99TH GENERAL ASSEMBLY State of Illinois 2015 and 2016 HB2607

Introduced , by Rep. Elaine Nekritz

SYNOPSIS AS INTRODUCED:

See Index

Amends the Illinois Power Agency Act. Requires the Planning and Procurement Bureau to establish a long-term renewable resources procurement plan that includes all renewable energy credits necessary to meet specified goals (replacing the current renewable portfolio standards). Sets forth guidelines for what shall be included in the procurement plan. Makes changes to provisions concerning definitions, the powers of the Agency, the Illinois Power Agency Renewable Energy Resources Fund, and the duties of the Planning and Procurement Bureau. Amends the Public Utilities Act. Makes changes concerning nondiscrimination, energy efficiency and demand-response measures, natural gas efficiency programs, real-time pricing, infrastructure investment and modernization, the Illinois Smart Grid test bed, and on-bill financing programs for electric and gas utilities. Adds provisions related to renewable energy credit procurement. Amends the Environmental Protection Act. Provides that upon promulgation by the U.S. Environmental Protection Agency of a final rule regulating carbon dioxide emissions from existing electric generating units, the Illinois Environmental Protection Agency shall be authorized to implement a cap and invest program or similar market mechanism to regulate

carbon dioxide emissions. Makes other changes. Effective immediately.

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FISCAL NOTE ACT MAY APPLY

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 5. The Illinois Power Agency Act is amended by

5 changing Sections 1-5, 1-10, 1-20, 1-56, and 1-75 as follows:

6 (20 ILCS 3855/1-5)

7 Sec. 1-5. Legislative declarations and findings. The

8 General Assembly finds and declares:

9 (1) The health, welfare, and prosperity of all Illinois

10 citizens require the provision of adequate, reliable,

11 affordable, efficient, and environmentally sustainable

12 electric service at the lowest total cost over time, taking

13 into account any benefits of price stability.

14 (2) The transition to retail competition is not

15 complete. Some customers, especially residential and small

16 commercial customers, have failed to benefit from lower

17 electricity costs from retail and wholesale competition.

18 (3) Escalating prices for electricity in Illinois pose

19 a serious threat to the economic well-being, health, and

20 safety of the residents of and the commerce and industry of

21 the State.

22 (4) To protect against this threat to economic

23 well-being, health, and safety it is necessary to improve

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1 the process of procuring electricity to serve Illinois

2 residents, to promote investment in energy efficiency and

3 demand-response measures, and to support development of

4 clean coal technologies and renewable resources.

5 (5) Procuring a diverse electricity supply portfolio

6 will ensure the lowest total cost over time for adequate,

7 reliable, efficient, and environmentally sustainable

8 electric service.

9 (6) Including cost-effective renewable resources in

10 that portfolio will reduce long-term direct and indirect

11 costs to consumers by decreasing environmental impacts and

12 by avoiding or delaying the need for new generation,

13 transmission, and distribution infrastructure.

14 (7) Energy efficiency, demand-response measures, and

15 renewable energy are resources currently underused in

16 Illinois. These and other demand-side resources should be

17 used when cost-effective to reduce costs to consumers and

18 encourage job creation.

19 (8) The State should encourage the use of advanced

20 clean coal technologies that capture and sequester carbon

21 dioxide emissions to advance environmental protection

22 goals and to demonstrate the viability of coal and

23 coal-derived fuels in a carbon-constrained economy.

24 (9) The General Assembly enacted Public Act 96-0795 to

25 reform the State's purchasing processes, recognizing that

26 government procurement is susceptible to abuse if

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1 structural and procedural safeguards are not in place to

2 ensure independence, insulation, oversight, and

3 transparency.

4 (10) The principles that underlie the procurement

5 reform legislation apply also in the context of power

6 purchasing.

7 The General Assembly therefore finds that it is necessary

8 to create the Illinois Power Agency and that the goals and

9 objectives of that Agency are to accomplish each of the

10 following:

11 (A) Develop electricity procurement plans to ensure

12 adequate, reliable, affordable, efficient, and

13 environmentally sustainable electric service at the lowest

14 total cost over time, taking into account any benefits of

15 price stability, for electric utilities that on December

16 31, 2005 provided electric service to at least 100,000

17 customers in Illinois and for small multi-jurisdictional

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

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

20 procurement plan for their Illinois jurisdictional load.

21 The procurement plan shall be updated on an annual basis

22 and shall include renewable energy resources sufficient to

23 achieve the standards specified in this Act.

24 (B) Conduct competitive procurement processes to

25 procure the supply resources identified in the procurement

26 plan.

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1 (C) Develop electric generation and co-generation

2 facilities that use indigenous coal or renewable

3 resources, or both, financed with bonds issued by the

4 Illinois Finance Authority.

5 (D) Supply electricity from the Agency's facilities at

6 cost to one or more of the following: municipal electric

7 systems, governmental aggregators, or rural electric

8 cooperatives in Illinois.

9 (E) Ensure that the process of power procurement is

10 conducted in an ethical and transparent fashion, immune

11 from improper influence.

12 (F) Continue to review its policies and practices to

13 determine how best to meet its mission of providing the

14 lowest cost power to the greatest number of people, at any

15 given point in time, in accordance with applicable law.

16 (G) Operate in a structurally insulated, independent,

17 and transparent fashion so that nothing impedes the

18 Agency's mission to secure power at the best prices the

19 market will bear, provided that the Agency meets all

20 applicable legal requirements.

21 (Source: P.A. 97-325, eff. 8-12-11; 97-618, eff. 10-26-11;

22 97-813, eff. 7-13-12.)

23 (20 ILCS 3855/1-10)

24 Sec. 1-10. Definitions.

25 "Agency" means the Illinois Power Agency.

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1 "Agency loan agreement" means any agreement pursuant to

2 which the Illinois Finance Authority agrees to loan the

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

4 the Agency upon terms providing for loan repayment installments

5 at least sufficient to pay when due all principal of, interest

6 and premium, if any, on those revenue bonds, and providing for

7 maintenance, insurance, and other matters in respect of the

8 project.

9 "Authority" means the Illinois Finance Authority.

10 "Brownfield solar project" means an electric generating

11 facility that:

12 (1) generates electricity using photovoltaic cells;

13 (2) is interconnected at the distribution system level

14 of either an electric utility as defined in this Section, a

15 municipal utility as defined in Section 3-105 of the Public

16 Utilities Act, or a rural electric cooperative as defined

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

18 (3) is located on a site that is regulated by any of

19 the following entities under the following programs:

20 (i) the United States Environmental Protection

21 Agency under the federal Comprehensive Environmental

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

23 amended;

24 (ii) the United States Environmental Protection

25 Agency under the Corrective Action Program of the

26 federal Resource Conservation and Recovery Act, as

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1 amended;

2 (iii) the Illinois Environmental Protection Agency

3 under the Illinois Site Remediation Program; or

4 (iv) the Illinois Environmental Protection Agency

5 under the Illinois Solid Waste Program.

6 "Clean coal facility" means an electric generating

7 facility that uses primarily coal as a feedstock and that

8 captures and sequesters carbon dioxide emissions at the

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

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

11 time construction commences, the facility is scheduled to

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

13 carbon dioxide emissions that the facility would otherwise emit

14 if, at the time construction commences, the facility is

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

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

17 facility would otherwise emit if, at the time construction

18 commences, the facility is scheduled to commence operation

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

20 not exceed allowable emission rates for sulfur dioxide,

21 nitrogen oxides, carbon monoxide, particulates and mercury for

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

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

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

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

26 bituminous rank and greater than 1.7 pounds of sulfur per

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

2 use gasification technology and was operating as a conventional

3 coal-fired electric generating facility on June 1, 2009 (the

4 effective date of Public Act 95-1027).

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

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

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

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

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

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

11 utility and the remainder of the feedstock may be either

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

13 bituminous rank and greater than 1.7 pounds of sulfur per

14 million Btu content unless the facility reasonably determines

15 that it is necessary to use additional petroleum coke to

16 deliver additional consumer savings, in which case the facility

17 shall use coal for at least 35% of the total feedstock over the

18 term of any sourcing agreement; and (4) captures and sequesters

19 at least 85% of the total carbon dioxide emissions that the

20 facility would otherwise emit.

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

22 gasification process to produce substitute natural gas, that

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

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

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

26 bituminous rank and greater than 1.7 pounds of sulfur per

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

2 to construct emission sources and air pollution control

3 equipment and approval with respect to the federal regulations

4 for Prevention of Significant Deterioration of Air Quality

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

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

7 not be a clean coal SNG facility.

8 "Commission" means the Illinois Commerce Commission.

9 "Community solar project" means an electric generating

10 facility that:

11 (1) generates electricity using photovoltaic cells;

12 (2) is interconnected at the distribution system level

13 of an electric utility as defined in this Section;

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

15 facility to the subscribers of the facility; and

16 (4) is limited in nameplate capacity to no more than

17 2,000 kilowatts.

18 "Costs incurred in connection with the development and

19 construction of a facility" means:

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

21 fixtures, and improvements in connection therewith and

22 equipment, personal property, and other property, rights,

23 and easements acquired that are deemed necessary for the

24 operation and maintenance of the facility;

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

26 other evidences of indebtedness of the Agency;

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1 (3) all origination, commitment, utilization,

2 facility, placement, underwriting, syndication, credit

3 enhancement, and rating agency fees;

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

5 legal, accounting, title insurance, survey, appraisal,

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

7 interest rate swap, capitalized interest, contingency, as

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

9 expenses for professional services; and

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

11 investigation, installation, surveys, other Agency costs

12 and estimates of costs, and other expenses necessary or

13 incidental to determining the feasibility of any project,

14 together with such other expenses as may be necessary or

15 incidental to the financing, insuring, acquisition, and

16 construction of a specific project and starting up,

17 commissioning, and placing that project in operation.

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

19 Section 16-102 of the Public Utilities Act.

20 "Delivery year" means the year beginning June 1 of the year

21 referenced and ending May 31 of the following year.

22 "Department" means the Department of Commerce and Economic

23 Opportunity.

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

25 "Demand-response" means measures that decrease peak

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

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1 periods.

2 "Distributed renewable energy generation device" means a

3 device that is:

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

5 photovoltaic cells and panels, biodiesel, crops and

6 untreated and unadulterated organic waste biomass, tree

7 waste, and hydropower that does not involve new

8 construction or significant expansion of hydropower dams;

9 (2) interconnected at the distribution system level of

10 either an electric utility as defined in this Section, ~~an~~

11 ~~alternative retail electric supplier as defined in Section~~

12 ~~16-102 of the Public Utilities Act,~~ a municipal utility as

13 defined in Section 3-105 of the Public Utilities Act, or a

14 rural electric cooperative as defined in Section 3-119 of

15 the Public Utilities Act;

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

17 electric meter and is primarily used to offset that

18 customer's electricity load; and

19 (4) limited in nameplate capacity to no more than 2,000

20 kilowatts.

21 "Energy efficiency" means measures that reduce the amount

22 of electricity or natural gas required to achieve a given end

23 use. "Energy efficiency" also includes measures that reduce the

24 total Btus of electricity and natural gas needed to meet the

25 end use or uses.

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

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1 Section 16-102 of the Public Utilities Act.

2 "Facility" means an electric generating unit or a

3 co-generating unit that produces electricity along with

4 related equipment necessary to connect the facility to an

5 electric transmission or distribution system.

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

7 government that individually or collectively procure

8 electricity to serve residential retail electrical loads

9 located within its or their jurisdiction.

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

11 defined in Section 1 of Article VII of the Illinois

12 Constitution.

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

14 town.

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

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

17 limited liability company, joint stock company, or association

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

19 representative thereof.

20 "Nameplate capacity" means the aggregate inverter

21 nameplate capacity in kilowatts AC.

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

23 a facility.

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

25 Section 3-105 of the Public Utilities Act.

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

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1 all structures, fixtures, and improvements thereon, including

2 lands under water and riparian rights, any easements,

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

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

5 other claims or security interests related to real property.

6 "Renewable energy credit" means a tradable credit that

7 represents the environmental attributes of one megawatt hour ~~a~~

8 ~~certain amount~~ of energy produced from a renewable energy

9 generating facility ~~resource~~.

10 "Renewable energy resources" includes energy and its

11 associated renewable energy credit or renewable energy credits

12 from wind, solar thermal energy, photovoltaic cells and panels,

13 biodiesel, anaerobic digestion, crops and untreated and

14 unadulterated organic waste biomass, tree waste, hydropower

15 that does not involve new construction or significant expansion

16 of hydropower dams, and other alternative sources of

17 environmentally preferable energy. For purposes of this Act,

18 landfill gas produced in the State is considered a renewable

19 energy resource. "Renewable energy resources" does not include

20 the incineration or burning of tires, garbage, general

21 household, institutional, and commercial waste, industrial

22 lunchroom or office waste, landscape waste other than tree

23 waste, railroad crossties, utility poles, or construction or

24 demolition debris, other than untreated and unadulterated

25 waste wood.

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

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1 indebtedness issued by the Authority, the principal and

2 interest of which is payable solely from revenues or income

3 derived from any project or activity of the Agency.

4 "Sequester" means permanent storage of carbon dioxide by

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

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

7 recovery process that may involve intermediate storage,

8 regardless of whether these activities are conducted by a clean

9 coal facility, a clean coal SNG facility, a clean coal SNG

10 brownfield facility, or a party with which a clean coal

11 facility, clean coal SNG facility, or clean coal SNG brownfield

12 facility has contracted for such purposes.

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

14 16-102 of the Public Utilities Act.

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

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

17 facility and such electric utility, which agreement shall have

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

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

20 alternative retail electric supplier, an agreement between the

21 owner of a clean coal facility and such alternative retail

22 electric supplier, which agreement shall have terms and

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

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

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

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

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1 terms and conditions meeting the requirements of subsection

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

3 "Standard wholesale product" means any type of product that

4 is routinely traded in a liquid regional wholesale market,

5 including, but not limited to, energy or demand-side resources.

6 "Subscriber" means any customer that takes delivery

7 service from an electric utility who owns one or more

8 subscriptions to a community solar project and who has

9 identified an individual billing meter within the same electric

10 utility service territory as the community solar project is

11 located to which each subscription shall be attributed. Each

12 subscriber to a single community solar project must have a

13 separate legal or corporate identity, and no subscriber's

14 subscriptions may total more than 40% of an individual

15 community solar project.

16 "Subscription" means a percentage interest in a community

17 solar project. Each subscription shall represent a percentage

18 of the community solar project's generating capacity, provided

19 that the subscription is intended to primarily offset part or

20 all of the subscriber's electricity usage.

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

22 by gasification of hydrocarbon feedstock, which is

23 substantially interchangeable in use and distribution with

24 conventional natural gas.

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

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

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

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

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

4 present value of the total costs as calculated over the

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

6 the sum of avoided electric utility costs, representing the

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

8 delivery of those efficiency measures, including avoided

9 energy costs, avoided generating capacity costs, avoided

10 transmission and distribution system investments and price

11 suppression effects, as well as other quantifiable societal

12 benefits, including avoided natural gas utility costs, other

13 avoided energy costs, and reasonable estimates of non-energy

14 benefits, such as the health, safety, comfort, operation and

15 maintenance, business productivity, and financial security

16 benefits to low-income and moderate-income customers of

17 efficiency investments, to the sum of all incremental costs of

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

19 (including both utility and participant contributions), plus

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

21 program, to quantify the net savings obtained by substituting

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

23 avoided costs of power and energy that an electric utility

24 would otherwise have had to acquire, reasonable estimates shall

25 be included of financial costs likely to be imposed by future

26 regulations and legislation on emissions of greenhouse gases.

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1 In discounting future costs and benefits for the purpose of

2 computing net present values, a societal discount rate based on

3 real, long-term Treasury bond yields or other appropriate

4 indictors should be used.

5 (Source: P.A. 97-96, eff. 7-13-11; 97-239, eff. 8-2-11; 97-491,

6 eff. 8-22-11; 97-616, eff. 10-26-11; 97-813, eff. 7-13-12;

7 98-90, eff. 7-15-13.)

8 (20 ILCS 3855/1-20)

9 Sec. 1-20. General powers of the Agency.

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

11 (1) Develop electricity procurement plans to ensure

12 adequate, reliable, affordable, efficient, and

13 environmentally sustainable electric service at the lowest

14 total cost over time, taking into account any benefits of

15 price stability, for electric utilities that on December

16 31, 2005 provided electric service to at least 100,000

17 customers in Illinois and for small multi-jurisdictional

18 electric utilities that (A) on December 31, 2005 served

19 less than 100,000 customers in Illinois and (B) request a

20 procurement plan for their Illinois jurisdictional load.

21 The electricity procurement plans shall be updated on an

22 annual basis and shall, until May 31, 2016, include

23 electricity generated from renewable resources sufficient

24 to achieve the standards specified in this Act and shall

25 include energy efficiency and demand response resources

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1 identified under Sections 16-108.5, 16-111.5, and

2 16-111.5B of the Public Utilities Act.

3 (1.5) Beginning with the planning process for the plan

4 or plans to be implemented in the 2016 delivery year,

5 develop a long-term renewable resources procurement plan

6 in accordance with subdivision (c) of Section 1-75 of this

7 Act for renewable energy credits in amounts sufficient to

8 achieve the standards specified in this Act for all

9 customers taking delivery service from an electric

10 utility.

11 (2) Conduct competitive procurement processes to

12 procure the supply resources identified in the electricity

13 procurement plan, pursuant to Section 16-111.5 of the

14 Public Utilities Act.

15 Beginning with the 2016 delivery year, conduct

16 competitive procurement processes and implement programs

17 to procure renewable energy credits identified in the

18 long-term renewable resources procurement plan developed

19 pursuant to subdivision (c) of Section 1-75 of this Act and

20 procured pursuant to Section 16-111.5C of the Public

21 Utilities Act.

22 (3) Develop electric generation and co-generation

23 facilities that use indigenous coal or renewable

24 resources, or both, financed with bonds issued by the

25 Illinois Finance Authority.

26 (4) Supply electricity from the Agency's facilities at

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1 cost to one or more of the following: municipal electric

2 systems, governmental aggregators, or rural electric

3 cooperatives in Illinois.

4 (b) Except as otherwise limited by this Act, the Agency has

5 all of the powers necessary or convenient to carry out the

6 purposes and provisions of this Act, including without

7 limitation, each of the following:

8 (1) To have a corporate seal, and to alter that seal at

9 pleasure, and to use it by causing it or a facsimile to be

10 affixed or impressed or reproduced in any other manner.

11 (2) To use the services of the Illinois Finance

12 Authority necessary to carry out the Agency's purposes.

13 (3) To negotiate and enter into loan agreements and

14 other agreements with the Illinois Finance Authority.

15 (4) To obtain and employ personnel and hire consultants

16 that are necessary to fulfill the Agency's purposes, and to

17 make expenditures for that purpose within the

18 appropriations for that purpose.

19 (5) To purchase, receive, take by grant, gift, devise,

20 bequest, or otherwise, lease, or otherwise acquire, own,

21 hold, improve, employ, use, and otherwise deal in and with,

22 real or personal property whether tangible or intangible,

23 or any interest therein, within the State.

24 (6) To acquire real or personal property, whether

25 tangible or intangible, including without limitation

26 property rights, interests in property, franchises,

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1 obligations, contracts, and debt and equity securities,

2 and to do so by the exercise of the power of eminent domain

3 in accordance with Section 1-21; except that any real

4 property acquired by the exercise of the power of eminent

5 domain must be located within the State.

6 (7) To sell, convey, lease, exchange, transfer,

7 abandon, or otherwise dispose of, or mortgage, pledge, or

8 create a security interest in, any of its assets,

9 properties, or any interest therein, wherever situated.

10 (8) To purchase, take, receive, subscribe for, or

11 otherwise acquire, hold, make a tender offer for, vote,

12 employ, sell, lend, lease, exchange, transfer, or

13 otherwise dispose of, mortgage, pledge, or grant a security

14 interest in, use, and otherwise deal in and with, bonds and

15 other obligations, shares, or other securities (or

16 interests therein) issued by others, whether engaged in a

17 similar or different business or activity.

18 (9) To make and execute agreements, contracts, and

19 other instruments necessary or convenient in the exercise

20 of the powers and functions of the Agency under this Act,

21 including contracts with any person, including personal

22 service contracts, or with any local government, State

23 agency, or other entity; and all State agencies and all

24 local governments are authorized to enter into and do all

25 things necessary to perform any such agreement, contract,

26 or other instrument with the Agency. No such agreement,

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1 contract, or other instrument shall exceed 40 years.

2 (10) To lend money, invest and reinvest its funds in

3 accordance with the Public Funds Investment Act, and take

4 and hold real and personal property as security for the

5 payment of funds loaned or invested.

6 (11) To borrow money at such rate or rates of interest

7 as the Agency may determine, issue its notes, bonds, or

8 other obligations to evidence that indebtedness, and

9 secure any of its obligations by mortgage or pledge of its

10 real or personal property, machinery, equipment,

11 structures, fixtures, inventories, revenues, grants, and

12 other funds as provided or any interest therein, wherever

13 situated.

14 (12) To enter into agreements with the Illinois Finance

15 Authority to issue bonds whether or not the income

16 therefrom is exempt from federal taxation.

17 (13) To procure insurance against any loss in

18 connection with its properties or operations in such amount

19 or amounts and from such insurers, including the federal

20 government, as it may deem necessary or desirable, and to

21 pay any premiums therefor.

22 (14) To negotiate and enter into agreements with

23 trustees or receivers appointed by United States

24 bankruptcy courts or federal district courts or in other

25 proceedings involving adjustment of debts and authorize

26 proceedings involving adjustment of debts and authorize

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1 legal counsel for the Agency to appear in any such

2 proceedings.

3 (15) To file a petition under Chapter 9 of Title 11 of

4 the United States Bankruptcy Code or take other similar

5 action for the adjustment of its debts.

6 (16) To enter into management agreements for the

7 operation of any of the property or facilities owned by the

8 Agency.

9 (17) To enter into an agreement to transfer and to

10 transfer any land, facilities, fixtures, or equipment of

11 the Agency to one or more municipal electric systems,

12 governmental aggregators, or rural electric agencies or

13 cooperatives, for such consideration and upon such terms as

14 the Agency may determine to be in the best interest of the

15 citizens of Illinois.

16 (18) To enter upon any lands and within any building

17 whenever in its judgment it may be necessary for the

18 purpose of making surveys and examinations to accomplish

19 any purpose authorized by this Act.

20 (19) To maintain an office or offices at such place or

21 places in the State as it may determine.

22 (20) To request information, and to make any inquiry,

23 investigation, survey, or study that the Agency may deem

24 necessary to enable it effectively to carry out the

25 provisions of this Act.

26 (21) To accept and expend appropriations.

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1 (22) To engage in any activity or operation that is

2 incidental to and in furtherance of efficient operation to

3 accomplish the Agency's purposes, including hiring

4 employees that the Director deems essential for the

5 operations of the Agency.

6 (23) To adopt, revise, amend, and repeal rules with

7 respect to its operations, properties, and facilities as

8 may be necessary or convenient to carry out the purposes of

9 this Act, subject to the provisions of the Illinois

10 Administrative Procedure Act and Sections 1-22 and 1-35 of

11 this Act.

12 (24) To establish and collect charges and fees as

13 described in this Act.

14 (25) To conduct competitive gasification feedstock

15 procurement processes to procure the feedstocks for the

16 clean coal SNG brownfield facility in accordance with the

17 requirements of Section 1-78 of this Act.

18 (26) To review, revise, and approve sourcing

19 agreements and mediate and resolve disputes between gas

20 utilities and the clean coal SNG brownfield facility

21 pursuant to subsection (h-1) of Section 9-220 of the Public

22 Utilities Act or to fulfill its responsibilities for

23 developing energy efficiency potential studies as required

24 under subsection (f) of Section 8-103 of the Public

25 Utilities Act.

26 (Source: P.A. 96-784, eff. 8-28-09; 96-1000, eff. 7-2-10;

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1 97-96, eff. 7-13-11; 97-325, eff. 8-12-11; 97-618, eff.

2 10-26-11; 97-813, eff. 7-13-12.)

3 (20 ILCS 3855/1-56)

4 Sec. 1-56. Illinois Power Agency Renewable Energy

5 Resources Fund.

6 (a) The Illinois Power Agency Renewable Energy Resources

7 Fund is created as a special fund in the State treasury.

8 (b) The Illinois Power Agency Renewable Energy Resources

9 Fund shall be administered by the Agency for the following

10 purposes:

11 (1) to purchase renewable energy credits according to

12 any approved procurement plan developed by the Agency prior

13 to June 1, 2016; and

14 (2) to purchase renewable energy credits and pay for

15 other applicable expenses as part of a low-income solar

16 program; the Agency shall create a low-income solar program

17 with the objective of bringing solar photovoltaics to

18 low-income communities in a manner that maximizes the

19 development of new renewable energy generating facilities,

20 provides workforce development opportunities within

21 low-income communities, creates a long-term, low-income

22 solar marketplace throughout Illinois, and minimizes

23 administrative costs; the Agency shall include the

24 low-income solar program as part of the long-term renewable

25 resources procurement plan authorized by subdivision (c)

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1 of Section 1-75 of this Act, and the program shall be

2 designed to grow the low-income solar market over at least

3 10 years; for this program, the Agency shall purchase

4 renewable energy credits from either (i) photovoltaic

5 distributed renewable energy generation devices or (ii)

6 community solar projects. The electricity generated by

7 each distributed generation device or community solar

8 project must primarily be used to offset the electricity

9 usage of (i) lower-income households, (ii) properties

10 where the majority of occupants are lower-income

11 households, (iii) public sector buildings that primarily

12 serve lower-income households, or (iv) not-for-profit

13 corporations that primarily serve lower-income households.

14 As used in this subsection (b), "lower-income households"

15 means persons and families whose income does not exceed 80% of

16 area median income, adjusted for family size and revised every

17 5 years.

18 Administrative costs associated with the low-income solar

19 program, including, but not limited to, the Agency's general

20 administrative expenses associated with developing and

21 operating the program, costs associated with the program

22 manager referenced in this Section, and costs related to the

23 evaluation of the low-income solar program, may be paid for

24 using the Illinois Power Agency Renewable Energy Resources

25 Fund, but the Agency and program manager shall strive to

26 minimize administrative expenses in the implementation of the

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1 program.

2 The Agency shall purchase renewable energy credits through

3 an upfront payment per kilowatt of installed nameplate capacity

4 paid once the device is energized. The payment shall be in

5 exchange for an assignment of all renewable energy credits

6 generated by the system during the first 15 years of operation

7 and shall be structured to overcome barriers to participation

8 in the solar market by the low-income community. The Agency

9 shall retire any renewable energy credits purchased from this

10 program and shall use the renewable energy credits to reduce

11 the obligation under subdivision (c) of Section 1-75 of this

12 Act for the electric utility to which the project is

13 interconnected.

14 The Agency shall establish the low-income solar program

15 terms, conditions, and requirements, including the initial

16 purchase price of renewable energy credits, through the

17 development, review, and approval of the Agency's long-term

18 renewable resources procurement plan described in subdivision

19 (c) of Section 1-75 of this Act. The Agency may review and

20 adjust the program terms, conditions, and requirements,

21 including the price offered to new systems, to ensure the

22 long-term viability and success of the program. The Commission

23 shall review and approve any modifications to the program

24 through the periodic plan revision process described in Section

25 16-111.5C of the Public Utilities Act.

26 The Agency shall issue a request for qualifications for a

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1 third-party program manager to administer the low-income solar

2 program. The third-party program manager may be a government

3 entity or a not-for-profit corporation and shall be chosen

4 through a competitive bid process based on selection criteria

5 and requirements developed by the Agency. In selecting a

6 program manager, the Agency shall consider a bidder's

7 experience in (i) administering low-income energy programs

8 with evidence of strong consumer protection, (ii) providing

9 low-income job training opportunities, and (iii) providing or

10 overseeing solar installation or energy efficiency services.

11 At least every 2 years, the Commission shall select an

12 independent evaluator to review and report on the low-income

13 solar program and the performance of the third-party program

14 manager of the low-income solar program. The report shall

15 include the number of projects installed, the total installed

16 capacity in kilowatts, the average cost per kilowatt of

17 installed capacity, the total number of jobs or job training

18 opportunities, and other economic, social and environmental

19 benefits created, and the total administrative costs expended

20 by the Agency and program manager to implement and evaluate the

21 program. The report shall be delivered to the Commission and

22 posted on the Agency's website and used, as needed, to revise

23 the low-income solar program.

