoverable expense. A

9 participating utility may elect to fund either new or existing

10 customer assistance programs, including, but not limited to,

11 those that are administered by the utility.

12 Programs that use funds that are provided by a

13 participating utility to reduce utility bills may be

14 implemented through tariffs that are filed with and reviewed

15 by the Commission. If a utility elects to file tariffs with the

16 Commission to implement all or a portion of the programs,

17 those tariffs shall, regardless of the date actually filed, be

18 deemed accepted and approved, and shall become effective on

19 December 30, 2011 (the effective date of Public Act 97-646).

20 The participating utilities whose customers benefit from the

21 funds that are disbursed as contemplated in this Section shall

22 file annual reports documenting the disbursement of those

23 funds with the Commission. The Commission has the authority to

24 audit disbursement of the funds to ensure they were disbursed

25 consistently with this Section.

26 If the Commission finds that a participating utility is no

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1 longer eligible to update the performance-based formula rate

2 tariff pursuant to subsection (d) of this Section, or the

3 performance-based formula rate is otherwise terminated, then

4 the participating utility's voluntary commitments and

5 obligations under this subsection (b-10) shall immediately

6 terminate.

7 (b-15) Beginning in 2022, without obtaining any approvals

8 from the Commission or any other agency, regardless of whether

9 any such approval would otherwise be required, a participating

10 utility that is a combination utility shall pay $1,000,000 per

11 year for 10 years to the energy low-income and support

12 program, which is intended to fund customer assistance

13 programs with the primary purpose of avoidance of imminent

14 disconnection and reconnecting customers who have been

15 disconnected for nonpayment. Such programs may include those

16 described in paragraphs (1) through (5) of subsection (b-10)

17 of this Section.

18 The payments made by a participating utility pursuant to

19 this subsection (b-15) is not a recoverable expense. A

20 participating utility may elect to fund either new or existing

21 customer assistance programs, including, but not limited to,

22 those that are administered by the utility.

23 Programs that use funds that are provided by a

24 participating utility to reduce utility bills may be

25 implemented through tariffs that are filed with and reviewed

26 by the Commission. If a utility elects to file tariffs with the

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1 Commission to implement all or a portion of the programs,

2 those tariffs shall, regardless of the date actually filed, be

3 deemed accepted and approved, and shall become effective on

4 the first business day after they are filed. The participating

5 utilities whose customers benefit from the funds that are

6 disbursed as contemplated in this subsection (b-15) shall file

7 annual reports documenting the disbursement of those funds

8 with the Commission. The Commission has the authority to audit

9 disbursement of the funds to ensure they were disbursed

10 consistently with this subsection (b-15).

11 If the Commission finds that a participating utility is no

12 longer eligible to update the performance-based formula rate

13 tariff pursuant to subsection (d) of this Section, or the

14 performance-based formula rate is otherwise terminated, then

15 the participating utility's voluntary commitments and

16 obligations under this subsection (b-15) shall immediately

17 terminate.

18 (c) A participating utility may elect to recover its

19 delivery services costs through a performance-based formula

20 rate approved by the Commission, which shall specify the cost

21 components that form the basis of the rate charged to

22 customers with sufficient specificity to operate in a

23 standardized manner and be updated annually with transparent

24 information that reflects the utility's actual costs to be

25 recovered during the applicable rate year, which is the period

26 beginning with the first billing day of January and extending

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1 through the last billing day of the following December. In the

2 event the utility recovers a portion of its costs through

3 automatic adjustment clause tariffs on October 26, 2011 (the

4 effective date of Public Act 97-616), the utility may elect to

5 continue to recover these costs through such tariffs, but then

6 these costs shall not be recovered through the

7 performance-based formula rate. In the event the participating

8 utility, prior to December 30, 2011 (the effective date of

9 Public Act 97-646), filed electric delivery services tariffs

10 with the Commission pursuant to Section 9-201 of this Act that

11 are related to the recovery of its electric delivery services

12 costs that are still pending on December 30, 2011 (the

13 effective date of Public Act 97-646), the participating

14 utility shall, at the time it files its performance-based

15 formula rate tariff with the Commission, also file a notice of

16 withdrawal with the Commission to withdraw the electric

17 delivery services tariffs previously filed pursuant to Section

18 9-201 of this Act. Upon receipt of such notice, the Commission

19 shall dismiss with prejudice any docket that had been

20 initiated to investigate the electric delivery services

21 tariffs filed pursuant to Section 9-201 of this Act, and such

22 tariffs and the record related thereto shall not be the

23 subject of any further hearing, investigation, or proceeding

24 of any kind related to rates for electric delivery services.