24 The low-income solar program manager shall administer the

25 low-income solar program, which shall include the development

26 of standard contract forms, the development and implementation

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1 of a marketing and outreach program for eligible low-income

2 customers, and providing solar installation services,

3 including subcontractor solicitations when necessary. The

4 low-income solar program shall also include energy efficiency

5 referral and education services, solar job training and

6 workforce development opportunities, and consumer protection

7 provisions.

8 (b-5) Upon the submission of all payments required by

9 Section 16-115D of the Public Utilities Act, no funds shall be

10 deposited into the Illinois Power Agency Renewable Energy

11 Resources Fund unless directed by order of the Commission.

12 (b-10) Upon the balance of the Illinois Power Agency

13 Renewable Energy Resources Fund falling below $5,000, the Fund

14 shall be terminated, and any remaining funds shall be

15 transferred to the Low Income Home Energy Assistance Program,

16 as authorized by the Energy Assistance Act.

17 ~~to procure renewable energy resources. Prior to June 1, 2011,~~

18 ~~resources procured pursuant to this Section shall be procured~~

19 ~~from facilities located in Illinois, provided the resources are~~

20 ~~available from those facilities. If resources are not available~~

21 ~~in Illinois, then they shall be procured in states that adjoin~~

22 ~~Illinois. If resources are not available in Illinois or in~~

23 ~~states that adjoin Illinois, then they may be purchased~~

24 ~~elsewhere. Beginning June 1, 2011, resources procured pursuant~~

25 ~~to this Section shall be procured from facilities located in~~

26 ~~Illinois or states that adjoin Illinois. If resources are not~~

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1 ~~available in Illinois or in states that adjoin Illinois, then~~

2 ~~they may be procured elsewhere. To the extent available, at~~

3 ~~least 75% of these renewable energy resources shall come from~~

4 ~~wind generation. Of the renewable energy resources procured~~

5 ~~pursuant to this Section at least the following specified~~

6 ~~percentages shall come from photovoltaics on the following~~

7 ~~schedule: 0.5% by June 1, 2012; 1.5% by June 1, 2013; 3% by~~

8 ~~June 1, 2014; and 6% by June 1, 2015 and thereafter. Of the~~

9 ~~renewable energy resources procured pursuant to this Section,~~

10 ~~at least the following percentages shall come from distributed~~

11 ~~renewable energy generation devices: 0.5% by June 1, 2013,~~

12 ~~0.75% by June 1, 2014, and 1% by June 1, 2015 and thereafter.~~

13 ~~To the extent available, half of the renewable energy resources~~

14 ~~procured from distributed renewable energy generation shall~~

15 ~~come from devices of less than 25 kilowatts in nameplate~~

16 ~~capacity. Renewable energy resources procured from distributed~~

17 ~~generation devices may also count towards the required~~

18 ~~percentages for wind and solar photovoltaics. Procurement of~~

19 ~~renewable energy resources from distributed renewable energy~~

20 ~~generation devices shall be done on an annual basis through~~

21 ~~multi-year contracts of no less than 5 years, and shall consist~~

22 ~~solely of renewable energy credits.~~

23 ~~The Agency shall create credit requirements for suppliers~~

24 ~~of distributed renewable energy. In order to minimize the~~

25 ~~administrative burden on contracting entities, the Agency~~

26 ~~shall solicit the use of third-party organizations to aggregate~~

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1 ~~distributed renewable energy into groups of no less than one~~

2 ~~megawatt in installed capacity. These third-party~~

3 ~~organizations shall administer contracts with individual~~

4 ~~distributed renewable energy generation device owners. An~~

5 ~~individual distributed renewable energy generation device~~

6 ~~owner shall have the ability to measure the output of his or~~

7 ~~her distributed renewable energy generation device.~~

8 (c) (Blank). ~~The Agency shall procure renewable energy~~

9 ~~resources at least once each year in conjunction with a~~

10 ~~procurement event for electric utilities required to comply~~

11 ~~with Section 1-75 of the Act and shall, whenever possible,~~

12 ~~enter into long-term contracts on an annual basis for a portion~~

13 ~~of the incremental requirement for the given procurement year.~~

14 (d) (Blank). ~~The price paid to procure renewable energy~~

15 ~~credits using monies from the Illinois Power Agency Renewable~~

16 ~~Energy Resources Fund shall not exceed the winning bid prices~~

17 ~~paid for like resources procured for electric utilities~~

18 ~~required to comply with Section 1-75 of this Act.~~

19 (e) All renewable energy credits procured using monies from

20 the Illinois Power Agency Renewable Energy Resources Fund shall

21 be permanently retired.

22 (f) The selection of the third-party program manager, the

23 selection of the independent evaluator, and the procurement

24 process described in this Section are exempt from the

25 requirements of Section 20-10 of the Illinois Procurement Code.

26 ~~The procurement process described in this Section is exempt~~

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1 ~~from the requirements of the Illinois Procurement Code,~~

2 ~~pursuant to Section 20-10 of that Code.~~

3 (g) All disbursements from the Illinois Power Agency

4 Renewable Energy Resources Fund shall be made only upon

5 warrants of the Comptroller drawn upon the Treasurer as

6 custodian of the Fund upon vouchers signed by the Director or

7 by the person or persons designated by the Director for that

8 purpose. The Comptroller is authorized to draw the warrant upon

9 vouchers so signed. The Treasurer shall accept all warrants so

10 signed and shall be released from liability for all payments

11 made on those warrants.

12 (h) The Illinois Power Agency Renewable Energy Resources

13 Fund shall not be subject to sweeps, administrative charges, or

14 chargebacks, including, but not limited to, those authorized

15 under Section 8h of the State Finance Act, that would in any

16 way result in the transfer of any funds from this Fund to any

17 other fund of this State or in having any such funds utilized

18 for any purpose other than the express purposes set forth in

19 this Section.

20 (i) Supplemental procurement process.

21 (1) Within 90 days after the effective date of this

22 amendatory Act of the 98th General Assembly, the Agency

23 shall develop a one-time supplemental procurement plan

24 limited to the procurement of renewable energy credits, if

25 available, from new or existing photovoltaics, including,

26 but not limited to, distributed photovoltaic generation.

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1 Nothing in this subsection (i) requires procurement of wind

2 generation through the supplemental procurement.

3 Renewable energy credits procured from new

4 photovoltaics, including, but not limited to, distributed

5 photovoltaic generation, under this subsection (i) must be

6 procured from devices installed by a qualified person. In

7 its supplemental procurement plan, the Agency shall

8 establish contractually enforceable mechanisms for

9 ensuring that the installation of new photovoltaics is

10 performed by a qualified person.

11 For the purposes of this paragraph (1), "qualified

12 person" means a person who performs installations of

13 photovoltaics, including, but not limited to, distributed

14 photovoltaic generation, and who: (A) has completed an

15 apprenticeship as a journeyman electrician from a United

16 States Department of Labor registered electrical

17 apprenticeship and training program and received a

18 certification of satisfactory completion; or (B) does not

19 currently meet the criteria under clause (A) of this

20 paragraph (1), but is enrolled in a United States

21 Department of Labor registered electrical apprenticeship

22 program, provided that the person is directly supervised by

23 a person who meets the criteria under clause (A) of this

24 paragraph (1); or (C) has obtained one of the following

25 credentials in addition to attesting to satisfactory

26 completion of at least 5 years or 8,000 hours of documented

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1 hands-on electrical experience: (i) a North American Board

2 of Certified Energy Practitioners (NABCEP) Installer

3 Certificate for Solar PV; (ii) an Underwriters

4 Laboratories (UL) PV Systems Installer Certificate; (iii)

5 an Electronics Technicians Association, International

6 (ETAI) Level 3 PV Installer Certificate; or (iv) an

7 Associate in Applied Science degree from an Illinois

8 Community College Board approved community college program

9 in renewable energy or a distributed generation

10 technology.

11 For the purposes of this paragraph (1), "directly

12 supervised" means that there is a qualified person who

13 meets the qualifications under clause (A) of this paragraph

14 (1) and who is available for supervision and consultation

15 regarding the work performed by persons under clause (B) of

16 this paragraph (1), including a final inspection of the

17 installation work that has been directly supervised to

18 ensure safety and conformity with applicable codes.

19 For the purposes of this paragraph (1), "install" means

20 the major activities and actions required to connect, in

21 accordance with applicable building and electrical codes,

22 the conductors, connectors, and all associated fittings,

23 devices, power outlets, or apparatuses mounted at the

24 premises that are directly involved in delivering energy to

25 the premises' electrical wiring from the photovoltaics,

26 including, but not limited to, to distributed photovoltaic

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1 generation.

2 The renewable energy credits procured pursuant to the

3 supplemental procurement plan shall be procured using up to

4 $30,000,000 from the Illinois Power Agency Renewable

5 Energy Resources Fund. The Agency shall not plan to use

6 funds from the Illinois Power Agency Renewable Energy

7 Resources Fund in excess of the monies on deposit in such

8 fund or projected to be deposited into such fund. The

9 supplemental procurement plan shall ensure adequate,

10 reliable, affordable, efficient, and environmentally

11 sustainable renewable energy resources (including credits)

12 at the lowest total cost over time, taking into account any

13 benefits of price stability.

14 To the extent available, 50% of the renewable energy

15 credits procured from distributed renewable energy

16 generation shall come from devices of less than 25

17 kilowatts in nameplate capacity. Procurement of renewable

18 energy credits from distributed renewable energy

19 generation devices shall be done through multi-year

20 contracts of no less than 5 years. The Agency shall create

21 credit requirements for counterparties. In order to

22 minimize the administrative burden on contracting

23 entities, the Agency shall solicit the use of third parties

24 to aggregate distributed renewable energy. These third

25 parties shall enter into and administer contracts with

26 individual distributed renewable energy generation device

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1 owners. An individual distributed renewable energy

2 generation device owner shall have the ability to measure

3 the output of his or her distributed renewable energy

4 generation device.

5 In developing the supplemental procurement plan, the

6 Agency shall hold at least one workshop open to the public

7 within 90 days after the effective date of this amendatory

8 Act of the 98th General Assembly and shall consider any

9 comments made by stakeholders or the public. Upon

10 development of the supplemental procurement plan within

11 this 90-day period, copies of the supplemental procurement

12 plan shall be posted and made publicly available on the

13 Agency's and Commission's websites. All interested parties

14 shall have 14 days following the date of posting to provide

15 comment to the Agency on the supplemental procurement plan.

16 All comments submitted to the Agency shall be specific,

17 supported by data or other detailed analyses, and, if

18 objecting to all or a portion of the supplemental

19 procurement plan, accompanied by specific alternative

20 wording or proposals. All comments shall be posted on the

21 Agency's and Commission's websites. Within 14 days

22 following the end of the 14-day review period, the Agency

23 shall revise the supplemental procurement plan as

24 necessary based on the comments received and file its

25 revised supplemental procurement plan with the Commission

26 for approval.

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1 (2) Within 5 days after the filing of the supplemental

2 procurement plan at the Commission, any person objecting to

3 the supplemental procurement plan shall file an objection

4 with the Commission. Within 10 days after the filing, the

5 Commission shall determine whether a hearing is necessary.

6 The Commission shall enter its order confirming or

7 modifying the supplemental procurement plan within 90 days

8 after the filing of the supplemental procurement plan by

9 the Agency.

10 (3) The Commission shall approve the supplemental

11 procurement plan of renewable energy credits to be procured

12 from new or existing photovoltaics, including, but not

13 limited to, distributed photovoltaic generation, if the

14 Commission determines that it will ensure adequate,

15 reliable, affordable, efficient, and environmentally

16 sustainable electric service in the form of renewable

17 energy credits at the lowest total cost over time, taking

18 into account any benefits of price stability.

19 (4) The supplemental procurement process under this

20 subsection (i) shall include each of the following

21 components:

22 (A) Procurement administrator. The Agency may

23 retain a procurement administrator in the manner set

24 forth in item (2) of subsection (a) of Section 1-75 of

25 this Act to conduct the supplemental procurement or may

26 elect to use the same procurement administrator

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1 administering the Agency's annual procurement under

2 Section 1-75.

3 (B) Procurement monitor. The procurement monitor

4 retained by the Commission pursuant to Section

5 16-111.5 of the Public Utilities Act shall:

6 (i) monitor interactions among the procurement

7 administrator and bidders and suppliers;

8 (ii) monitor and report to the Commission on

9 the progress of the supplemental procurement

10 process;

11 (iii) provide an independent confidential

12 report to the Commission regarding the results of

13 the procurement events;

14 (iv) assess compliance with the procurement

15 plan approved by the Commission for the

16 supplemental procurement process;

17 (v) preserve the confidentiality of supplier

18 and bidding information in a manner consistent

19 with all applicable laws, rules, regulations, and

20 tariffs;

21 (vi) provide expert advice to the Commission

22 and consult with the procurement administrator

23 regarding issues related to procurement process

24 design, rules, protocols, and policy-related

25 matters;

26 (vii) consult with the procurement

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1 administrator regarding the development and use of

2 benchmark criteria, standard form contracts,

3 credit policies, and bid documents; and

4 (viii) perform, with respect to the

5 supplemental procurement process, any other

6 procurement monitor duties specifically delineated

7 within subsection (i) of this Section.

8 (C) Solicitation, pre-qualification, and

9 registration of bidders. The procurement administrator

10 shall disseminate information to potential bidders to

11 promote a procurement event, notify potential bidders

12 that the procurement administrator may enter into a

13 post-bid price negotiation with bidders that meet the

14 applicable benchmarks, provide supply requirements,

15 and otherwise explain the competitive procurement

16 process. In addition to such other publication as the

17 procurement administrator determines is appropriate,

18 this information shall be posted on the Agency's and

19 the Commission's websites. The procurement

20 administrator shall also administer the

21 prequalification process, including evaluation of

22 credit worthiness, compliance with procurement rules,

23 and agreement to the standard form contract developed

24 pursuant to item (D) of this paragraph (4). The

25 procurement administrator shall then identify and

26 register bidders to participate in the procurement

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1 event.

2 (D) Standard contract forms and credit terms and

3 instruments. The procurement administrator, in

4 consultation with the Agency, the Commission, and

5 other interested parties and subject to Commission

6 oversight, shall develop and provide standard contract

7 forms for the supplier contracts that meet generally

8 accepted industry practices as well as include any

9 applicable State of Illinois terms and conditions that

10 are required for contracts entered into by an agency of

11 the State of Illinois. Standard credit terms and

12 instruments that meet generally accepted industry

13 practices shall be similarly developed. Contracts for

14 new photovoltaics shall include a provision attesting

15 that the supplier will use a qualified person for the

16 installation of the device pursuant to paragraph (1) of

17 subsection (i) of this Section. The procurement

18 administrator shall make available to the Commission

19 all written comments it receives on the contract forms,

20 credit terms, or instruments. If the procurement

21 administrator cannot reach agreement with the parties

22 as to the contract terms and conditions, the

23 procurement administrator must notify the Commission

24 of any disputed terms and the Commission shall resolve

25 the dispute. The terms of the contracts shall not be

26 subject to negotiation by winning bidders, and the

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1 bidders must agree to the terms of the contract in

2 advance so that winning bids are selected solely on the

3 basis of price.

4 (E) Requests for proposals; competitive

5 procurement process. The procurement administrator

6 shall design and issue requests for proposals to supply

7 renewable energy credits in accordance with the

8 supplemental procurement plan, as approved by the

9 Commission. The requests for proposals shall set forth

10 a procedure for sealed, binding commitment bidding

11 with pay-as-bid settlement, and provision for

12 selection of bids on the basis of price, provided,

13 however, that no bid shall be accepted if it exceeds

14 the benchmark developed pursuant to item (F) of this

15 paragraph (4).

16 (F) Benchmarks. Benchmarks for each product to be

17 procured shall be developed by the procurement

18 administrator in consultation with Commission staff,

19 the Agency, and the procurement monitor for use in this

20 supplemental procurement.

21 (G) A plan for implementing contingencies in the

22 event of supplier default, Commission rejection of

23 results, or any other cause.

24 (5) Within 2 business days after opening the sealed

25 bids, the procurement administrator shall submit a

26 confidential report to the Commission. The report shall

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1 contain the results of the bidding for each of the products

2 along with the procurement administrator's recommendation

3 for the acceptance and rejection of bids based on the price

4 benchmark criteria and other factors observed in the

5 process. The procurement monitor also shall submit a

6 confidential report to the Commission within 2 business

7 days after opening the sealed bids. The report shall

8 contain the procurement monitor's assessment of bidder

9 behavior in the process as well as an assessment of the

10 procurement administrator's compliance with the

11 procurement process and rules. The Commission shall review

12 the confidential reports submitted by the procurement

13 administrator and procurement monitor and shall accept or

14 reject the recommendations of the procurement

15 administrator within 2 business days after receipt of the

16 reports.

17 (6) Within 3 business days after the Commission

18 decision approving the results of a procurement event, the

19 Agency shall enter into binding contractual arrangements

20 with the winning suppliers using the standard form

21 contracts.

22 (7) The names of the successful bidders and the average

23 of the winning bid prices for each contract type and for

24 each contract term shall be made available to the public

25 within 2 days after the supplemental procurement event. The

26 Commission, the procurement monitor, the procurement

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1 administrator, the Agency, and all participants in the

2 procurement process shall maintain the confidentiality of

3 all other supplier and bidding information in a manner

4 consistent with all applicable laws, rules, regulations,

5 and tariffs. Confidential information, including the

6 confidential reports submitted by the procurement

7 administrator and procurement monitor pursuant to this

8 Section, shall not be made publicly available and shall not

9 be discoverable by any party in any proceeding, absent a

10 compelling demonstration of need, nor shall those reports

11 be admissible in any proceeding other than one for law

12 enforcement purposes.

13 (8) The supplemental procurement provided in this

14 subsection (i) shall not be subject to the requirements and

15 limitations of subsections (c) and (d) of this Section.

16 (9) Expenses incurred in connection with the

17 procurement process held pursuant to this Section,

18 including, but not limited to, the cost of developing the

19 supplemental procurement plan, the procurement

20 administrator, procurement monitor, and the cost of the

21 retirement of renewable energy credits purchased pursuant

22 to the supplemental procurement shall be paid for from the

23 Illinois Power Agency Renewable Energy Resources Fund. The

24 Agency shall enter into an interagency agreement with the

25 Commission to reimburse the Commission for its costs

26 associated with the procurement monitor for the

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1 supplemental procurement process.

2 (Source: P.A. 97-616, eff. 10-26-11; 98-672, eff. 6-30-14.)

3 (20 ILCS 3855/1-75)

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

5 and Procurement Bureau has the following duties and

6 responsibilities:

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

8 beginning in 2008, develop procurement plans and conduct

9 competitive procurement processes in accordance with the

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

11 for the eligible retail customers of electric utilities that on

12 December 31, 2005 provided electric service to at least 100,000

13 customers in Illinois. The Planning and Procurement Bureau

14 shall also develop procurement plans and conduct competitive

15 procurement processes in accordance with the requirements of

16 Section 16-111.5 of the Public Utilities Act for the eligible

17 retail customers of small multi-jurisdictional electric

18 utilities that (i) on December 31, 2005 served less than

19 100,000 customers in Illinois and (ii) request a procurement

20 plan for their Illinois jurisdictional load. This Section shall

21 not apply to a small multi-jurisdictional utility until such

22 time as a small multi-jurisdictional utility requests the

23 Agency to prepare a procurement plan for their Illinois

24 jurisdictional load. For the purposes of this Section, the term

25 "eligible retail customers" has the same definition as found in

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

2 Notwithstanding the requirements of this subdivision (a),

3 beginning with the planning process for the plan or plans to be

4 implemented in the 2016 delivery year, the Agency shall no

5 longer include the procurement of renewable energy resources in

6 the procurement plans required by this subdivision (a) and

7 shall instead develop a long-term renewable resources

8 procurement plan in accordance with subdivision (c) of this

9 Section.

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

11 needed, issue a request for qualifications for experts or

12 expert consulting firms to develop the procurement plans in

13 accordance with Section 16-111.5 of the Public Utilities

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

15 firm must have:

16 (A) direct previous experience assembling

17 large-scale power supply plans or portfolios for

18 end-use customers;

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

20 engineering, risk management, or a related area of

21 study;

22 (C) 10 years of experience in the electricity

23 sector, including managing supply risk;

24 (D) expertise in wholesale electricity market

25 rules, including those established by the Federal

26 Energy Regulatory Commission and regional transmission

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1 organizations;

2 (E) expertise in credit protocols and familiarity

3 with contract protocols;

4 (F) adequate resources to perform and fulfill the

5 required functions and responsibilities; and

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

7 inappropriate bias for or against potential bidders or

8 the affected electric utilities.

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

10 request for qualifications for a procurement administrator

11 to conduct the competitive procurement processes in

12 accordance with Section 16-111.5 of the Public Utilities

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

14 firm must have:

15 (A) direct previous experience administering a

16 large-scale competitive procurement process;

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

18 engineering, or a related area of study;

19 (C) 10 years of experience in the electricity

20 sector, including risk management experience;

21 (D) expertise in wholesale electricity market

22 rules, including those established by the Federal

23 Energy Regulatory Commission and regional transmission

24 organizations;

25 (E) expertise in credit and contract protocols;

26 (F) adequate resources to perform and fulfill the

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1 required functions and responsibilities; and

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

3 inappropriate bias for or against potential bidders or

4 the affected electric utilities.

5 (3) The Agency shall provide affected utilities and

6 other interested parties with the lists of qualified

7 experts or expert consulting firms identified through the

8 request for qualifications processes that are under

9 consideration to develop the procurement plans and to serve

10 as the procurement administrator. The Agency shall also

11 provide each qualified expert's or expert consulting

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

13 information provided under this subparagraph shall also be

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

15 for fees associated with supplying the information to

16 utilities and other interested parties. These parties

17 shall, within 5 business days, notify the Agency in writing

18 if they object to any experts or expert consulting firms on

19 the lists. Objections shall be based on:

20 (A) failure to satisfy qualification criteria;

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

22 (C) evidence of inappropriate bias for or against

23 potential bidders or the affected utilities.

24 The Agency shall remove experts or expert consulting

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

26 reasonable basis for an objection and provide the updated

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1 lists to the affected utilities and other interested

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

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

4 review by the Commission within 5 days thereafter by filing

5 a petition, and the Commission shall render a ruling on the

6 petition within 10 days. There is no right of appeal of the

7 Commission's ruling.

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

9 the qualified experts or expert consulting firms to develop

10 a procurement plan for the affected utilities and to serve

11 as procurement administrator.

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

13 consulting firm to develop procurement plans based on the

14 proposals submitted and shall award contracts of up to 5

15 years to those selected.

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

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

18 as procurement administrator based on the proposals

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

20 Agency's selection, the Agency shall submit another

21 recommendation within 3 days based on the proposals

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

23 expert or expert consulting firm so selected with

24 Commission approval.

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

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

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1 conduct a competitive procurement process as prescribed in

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

3 adequate, reliable, affordable, efficient, and environmentally

4 sustainable electric service at the lowest total cost over

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

6 eligible retail customers of electric utilities that on

7 December 31, 2005 provided electric service to at least 100,000

8 customers in the State of Illinois, and for eligible Illinois

9 retail customers of small multi-jurisdictional electric

10 utilities that (i) on December 31, 2005 served less than

11 100,000 customers in Illinois and (ii) request a procurement

12 plan for their Illinois jurisdictional load.

13 (c) Renewable portfolio standard.

14 (1) The Planning and Procurement Bureau shall develop a

15 long-term renewable resources procurement plan that

16 includes all renewable energy credits necessary to meet the

17 goals set forth in this subdivision (c). The long-term

18 renewable resources procurement plan shall include

19 long-term programs and competitive procurement events

20 designed to meet the renewable resources goals in this

21 subdivision (c) from the date of the plan through the 2030

22 delivery year. The initial long-term renewable resources

23 procurement plan shall be released for comment no later

24 than 120 days after the effective date of this amendatory

25 Act of the 99th General Assembly. The Agency shall review

26 and revise the long-term renewable resources procurement

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1 plan at least every 2 years. The initial long-term

2 renewable resources procurement plan and each revised plan

3 shall be subject to review and approval by the Commission

4 pursuant to Section 16-111.5C of the Public Utilities Act.

5 (1.5) The Agency shall continue to implement all

6 procurements of renewable energy credits included in all

7 prior procurement plans filed with the Commission prior to

8 June 1, 2016. Any renewable energy credits procured as a

9 result of these prior procurements, including renewable

10 energy credits as part of bundled renewable energy

11 resources, shall be used to meet the goals set forth in

12 this subdivision (c) and shall be included as resources in

13 the long-term renewable resources plan required in

14 paragraph (1) of this subdivision (c). Any costs associated

15 with the procurement of renewable energy credits as a

16 result of these prior procurements, including the cost of

17 renewable energy credits included in the cost of bundled

18 renewable energy resources, but not including any

19 renewable energy credits procured as a result of

20 procurements authorized by subsection (i) of Section 1-56

21 of this Act or paid for using funds collected as a result

22 of paragraph (5) of this subdivision (c), shall be included

23 in the total cost of renewable energy credits procured

24 pursuant to the long-term procurement plan, as limited in

25 paragraph (1.15) of this subdivision (c).

26 As used in this subdivision (c):

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1 "Bundled renewable energy resources" means electricity

2 generated by a renewable energy system and its associated

3 renewable energy credit.

4 "Cost of renewable energy credits included in the cost

5 of bundled renewable energy resources" means the

6 difference between the contract price for the bundled

7 renewable energy resources and the day-ahead locational

8 marginal price at the load zone at which the contract is

9 settled multiplied by the megawatt hours of electricity

10 generated in each hour.

11 (1.10) The cost of any renewable energy credits

12 procured through a competitive procurement event pursuant

13 to an approved plan shall not exceed benchmarks established

14 by the procurement administrator, in consultation with the

15 Commission staff, Agency staff, and the procurement

16 monitor. The benchmarks shall be based on price data for

17 similar products for the same delivery period and same

18 utility delivery hub or other utility delivery hubs after

19 adjusting for that difference. The price benchmarks may

20 also be adjusted to take into account differences between

21 the information reflected in the underlying data sources

22 and the specific products and procurement process being

23 used to procure power for the Illinois utilities. The

24 benchmarks shall be confidential, but shall be provided to

25 the Commission and shall be subject to Commission review

26 and approval prior to a procurement event.

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1 (1.15) Notwithstanding the requirements of this

2 subdivision (c), the total amount of renewable energy

3 credits procured pursuant to the long-term renewable

4 resources procurement plan shall be reduced by an amount

5 necessary to limit the annual estimated average net

6 increase due to the costs of these credits included in the

7 amounts paid by all customers taking delivery service from

8 an electric utility to no more than 2.015% of the amount

9 paid per kilowatthour by eligible retail customers during

10 the year ending May 31, 2007. For purposes of this

11 subdivision (c), the amount paid per kilowatthour means the

12 total amount paid for electric service expressed on a per

13 kilowatthour basis, including without limitation amounts

14 paid for supply, transmission, distribution, surcharges,

15 and add-on taxes.

16 (1.20) The long-term renewable resources procurement

17 plan shall include the procurement of renewable energy

18 credits in amounts equal to at least the following

19 percentages measured as a percentage of the projected

20 amount of electricity in kilowatthours to be delivered by

21 the electric utilities to all customers taking delivery

22 service from an electric utility: 11.5% by the 2016

23 delivery year, and increasing by at least 1.5% each

24 delivery year thereafter to at least 25% by the 2025

25 delivery year; and increasing at least 2% each delivery

26 year thereafter to at least 35% by the 2030 delivery year,

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1 continuing at that percentage for each delivery year

2 thereafter.

3 (A) By the end of the 2020 delivery year:

4 (i) 75% of the total renewable energy credits

5 procured shall come from wind generation, of which

6 at least 25% shall come from new wind projects; and

7 (ii) 5% of the total renewable energy credits

8 procured or the equivalent amount of renewable

9 energy credits from 1,000 megawatts of solar

10 photovoltaic nameplate capacity, whichever is

11 larger, shall come from new photovoltaic projects;

12 of that amount, to the extent possible, the Agency

13 shall procure 75% from photovoltaic projects using

14 the program outlined in paragraph (1.25) of this

15 subdivision (c) from distributed renewable energy

16 devices or community solar projects and shall give

17 preference to brownfield solar projects that are

18 not community solar projects for the remaining

19 25%.

20 (B) By the end of the 2025 delivery year:

21 (i) 75% of the total renewable energy credits

22 procured shall come from wind generation, of which

23 at least 25% shall come from new wind projects; and

24 (ii) 6% of the total renewable energy credits

25 procured or the equivalent amount of renewable

26 energy credits from 1,500 megawatts of solar

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1 photovoltaic nameplate capacity, whichever is

2 larger, shall come from new photovoltaic projects;

3 of that amount, to the extent possible the Agency

4 shall procure 75% from photovoltaic projects using

5 the program outlined in paragraph (1.25) of this

6 subdivision (c) from distributed renewable energy

7 devices or community solar projects and shall give

8 preference to brownfield solar projects that are

9 not community solar projects for the remaining

10 25%.

11 (C) By the end of the 2030 delivery year:

12 (i) 75% of the total renewable energy credits

13 procured shall come from wind generation, of which

14 at least 25% shall come from new wind projects; and

15 (ii) 7% of the total renewable energy credits

16 procured or the equivalent amount of renewable

17 energy credits from 2,000 megawatts of solar

18 photovoltaic nameplate capacity, whichever is

19 larger, shall come from new photovoltaic projects;

20 of that amount, to the extent possible the Agency

21 shall procure 75% from photovoltaic projects using

22 the program outlined in paragraph (1.25) of this

23 subdivision (c) from distributed renewable energy

24 devices or community solar projects and shall give

25 preference to brownfield solar projects that are

26 not community solar projects for the remaining

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1 25%.

2 Renewable energy credits are eligible to be counted

3 toward the renewable energy requirements of this

4 subsection (c) if the renewable energy facility is located

5 in Illinois, if the facility has a generator

6 interconnection agreement with PJM or MISO, or if the

7 renewable energy facility is located in the United States

8 and the output of the facility is delivered to a

9 transmission asset that is controlled by PJM or MISO, where

10 "delivered" means the generated output of the facility has

11 been demonstrated to have a distribution factor of 25% or

12 greater on the transmission asset of PJM or MISO, and where

13 "distribution factor" means a measurement of the

14 sensitivity of the flow of electricity from a renewable

15 energy generator to a consuming load on a transmission

16 asset under the control of MISO or PJM. In procuring

17 renewable energy credits, the Agency may consider bid

18 selection criteria that include public interest factors,

19 such as the potential to increase fuel and resource

20 diversity in Illinois, enhance system reliability and

21 resiliency, and contribute to a cleaner and healthier

22 environment for the citizens of Illinois. In its long-term

23 plan, the Agency shall develop the method for incorporating

24 these public interest factors, in addition to bid price,

25 into its bid selection process. The Agency's method may

26 include, but may not be limited to, quantitatively scoring

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1 the evaluation of individual bids under public interest

2 criteria or the establishment of procurement minimums for

3 project categories informed by the public interest factors

4 described in this paragraph (1.15).

5 In the event that the rate impact cap in paragraph

6 (1.15) of this subdivision (c) prevents the Agency from

7 meeting all of the percentage goals in this subdivision

8 (c), the Agency shall prioritize compliance with the goals

9 for new wind and photovoltaic projects.

10 As used in this paragraph (1.20):

11 "New wind projects" means wind renewable energy

12 projects (i) that begin energy delivery no earlier than 3

13 years prior to the procurement date and (ii) for projects

14 located within Illinois, for which the owner of the project

15 has certified that not less than the prevailing wage was or

16 will be paid to employees who are engaged in construction

17 activities associated with the project.

18 "New photovoltaic projects" means photovoltaic

19 renewable energy projects (i) that are interconnected at

20 the distribution system level of either an electric

21 utility, a municipal utility as defined in Section 3-105 of

22 the Public Utilities Act, or a rural electric cooperative

23 as defined in Section 3-119 of the Public Utilities Act,

24 (ii) that are energized after January 1, 2016 for the first

25 procurement year or within one year of the procurement date

26 for subsequent procurement years, and (iii) for projects

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1 over 1,000 kilowatts in nameplate capacity, for which the

2 owner of the project has certified that not less than the

3 prevailing wage was or will be paid to employees who are

4 engaged in construction activities associated with the

5 project.

6 "Prevailing wage" has the same definition as in

7 subsection (F) of Section 5.5(a)(3) of the Enterprise Zone

8 Act.

9 (1.25) The long-term renewable resources procurement

10 plan developed by the Agency in accordance with this

11 subdivision (c) shall include a declining block program for

12 the procurement of renewable energy credits from

13 photovoltaic projects that are distributed renewable

14 energy generation devices or community solar projects. The

15 declining block program shall be designed to provide a

16 transparent schedule of prices and capacity to enable the

17 photovoltaic market to scale up and for renewable energy

18 credit prices to fall at a predictable, sustainable rate

19 over time. The declining block program shall include for

20 each category of eligible projects: (i) a schedule of

21 standard, declining block purchase prices to be offered,

22 (ii) a series of steps, with associated nameplate capacity

23 and purchase prices that decline from step to step, and

24 (iii) automatic opening of the next step as soon as the

25 nameplate capacity and available purchase prices for an

26 open step are fully committed or reserved. Only projects

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1 energized on or after January 1, 2016, shall be eligible

2 for the declining block program. For each block group the

3 Agency shall determine the number of blocks, the amount of

4 generation capacity in each block, and the purchase price

5 for each block, provided that the purchase price provided

6 and the total amount of generation in all blocks for all

7 block groups shall be sufficient to meet the goals in

8 paragraph (1.20) of this subdivision (c). The Agency may

9 periodically review the purchase prices and may

10 redistribute available funds as necessary and appropriate,

11 subject to Commission approval as part of the periodic plan

12 revision process described in Section 16-111.5C of the

13 Public Utilities Act.

14 The declining block program shall include at least the

15 following block groups, which may be adjusted upon review

16 by the Agency and approval of the Commission:

17 (A) Distributed renewable energy generation

18 devices with a nameplate capacity of no more than 10

19 kilowatts.

20 (B) Distributed renewable energy generation

21 devices with a nameplate capacity of more than 10

22 kilowatts and no more than 100 kilowatts.

23 (C) Distributed renewable energy generation

24 devices with a nameplate capacity of more than 100

25 kilowatts and no more than 500 kilowatts.

26 (D) Distributed renewable energy generation

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1 devices with a nameplate capacity of more than 500

2 kilowatts and no more than 2,000 kilowatts.

3 (E) Distributed renewable energy generation

4 devices with a nameplate capacity of no more than 2,000

5 kilowatts that are owned by a municipality, a school

6 district, a unit of local government, a public

7 university, or a not-for-profit corporation, and

8 primarily used to offset their own electricity load.

9 (F) Community solar projects.

10 For projects that qualify under paragraph (A) of this

11 paragraph (1.25), the renewable energy credit purchase

12 price shall be paid as an upfront payment per installed

13 kilowatt of nameplate capacity paid once the device is

14 energized. The electric utility shall receive all

15 renewable energy credits generated by the project for the

16 first 15 years of operation. For projects that qualify

17 under items (B) through (F) of this paragraph (1.25) and

18 any additional categories included in the long-term

19 renewable resources plan and approved by the Commission,

20 the renewable energy credit purchase price shall be in

21 exchange for an assignment of all renewable energy credits

22 generated by the project for the first 15 years of

23 operation. The Agency shall pay for those credits over the

24 first 5 years of operation of the system through a partial

25 payment made after the system is first energized and

26 additional payments over the first 4 years of operation

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1 based on actual energy produced. The electric utility shall

2 receive all renewable energy credits generated by the

3 project for the first 15 years of operation.

4 The Agency shall issue a request for qualifications for

5 a third-party program manager to administer the declining

6 block program. The third-party program manager shall be

7 chosen through a competitive bid process based on selection

8 criteria and requirements developed by the Agency,

9 including consideration of prior experience in

10 administering an incentive program for energy efficiency,

11 renewable energy, or other similar resources. The

12 third-party program manager shall be the counterparty to

13 the contract to purchase renewable energy credits from

14 individual systems. The utility shall transfer funds

15 needed to cover the cost of purchasing renewable energy

16 credits and administering the declining block program to

17 the third-party program manager at the order of the

18 Commission. The utility's obligation under this paragraph

19 (1.25) shall be considered met upon transfer of funds to

20 the third-party program manager and retirement of

21 associated renewable energy credits. At least every 2

22 years, the Agency shall select an independent evaluator to

23 review and report on the declining block program and the

24 performance of the declining block program manager. The

25 report should include the number of projects installed, the

26 total installed capacity in kilowatts, the average cost per

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1 kilowatt of installed capacity, the total number of jobs,

2 and other economic, social, and environmental benefits

3 created. The report shall be posted on the Agency's website

4 and used, as needed, to revise the declining block program.

5 Upon order of the Commission, the utility shall provide

6 payment for the independent evaluation of the declining

7 block program. Costs associated with evaluation of the

8 declining block program shall not be included in paragraph

9 (1.15) of this subdivision (c), however these costs shall

10 be recoverable as a utility cost of service under the

11 Public Utilities Act. The selection of the third-party

12 program manager, the selection of the independent

13 evaluator, and the procurement process described in this

14 paragraph (1.25) are exempt from the requirements of

15 Section 20-10 of the Illinois Procurement Code.

16 (1.30) The long-term renewable resources procurement

17 plan required by the subdivision (c) shall include a

18 Community Solar Program. The Agency shall develop the

19 Community Solar Program to purchase renewable energy

20 credits from community solar projects with a goal to expand

21 renewable energy generating facility access to a broader

22 group of energy consumers, including those who cannot

23 install renewable energy on their own properties, while

24 prioritizing those persons most sensitive to market

25 barriers.

26 The Agency shall establish the terms, conditions, and

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1 program requirements for community solar projects as part

2 of the long-term renewable resources plan required by this

3 Section. Any plan approved by the Commission must

4 reasonably allow for the creation, financing, and

5 accessibility of community solar projects and shall allow

6 subscriptions to community solar projects to be portable

7 and transferrable. Electric utilities shall establish a

8 tariff to provide bill credits to subscribers of community

9 solar projects, as specified in an approved long-term

10 renewable resources plan. The community solar bill credits

11 shall account for the fair value of the distributed solar

12 energy and its delivery, generation capacity, transmission

13 capacity, transmission and distribution line losses, and

14 environmental value. The Agency may provide an enhanced

15 bill credit for community solar projects that are located

16 within brownfield sites or within strategic zones

17 identified by the utility with approval by the Commission

18 to provide the greatest benefits to the electric

19 distribution system. If the electrical capacity of a

20 community solar project is not fully subscribed during the

21 first full year of operation, the electric utility shall

22 purchase the energy associated with the unsubscribed

23 capacity at the electric utility's avoided cost of

24 electricity supply over the month period or as otherwise

25 specified by the terms of a power purchase agreement

26 negotiated by the community solar owners or subscribers and

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1 the electricity provider. After the first full year of

2 operation, if the electrical capacity of a community solar

3 project is not fully subscribed, the electric utility shall

4 purchase the energy associated with the unsubscribed

5 capacity at the electric utility's avoided cost of

6 electricity supply over the month period unless excess

7 capacity is otherwise provided for in a power purchase

8 agreement. The Agency shall purchase renewable energy

9 credits from subscribed shares of community solar projects

10 through the declining block program described in paragraph

11 (6) of this subdivision (c) or through the low income solar

12 program described in Section 1-56 of this Act. The owners

13 of and any subscribers to a community solar project shall

14 not be considered public utilities or alternative retail

15 electricity suppliers under the Public Utilities Act

16 solely as a result of their interest in or subscription to

17 a community solar project and shall not be required to

18 become an alternative retail electric supplier by

19 participating in a community solar project with a public

20 utility.

21 ~~The procurement plans shall include cost-effective~~

22 ~~renewable energy resources. A minimum percentage of each~~

23 ~~utility's total supply to serve the load of eligible retail~~

24 ~~customers, as defined in Section 16-111.5(a) of the Public~~

25 ~~Utilities Act, procured for each of the following years~~

26 ~~shall be generated from cost-effective renewable energy~~

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1 ~~resources: at least 2% by June 1, 2008; at least 4% by June~~

2 ~~1, 2009; at least 5% by June 1, 2010; at least 6% by June 1,~~

3 ~~2011; at least 7% by June 1, 2012; at least 8% by June 1,~~

4 ~~2013; at least 9% by June 1, 2014; at least 10% by June 1,~~

5 ~~2015; and increasing by at least 1.5% each year thereafter~~

6 ~~to at least 25% by June 1, 2025. To the extent that it is~~

7 ~~available, at least 75% of the renewable energy resources~~

8 ~~used to meet these standards shall come from wind~~

9 ~~generation and, beginning on June 1, 2011, at least the~~

10 ~~following percentages of the renewable energy resources~~

11 ~~used to meet these standards shall come from photovoltaics~~

12 ~~on the following schedule: 0.5% by June 1, 2012, 1.5% by~~

13 ~~June 1, 2013; 3% by June 1, 2014; and 6% by June 1, 2015 and~~

14 ~~thereafter. Of the renewable energy resources procured~~

15 ~~pursuant to this Section, at least the following~~

16 ~~percentages shall come from distributed renewable energy~~

17 ~~generation devices: 0.5% by June 1, 2013, 0.75% by June 1,~~

18 ~~2014, and 1% by June 1, 2015 and thereafter. To the extent~~

19 ~~available, half of the renewable energy resources procured~~

20 ~~from distributed renewable energy generation shall come~~

21 ~~from devices of less than 25 kilowatts in nameplate~~

22 ~~capacity. Renewable energy resources procured from~~

23 ~~distributed generation devices may also count towards the~~

24 ~~required percentages for wind and solar photovoltaics.~~

25 ~~Procurement of renewable energy resources from distributed~~

26 ~~renewable energy generation devices shall be done on an~~

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1 ~~annual basis through multi-year contracts of no less than 5~~

2 ~~years, and shall consist solely of renewable energy~~

3 ~~credits.~~

4 ~~The Agency shall create credit requirements for~~

5 ~~suppliers of distributed renewable energy. In order to~~

6 ~~minimize the administrative burden on contracting~~

7 ~~entities, the Agency shall solicit the use of third-party~~

8 ~~organizations to aggregate distributed renewable energy~~

9 ~~into groups of no less than one megawatt in installed~~

10 ~~capacity. These third-party organizations shall administer~~

11 ~~contracts with individual distributed renewable energy~~

12 ~~generation device owners. An individual distributed~~

13 ~~renewable energy generation device owner shall have the~~

14 ~~ability to measure the output of his or her distributed~~

15 ~~renewable energy generation device.~~

16 ~~For purposes of this subsection (c), "cost-effective"~~

17 ~~means that the costs of procuring renewable energy~~

18 ~~resources do not cause the limit stated in paragraph (2) of~~

19 ~~this subsection (c) to be exceeded and do not exceed~~

20 ~~benchmarks based on market prices for renewable energy~~

21 ~~resources in the region, which shall be developed by the~~

22 ~~procurement administrator, in consultation with the~~

23 ~~Commission staff, Agency staff, and the procurement~~

24 ~~monitor and shall be subject to Commission review and~~

25 ~~approval.~~

26 (2) (Blank). ~~For purposes of this subsection (c), the~~

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1 ~~required procurement of cost-effective renewable energy~~

2 ~~resources for a particular year shall be measured as a~~

3 ~~percentage of the actual amount of electricity~~

4 ~~(megawatt-hours) supplied by the electric utility to~~

5 ~~eligible retail customers in the planning year ending~~

6 ~~immediately prior to the procurement. For purposes of this~~

7 ~~subsection (c), the amount paid per kilowatthour means the~~

8 ~~total amount paid for electric service expressed on a per~~

9 ~~kilowatthour basis. For purposes of this subsection (c),~~

10 ~~the total amount paid for electric service includes without~~

11 ~~limitation amounts paid for supply, transmission,~~

12 ~~distribution, surcharges, and add-on taxes.~~

13 ~~Notwithstanding the requirements of this subsection~~

14 ~~(c), the total of renewable energy resources procured~~

15 ~~pursuant to the procurement plan for any single year shall~~

16 ~~be reduced by an amount necessary to limit the annual~~

17 ~~estimated average net increase due to the costs of these~~

18 ~~resources included in the amounts paid by eligible retail~~

19 ~~customers in connection with electric service to:~~

20 ~~(A) in 2008, no more than 0.5% of the amount paid~~

21 ~~per kilowatthour by those customers during the year~~

22 ~~ending May 31, 2007;~~

23 ~~(B) in 2009, the greater of an additional 0.5% of~~

24 ~~the amount paid per kilowatthour by those customers~~

25 ~~during the year ending May 31, 2008 or 1% of the amount~~

26 ~~paid per kilowatthour by those customers during the~~

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1 ~~year ending May 31, 2007;~~

2 ~~(C) in 2010, the greater of an additional 0.5% of~~

3 ~~the amount paid per kilowatthour by those customers~~

4 ~~during the year ending May 31, 2009 or 1.5% of the~~

5 ~~amount paid per kilowatthour by those customers during~~

6 ~~the year ending May 31, 2007;~~

7 ~~(D) in 2011, the greater of an additional 0.5% of~~

8 ~~the amount paid per kilowatthour by those customers~~

9 ~~during the year ending May 31, 2010 or 2% of the amount~~

10 ~~paid per kilowatthour by those customers during the~~

11 ~~year ending May 31, 2007; and~~

12 ~~(E) thereafter, the amount of renewable energy~~

13 ~~resources procured pursuant to the procurement plan~~

14 ~~for any single year shall be reduced by an amount~~

15 ~~necessary to limit the estimated average net increase~~

16 ~~due to the cost of these resources included in the~~

17 ~~amounts paid by eligible retail customers in~~

18 ~~connection with electric service to no more than the~~

19 ~~greater of 2.015% of the amount paid per kilowatthour~~

20 ~~by those customers during the year ending May 31, 2007~~

21 ~~or the incremental amount per kilowatthour paid for~~

22 ~~these resources in 2011.~~

23 ~~No later than June 30, 2011, the Commission shall~~

24 ~~review the limitation on the amount of renewable energy~~

25 ~~resources procured pursuant to this subsection (c) and~~

26 ~~report to the General Assembly its findings as to~~

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1 ~~whether that limitation unduly constrains the~~

2 ~~procurement of cost-effective renewable energy~~

3 ~~resources.~~

4 (3) (Blank). ~~Through June 1, 2011, renewable energy~~

5 ~~resources shall be counted for the purpose of meeting the~~

6 ~~renewable energy standards set forth in paragraph (1) of~~

7 ~~this subsection (c) only if they are generated from~~

8 ~~facilities located in the State, provided that~~

9 ~~cost-effective renewable energy resources are available~~

10 ~~from those facilities. If those cost-effective resources~~

11 ~~are not available in Illinois, they shall be procured in~~

12 ~~states that adjoin Illinois and may be counted towards~~

13 ~~compliance. If those cost-effective resources are not~~

14 ~~available in Illinois or in states that adjoin Illinois,~~

15 ~~they shall be purchased elsewhere and shall be counted~~

16 ~~towards compliance. After June 1, 2011, cost-effective~~

17 ~~renewable energy resources located in Illinois and in~~

18 ~~states that adjoin Illinois may be counted towards~~

19 ~~compliance with the standards set forth in paragraph (1) of~~

20 ~~this subsection (c). If those cost-effective resources are~~

21 ~~not available in Illinois or in states that adjoin~~

22 ~~Illinois, they shall be purchased elsewhere and shall be~~

23 ~~counted towards compliance.~~

24 (4) The electric utility shall retire all renewable

25 energy credits used to comply with the standard.

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

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1 after the 2016 delivery year ~~year commencing June 1, 2010~~,

2 an electric utility subject to this subsection (c) shall

3 apply the lesser of the maximum alternative compliance

4 payment rate or the most recent estimated alternative

5 compliance payment rate for its service territory for the

6 corresponding compliance period, established pursuant to

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

8 Act to its retail customers that take service pursuant to

9 the electric utility's hourly pricing tariff or tariffs.

10 The electric utility shall retain all amounts collected as

11 a result of the application of the alternative compliance

12 payment rate or rates to such customers, and, beginning in

13 2011, the utility shall include in the information provided

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

15 Public Utilities Act the amounts collected under the

16 alternative compliance payment rate or rates for the prior

17 year ending May 31. Notwithstanding any limitation on the

18 procurement of renewable energy resources imposed by item

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

20 spending on the purchase of renewable energy resources to

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

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

23 under the alternative compliance payment rate or rates in

24 the prior year ending May 31. Beginning April 1, 2012, and

25 each year thereafter, the Agency shall prepare a public

26 report for the General Assembly and Illinois Commerce

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1 Commission that shall include, but not necessarily be

2 limited to:

3 (A) a comparison of the costs associated with the

4 Agency's procurement of renewable energy resources to

5 (1) the Agency's costs associated with electricity

6 generated by other types of generation facilities and

7 (2) the benefits associated with the Agency's

8 procurement of renewable energy resources; and

9 (B) an analysis of the rate impacts associated with

10 the Illinois Power Agency's procurement of renewable

11 resources, including, but not limited to, any

12 long-term contracts, on the eligible retail customers

13 of electric utilities.

14 The analysis shall include the Agency's estimate of the

15 total dollar impact that the Agency's procurement of

16 renewable resources has had on the annual electricity bills

17 of the customer classes that comprise each eligible retail

18 customer class taking service from an electric utility. The

19 Agency's report shall also analyze how the operation of the

20 alternative compliance payment mechanism, any long-term

21 contracts, or other aspects of the applicable renewable

22 portfolio standards impacts the rates of customers of

23 alternative retail electric suppliers.

24 (6) Costs of procuring renewable energy credits

25 pursuant to plans approved under Section 16-111.5C of the

26 Public Utilities Act and associated reasonable expenses

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1 for implementing the procurement programs, including the

2 costs of administering and evaluating the declining block

3 program, shall be recoverable as a utility cost of service

4 under the Public Utilities Act.

5 (7) In meeting the renewable energy requirements of

6 this subdivision (c), to the extent feasible and consistent

7 with State and federal law, the renewable energy credit

8 procurements, declining block solar program, and community

9 solar program shall provide employment opportunities for

10 all segments of the population and workforce, including

11 minority-owned and female-owned business enterprises, and

12 shall not, consistent with State and federal law,

13 discriminate based on race or socioeconomic status.

14 (d) Clean coal portfolio standard.

15 (1) The procurement plans shall include electricity

16 generated using clean coal. Each utility shall enter into

17 one or more sourcing agreements with the initial clean coal

18 facility, as provided in paragraph (3) of this subsection

19 (d), covering electricity generated by the initial clean

20 coal facility representing at least 5% of each utility's

21 total supply to serve the load of eligible retail customers

22 in 2015 and each year thereafter, as described in paragraph

23 (3) of this subsection (d), subject to the limits specified

24 in paragraph (2) of this subsection (d). It is the goal of

25 the State that by January 1, 2025, 25% of the electricity

26 used in the State shall be generated by cost-effective

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1 clean coal facilities. For purposes of this subsection (d),

2 "cost-effective" means that the expenditures pursuant to

3 such sourcing agreements do not cause the limit stated in

4 paragraph (2) of this subsection (d) to be exceeded and do

5 not exceed cost-based benchmarks, which shall be developed

6 to assess all expenditures pursuant to such sourcing

7 agreements covering electricity generated by clean coal

8 facilities, other than the initial clean coal facility, by

9 the procurement administrator, in consultation with the

10 Commission staff, Agency staff, and the procurement

11 monitor and shall be subject to Commission review and

12 approval.

13 A utility party to a sourcing agreement shall

14 immediately retire any emission credits that it receives in

15 connection with the electricity covered by such agreement.

16 Utilities shall maintain adequate records documenting

17 the purchases under the sourcing agreement to comply with

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

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

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

21 16-111.5 of the Public Utilities Act.

22 A utility shall be deemed to have complied with the

23 clean coal portfolio standard specified in this subsection

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

25 required by this subsection (d).

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

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1 execution of sourcing agreements with the initial clean

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

3 percentage of the actual amount of electricity

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

5 eligible retail customers in the planning year ending

6 immediately prior to the agreement's execution. For

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

8 kilowatthour means the total amount paid for electric

9 service expressed on a per kilowatthour basis. For purposes

10 of this subsection (d), the total amount paid for electric

11 service includes without limitation amounts paid for

12 supply, transmission, distribution, surcharges and add-on

13 taxes.

14 Notwithstanding the requirements of this subsection

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

16 clean coal facilities pursuant to the procurement plan for

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

18 limit the annual estimated average net increase due to the

19 costs of these resources included in the amounts paid by

20 eligible retail customers in connection with electric

21 service to:

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

23 per kilowatthour by those customers during the year

24 ending May 31, 2009;

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

26 the amount paid per kilowatthour by those customers

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

2 paid per kilowatthour by those customers during the

3 year ending May 31, 2009;

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

5 the amount paid per kilowatthour by those customers

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

7 amount paid per kilowatthour by those customers during

8 the year ending May 31, 2009;

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

10 the amount paid per kilowatthour by those customers

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

12 paid per kilowatthour by those customers during the

13 year ending May 31, 2009; and

14 (E) thereafter, the total amount paid under

15 sourcing agreements with clean coal facilities

16 pursuant to the procurement plan for any single year

17 shall be reduced by an amount necessary to limit the

18 estimated average net increase due to the cost of these

19 resources included in the amounts paid by eligible

20 retail customers in connection with electric service

21 to no more than the greater of (i) 2.015% of the amount

22 paid per kilowatthour by those customers during the

23 year ending May 31, 2009 or (ii) the incremental amount

24 per kilowatthour paid for these resources in 2013.

25 These requirements may be altered only as provided by

26 statute.

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

2 review the limitation on the total amount paid under

3 sourcing agreements, if any, with clean coal facilities

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

5 Assembly its findings as to whether that limitation unduly

6 constrains the amount of electricity generated by

7 cost-effective clean coal facilities that is covered by

8 sourcing agreements.