25 The performance-based formula rate shall be implemented

26 through a tariff filed with the Commission consistent with the

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1 provisions of this subsection (c) that shall be applicable to

2 all delivery services customers. The Commission shall initiate

3 and conduct an investigation of the tariff in a manner

4 consistent with the provisions of this subsection (c) and the

5 provisions of Article IX of this Act to the extent they do not

6 conflict with this subsection (c). Except in the case where

7 the Commission finds, after notice and hearing, that a

8 participating utility is not satisfying its investment amount

9 commitments under subsection (b) of this Section, the

10 performance-based formula rate shall remain in effect at the

11 discretion of the utility. The performance-based formula rate

12 approved by the Commission shall do the following:

13 (1) Provide for the recovery of the utility's actual

14 costs of delivery services that are prudently incurred and

15 reasonable in amount consistent with Commission practice

16 and law. The sole fact that a cost differs from that

17 incurred in a prior calendar year or that an investment is

18 different from that made in a prior calendar year shall

19 not imply the imprudence or unreasonableness of that cost

20 or investment.

21 (2) Reflect the utility's actual year-end capital

22 structure for the applicable calendar year, excluding

23 goodwill, subject to a determination of prudence and

24 reasonableness consistent with Commission practice and

25 law. To enable the financing of the incremental capital

26 expenditures, including regulatory assets, for electric

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1 utilities that serve less than 3,000,000 retail customers

2 but more than 500,000 retail customers in the State, a

3 participating electric utility's actual year-end capital

4 structure that includes a common equity ratio, excluding

5 goodwill, of up to and including 54% ~~50%~~ of the total

6 capital structure shall be deemed reasonable and used to

7 set rates.

8 (3) Include a cost of equity, which in all years for a

9 participating utility that is not a combination utility,

10 and in each calendar year commencing before January 1,

11 2021 for a participating utility that is a combination

12 utility, shall be calculated as the sum of the following:

13 (A) the average for the applicable calendar year

14 of the monthly average yields of 30-year U.S. Treasury

15 bonds published by the Board of Governors of the

16 Federal Reserve System in its weekly H.15 Statistical

17 Release or successor publication; and

18 (B) 580 basis points.

19 For a participating utility that is a combination

20 utility, for each calendar year commencing after December

21 31, 2020, the cost of equity shall be equal to the national

22 average cost of equity as calculated under this paragraph

23 (3). For purposes of this paragraph (3), the national

24 average cost of equity for an applicable calendar year

25 shall be the simple average of the cost of equity

26 specified and approved in each order of a state regulatory

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1 commission, other than the Commission, issued during such

2 calendar year that is applicable to base rates for retail

3 electric service provided by an investor-owned public

4 utility company operating in the United States. No order

5 shall be excluded from the national average cost of equity

6 calculated under this paragraph (3) on the grounds that it

7 was arrived at by stipulation or agreement or is subject

8 to rehearing or appeal. In its final order in the

9 proceeding occurring pursuant to subsection (d) of this

10 Section during calendar year 2021, the Commission shall

11 set the cost of equity using the method applicable to

12 calendar years commencing prior to January 1, 2021. In its

13 final orders in the proceedings occurring pursuant to

14 subsection (d) of this Section in years subsequent to

15 calendar year 2021, including the reconciliation of the

16 2021 rate year, the Commission shall set the cost of

17 equity using the method applicable to calendar years

18 commencing after December 31, 2020. If, for any calendar

19 year, there are fewer than 15 applicable orders of state

20 regulatory commissions with which to compute the average

21 cost of equity, the Commission shall include in the

22 calculation of the national average the number of state

23 regulatory orders from the year or years immediately

24 preceding such calendar year necessary to reach a total of

25 15, beginning with the most recently issued and proceeding

26 in reverse chronological order.