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

10 development of clean coal facilities in Illinois, each

11 electric utility subject to this Section shall execute a

12 sourcing agreement to source electricity from a proposed

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

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

15 500 MW when commercial operation commences, that has a

16 final Clean Air Act permit on the effective date of this

17 amendatory Act of the 95th General Assembly, and that will

18 meet the definition of clean coal facility in Section 1-10

19 of this Act when commercial operation commences. The

20 sourcing agreements with this initial clean coal facility

21 shall be subject to both approval of the initial clean coal

22 facility by the General Assembly and satisfaction of the

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

24 shall be executed within 90 days after any such approval by

25 the General Assembly. The Agency and the Commission shall

26 have authority to inspect all books and records associated

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1 with the initial clean coal facility during the term of

2 such a sourcing agreement. A utility's sourcing agreement

3 for electricity produced by the initial clean coal facility

4 shall include:

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

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

7 subsection (d), which shall:

8 (i) be determined using a cost of service

9 methodology employing either a level or deferred

10 capital recovery component, based on a capital

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

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

13 Federal Energy Regulatory Commission, which in any

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

15 of return approved by the General Assembly

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

17 and

18 (ii) provide that all miscellaneous net

19 revenue, including but not limited to net revenue

20 from the sale of emission allowances, if any,

21 substitute natural gas, if any, grants or other

22 support provided by the State of Illinois or the

23 United States Government, firm transmission

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

25 facility, energy or capacity derived from the

26 facility and not covered by a sourcing agreement

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1 pursuant to paragraph (3) of this subsection (d) or

2 item (5) of subsection (d) of Section 16-115 of the

3 Public Utilities Act, whether generated from the

4 synthesis gas derived from coal, from SNG, or from

5 natural gas, shall be credited against the revenue

6 requirement for this initial clean coal facility;

7 (B) power purchase provisions, which shall:

8 (i) provide that the utility party to such

9 sourcing agreement shall pay the contract price

10 for electricity delivered under such sourcing

11 agreement;

12 (ii) require delivery of electricity to the

13 regional transmission organization market of the

14 utility that is party to such sourcing agreement;

15 (iii) require the utility party to such

16 sourcing agreement to buy from the initial clean

17 coal facility in each hour an amount of energy

18 equal to all clean coal energy made available from

19 the initial clean coal facility during such hour

20 times a fraction, the numerator of which is such

21 utility's retail market sales of electricity

22 (expressed in kilowatthours sold) in the State

23 during the prior calendar month and the

24 denominator of which is the total retail market

25 sales of electricity (expressed in kilowatthours

26 sold) in the State by utilities during such prior

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1 month and the sales of electricity (expressed in

2 kilowatthours sold) in the State by alternative

3 retail electric suppliers during such prior month

4 that are subject to the requirements of this

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

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

7 provided that the amount purchased by the utility

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

9 this subsection (d); and

10 (iv) be considered pre-existing contracts in

11 such utility's procurement plans for eligible

12 retail customers;

13 (C) contract for differences provisions, which

14 shall:

15 (i) require the utility party to such sourcing

16 agreement to contract with the initial clean coal

17 facility in each hour with respect to an amount of

18 energy equal to all clean coal energy made

19 available from the initial clean coal facility

20 during such hour times a fraction, the numerator of

21 which is such utility's retail market sales of

22 electricity (expressed in kilowatthours sold) in

23 the utility's service territory in the State

24 during the prior calendar month and the

25 denominator of which is the total retail market

26 sales of electricity (expressed in kilowatthours

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1 sold) in the State by utilities during such prior

2 month and the sales of electricity (expressed in

3 kilowatthours sold) in the State by alternative

4 retail electric suppliers during such prior month

5 that are subject to the requirements of this

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

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

8 provided that the amount paid by the utility in any

9 year will be limited by paragraph (2) of this

10 subsection (d);

11 (ii) provide that the utility's payment

12 obligation in respect of the quantity of

13 electricity determined pursuant to the preceding

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

15 (1) the difference between the contract price

16 determined pursuant to subparagraph (A) of

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

18 day-ahead price for electricity delivered to the

19 regional transmission organization market of the

20 utility that is party to such sourcing agreement

21 (or any successor delivery point at which such

22 utility's supply obligations are financially

23 settled on an hourly basis) (the "reference

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

25 electricity is delivered to the initial clean coal

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

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1 electricity determined pursuant to the preceding

2 clause (i); and

3 (iii) not require the utility to take physical

4 delivery of the electricity produced by the

5 facility;

6 (D) general provisions, which shall:

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

8 commencing on the commercial operation date of the

9 facility;

10 (ii) provide that utilities shall maintain

11 adequate records documenting purchases under the

12 sourcing agreements entered into to comply with

13 this subsection (d) and shall file an accounting

14 with the load forecast that must be filed with the

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

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

17 Utilities Act;

18 (iii) provide that all costs associated with

19 the initial clean coal facility will be

20 periodically reported to the Federal Energy

21 Regulatory Commission and to purchasers in

22 accordance with applicable laws governing

23 cost-based wholesale power contracts;

24 (iv) permit the Illinois Power Agency to

25 assume ownership of the initial clean coal

26 facility, without monetary consideration and

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1 otherwise on reasonable terms acceptable to the

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

3 years prior to the end of the stated contract term;

4 (v) require the owner of the initial clean coal

5 facility to provide documentation to the

6 Commission each year, starting in the facility's

7 first year of commercial operation, accurately

8 reporting the quantity of carbon emissions from

9 the facility that have been captured and

10 sequestered and report any quantities of carbon

11 released from the site or sites at which carbon

12 emissions were sequestered in prior years, based

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

14 year after the first year of commercial operation,

15 the owner of the facility fails to demonstrate that

16 the initial clean coal facility captured and

17 sequestered at least 50% of the total carbon

18 emissions that the facility would otherwise emit

19 or that sequestration of emissions from prior

20 years has failed, resulting in the release of

21 carbon dioxide into the atmosphere, the owner of

22 the facility must offset excess emissions. Any

23 such carbon offsets must be permanent, additional,

24 verifiable, real, located within the State of

25 Illinois, and legally and practicably enforceable.

26 The cost of such offsets for the facility that are

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1 not recoverable shall not exceed $15 million in any

2 given year. No costs of any such purchases of

3 carbon offsets may be recovered from a utility or

4 its customers. All carbon offsets purchased for

5 this purpose and any carbon emission credits

6 associated with sequestration of carbon from the

7 facility must be permanently retired. The initial

8 clean coal facility shall not forfeit its

9 designation as a clean coal facility if the

10 facility fails to fully comply with the applicable

11 carbon sequestration requirements in any given

12 year, provided the requisite offsets are

13 purchased. However, the Attorney General, on

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

15 specifically enforce the facility's sequestration

16 requirement and the other terms of this contract

17 provision. Compliance with the sequestration

18 requirements and offset purchase requirements

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

20 shall be reviewed annually by an independent

21 expert retained by the owner of the initial clean

22 coal facility, with the advance written approval

23 of the Attorney General. The Commission may, in the

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

25 reduce the allowable return on equity for the

26 facility if the facility wilfully fails to comply

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1 with the carbon capture and sequestration

2 requirements set forth in this item (v);

3 (vi) include limits on, and accordingly

4 provide for modification of, the amount the

5 utility is required to source under the sourcing

6 agreement consistent with paragraph (2) of this

7 subsection (d);

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

9 determine the justness, reasonableness, and

10 prudence of the inputs to the formula referenced in

11 subparagraphs (A)(i) through (A)(iii) of paragraph

12 (3) of this subsection (d), prior to an adjustment

13 in those inputs including, without limitation, the

14 capital structure and return on equity, fuel

15 costs, and other operations and maintenance costs

16 and (2) to approve the costs to be passed through

17 to customers under the sourcing agreement by which

18 the utility satisfies its statutory obligations.

19 Commission review shall occur no less than every 3

20 years, regardless of whether any adjustments have

21 been proposed, and shall be completed within 9

22 months;

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

24 amount as the utility is allowed to recover through

25 tariffs filed with the Commission, provided that

26 neither the clean coal facility nor the utility

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1 waives any right to assert federal pre-emption or

2 any other argument in response to a purported

3 disallowance of recovery costs;

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

5 electric supplier's obligation to incur any

6 liability until such time as the facility is in

7 commercial operation and generating power and

8 energy and such power and energy is being delivered

9 to the facility busbar;

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

11 initial clean coal facility, which is the

12 counterparty to such sourcing agreement, shall

13 have the right from time to time to elect whether

14 the obligations of the utility party thereto shall

15 be governed by the power purchase provisions or the

16 contract for differences provisions;

17 (xi) append documentation showing that the

18 formula rate and contract, insofar as they relate

19 to the power purchase provisions, have been

20 approved by the Federal Energy Regulatory

21 Commission pursuant to Section 205 of the Federal

22 Power Act;

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

24 the contract, insofar as such changes relate to the

25 power purchase provisions, are subject to review

26 under the public interest standard applied by the

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1 Federal Energy Regulatory Commission pursuant to

2 Sections 205 and 206 of the Federal Power Act; and

3 (xiii) conform with customary lender

4 requirements in power purchase agreements used as

5 the basis for financing non-utility generators.

6 (4) Effective date of sourcing agreements with the

7 initial clean coal facility.

8 Any proposed sourcing agreement with the initial clean

9 coal facility shall not become effective unless the

10 following reports are prepared and submitted and

11 authorizations and approvals obtained:

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

13 clean coal facility shall submit to the Commission, the

14 Agency, and the General Assembly a front-end

15 engineering and design study, a facility cost report,

16 method of financing (including but not limited to

17 structure and associated costs), and an operating and

18 maintenance cost quote for the facility (collectively

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

20 accordance with the requirements of this paragraph (4)

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

22 the Commission and the Agency access to the work

23 papers, relied upon documents, and any other backup

24 documentation related to the facility cost report.

25 (ii) Commission report. Within 6 months following

26 receipt of the facility cost report, the Commission, in

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1 consultation with the Agency, shall submit a report to

2 the General Assembly setting forth its analysis of the

3 facility cost report. Such report shall include, but

4 not be limited to, a comparison of the costs associated

5 with electricity generated by the initial clean coal

6 facility to the costs associated with electricity

7 generated by other types of generation facilities, an

8 analysis of the rate impacts on residential and small

9 business customers over the life of the sourcing

10 agreements, and an analysis of the likelihood that the

11 initial clean coal facility will commence commercial

12 operation by and be delivering power to the facility's

13 busbar by 2016. To assist in the preparation of its

14 report, the Commission, in consultation with the

15 Agency, may hire one or more experts or consultants,

16 the costs of which shall be paid for by the owner of

17 the initial clean coal facility. The Commission and

18 Agency may begin the process of selecting such experts

19 or consultants prior to receipt of the facility cost

20 report.

21 (iii) General Assembly approval. The proposed

22 sourcing agreements shall not take effect unless,

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

24 report, the General Assembly enacts authorizing

25 legislation approving (A) the projected price, stated

26 in cents per kilowatthour, to be charged for

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1 electricity generated by the initial clean coal

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

3 small business customers' bills over the life of the

4 sourcing agreements, and (C) the maximum allowable

5 return on equity for the project; and

6 (iv) Commission review. If the General Assembly

7 enacts authorizing legislation pursuant to

8 subparagraph (iii) approving a sourcing agreement, the

9 Commission shall, within 90 days of such enactment,

10 complete a review of such sourcing agreement. During

11 such time period, the Commission shall implement any

12 directive of the General Assembly, resolve any

13 disputes between the parties to the sourcing agreement

14 concerning the terms of such agreement, approve the

15 form of such agreement, and issue an order finding that

16 the sourcing agreement is prudent and reasonable.

17 The facility cost report shall be prepared as follows:

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

19 duly licensed engineering and construction firms

20 detailing the estimated capital costs payable to one or

21 more contractors or suppliers for the engineering,

22 procurement and construction of the components

23 comprising the initial clean coal facility and the

24 estimated costs of operation and maintenance of the

25 facility. The facility cost report shall include:

26 (i) an estimate of the capital cost of the core

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1 plant based on one or more front end engineering

2 and design studies for the gasification island and

3 related facilities. The core plant shall include

4 all civil, structural, mechanical, electrical,

5 control, and safety systems.

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

7 balance of the plant, including any capital costs

8 associated with sequestration of carbon dioxide

9 emissions and all interconnects and interfaces

10 required to operate the facility, such as

11 transmission of electricity, construction or

12 backfeed power supply, pipelines to transport

13 substitute natural gas or carbon dioxide, potable

14 water supply, natural gas supply, water supply,

15 water discharge, landfill, access roads, and coal

16 delivery.

17 The quoted construction costs shall be expressed

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

19 prepared and shall include capitalized financing costs

20 during construction, taxes, insurance, and other

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

22 and labor beyond the date as of which the construction

23 cost quote is expressed.

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

25 the gasification island and the cost study for the

26 balance of plant shall include sufficient design work

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1 to permit quantification of major categories of

2 materials, commodities and labor hours, and receipt of

3 quotes from vendors of major equipment required to

4 construct and operate the clean coal facility.

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

6 operating and maintenance cost quote that will provide

7 the estimated cost of delivered fuel, personnel,

8 maintenance contracts, chemicals, catalysts,

9 consumables, spares, and other fixed and variable

10 operations and maintenance costs. The delivered fuel

11 cost estimate will be provided by a recognized third

12 party expert or experts in the fuel and transportation

13 industries. The balance of the operating and

14 maintenance cost quote, excluding delivered fuel

15 costs, will be developed based on the inputs provided

16 by duly licensed engineering and construction firms

17 performing the construction cost quote, potential

18 vendors under long-term service agreements and plant

19 operating agreements, or recognized third party plant

20 operator or operators.

21 The operating and maintenance cost quote

22 (including the cost of the front end engineering and

23 design study) shall be expressed in nominal dollars as

24 of the date that the quote is prepared and shall

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

26 an assumed escalation in materials and labor beyond the

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1 date as of which the operating and maintenance cost

2 quote is expressed.

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

4 analysis of the initial clean coal facility's ability

5 to deliver power and energy into the applicable

6 regional transmission organization markets and an

7 analysis of the expected capacity factor for the

8 initial clean coal facility.

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

10 owner or owners of the initial clean coal facility to

11 prepare the core plant construction cost quote,

12 including the front end engineering and design study,

13 and the operating and maintenance cost quote will be

14 reimbursed through Coal Development Bonds.

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

16 plants previously owned by Illinois utilities to qualify as

17 clean coal facilities. During the 2009 procurement

18 planning process and thereafter, the Agency and the

19 Commission shall consider sourcing agreements covering

20 electricity generated by power plants that were previously

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

22 converted into clean coal facilities, as defined by Section

23 1-10 of this Act. Pursuant to such procurement planning

24 process, the owners of such facilities may propose to the

25 Agency sourcing agreements with utilities and alternative

26 retail electric suppliers required to comply with

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1 subsection (d) of this Section and item (5) of subsection

2 (d) of Section 16-115 of the Public Utilities Act, covering

3 electricity generated by such facilities. In the case of

4 sourcing agreements that are power purchase agreements,

5 the contract price for electricity sales shall be

6 established on a cost of service basis. In the case of

7 sourcing agreements that are contracts for differences,

8 the contract price from which the reference price is

9 subtracted shall be established on a cost of service basis.

10 The Agency and the Commission may approve any such utility

11 sourcing agreements that do not exceed cost-based

12 benchmarks developed by the procurement administrator, in

13 consultation with the Commission staff, Agency staff and

14 the procurement monitor, subject to Commission review and

15 approval. The Commission shall have authority to inspect

16 all books and records associated with these clean coal

17 facilities during the term of any such contract.

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

19 pursuant to a contract entered into under this subsection

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

21 amount and the electric utility shall be entitled to full

22 cost recovery pursuant to the tariffs filed with the

23 Commission.

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

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

26 Utilities Act.

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

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

3 the Commission determines that it does not meet the standards

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

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

6 to recover the costs incurred in preparation of the annual

7 procurement plan for the utility.

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

9 the costs incurred in connection with a competitive procurement

10 process.

11 (Source: P.A. 97-325, eff. 8-12-11; 97-616, eff. 10-26-11;

12 97-618, eff. 10-26-11; 97-658, eff. 1-13-12; 97-813, eff.

13 7-13-12; 98-463, eff. 8-16-13.)

14 Section 10. The Public Utilities Act is amended by changing

15 Sections 8-101, 8-103, 8-104, 16-107, 16-108.5, 16-108.8,

16 16-111.5, 16-111.5B, 16-111.7, 16-115D, and 19-140 and by

17 adding Section 16-111.5C as follows:

18 (220 ILCS 5/8-101) (from Ch. 111 2/3, par. 8-101)

19 Sec. 8-101. Duties of public utilities; nondiscrimination.

20 A public utility shall furnish, provide, and maintain such

21 service instrumentalities, equipment, and facilities as shall

22 promote the safety, health, comfort, and convenience of its

23 patrons, employees, and public and as shall be in all respects

24 adequate, efficient, just, and reasonable.

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1 All rules and regulations made by a public utility

2 affecting or pertaining to its charges or service to the public

3 shall be just and reasonable.

4 A public utility shall, upon reasonable notice, furnish to

5 all persons who may apply therefor and be reasonably entitled

6 thereto, suitable facilities and service, without

7 discrimination and without delay.

8 Nothing in this Section shall be construed to prevent a

9 public utility from accepting payment electronically or by the

10 use of a customer-preferred financially accredited credit or

11 debit methodology.

12 A public utility shall not discriminate against

13 technologies, regardless of generator, prime mover, or

14 inverter, when presented with an application for

15 interconnection of a distributed generation facility,

16 including without limitation a battery or energy storage

17 facility, that operates in parallel with the electric

18 distribution system.

19 (Source: P.A. 92-22, eff. 6-30-01.)

20 (220 ILCS 5/8-103)

21 Sec. 8-103. Energy efficiency and demand-response

22 measures.

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

24 are required to use cost-effective energy efficiency and

25 demand-response measures to reduce delivery load. Requiring

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1 investment in cost-effective energy efficiency and

2 demand-response measures will reduce direct and indirect costs

3 to consumers by decreasing environmental impacts, by reducing

4 electricity prices in the regional power market, and by

5 avoiding or delaying the need for new generation, transmission,

6 and distribution infrastructure. It serves the public interest

7 to allow electric utilities to recover costs for reasonably and

8 prudently incurred expenses for energy efficiency and

9 demand-response measures. As used in this Section,

10 "cost-effective" means that the measures satisfy the total

11 resource cost test. The low-income measures described in

12 subsection (f)(4) of this Section shall not be required to meet

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

14 terms "energy-efficiency", "demand-response", "electric

15 utility", and "total resource cost test" shall have the

16 meanings set forth in the Illinois Power Agency Act. For

17 purposes of this Section, the amount per kilowatthour means the

18 total amount paid for electric service expressed on a per

19 kilowatthour basis. For purposes of this Section, the total

20 amount paid for electric service includes without limitation

21 estimated amounts paid for supply, transmission, distribution,

22 surcharges, and add-on-taxes.

23 (b) Electric utilities shall implement cost-effective

24 energy efficiency measures to meet the following incremental

25 annual energy savings goals:

26 (1) 0.2% of energy delivered in the year commencing

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1 June 1, 2008;

2 (2) 0.4% of energy delivered in the year commencing

3 June 1, 2009;

4 (3) 0.6% of energy delivered in the year commencing

5 June 1, 2010;

6 (4) 0.8% of energy delivered in the year commencing

7 June 1, 2011;

8 (5) 1% of energy delivered in the year commencing June

9 1, 2012;

10 (6) 1.4% of energy delivered in the year commencing

11 June 1, 2013;

12 (7) 1.8% of energy delivered in the year commencing

13 June 1, 2014; ~~and~~

14 (8) 2% of energy delivered in each ~~the~~ year commencing

15 June 1, 2015 and ending on December 31, 2017; and ~~each year~~

16 ~~thereafter.~~

17 (9) beginning in January 2018, an amount to be

18 determined by the Illinois Commerce Commission through the

19 process described in subsection (f) of this Section in

20 order to achieve a cumulative annual persisting reduction

21 in electric energy demand from efficiency measures

22 implemented as a result of utility programs from 2012

23 through 2025 of 20%, relative to average annual electricity

24 sales from 2014 through 2016, by the year ending December

25 31 2025; cumulative persisting annual reductions are the

26 reductions realized in a given year from measures installed

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1 in either the that year or in previous years that are still

2 operational and providing savings in that year because they

3 have not yet reached the end of their useful life; and

4 After 2025, the incremental annual energy goal shall be an

5 amount to be determined by the Illinois Commerce Commission in

6 order to fully capture the cost-effective potential for

7 electricity savings as assessed by the Illinois Power Agency

8 under subsection (j-10) of this Section.

9 Electric utilities may comply with this subsection (b) by

10 meeting the annual incremental savings goal in the applicable

11 year or by showing that the total cumulative annual savings

12 within a 3-year planning period associated with measures

13 implemented after May 31, 2014 was equal to the sum of each

14 annual incremental savings requirement from May 31, 2014

15 through the end of the applicable year. Beginning January 1,

16 2018, electric utilities may comply by showing that the total

17 cumulative annual savings persisting the last year of the

18 applicable 4-year planning period was equal to the cumulative

19 persisting annual savings required in that year by the Illinois

20 Commerce Commission pursuant to the plans approved under

21 subsection (f) of this Section. Annually, beginning on March 1,

22 2019, each participating utility shall file third-party

23 evaluations of the savings achieved in the preceding year.

24 Within 5 days after the filing, any person objecting to the

25 filing shall file an objection. Within 10 days after the

26 filing, the Commission shall determine whether a hearing is

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1 necessary. The Commission shall enter its order confirming or

2 modifying the savings estimates within 90 days after the filing

3 date.

4 (c) Electric utilities shall implement cost-effective

5 demand-response measures to reduce peak demand by 0.1% over the

6 prior year for its delivery customers ~~eligible retail~~

7 ~~customers, as defined in Section 16-111.5 of this Act, and for~~

8 ~~customers that elect hourly service from the utility pursuant~~

9 ~~to Section 16-107 of this Act, provided those customers have~~

10 ~~not been declared competitive. This requirement commences June~~

11 ~~1, 2008 and continues for 10 years~~.

12 (d) Notwithstanding the requirements of subsections (b)

13 and (c) of this Section, an electric utility shall reduce the

14 amount of energy efficiency and demand-response measures

15 implemented over a 3-year planning period by an amount

16 necessary to limit the estimated average annual increase in the

17 amounts paid by retail customers in connection with electric

18 service due to the cost of those measures to:

19 (1) in 2008, no more than 0.5% of the amount paid per

20 kilowatthour by those customers during the year ending May

21 31, 2007;

22 (2) in 2009, the greater of an additional 0.5% of the

23 amount paid per kilowatthour by those customers during the

24 year ending May 31, 2008 or 1% of the amount paid per

25 kilowatthour by those customers during the year ending May

26 31, 2007;

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1 (3) in 2010, the greater of an additional 0.5% of the

2 amount paid per kilowatthour by those customers during the

3 year ending May 31, 2009 or 1.5% of the amount paid per

4 kilowatthour by those customers during the year ending May

5 31, 2007;

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

7 amount paid per kilowatthour by those customers during the

8 year ending May 31, 2010 or 2% of the amount paid per

9 kilowatthour by those customers during the year ending May

10 31, 2007; and

11 (5) in 2012 and in each subsequent year through 2017

12 ~~thereafter~~, the amount of energy efficiency and

13 demand-response measures implemented for any single year

14 shall be reduced by an amount necessary to limit the

15 estimated average net increase due to the cost of these

16 measures included in the amounts paid by eligible retail

17 customers in connection with electric service to no more

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

19 kilowatthour by those customers during the year ending May

20 31, 2007 or the incremental amount per kilowatthour paid

21 for these measures in 2011.

22 No later than June 30, 2011, the Commission shall review

23 the limitation on the amount of energy efficiency and

24 demand-response measures implemented pursuant to this Section

25 and report to the General Assembly its findings as to whether

26 that limitation unduly constrains the procurement of energy

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1 efficiency and demand-response measures.

2 For utility efficiency programs offered on or after January

3 2018, the amount of savings shall be limited only to the extent

4 necessary to ensure that the measures installed will, in the

5 aggregate, result in net benefits to customers when the full

6 costs of the efficiency programs are compared with the full

7 benefits, as defined in the total resource cost test.

8 (e) Electric utilities shall be responsible for overseeing

9 the design, development, and filing of energy efficiency and

10 demand-response plans with the Commission. Electric utilities

11 shall implement 100% of the demand-response measures in the

12 plans. Electric utilities shall implement 75% of the energy

13 efficiency measures approved by the Commission, and may, as

14 part of that implementation, outsource various aspects of

15 program development and implementation. The remaining 25% of

16 those energy efficiency measures approved by the Commission

17 shall be implemented by the Department of Commerce and Economic

18 Opportunity, and must be designed in conjunction with the

19 utility and the filing process. The Department may outsource

20 development and implementation of energy efficiency measures.

21 A minimum of 10% of the entire portfolio of cost-effective

22 energy efficiency measures shall be procured from units of

23 local government, municipal corporations, school districts,

24 and community college districts. A minimum of 12.5% of the

25 entire portfolio of cost-effective energy efficiency measures

26 shall be allocated to programs that serve low-income

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1 residential customers. The Department shall coordinate the

2 implementation of these measures. As much as half of the

3 minimum low-income requirement may be met through energy

4 efficiency measures that result in savings related to fuels

5 other than electricity if necessary:

6 (1) to comprehensively capture treatment of efficiency

7 opportunities for low-income residential customers;

8 (2) to enable effective administration of low-income

9 programs; or

10 (3) to address limitations on availability of other

11 funding sources for efficiency measures to improve the

12 efficiency of use of natural gas, fuel oil, or other fuels

13 used by low-income residential customers.

14 The Department shall coordinate the implementation of these

15 measures.

16 The apportionment of the dollars to cover the costs to

17 implement the Department's share of the portfolio of energy

18 efficiency measures shall be made to the Department once the

19 Department has executed rebate agreements, grants, or

20 contracts for energy efficiency measures and provided

21 supporting documentation for those rebate agreements, grants,

22 and contracts to the utility. The Department is authorized to

23 adopt any rules necessary and prescribe procedures in order to

24 ensure compliance by applicants in carrying out the purposes of

25 rebate agreements for energy efficiency measures implemented

26 by the Department made under this Section.

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1 The details of the measures implemented by the Department

2 shall be submitted by the Department to the Commission in

3 connection with the utility's filing regarding the energy

4 efficiency and demand-response measures that the utility

5 implements.

6 A utility providing approved energy efficiency and

7 demand-response measures in the State before December 31, 2017

8 shall be permitted to recover costs of those measures through

9 an automatic adjustment clause tariff filed with and approved

10 by the Commission. The tariff shall be established outside the

11 context of a general rate case. Each year the Commission shall

12 initiate a review to reconcile any amounts collected with the

13 actual costs and to determine the required adjustment to the

14 annual tariff factor to match annual expenditures. Beginning

15 January 1, 2018, a participating utility providing approved

16 energy efficiency and demand-response measures in the State

17 that has elected to be subject to Section 16-108.5 of the

18 Public Utilities Act may recover the costs of those measures as

19 part of its cost of service in its performance-based formula

20 rate as provided in paragraph (1) of subsection (c) of Section

21 16-108.5.

22 Each utility shall include, in its recovery of costs, the

23 costs estimated for both the utility's and the Department's

24 implementation of energy efficiency and demand-response

25 measures. Costs collected by the utility for measures

26 implemented by the Department shall be submitted to the

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1 Department pursuant to Section 605-323 of the Civil

2 Administrative Code of Illinois, shall be deposited into the

3 Energy Efficiency Portfolio Standards Fund, and shall be used

4 by the Department solely for the purpose of implementing these

5 measures. A utility shall not be required to advance any moneys

6 to the Department but only to forward such funds as it has

7 collected. The Department shall report to the Commission on an

8 annual basis regarding the costs actually incurred by the

9 Department in the implementation of the measures. Any changes

10 to the costs of energy efficiency measures as a result of plan

11 modifications shall be appropriately reflected in amounts

12 recovered by the utility and turned over to the Department.

13 The portfolio of measures, administered by both the

14 utilities and the Department, shall, in combination, be

15 designed to achieve the annual savings targets described in

16 subsections (b) and (c) of this Section, as modified by

17 subsection (d) of this Section.

18 The utility and the Department shall agree upon a

19 reasonable portfolio of measures and determine the measurable

20 corresponding percentage of the savings goals associated with

21 measures implemented by the utility or Department.

22 No utility shall be assessed a penalty under subsection (f)

23 of this Section for failure to make a timely filing if that

24 failure is the result of a lack of agreement with the

25 Department with respect to the allocation of responsibilities

26 or related costs or target assignments. In that case, the

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1 Department and the utility shall file their respective plans

2 with the Commission and the Commission shall determine an

3 appropriate division of measures and programs that meets the

4 requirements of this Section.

5 If the Department is unable to meet incremental annual

6 performance goals for the portion of the portfolio implemented

7 by the Department, then the utility and the Department shall

8 jointly submit a modified filing to the Commission explaining

9 the performance shortfall and recommending an appropriate

10 course going forward, including any program modifications that

11 may be appropriate in light of the evaluations conducted under

12 item (7) of subsection (f) of this Section. In this case, the

13 utility obligation to collect the Department's costs and turn

14 over those funds to the Department under this subsection (e)

15 shall continue only if the Commission approves the

16 modifications to the plan proposed by the Department.

17 (f) No later than November 15, 2007, each electric utility

18 shall file an energy efficiency and demand-response plan with

19 the Commission to meet the energy efficiency and

20 demand-response standards for 2008 through 2010. No later than

21 October 1, 2010, each electric utility shall file an energy

22 efficiency and demand-response plan with the Commission to meet

23 the energy efficiency and demand-response standards for 2011

24 through 2013. By September 1, 2013, each electric utility shall

25 file an energy efficiency and demand-response plan for 2014

26 through 2017. By January 1, 2016, the Illinois Power Agency

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1 shall publish a draft statewide energy efficiency potential

2 study that assesses the technical, economic, and maximum

3 cost-effective achievable potential for energy efficiency for

4 each electric utility service territory from 2018 through 2021

5 and from 2022 through 2025. The Agency shall seek input from

6 stakeholders in advance of conducting the study. After the

7 draft study is published, the Agency shall accept public

8 comments on the study through March 1, 2016 and shall transmit

9 a final proposed study to the Commission by April 15, 2017. The

10 Commission shall approve the study or approve with

11 modifications by June 1, 2016. By January 1, 2017, each

12 electric utility and the Department shall file an energy

13 efficiency plan for the period beginning January 1, 2018

14 through December 31, 2021 that seeks to achieve a cumulative

15 persisting annual reduction in electricity demand in 2021, from

16 efficiency measures installed as a result of its programs from

17 2012 through 2021, of at least 12% compared to average annual

18 electricity sales from 2014 through 2016, unless such levels

19 have been clearly shown by the Illinois Power Agency's

20 potential study to not be cost-effective or achievable, in

21 which case the plans should be designed to capture all of the

22 cost-effective potential for energy savings identified as

23 achievable in the potential study completed by the Illinois

24 Power Agency. By January 1, 2020 and every 4 years thereafter,

25 the Illinois Power Agency shall publish a second draft

26 statewide energy efficiency potential study updating its

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1 assessment of the cost-effective achievable potential for

2 energy efficiency for each electric utility service territory

3 from 2022 through 2025. The agency shall seek input from

4 stakeholders in advance of conducting the study. The agency

5 will accept public comments on the draft study through March 1,

6 2020 and shall transmit a final proposed study to the

7 Commission by April 15, 2020. The Commission shall approve the

8 study or approve with modifications by June 1, 2020. By January

9 1, 2021, each electric utility and the Department shall file an

10 energy efficiency plan for the period beginning January 1, 2022

11 through December 31, 2025 that seeks to achieve a cumulative

12 persisting annual reduction in electricity demand in 2025, from

13 efficiency measures installed as a result of its programs from

14 2012 through 2025, of at least 20% compared to average annual

15 electricity sales from 2014 through 2016, unless such levels

16 have been clearly shown by the Illinois Power Agency's study to

17 not be cost-effective or achievable, in which case the plans

18 should be designed to capture all of the cost-effective

19 potential for energy savings identified in the potential study

20 completed by the Illinois Power Agency. On January 1, 2024 and

21 every 4 years thereafter, each electric utility and the

22 Department shall file an energy efficiency plan covering a

23 4-year period beginning January 1 of the following year. ~~Every~~

24 ~~3 years thereafter, each electric utility shall file, no later~~

25 ~~than September 1, an energy efficiency and demand-response plan~~

26 ~~with the Commission.~~ If a utility does not file such a plan by

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1 the deadlines described in this Section ~~September 1 of an~~

2 ~~applicable year~~, it shall face a penalty of $100,000 per day

3 until the plan is filed. Each utility's plan shall set forth

4 the utility's proposals to meet the utility's portion of the

5 energy efficiency standards identified in subsection (b) and

6 the demand-response standards identified in subsection (c) of

7 this Section as modified by subsections (d) and (e), taking

8 into account the unique circumstances of the utility's service

9 territory. The Commission shall seek public comment on the

10 utility's plan and shall issue an order approving or

11 disapproving each plan within 6 ~~5~~ months after its submission.

12 If the Commission disapproves a plan, the Commission shall,

13 within 30 days, describe in detail the reasons for the

14 disapproval and describe a path by which the utility may file a

15 revised draft of the plan to address the Commission's concerns

16 satisfactorily. If the utility does not refile with the

17 Commission within 60 days, the utility shall be subject to

18 penalties at a rate of $100,000 per day until the plan is

19 filed. This process shall continue, and penalties shall accrue,

20 until the utility has successfully filed a portfolio of energy

21 efficiency and demand-response measures. Penalties shall be

22 deposited into the Energy Efficiency Trust Fund. In submitting

23 proposed energy efficiency and demand-response plans and

24 funding levels to meet the savings goals adopted by this Act

25 the utility shall:

26 (1) Demonstrate that its proposed energy efficiency

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1 and demand-response measures will achieve the requirements

2 that are identified in subsections (b) and (c) of this

3 Section, as modified by subsections (d) and (e).

4 (2) Present specific proposals to implement new

5 building and appliance standards that have been placed into

6 effect.

7 (3) Present estimates of the total amount paid for

8 electric service expressed on a per kilowatthour basis

9 associated with the proposed portfolio of measures

10 designed to meet the requirements that are identified in

11 subsections (b) and (c) of this Section, as modified by

12 subsections (d) and (e).

13 (4) Coordinate with the Department to present a

14 portfolio of energy efficiency measures proportionate to

15 the share of total annual utility revenues in Illinois from

16 households at or below 150% of the poverty level. The

17 energy efficiency programs shall be targeted to households

18 with incomes at or below 80% of area median income.

19 (5) Demonstrate that its overall portfolio of energy

20 efficiency and demand-response measures, not including

21 programs covered by item (4) of this subsection (f), are

22 cost-effective using the total resource cost test and

23 represent a diverse cross-section of opportunities for

24 customers of all rate classes to participate in the

25 programs.

26 (5.5) Include meaningful opportunities for third-party

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1 energy efficiency businesses to deliver energy savings.

2 (5.10) Ensure that the portfolio as a whole, including

3 the portion administered by the Department of Commerce and

4 Economic Opportunity and programs offered by third-party

5 energy service providers, include opportunities for a

6 diverse set of building types, including both program

7 offering tailored to the needs of specific building types

8 and opportunities to source energy efficiency savings from

9 building, including, but not limited to, hospitals, health

10 care facilities, long-term care facilities, units of local

11 government, school districts, park districts, cultural

12 institutions, museums, facilities licensed under the Child

13 Care Act of 1969, preschools, churches and houses of

14 worship, public universities, private colleges, community

15 college districts, and wastewater and drinking water

16 treatment plant agencies and operators.

17 (5.15) Demonstrate that the utility consulted with

18 interested stakeholders, including customer groups,

19 environmental advocates, Commission staff, the Illinois

20 Commission on Environmental Justice, and other entities

21 who have participated in Commission proceedings to

22 consider the approval of past energy efficiency plans under

23 this Section and that those entities concerns and input

24 have been taken into consideration during the development

25 of the proposed plan.

26 (5.20) Ensure that the portfolio maximizes the use of

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1 cost-effective measures with measure lives of 10 years or

2 greater.

3 (6) Include a proposed cost-recovery tariff mechanism

4 to fund the proposed energy efficiency and demand-response

5 measures and to ensure the recovery of the prudently and

6 reasonably incurred costs of Commission-approved programs.

7 Beginning in 2018, a participating utility, as defined in

8 Section 16-108.5, providing approved energy efficiency and

9 demand-response measures in the State shall recover the

10 costs of those measures as part of its performance-based

11 formula rate as provided in paragraph (1) of subsection (c)

12 of Section 16-108.5.

13 (7) Provide for an annual independent evaluation of the

14 performance of the cost-effectiveness of the utility's

15 portfolio of measures and the Department's portfolio of

16 measures, as well as a full review of the full multi-year

17 portfolio ~~3-year~~ results ~~of the broader net program impacts~~

18 ~~and~~, to the extent practical, for adjustment of the

19 measures on a going-forward basis as a result of the

20 evaluations. The resources dedicated to evaluation shall

21 not exceed 3% of portfolio resources in any given year. The

22 evaluations shall be performed by independent experts that

23 are retained for this purpose by the Illinois Commerce

24 Commission.

25 (g) No more than 3% of energy efficiency and

26 demand-response program revenue may be allocated for research,

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1 development, or pilot deployment of new equipment or measures

2 ~~demonstration of breakthrough equipment and devices~~.

3 (h) This Section does not apply to an electric utility that

4 on December 31, 2005 provided electric service to fewer than

5 100,000 customers in Illinois.

6 (i) If, after 2 years, an electric utility fails to meet

7 the efficiency standard specified in subsection (b) of this

8 Section, as modified by subsections (d) and (e), it shall make

9 a contribution to the Low-Income Home Energy Assistance

10 Program. The combined total liability for failure to meet the

11 goal shall be $1,000,000, which shall be assessed as follows: a

12 large electric utility shall pay $665,000, and a medium

13 electric utility shall pay $335,000. If, after 3 years, an

14 electric utility fails to meet the efficiency standard

15 specified in subsection (b) of this Section, as modified by

16 subsections (d) and (e), it shall make a contribution to the

17 Low-Income Home Energy Assistance Program. The combined total

18 liability for failure to meet the goal shall be $1,000,000,

19 which shall be assessed as follows: a large electric utility

20 shall pay $665,000, and a medium electric utility shall pay

21 $335,000. In addition, the responsibility for implementing the

22 energy efficiency measures of the utility making the payment

23 shall be transferred to the Illinois Power Agency if, after 3

24 years, or in any subsequent 3-year period, the utility fails to

25 meet the efficiency standard specified in subsection (b) of

26 this Section, as modified by subsections (d) and (e). The

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1 Agency shall implement a competitive procurement program to

2 procure resources necessary to meet the standards specified in

3 this Section as modified by subsections (d) and (e), with costs

4 for those resources to be recovered in the same manner as

5 products purchased through the procurement plan as provided in

6 Section 16-111.5. The Director shall implement this

7 requirement in connection with the procurement plan as provided

8 in Section 16-111.5.

9 For purposes of this Section, (i) a "large electric

10 utility" is an electric utility that, on December 31, 2005,

11 served more than 2,000,000 electric customers in Illinois; (ii)

12 a "medium electric utility" is an electric utility that, on

13 December 31, 2005, served 2,000,000 or fewer but more than

14 100,000 electric customers in Illinois; and (iii) Illinois

15 electric utilities that are affiliated by virtue of a common

16 parent company are considered a single electric utility.

17 (j) If, after 3 years, or any subsequent 3-year period, the

18 Department fails to implement the Department's share of energy

19 efficiency measures required by the standards in subsection

20 (b), then the Illinois Power Agency may assume responsibility

21 for and control of the Department's share of the required

22 energy efficiency measures. The Agency shall implement a

23 competitive procurement program to procure resources necessary

24 to meet the standards specified in this Section, with the costs

25 of these resources to be recovered in the same manner as

26 provided for the Department in this Section.

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1 (j-5) By June 1, 2016 and every 4 years thereafter, the

2 Department of Commerce and Economic Opportunity shall perform

3 and make publicly available a study assessing the job creation

4 impact of implementation of energy efficiency programs and

5 policies in Illinois. The Department shall seek input from

6 stakeholders in advance of conducting the study.

7 (j-10) For the purposes of conducting the energy efficiency

8 potential studies required in subsection (f) of this Section,

9 the Illinois Power Agency shall:

10 (1) base estimates of the portion of economic potential

11 that could be achieved on document experience of the most

12 successful programs in other jurisdictions in each of the

13 specific efficiency markets being analyzed;

14 (2) include impacts from emergence of new technologies

15 that can reasonably be expected to emerge after the study

16 is conducted but during the period covered by the study;

17 (3) account for potential for measure costs to decline

18 as volumes of sales increase;

19 (4) account for economies that could be achieved

20 through joint electric-gas program delivery or

21 coordination;

22 (5) include estimates of potential from behavioral

23 changes and process improvements (in addition to

24 technologies);

25 (6) include estimates of impacts from fuel-switching

26 measures; and

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1 (7) include estimates of impacts from either

2 supporting adoption of stricter building codes or

3 equipment standards or better compliance with existing

4 codes and standards.

5 (j-15) The Commission shall issue an order extending the

6 programs approved under subsection (f) of this Section for the

7 period beginning June 1, 2014 and ending May 31, 2017 so that

8 these programs continue to be offered until December 31, 2017.

9 The savings goals and budgets associated with these approved

10 programs shall be modified to ensure that the programs will

11 continue to operate and acquire additional savings during this

12 period and under the same cost-effectiveness requirements

13 applicable when the programs were approved.

14 (k) No electric utility shall be deemed to have failed to

15 meet the energy efficiency standards to the extent any such

16 failure is due to a failure of the Department or the Agency.

17 (l) In meeting the energy efficiency requirements of this

18 Section, to the extent feasible and consistent with State and

19 federal law, the energy efficiency credit procurements,

20 declining block solar program, and community solar program

21 should provide employment opportunities for all segments of the

22 population and workforce, including minority-owned and

23 female-owned business enterprises, and shall not, consistent

24 with State and federal law, discriminate based on race or

25 socioeconomic status.

26 (Source: P.A. 97-616, eff. 10-26-11; 97-841, eff. 7-20-12;

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1 98-90, eff. 7-15-13.)

2 (220 ILCS 5/8-104)

3 Sec. 8-104. Natural gas energy efficiency programs.

4 (a) It is the policy of the State that natural gas

5 utilities and the Department of Commerce and Economic

6 Opportunity are required to use cost-effective energy

7 efficiency to reduce direct and indirect costs to consumers. It

8 serves the public interest to allow natural gas utilities to

9 recover costs for reasonably and prudently incurred expenses

10 for cost-effective energy efficiency measures.

11 (b) For purposes of this Section, "energy efficiency" means

12 measures that reduce the amount of energy required to achieve a

13 given end use. "Energy efficiency" also includes measures that

14 reduce the total Btus of electricity and natural gas needed to

15 meet the end use or uses. "Cost-effective" means that the

16 measures satisfy the total resource cost test, which, for

17 purposes of this Section, has the meaning given to that term in

18 Section 1-10 of the Illinois Power Agency Act. ~~means a standard~~

19 ~~that is met if, for an investment in energy efficiency, the~~

20 ~~benefit-cost ratio is greater than one. The benefit-cost ratio~~

21 ~~is the ratio of the net present value of the total benefits of~~

22 ~~the measures to the net present value of the total costs as~~

23 ~~calculated over the lifetime of the measures. The total~~

24 ~~resource cost test compares the sum of avoided natural gas~~

25 ~~utility costs, representing the benefits that accrue to the~~

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1 ~~system and the participant in the delivery of those efficiency~~

2 ~~measures, as well as other quantifiable societal benefits,~~

3 ~~including avoided electric utility costs, to the sum of all~~

4 ~~incremental costs of end use measures (including both utility~~

5 ~~and participant contributions), plus costs to administer,~~

6 ~~deliver, and evaluate each demand-side measure, to quantify the~~

7 ~~net savings obtained by substituting demand-side measures for~~

8 ~~supply resources. In calculating avoided costs, reasonable~~

9 ~~estimates shall be included for financial costs likely to be~~

10 ~~imposed by future regulation of emissions of greenhouse gases.~~

11 The low-income programs described in item (4) of subsection (f)

12 of this Section shall not be required to meet the total

13 resource cost test.

14 (c) Natural gas utilities shall implement cost-effective

15 energy efficiency measures to meet at least the following

16 natural gas savings requirements, which shall be based upon the

17 total amount of gas delivered to retail customers, other than

18 the customers described in subsection (m) of this Section,

19 during calendar year 2009 multiplied by the applicable

20 percentage. Natural gas utilities may comply with this Section

21 by meeting the annual incremental savings goal in the

22 applicable year or by showing that total cumulative annual

23 savings within a 3-year planning period associated with

24 measures implemented after May 31, 2011 were equal to the sum

25 of each annual incremental savings requirement from May 31,

26 2011 through the end of the applicable year:

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1 (1) 0.2% by May 31, 2012;

2 (2) an additional 0.4% by May 31, 2013, increasing

3 total savings to .6%;

4 (3) an additional 0.6% by May 31, 2014, increasing

5 total savings to 1.2%;

6 (4) an additional 0.8% by May 31, 2015, increasing

7 total savings to 2.0%;

8 (5) an additional 1% by May 31, 2016, increasing total

9 savings to 3.0%;

10 (6) an additional 1.2% by May 31, 2017, increasing

11 total savings to 4.2%;

12 (7) an additional 1.4% by May 31, 2018, increasing

13 total savings to 5.6%;

14 (8) an additional 1.5% by May 31, 2019, increasing

15 total savings to 7.1%; and

16 (9) an additional 1.5% in each 12-month period

17 thereafter.

18 (d) Notwithstanding the requirements of subsection (c) of

19 this Section, a natural gas utility shall limit the amount of

20 energy efficiency implemented in any 3-year reporting period

21 established by subsection (f) of Section 8-104 of this Act, by

22 an amount necessary to limit the estimated average increase in

23 the amounts paid by retail customers in connection with natural

24 gas service to no more than 2% in the applicable 3-year

25 reporting period. The energy savings requirements in

26 subsection (c) of this Section may be reduced by the Commission

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1 for the subject plan, if the utility demonstrates by

2 substantial evidence that it is highly unlikely that the

3 requirements could be achieved without exceeding the

4 applicable spending limits in any 3-year reporting period. No

5 later than September 1, 2013, the Commission shall review the

6 limitation on the amount of energy efficiency measures

7 implemented pursuant to this Section and report to the General

8 Assembly, in the report required by subsection (k) of this

9 Section, its findings as to whether that limitation unduly

10 constrains the procurement of energy efficiency measures.

11 (e) Natural gas utilities shall be responsible for

12 overseeing the design, development, and filing of their

13 efficiency plans with the Commission. The utility shall utilize

14 75% of the available funding associated with energy efficiency

15 programs approved by the Commission, and may outsource various

16 aspects of program development and implementation. The

17 remaining 25% of available funding shall be used by the

18 Department of Commerce and Economic Opportunity to implement

19 energy efficiency measures that achieve no less than 20% of the

20 requirements of subsection (c) of this Section. Such measures

21 shall be designed in conjunction with the utility and approved

22 by the Commission. The Department may outsource development and

23 implementation of energy efficiency measures. A minimum of 10%

24 of the entire portfolio of cost-effective energy efficiency

25 measures shall be procured from local government, municipal

26 corporations, school districts, and community college

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1 districts. Five percent of the entire portfolio of

2 cost-effective energy efficiency measures may be granted to

3 local government and municipal corporations for market

4 transformation initiatives. The Department shall coordinate

5 the implementation of these measures and shall integrate

6 delivery of natural gas efficiency programs with electric

7 efficiency programs delivered pursuant to Section 8-103 of this

8 Act, unless the Department can show that integration is not

9 feasible.

10 The apportionment of the dollars to cover the costs to

11 implement the Department's share of the portfolio of energy

12 efficiency measures shall be made to the Department once the

13 Department has executed rebate agreements, grants, or

14 contracts for energy efficiency measures and provided

15 supporting documentation for those rebate agreements, grants,

16 and contracts to the utility. The Department is authorized to

17 adopt any rules necessary and prescribe procedures in order to

18 ensure compliance by applicants in carrying out the purposes of

19 rebate agreements for energy efficiency measures implemented

20 by the Department made under this Section.

21 The details of the measures implemented by the Department

22 shall be submitted by the Department to the Commission in

23 connection with the utility's filing regarding the energy

24 efficiency measures that the utility implements.

25 A utility providing approved energy efficiency measures in

26 this State shall be permitted to recover costs of those

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1 measures through an automatic adjustment clause tariff filed

2 with and approved by the Commission. The tariff shall be

3 established outside the context of a general rate case and

4 shall be applicable to the utility's customers other than the

5 customers described in subsection (m) of this Section. Each

6 year the Commission shall initiate a review to reconcile any

7 amounts collected with the actual costs and to determine the

8 required adjustment to the annual tariff factor to match annual

9 expenditures.

10 Each utility shall include, in its recovery of costs, the

11 costs estimated for both the utility's and the Department's

12 implementation of energy efficiency measures. Costs collected

13 by the utility for measures implemented by the Department shall

14 be submitted to the Department pursuant to Section 605-323 of

15 the Civil Administrative Code of Illinois, shall be deposited

16 into the Energy Efficiency Portfolio Standards Fund, and shall

17 be used by the Department solely for the purpose of

18 implementing these measures. A utility shall not be required to

19 advance any moneys to the Department but only to forward such

20 funds as it has collected. The Department shall report to the

21 Commission on an annual basis regarding the costs actually

22 incurred by the Department in the implementation of the

23 measures. Any changes to the costs of energy efficiency

24 measures as a result of plan modifications shall be

25 appropriately reflected in amounts recovered by the utility and

26 turned over to the Department.

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1 The portfolio of measures, administered by both the

2 utilities and the Department, shall, in combination, be

3 designed to achieve the annual energy savings requirements set

4 forth in subsection (c) of this Section, as modified by

5 subsection (d) of this Section.

6 The utility and the Department shall agree upon a

7 reasonable portfolio of measures and determine the measurable

8 corresponding percentage of the savings goals associated with

9 measures implemented by the Department.

10 No utility shall be assessed a penalty under subsection (f)

11 of this Section for failure to make a timely filing if that

12 failure is the result of a lack of agreement with the

13 Department with respect to the allocation of responsibilities

14 or related costs or target assignments. In that case, the

15 Department and the utility shall file their respective plans

16 with the Commission and the Commission shall determine an

17 appropriate division of measures and programs that meets the

18 requirements of this Section.

19 If the Department is unable to meet performance

20 requirements for the portion of the portfolio implemented by

21 the Department, then the utility and the Department shall

22 jointly submit a modified filing to the Commission explaining

23 the performance shortfall and recommending an appropriate

24 course going forward, including any program modifications that

25 may be appropriate in light of the evaluations conducted under

26 item (8) of subsection (f) of this Section. In this case, the

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1 utility obligation to collect the Department's costs and turn

2 over those funds to the Department under this subsection (e)

3 shall continue only if the Commission approves the

4 modifications to the plan proposed by the Department.

5 (f) No later than October 1, 2010, each gas utility shall

6 file an energy efficiency plan with the Commission to meet the

7 energy efficiency standards through May 31, 2014. Every 3 years

8 thereafter, each utility shall file, no later than October 1,

9 an energy efficiency plan with the Commission, except that for

10 plans covering 2018 through 2025, each gas utility shall file

11 plans on the same schedule as is required for the electric

12 utilities under subsection (f) of Section 8-103 of this Act. If

13 a utility does not file such a plan by the statutory deadline

14 described in this Section ~~October 1 of the applicable year~~,

15 then it shall face a penalty of $100,000 per day until the plan

16 is filed. Each utility's plan shall set forth the utility's

17 proposals to meet the utility's portion of the energy

18 efficiency standards identified in subsection (c) of this

19 Section, as modified by subsection (d) of this Section, taking

20 into account the unique circumstances of the utility's service

21 territory. The Commission shall seek public comment on the

22 utility's plan and shall issue an order approving or

23 disapproving each plan. If the Commission disapproves a plan,

24 the Commission shall, within 30 days, describe in detail the

25 reasons for the disapproval and describe a path by which the

26 utility may file a revised draft of the plan to address the

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1 Commission's concerns satisfactorily. If the utility does not

2 refile with the Commission within 60 days after the

3 disapproval, the utility shall be subject to penalties at a

4 rate of $100,000 per day until the plan is filed. This process

5 shall continue, and penalties shall accrue, until the utility

6 has successfully filed a portfolio of energy efficiency

7 measures. Penalties shall be deposited into the Energy

8 Efficiency Trust Fund and the cost of any such penalties may

9 not be recovered from ratepayers. In submitting proposed energy

10 efficiency plans and funding levels to meet the savings goals

11 adopted by this Act the utility shall:

12 (1) Demonstrate that its proposed energy efficiency

13 measures will achieve the requirements that are identified

14 in subsection (c) of this Section, as modified by

15 subsection (d) of this Section.

16 (2) Present specific proposals to implement new

17 building and appliance standards that have been placed into

18 effect.

19 (3) Present estimates of the total amount paid for gas

20 service expressed on a per therm basis associated with the

21 proposed portfolio of measures designed to meet the

22 requirements that are identified in subsection (c) of this

23 Section, as modified by subsection (d) of this Section.

24 (4) Coordinate with the Department to present a

25 portfolio of energy efficiency measures proportionate to

26 the share of total annual utility revenues in Illinois from

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1 households at or below 150% of the poverty level. Such

2 programs shall be targeted to households with incomes at or

3 below 80% of area median income.

4 (5) Demonstrate that its overall portfolio of energy

5 efficiency measures, not including programs covered by

6 item (4) of this subsection (f), are cost-effective using

7 the total resource cost test and represent a diverse cross

8 section of opportunities for customers of all rate classes

9 to participate in the programs.

10 (6) Demonstrate that a gas utility affiliated with an

11 electric utility that is required to comply with Section

12 8-103 of this Act has integrated gas and electric

13 efficiency measures into a single program that reduces

14 program or participant costs and appropriately allocates

15 costs to gas and electric ratepayers. The Department shall

16 integrate all gas and electric programs it delivers in any

17 such utilities' service territories, unless the Department

18 can show that integration is not feasible or appropriate.

19 (7) Include a proposed cost recovery tariff mechanism

20 to fund the proposed energy efficiency measures and to

21 ensure the recovery of the prudently and reasonably

22 incurred costs of Commission-approved programs.

23 (8) Provide for quarterly status reports tracking

24 implementation of and expenditures for the utility's

25 portfolio of measures and the Department's portfolio of

26 measures, an annual independent review, and a full

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1 independent evaluation of the 3-year results of the

2 performance and the cost-effectiveness of the utility's

3 and Department's portfolios of measures and broader net

4 program impacts and, to the extent practical, for

5 adjustment of the measures on a going forward basis as a

6 result of the evaluations. The resources dedicated to

7 evaluation shall not exceed 3% of portfolio resources in

8 any given 3-year period.

9 (g) No more than 3% of expenditures on energy efficiency

10 measures may be allocated for demonstration of breakthrough

11 equipment and devices.

12 (h) Illinois natural gas utilities that are affiliated by

13 virtue of a common parent company may, at the utilities'

14 request, be considered a single natural gas utility for

15 purposes of complying with this Section.

16 (i) If, after 3 years, a gas utility fails to meet the

17 efficiency standard specified in subsection (c) of this Section

18 as modified by subsection (d), then it shall make a

19 contribution to the Low-Income Home Energy Assistance Program.

20 The total liability for failure to meet the goal shall be

21 assessed as follows:

22 (1) a large gas utility shall pay $600,000;

23 (2) a medium gas utility shall pay $400,000; and

24 (3) a small gas utility shall pay $200,000.

25 For purposes of this Section, (i) a "large gas utility" is

26 a gas utility that on December 31, 2008, served more than

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1 1,500,000 gas customers in Illinois; (ii) a "medium gas

2 utility" is a gas utility that on December 31, 2008, served

3 fewer than 1,500,000, but more than 500,000 gas customers in

4 Illinois; and (iii) a "small gas utility" is a gas utility that

5 on December 31, 2008, served fewer than 500,000 and more than

6 100,000 gas customers in Illinois. The costs of this

7 contribution may not be recovered from ratepayers.

8 If a gas utility fails to meet the efficiency standard

9 specified in subsection (c) of this Section, as modified by

10 subsection (d) of this Section, in any 2 consecutive 3-year

11 planning periods, then the responsibility for implementing the

12 utility's energy efficiency measures shall be transferred to an

13 independent program administrator selected by the Commission.

14 Reasonable and prudent costs incurred by the independent

15 program administrator to meet the efficiency standard

16 specified in subsection (c) of this Section, as modified by

17 subsection (d) of this Section, may be recovered from the

18 customers of the affected gas utilities, other than customers

19 described in subsection (m) of this Section. The utility shall

20 provide the independent program administrator with all

21 information and assistance necessary to perform the program

22 administrator's duties including but not limited to customer,

23 account, and energy usage data, and shall allow the program

24 administrator to include inserts in customer bills. The utility

25 may recover reasonable costs associated with any such

26 assistance.

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1 (j) No utility shall be deemed to have failed to meet the

2 energy efficiency standards to the extent any such failure is

3 due to a failure of the Department.

4 (k) Not later than January 1, 2012, the Commission shall

5 develop and solicit public comment on a plan to foster

6 statewide coordination and consistency between statutorily

7 mandated natural gas and electric energy efficiency programs to

8 reduce program or participant costs or to improve program

9 performance. Not later than September 1, 2013, the Commission

10 shall issue a report to the General Assembly containing its

11 findings and recommendations.

12 (l) This Section does not apply to a gas utility that on

13 January 1, 2009, provided gas service to fewer than 100,000

14 customers in Illinois.

15 (m) Subsections (a) through (k) of this Section do not

16 apply to customers of a natural gas utility that have a North

17 American Industry Classification System code number that is

18 22111 or any such code number beginning with the digits 31, 32,

19 or 33 and (i) annual usage in the aggregate of 4 million therms

20 or more within the service territory of the affected gas

21 utility or with aggregate usage of 8 million therms or more in

22 this State and complying with the provisions of item (l) of

23 this subsection (m); or (ii) using natural gas as feedstock and

24 meeting the usage requirements described in item (i) of this

25 subsection (m), to the extent such annual feedstock usage is

26 greater than 60% of the customer's total annual usage of

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1 natural gas.