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1 At such time as the Board of Governors of the Federal

2 Reserve System ceases to include the monthly average

3 yields of 30-year U.S. Treasury bonds in its weekly H.15

4 Statistical Release or successor publication, the monthly

5 average yields of the U.S. Treasury bonds then having the

6 longest duration published by the Board of Governors in

7 its weekly H.15 Statistical Release or successor

8 publication shall instead be used for purposes of this

9 paragraph (3).

10 (4) Permit and set forth protocols, subject to a

11 determination of prudence and reasonableness consistent

12 with Commission practice and law, for the following:

13 (A) recovery of incentive compensation expense

14 that is based on the achievement of operational

15 metrics, including metrics related to budget controls,

16 outage duration and frequency, safety, customer

17 service, efficiency and productivity, and

18 environmental compliance. Incentive compensation

19 expense that is based on net income or an affiliate's

20 earnings per share shall not be recoverable under the

21 performance-based formula rate;

22 (B) recovery of pension and other post-employment

23 benefits expense, provided that such costs are

24 supported by an actuarial study;

25 (C) recovery of severance costs, provided that if

26 the amount is over $3,700,000 for a participating

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1 utility that is a combination utility or $10,000,000

2 for a participating utility that serves more than 3

3 million retail customers, then the full amount shall

4 be amortized consistent with subparagraph (F) of this

5 paragraph (4);

6 (D) investment return at a rate equal to the

7 utility's weighted average cost of long-term debt, on

8 the pension assets as, and in the amount, reported in

9 Account 186 (or in such other Account or Accounts as

10 such asset may subsequently be recorded) of the

11 utility's most recently filed FERC Form 1, net of

12 deferred tax benefits;

13 (E) recovery of the expenses related to the

14 Commission proceeding under this subsection (c) to

15 approve this performance-based formula rate and

16 initial rates or to subsequent proceedings related to

17 the formula, provided that the recovery shall be

18 amortized over a 3-year period; recovery of expenses

19 related to the annual Commission proceedings under

20 subsection (d) of this Section to review the inputs to

21 the performance-based formula rate shall be expensed

22 and recovered through the performance-based formula

23 rate;

24 (F) amortization over a 5-year period of the full

25 amount of each charge or credit that exceeds

26 $3,700,000 for a participating utility that is a

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1 combination utility or $10,000,000 for a participating

2 utility that serves more than 3 million retail

3 customers in the applicable calendar year and that

4 relates to a workforce reduction program's severance

5 costs, changes in accounting rules, changes in law,

6 compliance with any Commission-initiated audit, or a

7 single storm or other similar expense, provided that

8 any unamortized balance shall be reflected in rate

9 base. For purposes of this subparagraph (F), changes

10 in law includes any enactment, repeal, or amendment in

11 a law, ordinance, rule, regulation, interpretation,

12 permit, license, consent, or order, including those

13 relating to taxes, accounting, or to environmental

14 matters, or in the interpretation or application

15 thereof by any governmental authority occurring after

16 October 26, 2011 (the effective date of Public Act

17 97-616);

18 (G) recovery of existing regulatory assets over

19 the periods previously authorized by the Commission;

20 (H) historical weather normalized billing

21 determinants; and

22 (I) allocation methods for common costs.

23 (5) Provide that if the participating utility's earned

24 rate of return on common equity related to the provision

25 of delivery services for the prior rate year (calculated

26 using costs and capital structure approved by the

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1 Commission as provided in subparagraph (2) of this

2 subsection (c), consistent with this Section, in

3 accordance with Commission rules and orders, including,

4 but not limited to, adjustments for goodwill, and after

5 any Commission-ordered disallowances and taxes) is more

6 than 50 basis points higher than the rate of return on

7 common equity calculated pursuant to paragraph (3) of this

8 subsection (c) (after ~~adjusting for~~ any adjustments

9 ~~penalties~~ to the rate of return on common equity applied

10 pursuant to the performance metrics provision of

11 subsections ~~subsection~~ (f), (f-5), (f-10), or (f-15) of

12 this Section, as applicable), then the participating

13 utility shall apply a credit through the performance-based

14 formula rate that reflects an amount equal to the value of

15 that portion of the earned rate of return on common equity

16 that is more than 50 basis points higher than the rate of

17 return on common equity calculated pursuant to paragraph

18 (3) of this subsection (c) (after ~~adjusting for~~ any

19 adjustments ~~penalties~~ to the rate of return on common

20 equity applied pursuant to the performance metrics

21 provision of subsections ~~subsection~~ (f), (f-5), (f-10), or

22 (f-15) of this Section, as applicable) for the prior rate

23 year, adjusted for taxes. If the participating utility's

24 earned rate of return on common equity related to the

25 provision of delivery services for the prior rate year

26 (calculated using costs and capital structure approved by

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1 the Commission as provided in subparagraph (2) of this

2 subsection (c), consistent with this Section, in

3 accordance with Commission rules and orders, including,

4 but not limited to, adjustments for goodwill, and after

5 any Commission-ordered disallowances and taxes) is more

6 than 50 basis points less than the return on common equity

7 calculated pursuant to paragraph (3) of this subsection

8 (c) (after ~~adjusting for~~ any adjustments ~~penalties~~ to the

9 rate of return on common equity applied pursuant to the

10 performance metrics provision of subsections ~~subsection~~

11 (f), (f-5), (f-10), or (f-15) of this Section, as

12 applicable), then the participating utility shall apply a

13 charge through the performance-based formula rate that

14 reflects an amount equal to the value of that portion of

15 the earned rate of return on common equity that is more

16 than 50 basis points less than the rate of return on common

17 equity calculated pursuant to paragraph (3) of this

18 subsection (c) (after ~~adjusting for~~ any adjustments

19 ~~penalties~~ to the rate of return on common equity applied

20 pursuant to the performance metrics provision of

21 subsections ~~subsection~~ (f), (f-5), (f-10), or (f-15) of

22 this Section, as applicable) for the prior rate year,

23 adjusted for taxes.

24 (6) Provide for an annual reconciliation, as described

25 in subsection (d) of this Section, with interest, of the

26 revenue requirement reflected in rates for each calendar

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1 year, beginning with the calendar year in which the

2 utility files its performance-based formula rate tariff

3 pursuant to subsection (c) of this Section, with what the

4 revenue requirement would have been had the actual cost

5 information for the applicable calendar year been

6 available at the filing date.

7 The utility shall file, together with its tariff, final

8 data based on its most recently filed FERC Form 1, plus

9 projected plant additions and correspondingly updated

10 depreciation reserve and expense for the calendar year in

11 which the tariff and data are filed, that shall populate the

12 performance-based formula rate and set the initial delivery

13 services rates under the formula. For purposes of this

14 Section, "FERC Form 1" means the Annual Report of Major

15 Electric Utilities, Licensees and Others that electric

16 utilities are required to file with the Federal Energy

17 Regulatory Commission under the Federal Power Act, Sections 3,

18 4(a), 304 and 209, modified as necessary to be consistent with

19 83 Ill. Admin. Code Part 415 as of May 1, 2011. Nothing in this

20 Section is intended to allow costs that are not otherwise

21 recoverable to be recoverable by virtue of inclusion in FERC

22 Form 1.

23 After the utility files its proposed performance-based

24 formula rate structure and protocols and initial rates, the

25 Commission shall initiate a docket to review the filing. The

26 Commission shall enter an order approving, or approving as

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1 modified, the performance-based formula rate, including the

2 initial rates, as just and reasonable within 270 days after

3 the date on which the tariff was filed, or, if the tariff is

4 filed within 14 days after October 26, 2011 (the effective

5 date of Public Act 97-616), then by May 31, 2012. Such review

6 shall be based on the same evidentiary standards, including,

7 but not limited to, those concerning the prudence and

8 reasonableness of the costs incurred by the utility, the

9 Commission applies in a hearing to review a filing for a

10 general increase in rates under Article IX of this Act. The

11 initial rates shall take effect within 30 days after the

12 Commission's order approving the performance-based formula

13 rate tariff.

14 Until such time as the Commission approves a different

15 rate design and cost allocation pursuant to subsection (e) of

16 this Section, rate design and cost allocation across customer

17 classes shall be consistent with the Commission's most recent