2 (1) Customers described in this subsection (m) of this

3 Section shall apply, on a form approved on or before

4 October 1, 2009 by the Department, to the Department to be

5 designated as a self-directing customer ("SDC") or as an

6 exempt customer using natural gas as a feedstock from which

7 other products are made, including, but not limited to,

8 feedstock for a hydrogen plant, on or before the 1st day of

9 February, 2010. Thereafter, application may be made not

10 less than 6 months before the filing date of the gas

11 utility energy efficiency plan described in subsection (f)

12 of this Section; however, a new customer that commences

13 taking service from a natural gas utility after February 1,

14 2010 may apply to become a SDC or exempt customer up to 30

15 days after beginning service. Customers described in this

16 subsection (m) that have not already been approved by the

17 Department may apply to be designated a self-directing

18 customer or exempt customer, on a form approved by the

19 Department, between September 1, 2013 and September 30,

20 2013. Customer applications that are approved by the

21 Department under this amendatory Act of the 98th General

22 Assembly shall be considered to be a self-directing

23 customer or exempt customer, as applicable, for the current

24 3-year planning period effective December 1, 2013. Such

25 application shall contain the following:

26 (A) the customer's certification that, at the time

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1 of its application, it qualifies to be a SDC or exempt

2 customer described in this subsection (m) of this

3 Section;

4 (B) in the case of a SDC, the customer's

5 certification that it has established or will

6 establish by the beginning of the utility's 3-year

7 planning period commencing subsequent to the

8 application, and will maintain for accounting

9 purposes, an energy efficiency reserve account and

10 that the customer will accrue funds in said account to

11 be held for the purpose of funding, in whole or in

12 part, energy efficiency measures of the customer's

13 choosing, which may include, but are not limited to,

14 projects involving combined heat and power systems

15 that use the same energy source both for the generation

16 of electrical or mechanical power and the production of

17 steam or another form of useful thermal energy or the

18 use of combustible gas produced from biomass, or both;

19 (C) in the case of a SDC, the customer's

20 certification that annual funding levels for the

21 energy efficiency reserve account will be equal to 2%

22 of the customer's cost of natural gas, composed of the

23 customer's commodity cost and the delivery service

24 charges paid to the gas utility, or $150,000, whichever

25 is less;

26 (D) in the case of a SDC, the customer's

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1 certification that the required reserve account

2 balance will be capped at 3 years' worth of accruals

3 and that the customer may, at its option, make further

4 deposits to the account to the extent such deposit

5 would increase the reserve account balance above the

6 designated cap level;

7 (E) in the case of a SDC, the customer's

8 certification that by October 1 of each year, beginning

9 no sooner than October 1, 2012, the customer will

10 report to the Department information, for the 12-month

11 period ending May 31 of the same year, on all deposits

12 and reductions, if any, to the reserve account during

13 the reporting year, and to the extent deposits to the

14 reserve account in any year are in an amount less than

15 $150,000, the basis for such reduced deposits; reserve

16 account balances by month; a description of energy

17 efficiency measures undertaken by the customer and

18 paid for in whole or in part with funds from the

19 reserve account; an estimate of the energy saved, or to

20 be saved, by the measure; and that the report shall

21 include a verification by an officer or plant manager

22 of the customer or by a registered professional

23 engineer or certified energy efficiency trade

24 professional that the funds withdrawn from the reserve

25 account were used for the energy efficiency measures;

26 (F) in the case of an exempt customer, the

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1 customer's certification of the level of gas usage as

2 feedstock in the customer's operation in a typical year

3 and that it will provide information establishing this

4 level, upon request of the Department;

5 (G) in the case of either an exempt customer or a

6 SDC, the customer's certification that it has provided

7 the gas utility or utilities serving the customer with

8 a copy of the application as filed with the Department;

9 (H) in the case of either an exempt customer or a

10 SDC, certification of the natural gas utility or

11 utilities serving the customer in Illinois including

12 the natural gas utility accounts that are the subject

13 of the application; and

14 (I) in the case of either an exempt customer or a

15 SDC, a verification signed by a plant manager or an

16 authorized corporate officer attesting to the

17 truthfulness and accuracy of the information contained

18 in the application.

19 (2) The Department shall review the application to

20 determine that it contains the information described in

21 provisions (A) through (I) of item (1) of this subsection

22 (m), as applicable. The review shall be completed within 30

23 days after the date the application is filed with the

24 Department. Absent a determination by the Department

25 within the 30-day period, the applicant shall be considered

26 to be a SDC or exempt customer, as applicable, for all

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1 subsequent 3-year planning periods, as of the date of

2 filing the application described in this subsection (m). If

3 the Department determines that the application does not

4 contain the applicable information described in provisions

5 (A) through (I) of item (1) of this subsection (m), it

6 shall notify the customer, in writing, of its determination

7 that the application does not contain the required

8 information and identify the information that is missing,

9 and the customer shall provide the missing information

10 within 15 working days after the date of receipt of the

11 Department's notification.

12 (3) The Department shall have the right to audit the

13 information provided in the customer's application and

14 annual reports to ensure continued compliance with the

15 requirements of this subsection. Based on the audit, if the

16 Department determines the customer is no longer in

17 compliance with the requirements of items (A) through (I)

18 of item (1) of this subsection (m), as applicable, the

19 Department shall notify the customer in writing of the

20 noncompliance. The customer shall have 30 days to establish

21 its compliance, and failing to do so, may have its status

22 as a SDC or exempt customer revoked by the Department. The

23 Department shall treat all information provided by any

24 customer seeking SDC status or exemption from the

25 provisions of this Section as strictly confidential.

26 (4) Upon request, or on its own motion, the Commission

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1 may open an investigation, no more than once every 3 years

2 and not before October 1, 2014, to evaluate the

3 effectiveness of the self-directing program described in

4 this subsection (m).

5 Customers described in this subsection (m) that applied to

6 the Department on January 3, 2013, were approved by the

7 Department on February 13, 2013 to be a self-directing customer

8 or exempt customer, and receive natural gas from a utility that

9 provides gas service to at least 500,000 retail customers in

10 Illinois and electric service to at least 1,000,000 retail

11 customers in Illinois shall be considered to be a

12 self-directing customer or exempt customer, as applicable, for

13 the current 3-year planning period effective December 1, 2013.

14 (n) The applicability of this Section to customers

15 described in subsection (m) of this Section is conditioned on

16 the existence of the SDC program. In no event will any

17 provision of this Section apply to such customers after January

18 1, 2020.

19 (Source: P.A. 97-813, eff. 7-13-12; 97-841, eff. 7-20-12;

20 98-90, eff. 7-15-13; 98-225, eff. 8-9-13; 98-604, eff.

21 12-17-13.)

22 (220 ILCS 5/16-107)

23 Sec. 16-107. Real-time pricing.

24 (a) Each electric utility shall file, on or before May 1,

25 1998, a tariff or tariffs which allow nonresidential retail

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1 customers in the electric utility's service area to elect

2 real-time pricing beginning October 1, 1998.

3 (b) Each electric utility shall file, on or before May 1,

4 2000, a tariff or tariffs which allow residential retail

5 customers in the electric utility's service area to elect

6 real-time pricing beginning October 1, 2000.

7 (b-5) Each electric utility shall file a tariff or tariffs

8 allowing residential retail customers in the electric

9 utility's service area to elect real-time pricing beginning

10 January 2, 2007. ~~A customer who elects real-time pricing shall~~

11 ~~remain on such rate for a minimum of 12 months.~~ The Commission

12 may, after notice and hearing, approve the tariff or tariffs,

13 provided that the Commission finds that the potential for

14 demand reductions will result in net economic benefits to all

15 residential customers of the electric utility. In examining

16 economic benefits from demand reductions, the Commission

17 shall, at a minimum, consider the following: improvements to

18 system reliability and power quality, reduction in wholesale

19 market prices and price volatility, electric utility cost

20 avoidance and reductions, market power mitigation, and other

21 benefits of demand reductions, but only to the extent that the

22 effects of reduced demand can be demonstrated to lower the cost

23 of electricity delivered to residential customers. A tariff or

24 tariffs approved pursuant to this subsection (b-5) shall, at a

25 minimum, describe (i) the methodology for determining the

26 market price of energy to be reflected in the real-time rate

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1 and (ii) the manner in which customers who elect real-time

2 pricing will be provided with ready access to hourly market

3 prices, including, but not limited to, day-ahead hourly energy

4 prices.

5 A proceeding under this subsection (b-5) may not exceed 120

6 days in length.

7 (b-10) Each electric utility providing real-time pricing

8 pursuant to subsection (b-5) shall install a meter capable of

9 recording hourly interval energy use at the service location of

10 each customer that elects real-time pricing pursuant to this

11 subsection.

12 (b-15) If the Commission issues an order pursuant to

13 subsection (b-5), the affected electric utility shall contract

14 with an entity not affiliated with the electric utility to

15 serve as a program administrator to develop and implement a

16 program to provide consumer outreach, enrollment, and

17 education concerning real-time pricing and to establish and

18 administer an information system and technical and other

19 customer assistance that is necessary to enable customers to

20 manage electricity use. The program administrator: (i) shall be

21 selected and compensated by the electric utility, subject to

22 Commission approval; (ii) shall have demonstrated technical

23 and managerial competence in the development and

24 administration of demand management programs; and (iii) may

25 develop and implement risk management, energy efficiency, and

26 other services related to energy use management for which the

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1 program administrator shall be compensated by participants in

2 the program receiving such services. The electric utility shall

3 provide the program administrator with all information and

4 assistance necessary to perform the program administrator's

5 duties, including, but not limited to, customer, account, and

6 energy use data. The electric utility shall permit the program

7 administrator to include inserts in residential customer bills

8 2 times per year to assist with customer outreach and

9 enrollment.

10 The program administrator shall submit an annual report to

11 the electric utility no later than April 1 of each year

12 describing the operation and results of the program, including

13 information concerning the number and types of customers using

14 real-time pricing, changes in customers' energy use patterns,

15 an assessment of the value of the program to both participants

16 and non-participants, and recommendations concerning

17 modification of the program and the tariff or tariffs filed

18 under subsection (b-5). This report shall be filed by the

19 electric utility with the Commission within 30 days of receipt

20 and shall be available to the public on the Commission's web

21 site.

22 (b-20) The Commission shall monitor the performance of

23 programs established pursuant to subsection (b-15) and shall

24 order the termination or modification of a program if it

25 determines that the program is not, after a reasonable period

26 of time for development not to exceed 4 years, resulting in net

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1 benefits to the residential customers of the electric utility.

2 (b-25) An electric utility shall be entitled to recover

3 reasonable costs incurred in complying with this Section,

4 provided that recovery of the costs is fairly apportioned among

5 its residential customers as provided in this subsection

6 (b-25). The electric utility may apportion greater costs on the

7 residential customers who elect real-time pricing, but may also

8 impose some of the costs of real-time pricing on customers who

9 do not elect real-time pricing, provided that the Commission

10 determines that the cost savings resulting from real-time

11 pricing will exceed the costs imposed on customers for

12 maintaining the program.

13 (c) The electric utility's tariff or tariffs filed pursuant

14 to this Section shall be subject to Article IX.

15 (d) This Section does not apply to any electric utility

16 providing service to 100,000 or fewer customers.

17 (Source: P.A. 94-977, eff. 6-30-06.)

18 (220 ILCS 5/16-108.5)

19 Sec. 16-108.5. Infrastructure investment and

20 modernization; regulatory reform.

21 (a) (Blank).

22 (b) For purposes of this Section, "participating utility"

23 means an electric utility or a combination utility serving more

24 than 1,000,000 customers in Illinois that voluntarily elects

25 and commits to undertake (i) the infrastructure investment

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1 program consisting of the commitments and obligations

2 described in this subsection (b) and (ii) the customer

3 assistance program consisting of the commitments and

4 obligations described in subsection (b-10) of this Section,

5 notwithstanding any other provisions of this Act and without

6 obtaining any approvals from the Commission or any other agency

7 other than as set forth in this Section, regardless of whether

8 any such approval would otherwise be required. "Combination

9 utility" means a utility that, as of January 1, 2011, provided

10 electric service to at least one million retail customers in

11 Illinois and gas service to at least 500,000 retail customers

12 in Illinois. A participating utility shall recover the

13 expenditures made under the infrastructure investment program

14 through the ratemaking process, including, but not limited to,

15 the performance-based formula rate and process set forth in

16 this Section.

17 During the infrastructure investment program's peak

18 program year, a participating utility other than a combination

19 utility shall create 2,000 full-time equivalent jobs in

20 Illinois, and a participating utility that is a combination

21 utility shall create 450 full-time equivalent jobs in Illinois

22 related to the provision of electric service. These jobs shall

23 include direct jobs, contractor positions, and induced jobs,

24 but shall not include any portion of a job commitment, not

25 specifically contingent on an amendatory Act of the 97th

26 General Assembly becoming law, between a participating utility

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1 and a labor union that existed on the effective date of this

2 amendatory Act of the 97th General Assembly and that has not

3 yet been fulfilled. A portion of the full-time equivalent jobs

4 created by each participating utility shall include

5 incremental personnel hired subsequent to the effective date of

6 this amendatory Act of the 97th General Assembly. For purposes

7 of this Section, "peak program year" means the consecutive

8 12-month period with the highest number of full-time equivalent

9 jobs that occurs between the beginning of investment year 2 and

10 the end of investment year 4.

11 A participating utility shall meet one of the following

12 commitments, as applicable:

13 (1) Beginning no later than 180 days after a

14 participating utility other than a combination utility

15 files a performance-based formula rate tariff pursuant to

16 subsection (c) of this Section, or, beginning no later than

17 January 1, 2012 if such utility files such

18 performance-based formula rate tariff within 14 days of the

19 effective date of this amendatory Act of the 97th General

20 Assembly, the participating utility shall, except as

21 provided in subsection (b-5):

22 (A) over a 5-year period, invest an estimated

23 $1,300,000,000 in electric system upgrades,

24 modernization projects, and training facilities,

25 including, but not limited to:

26 (i) distribution infrastructure improvements

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1 totaling an estimated $1,000,000,000, including

2 underground residential distribution cable

3 injection and replacement and mainline cable

4 system refurbishment and replacement projects;

5 (ii) training facility construction or upgrade

6 projects totaling an estimated $10,000,000,

7 provided that, at a minimum, one such facility

8 shall be located in a municipality having a

9 population of more than 2 million residents and one

10 such facility shall be located in a municipality

11 having a population of more than 150,000 residents

12 but fewer than 170,000 residents; any such new

13 facility located in a municipality having a

14 population of more than 2 million residents must be

15 designed for the purpose of obtaining, and the

16 owner of the facility shall apply for,

17 certification under the United States Green

18 Building Council's Leadership in Energy Efficiency

19 Design Green Building Rating System;

20 (iii) wood pole inspection, treatment, and

21 replacement programs;

22 (iv) an estimated $200,000,000 for reducing

23 the susceptibility of certain circuits to

24 storm-related damage, including, but not limited

25 to, high winds, thunderstorms, and ice storms;

26 improvements may include, but are not limited to,

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1 overhead to underground conversion and other

2 engineered outcomes for circuits; the

3 participating utility shall prioritize the

4 selection of circuits based on each circuit's

5 historical susceptibility to storm-related damage

6 and the ability to provide the greatest customer

7 benefit upon completion of the improvements; to be

8 eligible for improvement, the participating

9 utility's ability to maintain proper tree

10 clearances surrounding the overhead circuit must

11 not have been impeded by third parties; and

12 (B) over a 10-year period, invest an estimated

13 $1,300,000,000 to upgrade and modernize its

14 transmission and distribution infrastructure and in

15 Smart Grid electric system upgrades, including, but

16 not limited to:

17 (i) additional smart meters;

18 (ii) distribution automation;

19 (iii) associated cyber secure data

20 communication network; and

21 (iv) substation micro-processor relay

22 upgrades.

23 (2) Beginning no later than 180 days after a

24 participating utility that is a combination utility files a

25 performance-based formula rate tariff pursuant to

26 subsection (c) of this Section, or, beginning no later than

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1 January 1, 2012 if such utility files such

2 performance-based formula rate tariff within 14 days of the

3 effective date of this amendatory Act of the 97th General

4 Assembly, the participating utility shall, except as

5 provided in subsection (b-5):

6 (A) over a 10-year period, invest an estimated

7 $265,000,000 in electric system upgrades,

8 modernization projects, and training facilities,

9 including, but not limited to:

10 (i) distribution infrastructure improvements

11 totaling an estimated $245,000,000, which may

12 include bulk supply substations, transformers,

13 reconductoring, and rebuilding overhead

14 distribution and sub-transmission lines,

15 underground residential distribution cable

16 injection and replacement and mainline cable

17 system refurbishment and replacement projects;

18 (ii) training facility construction or upgrade

19 projects totaling an estimated $1,000,000; any

20 such new facility must be designed for the purpose

21 of obtaining, and the owner of the facility shall

22 apply for, certification under the United States

23 Green Building Council's Leadership in Energy

24 Efficiency Design Green Building Rating System;

25 and

26 (iii) wood pole inspection, treatment, and

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1 replacement programs; and

2 (B) over a 10-year period, invest an estimated

3 $360,000,000 to upgrade and modernize its transmission

4 and distribution infrastructure and in Smart Grid

5 electric system upgrades, including, but not limited

6 to:

7 (i) additional smart meters;

8 (ii) distribution automation;

9 (iii) associated cyber secure data

10 communication network; and

11 (iv) substation micro-processor relay

12 upgrades.

13 For purposes of this Section, "Smart Grid electric system

14 upgrades" shall have the meaning set forth in subsection (a) of

15 Section 16-108.6 of this Act.

16 The investments in the infrastructure investment program

17 described in this subsection (b) shall be incremental to the

18 participating utility's annual capital investment program, as

19 defined by, for purposes of this subsection (b), the

20 participating utility's average capital spend for calendar

21 years 2008, 2009, and 2010 as reported in the applicable

22 Federal Energy Regulatory Commission (FERC) Form 1; provided

23 that where one or more utilities have merged, the average

24 capital spend shall be determined using the aggregate of the

25 merged utilities' capital spend reported in FERC Form 1 for the

26 years 2008, 2009, and 2010. A participating utility may add

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1 reasonable construction ramp-up and ramp-down time to the

2 investment periods specified in this subsection (b). For each

3 such investment period, the ramp-up and ramp-down time shall

4 not exceed a total of 6 months.

5 Within 60 days after filing a tariff under subsection (c)

6 of this Section, a participating utility shall submit to the

7 Commission its plan, including scope, schedule, and staffing,

8 for satisfying its infrastructure investment program

9 commitments pursuant to this subsection (b). The submitted plan

10 shall include a schedule and staffing plan for the next

11 calendar year. The plan shall also include a plan for the

12 creation, operation, and administration of a Smart Grid test

13 bed as described in subsection (c) of Section 16-108.8. The

14 plan need not allocate the work equally over the respective

15 periods, but should allocate material increments throughout

16 such periods commensurate with the work to be undertaken. No

17 later than April 1 of each subsequent year, the utility shall

18 submit to the Commission a report that includes any updates to

19 the plan, a schedule for the next calendar year, the

20 expenditures made for the prior calendar year and cumulatively,

21 and the number of full-time equivalent jobs created for the

22 prior calendar year and cumulatively. If the utility is

23 materially deficient in satisfying a schedule or staffing plan,

24 then the report must also include a corrective action plan to

25 address the deficiency. The fact that the plan, implementation

26 of the plan, or a schedule changes shall not imply the

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1 imprudence or unreasonableness of the infrastructure

2 investment program, plan, or schedule. Further, no later than

3 45 days following the last day of the first, second, and third

4 quarters of each year of the plan, a participating utility

5 shall submit to the Commission a verified quarterly report for

6 the prior quarter that includes (i) the total number of

7 full-time equivalent jobs created during the prior quarter,

8 (ii) the total number of employees as of the last day of the

9 prior quarter, (iii) the total number of full-time equivalent

10 hours in each job classification or job title, (iv) the total

11 number of incremental employees and contractors in support of

12 the investments undertaken pursuant to this subsection (b) for

13 the prior quarter, and (v) any other information that the

14 Commission may require by rule.

15 With respect to the participating utility's peak job

16 commitment, if, after considering the utility's corrective

17 action plan and compliance thereunder, the Commission enters an

18 order finding, after notice and hearing, that a participating

19 utility did not satisfy its peak job commitment described in

20 this subsection (b) for reasons that are reasonably within its

21 control, then the Commission shall also determine, after

22 consideration of the evidence, including, but not limited to,

23 evidence submitted by the Department of Commerce and Economic

24 Opportunity and the utility, the deficiency in the number of

25 full-time equivalent jobs during the peak program year due to

26 such failure. The Commission shall notify the Department of any

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1 proceeding that is initiated pursuant to this paragraph. For

2 each full-time equivalent job deficiency during the peak

3 program year that the Commission finds as set forth in this

4 paragraph, the participating utility shall, within 30 days

5 after the entry of the Commission's order, pay $6,000 to a fund

6 for training grants administered under Section 605-800 of The

7 Department of Commerce and Economic Opportunity Law, which

8 shall not be a recoverable expense.

9 With respect to the participating utility's investment

10 amount commitments, if, after considering the utility's

11 corrective action plan and compliance thereunder, the

12 Commission enters an order finding, after notice and hearing,

13 that a participating utility is not satisfying its investment

14 amount commitments described in this subsection (b), then the

15 utility shall no longer be eligible to annually update the

16 performance-based formula rate tariff pursuant to subsection

17 (d) of this Section. In such event, the then current rates

18 shall remain in effect until such time as new rates are set

19 pursuant to Article IX of this Act, subject to retroactive

20 adjustment, with interest, to reconcile rates charged with

21 actual costs.

22 If the Commission finds that a participating utility is no

23 longer eligible to update the performance-based formula rate

24 tariff pursuant to subsection (d) of this Section, or the

25 performance-based formula rate is otherwise terminated, then

26 the participating utility's voluntary commitments and

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1 obligations under this subsection (b) shall immediately

2 terminate, except for the utility's obligation to pay an amount

3 already owed to the fund for training grants pursuant to a

4 Commission order.

5 In meeting the obligations of this subsection (b), to the

6 extent feasible and consistent with State and federal law, the

7 investments under the infrastructure investment program should

8 provide employment opportunities for all segments of the

9 population and workforce, including minority-owned and

10 female-owned business enterprises, and shall not, consistent

11 with State and federal law, discriminate based on race or

12 socioeconomic status.

13 (b-5) Nothing in this Section shall prohibit the Commission

14 from investigating the prudence and reasonableness of the

15 expenditures made under the infrastructure investment program

16 during the annual review required by subsection (d) of this

17 Section and shall, as part of such investigation, determine

18 whether the utility's actual costs under the program are

19 prudent and reasonable. The fact that a participating utility

20 invests more than the minimum amounts specified in subsection

21 (b) of this Section or its plan shall not imply imprudence or

22 unreasonableness.

23 If the participating utility finds that it is implementing

24 its plan for satisfying the infrastructure investment program

25 commitments described in subsection (b) of this Section at a

26 cost below the estimated amounts specified in subsection (b) of

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1 this Section, then the utility may file a petition with the

2 Commission requesting that it be permitted to satisfy its

3 commitments by spending less than the estimated amounts

4 specified in subsection (b) of this Section. The Commission

5 shall, after notice and hearing, enter its order approving, or

6 approving as modified, or denying each such petition within 150

7 days after the filing of the petition.

8 In no event, absent General Assembly approval, shall the

9 capital investment costs incurred by a participating utility

10 other than a combination utility in satisfying its

11 infrastructure investment program commitments described in

12 subsection (b) of this Section exceed $3,000,000,000 or, for a

13 participating utility that is a combination utility,

14 $720,000,000. If the participating utility's updated cost

15 estimates for satisfying its infrastructure investment program

16 commitments described in subsection (b) of this Section exceed

17 the limitation imposed by this subsection (b-5), then it shall

18 submit a report to the Commission that identifies the increased

19 costs and explains the reason or reasons for the increased

20 costs no later than the year in which the utility estimates it

21 will exceed the limitation. The Commission shall review the

22 report and shall, within 90 days after the participating

23 utility files the report, report to the General Assembly its

24 findings regarding the participating utility's report. If the

25 General Assembly does not amend the limitation imposed by this

26 subsection (b-5), then the utility may modify its plan so as

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1 not to exceed the limitation imposed by this subsection (b-5)

2 and may propose corresponding changes to the metrics

3 established pursuant to subparagraphs (5) through (8) of

4 subsection (f) of this Section, and the Commission may modify

5 the metrics and incremental savings goals established pursuant

6 to subsection (f) of this Section accordingly.

7 (b-10) All participating utilities shall make

8 contributions for an energy low-income and support program in

9 accordance with this subsection. Beginning no later than 180

10 days after a participating utility files a performance-based

11 formula rate tariff pursuant to subsection (c) of this Section,

12 or beginning no later than January 1, 2012 if such utility

13 files such performance-based formula rate tariff within 14 days

14 of the effective date of this amendatory Act of the 97th

15 General Assembly, and without obtaining any approvals from the

16 Commission or any other agency other than as set forth in this

17 Section, regardless of whether any such approval would

18 otherwise be required, a participating utility other than a

19 combination utility shall pay $10,000,000 per year for 5 years

20 and a participating utility that is a combination utility shall

21 pay $1,000,000 per year for 10 years to the energy low-income

22 and support program, which is intended to fund customer

23 assistance programs with the primary purpose being avoidance of

24 imminent disconnection. Such programs may include:

25 (1) a residential hardship program that may partner

26 with community-based organizations, including senior

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1 citizen organizations, and provides grants to low-income

2 residential customers, including low-income senior

3 citizens, who demonstrate a hardship;

4 (2) a program that provides grants and other bill

5 payment concessions to disabled veterans who demonstrate a

6 hardship and members of the armed services or reserve

7 forces of the United States or members of the Illinois

8 National Guard who are on active duty pursuant to an

9 executive order of the President of the United States, an

10 act of the Congress of the United States, or an order of

11 the Governor and who demonstrate a hardship;

12 (3) a budget assistance program that provides tools and

13 education to low-income senior citizens to assist them with

14 obtaining information regarding energy usage and effective

15 means of managing energy costs;

16 (4) a non-residential special hardship program that

17 provides grants to non-residential customers such as small

18 businesses and non-profit organizations that demonstrate a

19 hardship, including those providing services to senior

20 citizen and low-income customers; and

21 (5) a performance-based assistance program that

22 provides grants to encourage residential customers to make

23 on-time payments by matching a portion of the customer's

24 payments or providing credits towards arrearages.

25 The payments made by a participating utility pursuant to

26 this subsection (b-10) shall not be a recoverable expense. A

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1 participating utility may elect to fund either new or existing

2 customer assistance programs, including, but not limited to,

3 those that are administered by the utility.

4 Programs that use funds that are provided by a

5 participating utility to reduce utility bills shall ~~may~~ be

6 implemented through tariffs that are filed with and reviewed by

7 the Commission. If a utility elects to file tariffs with the

8 Commission to implement all or a portion of the programs, those

9 tariffs shall, regardless of the date actually filed, be deemed

10 accepted and approved, and shall become effective on the

11 effective date of this amendatory Act of the 97th General

12 Assembly. The participating utilities whose customers benefit

13 from the funds that are disbursed as contemplated in this

14 Section shall file annual reports documenting the disbursement

15 of those funds with the Commission. The Commission has the

16 authority to audit disbursement of the funds to ensure they

17 were disbursed consistently with this Section.

18 If the Commission finds that a participating utility is no

19 longer eligible to update the performance-based formula rate

20 tariff pursuant to subsection (d) of this Section, or the

21 performance-based formula rate is otherwise terminated, then

22 the participating utility's voluntary commitments and

23 obligations under this subsection (b-10) shall immediately

24 terminate.

25 (c) A participating utility shall ~~may elect to~~ recover its

26 delivery services costs through a performance-based formula

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1 rate approved by the Commission, which shall specify the cost

2 components that form the basis of the rate charged to customers

3 with sufficient specificity to operate in a standardized manner

4 and be updated annually with transparent information that

5 reflects the utility's actual costs to be recovered during the

6 applicable rate year, which is the period beginning with the

7 first billing day of January and extending through the last

8 billing day of the following December. In the event the utility

9 recovers a portion of its costs through automatic adjustment

10 clause tariffs on the effective date of this amendatory Act of

11 the 97th General Assembly, the utility may elect to continue to

12 recover these costs through such tariffs, but then these costs

13 shall not be recovered through the performance-based formula

14 rate. In the event the participating utility, prior to the

15 effective date of this amendatory Act of the 97th General

16 Assembly, filed electric delivery services tariffs with the

17 Commission pursuant to Section 9-201 of this Act that are

18 related to the recovery of its electric delivery services costs

19 that are still pending on the effective date of this amendatory

20 Act of the 97th General Assembly, the participating utility

21 shall, at the time it files its performance-based formula rate

22 tariff with the Commission, also file a notice of withdrawal

23 with the Commission to withdraw the electric delivery services

24 tariffs previously filed pursuant to Section 9-201 of this Act.

25 Upon receipt of such notice, the Commission shall dismiss with

26 prejudice any docket that had been initiated to investigate the

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1 electric delivery services tariffs filed pursuant to Section

2 9-201 of this Act, and such tariffs and the record related

3 thereto shall not be the subject of any further hearing,

4 investigation, or proceeding of any kind related to rates for

5 electric delivery services.

6 The performance-based formula rate shall be implemented

7 through a tariff filed with the Commission consistent with the

8 provisions of this subsection (c) that shall be applicable to

9 all delivery services customers. The Commission shall initiate

10 and conduct an investigation of the tariff in a manner

11 consistent with the provisions of this subsection (c) and the

12 provisions of Article IX of this Act to the extent they do not

13 conflict with this subsection (c). Except in the case where the

14 Commission finds, after notice and hearing, that a

15 participating utility is not satisfying its investment amount

16 commitments under subsection (b) of this Section, the

17 performance-based formula rate shall remain in effect at the

18 discretion of the utility. The performance-based formula rate

19 approved by the Commission shall do the following:

20 (1) Provide for the recovery of the utility's actual

21 costs of delivery services that are prudently incurred and

22 reasonable in amount consistent with Commission practice

23 and law. The sole fact that a cost differs from that

24 incurred in a prior calendar year or that an investment is

25 different from that made in a prior calendar year shall not

26 imply the imprudence or unreasonableness of that cost or

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1 investment.

2 (2) Reflect the utility's actual year-end capital

3 structure for the applicable calendar year, excluding

4 goodwill, subject to a determination of prudence and

5 reasonableness consistent with Commission practice and

6 law.

7 (3) Include a cost of equity, which shall be calculated

8 as the sum of the following:

9 (A) the average for the applicable calendar year of

10 the monthly average yields of 30-year U.S. Treasury

11 bonds published by the Board of Governors of the

12 Federal Reserve System in its weekly H.15 Statistical

13 Release or successor publication; and

14 (B) 580 basis points.

15 At such time as the Board of Governors of the Federal

16 Reserve System ceases to include the monthly average yields

17 of 30-year U.S. Treasury bonds in its weekly H.15

18 Statistical Release or successor publication, the monthly

19 average yields of the U.S. Treasury bonds then having the

20 longest duration published by the Board of Governors in its

21 weekly H.15 Statistical Release or successor publication

22 shall instead be used for purposes of this paragraph (3).

23 (4) Permit and set forth protocols, subject to a

24 determination of prudence and reasonableness consistent

25 with Commission practice and law, for the following:

26 (A) recovery of incentive compensation expense

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1 that is based on the achievement of operational

2 metrics, including metrics related to budget controls,

3 outage duration and frequency, safety, customer

4 service, efficiency and productivity, and

5 environmental compliance. Incentive compensation

6 expense that is based on net income or an affiliate's

7 earnings per share shall not be recoverable under the

8 performance-based formula rate;

9 (B) recovery of pension and other post-employment

10 benefits expense, provided that such costs are

11 supported by an actuarial study;

12 (C) recovery of severance costs, provided that if

13 the amount is over $3,700,000 for a participating

14 utility that is a combination utility or $10,000,000

15 for a participating utility that serves more than 3

16 million retail customers, then the full amount shall be

17 amortized consistent with subparagraph (F) of this

18 paragraph (4);

19 (D) investment return at a rate equal to the

20 utility's weighted average cost of long-term debt, on

21 the pension assets as, and in the amount, reported in

22 Account 186 (or in such other Account or Accounts as

23 such asset may subsequently be recorded) of the

24 utility's most recently filed FERC Form 1, net of

25 deferred tax benefits;

26 (E) recovery of the expenses related to the

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1 Commission proceeding under this subsection (c) to

2 approve this performance-based formula rate and

3 initial rates or to subsequent proceedings related to

4 the formula, provided that the recovery shall be

5 amortized over a 3-year period; recovery of expenses

6 related to the annual Commission proceedings under

7 subsection (d) of this Section to review the inputs to

8 the performance-based formula rate shall be expensed

9 and recovered through the performance-based formula

10 rate;

11 (F) amortization over a 5-year period of the full

12 amount of each charge or credit that exceeds $3,700,000

13 for a participating utility that is a combination

14 utility or $10,000,000 for a participating utility

15 that serves more than 3 million retail customers in the

16 applicable calendar year and that relates to a

17 workforce reduction program's severance costs, changes

18 in accounting rules, changes in law, compliance with

19 any Commission-initiated audit, or a single storm or

20 other similar expense, provided that any unamortized

21 balance shall be reflected in rate base. For purposes

22 of this subparagraph (F), changes in law includes any

23 enactment, repeal, or amendment in a law, ordinance,

24 rule, regulation, interpretation, permit, license,

25 consent, or order, including those relating to taxes,

26 accounting, or to environmental matters, or in the

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1 interpretation or application thereof by any

2 governmental authority occurring after the effective

3 date of this amendatory Act of the 97th General

4 Assembly;

5 (G) recovery of existing regulatory assets over

6 the periods previously authorized by the Commission;

7 (H) historical weather normalized billing

8 determinants; and

9 (I) allocation methods for common costs.

10 (5) Provide that if the participating utility's earned

11 rate of return on common equity related to the provision of

12 delivery services for the prior rate year (calculated using

13 costs and capital structure approved by the Commission as

14 provided in subparagraph (2) of this subsection (c),

15 consistent with this Section, in accordance with

16 Commission rules and orders, including, but not limited to,

17 adjustments for goodwill, and after any Commission-ordered

18 disallowances and taxes) is more than 50 basis points

19 higher than the rate of return on common equity calculated

20 pursuant to paragraph (3) of this subsection (c) (after

21 adjusting for any penalties to the rate of return on common

22 equity applied pursuant to the performance metrics

23 provision of subsection (f) of this Section), then the

24 participating utility shall apply a credit through the

25 performance-based formula rate that reflects an amount

26 equal to the value of that portion of the earned rate of

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1 return on common equity that is more than 50 basis points

2 higher than the rate of return on common equity calculated

3 pursuant to paragraph (3) of this subsection (c) (after

4 adjusting for any penalties to the rate of return on common

5 equity applied pursuant to the performance metrics

6 provision of subsection (f) of this Section) for the prior

7 rate year, adjusted for taxes. If the participating

8 utility's earned rate of return on common equity related to

9 the provision of delivery services for the prior rate year

10 (calculated using costs and capital structure approved by

11 the Commission as provided in subparagraph (2) of this

12 subsection (c), consistent with this Section, in

13 accordance with Commission rules and orders, including,

14 but not limited to, adjustments for goodwill, and after any

15 Commission-ordered disallowances and taxes) is more than

16 50 basis points less than the return on common equity

17 calculated pursuant to paragraph (3) of this subsection (c)

18 (after adjusting for any penalties to the rate of return on

19 common equity applied pursuant to the performance metrics

20 provision of subsection (f) of this Section), then the

21 participating utility shall apply a charge through the

22 performance-based formula rate that reflects an amount

23 equal to the value of that portion of the earned rate of

24 return on common equity that is more than 50 basis points

25 less than the rate of return on common equity calculated

26 pursuant to paragraph (3) of this subsection (c) (after

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1 adjusting for any penalties to the rate of return on common

2 equity applied pursuant to the performance metrics

3 provision of subsection (f) of this Section) for the prior

4 rate year, adjusted for taxes.

5 (6) Provide for an annual reconciliation, as described

6 in subsection (d) of this Section, with interest, of the

7 revenue requirement reflected in rates for each calendar

8 year, beginning with the calendar year in which the utility

9 files its performance-based formula rate tariff pursuant

10 to subsection (c) of this Section, with what the revenue

11 requirement would have been had the actual cost information

12 for the applicable calendar year been available at the

13 filing date.

14 The utility shall file, together with its tariff, final

15 data based on its most recently filed FERC Form 1, plus

16 projected plant additions and correspondingly updated

17 depreciation reserve and expense for the calendar year in which

18 the tariff and data are filed, that shall populate the

19 performance-based formula rate and set the initial delivery

20 services rates under the formula. For purposes of this Section,

21 "FERC Form 1" means the Annual Report of Major Electric

22 Utilities, Licensees and Others that electric utilities are

23 required to file with the Federal Energy Regulatory Commission

24 under the Federal Power Act, Sections 3, 4(a), 304 and 209,

25 modified as necessary to be consistent with 83 Ill. Admin. Code

26 Part 415 as of May 1, 2011. Nothing in this Section is intended

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1 to allow costs that are not otherwise recoverable to be

2 recoverable by virtue of inclusion in FERC Form 1.

3 After the utility files its proposed performance-based

4 formula rate structure and protocols and initial rates, the

5 Commission shall initiate a docket to review the filing. The

6 Commission shall enter an order approving, or approving as

7 modified, the performance-based formula rate, including the

8 initial rates, as just and reasonable within 270 days after the

9 date on which the tariff was filed, or, if the tariff is filed

10 within 14 days after the effective date of this amendatory Act

11 of the 97th General Assembly, then by May 31, 2012. Such review

12 shall be based on the same evidentiary standards, including,

13 but not limited to, those concerning the prudence and

14 reasonableness of the costs incurred by the utility, the

15 Commission applies in a hearing to review a filing for a

16 general increase in rates under Article IX of this Act. The

17 initial rates shall take effect within 30 days after the

18 Commission's order approving the performance-based formula

19 rate tariff.

20 Until such time as the Commission approves a different rate

21 design and cost allocation pursuant to subsection (e) of this

22 Section, rate design and cost allocation across customer

23 classes shall be consistent with the Commission's most recent

24 order regarding the participating utility's request for a

25 general increase in its delivery services rates.

26 Subsequent changes to the performance-based formula rate

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1 structure or protocols shall be made as set forth in Section

2 9-201 of this Act, but nothing in this subsection (c) is

3 intended to limit the Commission's authority under Article IX

4 and other provisions of this Act to initiate an investigation

5 of a participating utility's performance-based formula rate

6 tariff, provided that any such changes shall be consistent with

7 paragraphs (1) through (6) of this subsection (c). Any change

8 ordered by the Commission shall be made at the same time new

9 rates take effect following the Commission's next order

10 pursuant to subsection (d) of this Section, provided that the

11 new rates take effect no less than 30 days after the date on

12 which the Commission issues an order adopting the change.

13 A participating utility that files a tariff pursuant to

14 this subsection (c) must submit a one-time $200,000 filing fee

15 at the time the Chief Clerk of the Commission accepts the

16 filing, which shall be a recoverable expense.

17 In the event the performance-based formula rate is

18 terminated, the then current rates shall remain in effect until

19 such time as new rates are set pursuant to Article IX of this

20 Act, subject to retroactive rate adjustment, with interest, to

21 reconcile rates charged with actual costs. At such time that

22 the performance-based formula rate is terminated, the

23 participating utility's voluntary commitments and obligations

24 under subsection (b) of this Section shall immediately

25 terminate, except for the utility's obligation to pay an amount

26 already owed to the fund for training grants pursuant to a

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1 Commission order issued under subsection (b) of this Section.

2 (d) Subsequent to the Commission's issuance of an order

3 approving the utility's performance-based formula rate

4 structure and protocols, and initial rates under subsection (c)

5 of this Section, the utility shall file, on or before May 1 of

6 each year, with the Chief Clerk of the Commission its updated

7 cost inputs to the performance-based formula rate for the

8 applicable rate year and the corresponding new charges. Each

9 such filing shall conform to the following requirements and

10 include the following information:

11 (1) The inputs to the performance-based formula rate

12 for the applicable rate year shall be based on final

13 historical data reflected in the utility's most recently

14 filed annual FERC Form 1 plus projected plant additions and

15 correspondingly updated depreciation reserve and expense

16 for the calendar year in which the inputs are filed. The

17 filing shall also include a reconciliation of the revenue

18 requirement that was in effect for the prior rate year (as

19 set by the cost inputs for the prior rate year) with the

20 actual revenue requirement for the prior rate year

21 (determined using a year-end rate base) that uses amounts

22 reflected in the applicable FERC Form 1 that reports the

23 actual costs for the prior rate year. Any over-collection

24 or under-collection indicated by such reconciliation shall

25 be reflected as a credit against, or recovered as an

26 additional charge to, respectively, with interest

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1 calculated at a rate equal to the utility's weighted

2 average cost of capital approved by the Commission for the

3 prior rate year, the charges for the applicable rate year.

4 Provided, however, that the first such reconciliation

5 shall be for the calendar year in which the utility files

6 its performance-based formula rate tariff pursuant to

7 subsection (c) of this Section and shall reconcile (i) the

8 revenue requirement or requirements established by the

9 rate order or orders in effect from time to time during

10 such calendar year (weighted, as applicable) with (ii) the

11 revenue requirement determined using a year-end rate base

12 for that calendar year calculated pursuant to the

13 performance-based formula rate using (A) actual costs for

14 that year as reflected in the applicable FERC Form 1, and

15 (B) for the first such reconciliation only, the cost of

16 equity, which shall be calculated as the sum of 590 basis

17 points plus the average for the applicable calendar year of

18 the monthly average yields of 30-year U.S. Treasury bonds

19 published by the Board of Governors of the Federal Reserve

20 System in its weekly H.15 Statistical Release or successor

21 publication. The first such reconciliation is not intended

22 to provide for the recovery of costs previously excluded

23 from rates based on a prior Commission order finding of

24 imprudence or unreasonableness. Each reconciliation shall

25 be certified by the participating utility in the same

26 manner that FERC Form 1 is certified. The filing shall also

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1 include the charge or credit, if any, resulting from the

2 calculation required by paragraph (6) of subsection (c) of

3 this Section.

4 Notwithstanding anything that may be to the contrary,

5 the intent of the reconciliation is to ultimately reconcile

6 the revenue requirement reflected in rates for each

7 calendar year, beginning with the calendar year in which

8 the utility files its performance-based formula rate

9 tariff pursuant to subsection (c) of this Section, with

10 what the revenue requirement determined using a year-end

11 rate base for the applicable calendar year would have been

12 had the actual cost information for the applicable calendar

13 year been available at the filing date.

14 (2) The new charges shall take effect beginning on the

15 first billing day of the following January billing period

16 and remain in effect through the last billing day of the

17 next December billing period regardless of whether the

18 Commission enters upon a hearing pursuant to this

19 subsection (d).

20 (3) The filing shall include relevant and necessary

21 data and documentation for the applicable rate year that is

22 consistent with the Commission's rules applicable to a

23 filing for a general increase in rates or any rules adopted

24 by the Commission to implement this Section. Normalization

25 adjustments shall not be required. Notwithstanding any

26 other provision of this Section or Act or any rule or other

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1 requirement adopted by the Commission, a participating

2 utility that is a combination utility with more than one

3 rate zone shall not be required to file a separate set of

4 such data and documentation for each rate zone and may

5 combine such data and documentation into a single set of

6 schedules.

7 Within 45 days after the utility files its annual update of

8 cost inputs to the performance-based formula rate, the

9 Commission shall have the authority, either upon complaint or

10 its own initiative, but with reasonable notice, to enter upon a

11 hearing concerning the prudence and reasonableness of the costs

12 incurred by the utility to be recovered during the applicable

13 rate year that are reflected in the inputs to the

14 performance-based formula rate derived from the utility's FERC

15 Form 1. During the course of the hearing, each objection shall

16 be stated with particularity and evidence provided in support

17 thereof, after which the utility shall have the opportunity to

18 rebut the evidence. Discovery shall be allowed consistent with

19 the Commission's Rules of Practice, which Rules shall be

20 enforced by the Commission or the assigned hearing examiner.

21 The Commission shall apply the same evidentiary standards,

22 including, but not limited to, those concerning the prudence

23 and reasonableness of the costs incurred by the utility, in the

24 hearing as it would apply in a hearing to review a filing for a

25 general increase in rates under Article IX of this Act. The

26 Commission shall not, however, have the authority in a

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1 proceeding under this subsection (d) to consider or order any

2 changes to the structure or protocols of the performance-based

3 formula rate approved pursuant to subsection (c) of this

4 Section. In a proceeding under this subsection (d), the

5 Commission shall enter its order no later than the earlier of

6 240 days after the utility's filing of its annual update of

7 cost inputs to the performance-based formula rate or December

8 31. The Commission's determinations of the prudence and

9 reasonableness of the costs incurred for the applicable

10 calendar year shall be final upon entry of the Commission's

11 order and shall not be subject to reopening, reexamination, or

12 collateral attack in any other Commission proceeding, case,

13 docket, order, rule or regulation, provided, however, that

14 nothing in this subsection (d) shall prohibit a party from

15 petitioning the Commission to rehear or appeal to the courts

16 the order pursuant to the provisions of this Act.

17 In the event the Commission does not, either upon complaint

18 or its own initiative, enter upon a hearing within 45 days

19 after the utility files the annual update of cost inputs to its

20 performance-based formula rate, then the costs incurred for the

21 applicable calendar year shall be deemed prudent and

22 reasonable, and the filed charges shall not be subject to

23 reopening, reexamination, or collateral attack in any other

24 proceeding, case, docket, order, rule, or regulation.

25 A participating utility's first filing of the updated cost

26 inputs, and any Commission investigation of such inputs

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1 pursuant to this subsection (d) shall proceed notwithstanding

2 the fact that the Commission's investigation under subsection

3 (c) of this Section is still pending and notwithstanding any

4 other law, order, rule, or Commission practice to the contrary.

5 (e) Nothing in subsections (c) or (d) of this Section shall

6 prohibit the Commission from investigating, or a participating

7 utility from filing, revenue-neutral tariff changes related to

8 rate design of a performance-based formula rate that has been

9 placed into effect for the utility. Following approval of a

10 participating utility's performance-based formula rate tariff

11 pursuant to subsection (c) of this Section, the utility shall

12 make a filing with the Commission within one year after the

13 effective date of the performance-based formula rate tariff

14 that proposes changes to the tariff to incorporate the findings

15 of any final rate design orders of the Commission applicable to

16 the participating utility and entered subsequent to the

17 Commission's approval of the tariff. The Commission shall,

18 after notice and hearing, enter its order approving, or

19 approving with modification, the proposed changes to the

20 performance-based formula rate tariff within 240 days after the

21 utility's filing. Following such approval, the utility shall

22 make a filing with the Commission during each subsequent 3-year

23 period that either proposes revenue-neutral tariff changes or

24 re-files the existing tariffs without change, which shall

25 present the Commission with an opportunity to suspend the

26 tariffs and consider revenue-neutral tariff changes related to

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1 rate design.

2 (f) Within 30 days after the filing of a tariff pursuant to

3 subsection (c) of this Section, each participating utility

4 shall develop and file with the Commission multi-year metrics

5 designed to achieve, ratably (i.e., in equal segments) over a

6 10-year period, improvement over baseline performance values

7 as follows:

8 (1) Twenty percent improvement in the System Average

9 Interruption Frequency Index, using a baseline of the

10 average of the data from 2001 through 2010.

11 (2) Fifteen percent improvement in the system Customer

12 Average Interruption Duration Index, using a baseline of

13 the average of the data from 2001 through 2010.

14 (3) For a participating utility other than a

15 combination utility, 20% improvement in the System Average

16 Interruption Frequency Index for its Southern Region,

17 using a baseline of the average of the data from 2001

18 through 2010. For purposes of this paragraph (3), Southern

19 Region shall have the meaning set forth in the

20 participating utility's most recent report filed pursuant

21 to Section 16-125 of this Act.

22 (3.5) For a participating utility other than a

23 combination utility, 20% improvement in the System Average

24 Interruption Frequency Index for its Northeastern Region,

25 using a baseline of the average of the data from 2001

26 through 2010. For purposes of this paragraph (3.5),

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1 Northeastern Region shall have the meaning set forth in the

2 participating utility's most recent report filed pursuant

3 to Section 16-125 of this Act.

4 (4) Seventy-five percent improvement in the total

5 number of customers who exceed the service reliability

6 targets as set forth in subparagraphs (A) through (C) of

7 paragraph (4) of subsection (b) of 83 Ill. Admin. Code Part

8 411.140 as of May 1, 2011, using 2010 as the baseline year.

9 (5) Reduction in issuance of estimated electric bills:

10 90% improvement for a participating utility other than a

11 combination utility, and 56% improvement for a

12 participating utility that is a combination utility, using

13 a baseline of the average number of estimated bills for the

14 years 2008 through 2010.

15 (6) Consumption on inactive meters: 90% improvement

16 for a participating utility other than a combination

17 utility, and 56% improvement for a participating utility

18 that is a combination utility, using a baseline of the

19 average unbilled kilowatthours for the years 2009 and 2010.

20 (7) Unaccounted for energy: 50% improvement for a

21 participating utility other than a combination utility

22 using a baseline of the non-technical line loss unaccounted

23 for energy kilowatthours for the year 2009.

24 (8) Uncollectible expense: reduce uncollectible

25 expense by at least $30,000,000 for a participating utility

26 other than a combination utility and by at least $3,500,000

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1 for a participating utility that is a combination utility,

2 using a baseline of the average uncollectible expense for

3 the years 2008 through 2010.

4 (9) Opportunities for minority-owned and female-owned

5 business enterprises: design a performance metric

6 regarding the creation of opportunities for minority-owned

7 and female-owned business enterprises consistent with

8 State and federal law using a base performance value of the

9 percentage of the participating utility's capital

10 expenditures that were paid to minority-owned and

11 female-owned business enterprises in 2010.

12 (10) Achieving cost-effective energy efficiency

13 savings consistent with Section 8-103 of this Act. By

14 January 1, 2018, each participating utility shall file with

15 the Commission a proposed set of performance metrics

16 designed to align financial rewards with the utility's

17 performance relative to the goal provided in Section 8-103

18 of this Act.

19 (11) Improve load shape by achieving a 20% reduction in

20 peak load by January 1, 2025 as compared to the baseline

21 year of 2009 through annual incremental reductions.

22 The definitions set forth in 83 Ill. Admin. Code Part

23 411.20 as of May 1, 2011 shall be used for purposes of

24 calculating performance under paragraphs (1) through (3.5) of

25 this subsection (f), provided, however, that the participating

26 utility may exclude up to 9 extreme weather event days from

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1 such calculation for each year, and provided further that the

2 participating utility shall exclude 9 extreme weather event

3 days when calculating each year of the baseline period to the

4 extent that there are 9 such days in a given year of the

5 baseline period. For purposes of this Section, an extreme

6 weather event day is a 24-hour calendar day (beginning at 12:00

7 a.m. and ending at 11:59 p.m.) during which any weather event

8 (e.g., storm, tornado) caused interruptions for 10,000 or more

9 of the participating utility's customers for 3 hours or more.

10 If there are more than 9 extreme weather event days in a year,

11 then the utility may choose no more than 9 extreme weather

12 event days to exclude, provided that the same extreme weather

13 event days are excluded from each of the calculations performed

14 under paragraphs (1) through (3.5) of this subsection (f).

15 The metrics shall include incremental performance goals

16 for each year of the 10-year period, which shall be designed to

17 demonstrate that the utility is on track to achieve the

18 performance goal in each category at the end of the 10-year

19 period. The utility shall elect when the 10-year period shall

20 commence for the metrics set forth in subparagraphs (1) through

21 (4) and (9) of this subsection (f), provided that it begins no

22 later than 14 months following the date on which the utility

23 begins investing pursuant to subsection (b) of this Section,

24 and when the 10-year period shall commence for the metrics set

25 forth in subparagraphs (5) through (8) of this subsection (f),

26 provided that it begins no later than 14 months following the

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1 date on which the Commission enters its order approving the

2 utility's Advanced Metering Infrastructure Deployment Plan

3 pursuant to subsection (c) of Section 16-108.6 of this Act.

4 The metrics and performance goals set forth in

5 subparagraphs (5) through (8) of this subsection (f) are based

6 on the assumptions that the participating utility may fully

7 implement the technology described in subsection (b) of this

8 Section, including utilizing the full functionality of such

9 technology and that there is no requirement for personal

10 on-site notification. If the utility is unable to meet the

11 metrics and performance goals set forth in subparagraphs (5)

12 through (8) of this subsection (f) for such reasons, and the

13 Commission so finds after notice and hearing, then the utility

14 shall be excused from compliance, but only to the limited

15 extent achievement of the affected metrics and performance

16 goals was hindered by the less than full implementation.

17 (f-5) The financial penalties applicable to the metrics

18 described in subparagraphs (1) through (8) of subsection (f) of

19 this Section, as applicable, shall be applied through an

20 adjustment to the participating utility's return on equity of

21 no more than a total of 30 basis points in each of the first 3

22 years, of no more than a total of 34 basis points in each of the

23 3 years thereafter, and of no more than a total of 38 basis

24 points in each of the 4 years thereafter, as follows:

25 (1) With respect to each of the incremental annual

26 performance goals established pursuant to paragraph (1) of

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1 subsection (f) of this Section,

2 (A) for each year that a participating utility

3 other than a combination utility does not achieve the

4 annual goal, the participating utility's return on

5 equity shall be reduced as follows: during years 1

6 through 3, by 5 basis points; during years 4 through 6,

7 by 6 basis points; and during years 7 through 10, by 7

8 basis points; and

9 (B) for each year that a participating utility that

10 is a combination utility does not achieve the annual

11 goal, the participating utility's return on equity

12 shall be reduced as follows: during years 1 through 3,

13 by 10 basis points; during years 4 through 6, by 12

14 basis points; and during years 7 through 10, by 14

15 basis points.

16 (2) With respect to each of the incremental annual

17 performance goals established pursuant to paragraph (2) of

18 subsection (f) of this Section, for each year that the

19 participating utility does not achieve each such goal, the

20 participating utility's return on equity shall be reduced

21 as follows: during years 1 through 3, by 5 basis points;

22 during years 4 through 6, by 6 basis points; and during

23 years 7 through 10, by 7 basis points.

24 (3) With respect to each of the incremental annual

25 performance goals established pursuant to paragraphs (3)

26 and (3.5) of subsection (f) of this Section, for each year

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1 that a participating utility other than a combination

2 utility does not achieve both such goals, the participating

3 utility's return on equity shall be reduced as follows:

4 during years 1 through 3, by 5 basis points; during years 4

5 through 6, by 6 basis points; and during years 7 through

6 10, by 7 basis points.

7 (4) With respect to each of the incremental annual

8 performance goals established pursuant to paragraph (4) of

9 subsection (f) of this Section, for each year that the

10 participating utility does not achieve each such goal, the

11 participating utility's return on equity shall be reduced

12 as follows: during years 1 through 3, by 5 basis points;

13 during years 4 through 6, by 6 basis points; and during

14 years 7 through 10, by 7 basis points.

15 (5) With respect to each of the incremental annual

16 performance goals established pursuant to subparagraph (5)

17 of subsection (f) of this Section, for each year that the

18 participating utility does not achieve at least 95% of each

19 such goal, the participating utility's return on equity

20 shall be reduced by 5 basis points for each such unachieved

21 goal.

22 (6) With respect to each of the incremental annual

23 performance goals established pursuant to paragraphs (6),

24 (7), and (8) of subsection (f) of this Section, as

25 applicable, which together measure non-operational

26 customer savings and benefits relating to the

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1 implementation of the Advanced Metering Infrastructure

2 Deployment Plan, as defined in Section 16-108.6 of this

3 Act, the performance under each such goal shall be

4 calculated in terms of the percentage of the goal achieved.

5 The percentage of goal achieved for each of the goals shall

6 be aggregated, and an average percentage value calculated,

7 for each year of the 10-year period. If the utility does

8 not achieve an average percentage value in a given year of

9 at least 95%, the participating utility's return on equity

10 shall be reduced by 5 basis points.

11 The financial penalties shall be applied as described in

12 this subsection (f-5) for the 12-month period in which the

13 deficiency occurred through a separate tariff mechanism, which

14 shall be filed by the utility together with its metrics. In the

15 event the formula rate tariff established pursuant to

16 subsection (c) of this Section terminates, the utility's

17 obligations under subsection (f) of this Section and this

18 subsection (f-5) shall also terminate, provided, however, that

19 the tariff mechanism established pursuant to subsection (f) of

20 this Section and this subsection (f-5) shall remain in effect

21 until any penalties due and owing at the time of such

22 termination are applied.

23 The Commission shall, after notice and hearing, enter an

24 order within 120 days after the metrics are filed approving, or

25 approving with modification, a participating utility's tariff

26 or mechanism to satisfy the metrics set forth in subsection (f)

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1 of this Section. On June 1 of each subsequent year, each

2 participating utility shall file a report with the Commission

3 that includes, among other things, a description of how the

4 participating utility performed under each metric and an

5 identification of any extraordinary events that adversely

6 impacted the utility's performance. Whenever a participating

7 utility does not satisfy the metrics required pursuant to

8 subsection (f) of this Section, the Commission shall, after

9 notice and hearing, enter an order approving financial

10 penalties in accordance with this subsection (f-5). The

11 Commission-approved financial penalties shall be applied

12 beginning with the next rate year. Nothing in this Section

13 shall authorize the Commission to reduce or otherwise obviate

14 the imposition of financial penalties for failing to achieve

15 one or more of the metrics established pursuant to subparagraph

16 (1) through (4) of subsection (f) of this Section.

17 (g) On or before July 31, 2014, each participating utility

18 shall file a report with the Commission that sets forth the

19 average annual increase in the average amount paid per

20 kilowatthour for residential eligible retail customers,

21 exclusive of the effects of energy efficiency programs,

22 comparing the 12-month period ending May 31, 2012; the 12-month

23 period ending May 31, 2013; and the 12-month period ending May

24 31, 2014. For a participating utility that is a combination

25 utility with more than one rate zone, the weighted average

26 aggregate increase shall be provided. The report shall be filed

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1 together with a statement from an independent auditor attesting

2 to the accuracy of the report. The cost of the independent

3 auditor shall be borne by the participating utility and shall

4 not be a recoverable expense. "The average amount paid per

5 kilowatthour" shall be based on the participating utility's

6 tariffed rates actually in effect and shall not be calculated

7 using any hypothetical rate or adjustments to actual charges

8 (other than as specified for energy efficiency) as an input.

9 In the event that the average annual increase exceeds 2.5%

10 as calculated pursuant to this subsection (g), then Sections

11 16-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act, other

12 than this subsection, shall be inoperative as they relate to

13 the utility and its service area as of the date of the report

14 due to be submitted pursuant to this subsection and the utility

15 shall no longer be eligible to annually update the

16 performance-based formula rate tariff pursuant to subsection

17 (d) of this Section. In such event, the then current rates

18 shall remain in effect until such time as new rates are set

19 pursuant to Article IX of this Act, subject to retroactive

20 adjustment, with interest, to reconcile rates charged with

21 actual costs, and the participating utility's voluntary

22 commitments and obligations under subsection (b) of this

23 Section shall immediately terminate, except for the utility's

24 obligation to pay an amount already owed to the fund for

25 training grants pursuant to a Commission order issued under

26 subsection (b) of this Section.

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1 In the event that the average annual increase is 2.5% or

2 less as calculated pursuant to this subsection (g), then the

3 performance-based formula rate shall remain in effect as set

4 forth in this Section.

5 For purposes of this Section, the amount per kilowatthour

6 means the total amount paid for electric service expressed on a

7 per kilowatthour basis, and the total amount paid for electric

8 service includes without limitation amounts paid for supply,

9 transmission, distribution, surcharges, and add-on taxes

10 exclusive of any increases in taxes or new taxes imposed after

11 the effective date of this amendatory Act of the 97th General

12 Assembly. For purposes of this Section, "eligible retail

13 customers" shall have the meaning set forth in Section 16-111.5

14 of this Act.

15 The fact that this Section becomes inoperative as set forth

16 in this subsection shall not be construed to mean that the

17 Commission may reexamine or otherwise reopen prudence or

18 reasonableness determinations already made.

19 (h) Sections 16-108.5, 16-108.6, 16-108.7, and 16-108.8 of

20 this Act, other than this subsection, are inoperative after

21 December 31, 2017 for every participating utility, after which

22 time a participating utility shall no longer be eligible to

23 annually update the performance-based formula rate tariff

24 pursuant to subsection (d) of this Section. At such time, 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 adjustment, with interest, to reconcile rates

2 charged with actual costs.

3 By December 31, 2017, the Commission shall prepare and file

4 with the General Assembly a report on the infrastructure

5 program and the performance-based formula rate. The report

6 shall include the change in the average amount per kilowatthour

7 paid by residential customers between June 1, 2011 and May 31,

8 2017. If the change in the total average rate paid exceeds 2.5%

9 compounded annually, the Commission shall include in the report

10 an analysis that shows the portion of the change due to the

11 delivery services component and the portion of the change due

12 to the supply component of the rate. The report shall include

13 separate sections for each participating utility.

14 In the event Sections 16-108.5, 16-108.6, 16-108.7, and

15 16-108.8 of this Act do not become inoperative after December

16 31, 2017, then these Sections are inoperative after December

17 31, 2022 for every participating utility, after which time a

18 participating utility shall no longer be eligible to annually

19 update the performance-based formula rate tariff pursuant to

20 subsection (d) of this Section. At such time, the then current

21 rates shall remain in effect until such time as new rates are

22 set pursuant to Article IX of this Act, subject to retroactive

23 adjustment, with interest, to reconcile rates charged with

24 actual costs.

25 The fact that this Section becomes inoperative as set forth

26 in this subsection shall not be construed to mean that the

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1 Commission may reexamine or otherwise reopen prudence or

2 reasonableness determinations already made. The fact that this

3 Section becomes inoperative, as set forth in this Section,

4 shall not eliminate a utility's obligations under Section 8-103

5 of this Act.

6 (i) While a participating utility may use, develop, and

7 maintain broadband systems and the delivery of broadband

8 services, voice-over-internet-protocol services,

9 telecommunications services, and cable and video programming

10 services for use in providing delivery services and Smart Grid

11 functionality or application to its retail customers,

12 including, but not limited to, the installation,

13 implementation and maintenance of Smart Grid electric system

14 upgrades as defined in Section 16-108.6 of this Act, a

15 participating utility is prohibited from offering to its retail

16 customers broadband services or the delivery of broadband

17 services, voice-over-internet-protocol services,

18 telecommunications services, or cable or video programming

19 services, unless they are part of a service directly related to

20 delivery services or Smart Grid functionality or applications

21 as defined in Section 16-108.6 of this Act, and from recovering

22 the costs of such offerings from retail customers.

23 (j) Nothing in this Section is intended to legislatively

24 overturn the opinion issued in Commonwealth Edison Co. v. Ill.

25 Commerce Comm'n, Nos. 2-08-0959, 2-08-1037, 2-08-1137,

26 1-08-3008, 1-08-3030, 1-08-3054, 1-08-3313 cons. (Ill. App.

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1 Ct. 2d Dist. Sept. 30, 2010). This amendatory Act of the 97th

2 General Assembly shall not be construed as creating a contract

3 between the General Assembly and the participating utility, and

4 shall not establish a property right in the participating

5 utility.

6 (k) The changes made in subsections (c) and (d) of this

7 Section by this amendatory Act of the 98th General Assembly are

8 intended to be a restatement and clarification of existing law,

9 and intended to give binding effect to the provisions of House

10 Resolution 1157 adopted by the House of Representatives of the

11 97th General Assembly and Senate Resolution 821 adopted by the

12 Senate of the 97th General Assembly that are reflected in

13 paragraph (3) of this subsection. In addition, this amendatory

14 Act of the 98th General Assembly preempts and supersedes any

15 final Commission orders entered in Docket Nos. 11-0721,

16 12-0001, 12-0293, and 12-0321 to the extent inconsistent with

17 the amendatory language added to subsections (c) and (d).

18 (1) No earlier than 5 business days after the effective

19 date of this amendatory Act of the 98th General Assembly,

20 each participating utility shall file any tariff changes

21 necessary to implement the amendatory language set forth in

22 subsections (c) and (d) of this Section by this amendatory

23 Act of the 98th General Assembly and a revised revenue

24 requirement under the participating utility's

25 performance-based formula rate. The Commission shall enter

26 a final order approving such tariff changes and revised

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1 revenue requirement within 21 days after the participating

2 utility's filing.

3 (2) Notwithstanding anything that may be to the

4 contrary, a participating utility may file a tariff to

5 retroactively recover its previously unrecovered actual

6 costs of delivery service that are no longer subject to

7 recovery through a reconciliation adjustment under

8 subsection (d) of this Section. This retroactive recovery

9 shall include any derivative adjustments resulting from

10 the changes to subsections (c) and (d) of this Section by

11 this amendatory Act of the 98th General Assembly. Such

12 tariff shall allow the utility to assess, on current

13 customer bills over a period of 12 monthly billing periods,

14 a charge or credit related to those unrecovered costs with

15 interest at the utility's weighted average cost of capital

16 during the period in which those costs were unrecovered. A

17 participating utility may file a tariff that implements a

18 retroactive charge or credit as described in this paragraph

19 for amounts not otherwise included in the tariff filing

20 provided for in paragraph (1) of this subsection (k). The

21 Commission shall enter a final order approving such tariff

22 within 21 days after the participating utility's filing.

23 (3) The tariff changes described in paragraphs (1) and

24 (2) of this subsection (k) shall relate only to, and be

25 consistent with, the following provisions of this

26 amendatory Act of the 98th General Assembly: paragraph (2)

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1 of subsection (c) regarding year-end capital structure,

2 subparagraph (D) of paragraph (4) of subsection (c)

3 regarding pension assets, and subsection (d) regarding the

4 reconciliation components related to year-end rate base

5 and interest calculated at a rate equal to the utility's

6 weighted average cost of capital.

7 (4) Nothing in this subsection is intended to effect a

8 dismissal of or otherwise affect an appeal from any final

9 Commission orders entered in Docket Nos. 11-0721, 12-0001,

10 12-0293, and 12-0321 other than to the extent of the

11 amendatory language contained in subsections (c) and (d) of

12 this amendatory Act of the 98th General Assembly.

13 (l) Each participating utility shall be deemed to have been

14 in full compliance with all requirements of subsection (b) of

15 this Section, subsection (c) of this Section, Section 16-108.6

16 of this Act, and all Commission orders entered pursuant to

17 Sections 16-108.5 and 16-108.6 of this Act, up to and including

18 the effective date of this amendatory Act of the 98th General

19 Assembly. The Commission shall not undertake any investigation

20 of such compliance and no penalty shall be assessed or adverse

21 action taken against a participating utility for noncompliance

22 with Commission orders associated with subsection (b) of this

23 Section, subsection (c) of this Section, and Section 16-108.6

24 of this Act prior to such date. Each participating utility

25 other than a combination utility shall be permitted, without

26 penalty, a period of 12 months after such effective date to

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1 take actions required to ensure its infrastructure investment

2 program is in compliance with subsection (b) of this Section

3 and with Section 16-108.6 of this Act. Provided further:

4 (1) if this amendatory Act of the 98th General Assembly

5 takes effect on or before June 15, 2013, the following

6 subparagraphs shall apply to a participating utility other

7 than a combination utility:

8 (A) if the Commission has initiated a proceeding

9 pursuant to subsection (e) of Section 16-108.6 of this

10 Act that is pending as of the effective date of this

11 amendatory Act of the 98th General Assembly, then the

12 order entered in such proceeding shall, after notice

13 and hearing, accelerate the commencement of the meter

14 deployment schedule approved in the final Commission

15 order on rehearing entered in Docket No. 12-0298;

16 (B) if the Commission has entered an order pursuant

17 to subsection (e) of Section 16-108.6 of this Act prior

18 to the effective date of this amendatory Act of the

19 98th General Assembly that does not accelerate the

20 commencement of the meter deployment schedule approved

21 in the final Commission order on rehearing entered in

22 Docket No. 12-0298, then the utility shall file with

23 the Commission, within 45 days after such effective

24 date, a plan for accelerating the commencement of the

25 utility's meter deployment schedule approved in the

26 final Commission order on rehearing entered in Docket

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1 No. 12-0298; the Commission shall reopen the

2 proceeding in which it entered its order pursuant to

3 subsection (e) of Section 16-108.6 of this Act and

4 shall, after notice and hearing, enter an amendatory

5 order that approves or approves as modified such

6 accelerated plan within 90 days after the utility's

7 filing; or

8 (C) if the Commission has not initiated a

9 proceeding pursuant to subsection (e) of Section

10 16-108.6 of this Act prior to the effective date of

11 this amendatory Act of the 98th General Assembly, then

12 the utility shall file with the Commission, within 45

13 days after such effective date, a plan for accelerating

14 the commencement of the utility's meter deployment

15 schedule approved in the final Commission order on

16 rehearing entered in Docket No. 12-0298 and the

17 Commission shall, after notice and hearing, approve or

18 approve as modified such plan within 90 days after the

19 utility's filing;

20 (2) if this amendatory Act of the 98th General Assembly

21 takes effect after June 15, 2013, then each participating

22 utility other than a combination utility shall file with

23 the Commission, within 45 days after such effective date, a

24 plan for accelerating the commencement of the utility's

25 meter deployment schedule approved in the final Commission

26 order on rehearing entered in Docket No. 12-0298; the

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1 Commission shall reopen the most recent proceeding in which

2 it entered an order pursuant to subsection (e) of Section

3 16-108.6 of this Act and within 90 days after the utility's

4 filing shall, after notice and hearing, enter an amendatory

5 order that approves or approves as modified such

6 accelerated plan, provided that if there was no such prior

7 proceeding the Commission shall open a new proceeding and

8 within 90 days after the utility's filing shall, after

9 notice and hearing, enter an order that approves or

10 approves as modified such accelerated plan.

11 Any schedule for meter deployment approved by the

12 Commission pursuant to subparagraphs (1) or (2) of this

13 subsection (l) shall take into consideration procurement times

14 for meters and other equipment and operational issues. Nothing

15 in this amendatory Act of the 98th General Assembly shall

16 shorten or extend the end dates for the 5-year or 10-year

17 periods set forth in subsection (b) of this Section or Section

18 16-108.6 of this Act. Nothing in this subsection is intended to

19 address whether a participating utility has, or has not,

20 satisfied any or all of the metrics and performance goals

21 established pursuant to subsection (f) of this Section.

22 (m) The provisions of this amendatory Act of the 98th

23 General Assembly are severable under Section 1.31 of the

24 Statute on Statutes.

25 (Source: P.A. 97-616, eff. 10-26-11; 97-646, eff. 12-30-11;

26 98-15, eff. 5-22-13.)

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1 (220 ILCS 5/16-108.8)

2 Sec. 16-108.8. Illinois Smart Grid test bed.

3 (a) Within 180 days after the effective date of this

4 amendatory Act of the 97th General Assembly, each participating

5 utility, as defined by Section 16-108.5 of this Act, shall

6 create or otherwise designate a Smart Grid test bed, which may

7 be located at one or more places within the utility's system,

8 for the purposes of allowing for the testing of Smart Grid

9 technologies. The objectives of this test bed shall be to:

10 (1) provide an open, unbiased opportunity for testing

11 programs, technologies, business models, and other Smart

12 Grid-related activities;

13 (2) provide on-grid locations for the testing of

14 potentially innovative Smart Grid-related technologies and

15 services, including but not limited to those funded by the

16 trust or foundation established pursuant to Section

17 16-108.7 of this Act;

18 (3) facilitate testing of business models or services

19 that help integrate Smart Grid-related technologies into

20 the electric grid, especially those business models that

21 may help promote new products and services for retail

22 customers;

23 (4) offer opportunities to test and showcase Smart Grid

24 technologies and services, especially those likely to

25 support the economic development goals of the State of

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1 Illinois.

2 (b) The test bed shall reside in one or more locations on

3 the participating utility's network. Such locations shall be

4 chosen by the utility to maximize the opportunity for real-time

5 and real-world testing of Smart Grid technologies and services

6 taking into account the safety and security of the

7 participating utility's grid and grid operations.

8 (c) The participating utility, with input from the Smart

9 Grid Advisory Council established pursuant to Section 16-108.6

10 of this Act, shall, as part of its filing under subsection (b)

11 of Section 16-108.5, include a plan for the creation,

12 operation, and administration of the test bed. This plan shall

13 address the following:

14 (1) how the utility proposes to comply with each of the

15 objectives set forth in subsection (a) of this Section;

16 (2) the proposed location or locations of the test bed;

17 (3) the process by which the utility will receive,

18 review, and qualify proposals to use the test bed;

19 (4) the criteria by which the utility proposes to

20 qualify proposals to use the test bed, including, but not

21 limited to, safety, reliability, security, customer data

22 security, privacy, and economic development

23 considerations;

24 (5) the engineering and operations support that the

25 utility will provide to test bed users, including provision

26 of customer data; and

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1 (6) the estimated costs to establish, administer and

2 promote the availability of the test bed.

3 (d) The test bed should be open to all qualified entities

4 wishing to test programs, technologies, business models, and

5 other Smart Grid-related activities, provided that the utility

6 retains control of its grid and operations and may reject any

7 programs, technologies, business models, and other Smart

8 Grid-related activities that threaten the reliability, safety,

9 security, or operations of its network, or that would threaten

10 the security of customer-identifiable data in the judgment of

11 the utility. The number of technologies and entities

12 participating in the test bed at any time may be limited by the

13 utility based on its determination of its ability to maintain a

14 secure, safe, and reliable grid.

15 (e) At a minimum, the test bed shall have the ability to

16 receive live signals from PJM Interconnection LLC or other

17 applicable regional transmission organization, the ability to

18 test new applications in a utility scale environment (to

19 include ramp rate regulations for distributed wind and solar

20 resources), critical peak price response, and market-based

21 power dispatch.

22 (f) At the end of the fourth year of operation the test bed

23 shall be subject to an independent evaluation to determine if

24 the test bed is meeting the objectives of this Section or is

25 likely to meet the objectives in the future. The evaluation

26 shall include the performance of the utility as test bed

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1 operator. Subject to the findings, the utility and the trust or

2 foundation established pursuant to Section 16-108.7 of this Act

3 may choose to continue operating the test bed.

4 (g) The utility shall be entitled to recover all prudently

5 incurred and reasonable costs associated with evaluation of

6 proposals, engineering, construction, operation, and

7 administration of the test bed through the performance-based

8 formula rate tariff established pursuant to Section 16-108.5 of

9 this Act.

10 (h) The utility is authorized to charge fees to users of

11 the test bed that shall recover the costs associated with the

12 incremental direct costs to the utility associated with

13 administration of the test bed, provided, however, that any

14 such fees collected by the utility shall be used to offset the

15 costs to be recovered pursuant to subsection (g) of this

16 Section.

17 (i) On a quarterly basis, the utility shall provide the

18 trust or foundation established pursuant to Section 16-108.7 of

19 this Act with a report summarizing test bed activities,

20 customers, discoveries, and other information as shall be

21 mutually deemed relevant.

22 (j) To the extent practicable, the utility and trust or

23 foundation established pursuant to Section 16-108.7 of this Act

24 shall jointly pursue resources that enhance the capabilities

25 and capacity of the test bed.

26 (k) If Section 16-108.5 of this Act becomes inoperative

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1 with respect to one or more participating utilities as set

2 forth in subsection (g) or (h) of that Section, then Sections

3 16-108.5, 16-108.6, 16-108.7, and 16-108.8 of this Act shall

4 become inoperative as to each affected utility and its service

5 area on the same date as Section 16-108.5 become inoperative.

6 (Source: P.A. 97-616, eff. 10-26-11.)

7 (220 ILCS 5/16-111.5)

8 Sec. 16-111.5. Provisions relating to electricity

9 procurement.

10 (a) An electric utility that on December 31, 2005 served at

11 least 100,000 customers in Illinois shall procure power and

12 energy for its eligible retail customers in accordance with the

13 applicable provisions set forth in Section 1-75 of the Illinois

14 Power Agency Act and this Section. A small multi-jurisdictional

15 electric utility that on December 31, 2005 served less than

16 100,000 customers in Illinois may elect to procure power and

17 energy for all or a portion of its eligible Illinois retail

18 customers in accordance with the applicable provisions set

19 forth in this Section and Section 1-75 of the Illinois Power

20 Agency Act. This Section shall not apply to a small

21 multi-jurisdictional utility until such time as a small

22 multi-jurisdictional utility requests the Illinois Power

23 Agency to prepare an electricity ~~a~~ procurement plan for its

24 eligible retail customers. "Eligible retail customers" for the

25 purposes of this Section means those retail customers that

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1 purchase power and energy from the electric utility under

2 fixed-price bundled service tariffs, other than those retail

3 customers whose service is declared or deemed competitive under

4 Section 16-113 and those other customer groups specified in

5 this Section, including self-generating customers, customers

6 electing hourly pricing, or those customers who are otherwise

7 ineligible for fixed-price bundled tariff service. Those

8 customers that are excluded from the definition of "eligible

9 retail customers" shall not be included in the electricity

10 procurement plan load requirements, and the utility shall

11 procure any supply requirements, including capacity, ancillary

12 services, and hourly priced energy, in the applicable markets

13 as needed to serve those customers, provided that the utility

14 may include in its electricity procurement plan load

15 requirements for the load that is associated with those retail

16 customers whose service has been declared or deemed competitive

17 pursuant to Section 16-113 of this Act to the extent that those

18 customers are purchasing power and energy during one of the

19 transition periods identified in subsection (b) of Section

20 16-113 of this Act.

21 (b) An electricity ~~A~~ procurement plan shall be prepared for

22 each electric utility consistent with the applicable

23 requirements of the Illinois Power Agency Act and this Section.

24 For purposes of this Section, Illinois electric utilities that

25 are affiliated by virtue of a common parent company are

26 considered to be a single electric utility. Small

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1 multi-jurisdictional utilities may request an electricity ~~a~~

2 procurement plan for a portion of or all of its Illinois load.

3 Each electricity procurement plan shall analyze the projected

4 balance of supply and demand for eligible retail customers over

5 a 5-year period with the first planning year beginning on June

6 1 of the year following the year in which the plan is filed.

7 The plan shall specifically identify the wholesale products to

8 be procured following plan approval, and shall follow all the

9 requirements set forth in the Public Utilities Act and all

10 applicable State and federal laws, statutes, rules, or

11 regulations, as well as Commission orders. Nothing in this

12 Section precludes consideration of contracts longer than 5

13 years and related forecast data. Unless specified otherwise in

14 this Section, in the electricity procurement plan or in the

15 implementing tariff, any procurement occurring in accordance

16 with this plan shall be competitively bid through a request for

17 proposals process. Approval and implementation of the

18 electricity procurement plan shall be subject to review and

19 approval by the Commission according to the provisions set

20 forth in this Section. An electricity ~~A~~ procurement plan shall

21 include each of the following components:

22 (1) Hourly load analysis. This analysis shall include:

23 (i) multi-year historical analysis of hourly

24 loads;

25 (ii) switching trends and competitive retail

26 market analysis;

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1 (iii) known or projected changes to future loads;

2 and

3 (iv) growth forecasts by customer class.

4 (2) Analysis of the impact of any demand side and

5 renewable energy initiatives. This analysis shall include:

6 (i) the impact of demand response programs and

7 energy efficiency programs, both current and

8 projected; for small multi-jurisdictional utilities,

9 the impact of demand response and energy efficiency

10 programs approved pursuant to Section 8-408 of this

11 Act, both current and projected; and

12 (ii) supply side needs that are projected to be

13 offset by purchases of renewable energy resources, if

14 any.

15 (3) A plan for meeting the expected load requirements

16 that will not be met through preexisting contracts. This

17 plan shall include:

18 (i) definitions of the different Illinois retail

19 customer classes for which supply is being purchased;

20 (ii) the proposed mix of demand-response products

21 for which contracts will be executed during the next

22 year. For small multi-jurisdictional electric

23 utilities that on December 31, 2005 served fewer than

24 100,000 customers in Illinois, these shall be defined

25 as demand-response products offered in an energy

26 efficiency plan approved pursuant to Section 8-408 of

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1 this Act. The cost-effective demand-response measures

2 shall be procured whenever the cost is lower than

3 procuring comparable capacity products, provided that

4 such products shall:

5 (A) be procured by a demand-response provider

6 from eligible retail customers;

7 (B) at least satisfy the demand-response

8 requirements of the regional transmission

9 organization market in which the utility's service

10 territory is located, including, but not limited

11 to, any applicable capacity or dispatch

12 requirements;

13 (C) provide for customers' participation in

14 the stream of benefits produced by the

15 demand-response products;

16 (D) provide for reimbursement by the

17 demand-response provider of the utility for any

18 costs incurred as a result of the failure of the

19 supplier of such products to perform its

20 obligations thereunder; and

21 (E) meet the same credit requirements as apply

22 to suppliers of capacity, in the applicable

23 regional transmission organization market;

24 (iii) monthly forecasted system supply

25 requirements, including expected minimum, maximum, and

26 average values for the planning period;

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1 (iv) the proposed mix and selection of standard

2 wholesale products for which contracts will be

3 executed during the next year, separately or in

4 combination, to meet that portion of its load

5 requirements not met through pre-existing contracts,

6 including but not limited to monthly 5 x 16 peak period

7 block energy, monthly off-peak wrap energy, monthly 7 x

8 24 energy, annual 5 x 16 energy, annual off-peak wrap

9 energy, annual 7 x 24 energy, monthly capacity, annual

10 capacity, peak load capacity obligations, capacity

11 purchase plan, and ancillary services;

12 (v) proposed term structures for each wholesale

13 product type included in the proposed electricity

14 procurement plan portfolio of products; and

15 (vi) an assessment of the price risk, load

16 uncertainty, and other factors that are associated

17 with the proposed electricity procurement plan; this

18 assessment, to the extent possible, shall include an

19 analysis of the following factors: contract terms,

20 time frames for securing products or services, fuel

21 costs, weather patterns, transmission costs, market

22 conditions, and the governmental regulatory

23 environment; the proposed electricity procurement plan

24 shall also identify alternatives for those portfolio

25 measures that are identified as having significant

26 price risk.

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1 (4) Proposed procedures for balancing loads. The

2 electricity procurement plan shall include, for load

3 requirements included in the electricity procurement plan,

4 the process for (i) hourly balancing of supply and demand

5 and (ii) the criteria for portfolio re-balancing in the

6 event of significant shifts in load.

7 (c) The procurement process set forth in Section 1-75 of

8 the Illinois Power Agency Act and subsection (e) of this

9 Section shall be administered by a procurement administrator

10 and monitored by a procurement monitor.

11 (1) The procurement administrator shall:

12 (i) design the final procurement process in

13 accordance with Section 1-75 of the Illinois Power

14 Agency Act and subsection (e) of this Section following

15 Commission approval of the electricity procurement

16 plan;

17 (ii) develop benchmarks in accordance with

18 subsection (e)(3) to be used to evaluate bids; these

19 benchmarks shall be submitted to the Commission for

20 review and approval on a confidential basis prior to

21 the procurement event;

22 (iii) serve as the interface between the electric

23 utility and suppliers;

24 (iv) manage the bidder pre-qualification and

25 registration process;

26 (v) obtain the electric utilities' agreement to

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1 the final form of all supply contracts and credit

2 collateral agreements;

3 (vi) administer the request for proposals process;

4 (vii) have the discretion to negotiate to

5 determine whether bidders are willing to lower the

6 price of bids that meet the benchmarks approved by the

7 Commission; any post-bid negotiations with bidders

8 shall be limited to price only and shall be completed

9 within 24 hours after opening the sealed bids and shall

10 be conducted in a fair and unbiased manner; in

11 conducting the negotiations, there shall be no

12 disclosure of any information derived from proposals

13 submitted by competing bidders; if information is

14 disclosed to any bidder, it shall be provided to all

15 competing bidders;

16 (viii) maintain confidentiality of supplier and

17 bidding information in a manner consistent with all

18 applicable laws, rules, regulations, and tariffs;

19 (ix) submit a confidential report to the

20 Commission recommending acceptance or rejection of

21 bids;

22 (x) notify the utility of contract counterparties

23 and contract specifics; and

24 (xi) administer related contingency procurement

25 events.

26 (2) The procurement monitor, who shall be retained by

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1 the Commission, shall:

2 (i) monitor interactions among the procurement

3 administrator, suppliers, and utility;

4 (ii) monitor and report to the Commission on the

5 progress of the procurement process;

6 (iii) provide an independent confidential report

7 to the Commission regarding the results of the

8 procurement event;

9 (iv) assess compliance with the electricity

10 procurement plans approved by the Commission for each

11 utility that on December 31, 2005 provided electric

12 service to a least 100,000 customers in Illinois and

13 for each small multi-jurisdictional utility that on

14 December 31, 2005 served less than 100,000 customers in

15 Illinois;

16 (v) preserve the confidentiality of supplier and

17 bidding information in a manner consistent with all

18 applicable laws, rules, regulations, and tariffs;

19 (vi) provide expert advice to the Commission and

20 consult with the procurement administrator regarding

21 issues related to procurement process design, rules,

22 protocols, and policy-related matters; and

23 (vii) consult with the procurement administrator

24 regarding the development and use of benchmark

25 criteria, standard form contracts, credit policies,

26 and bid documents.

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1 (d) Except as provided in subsection (j), the planning

2 process shall be conducted as follows:

3 (1) Beginning in 2008, each Illinois utility procuring

4 power pursuant to this Section shall annually provide a

5 range of load forecasts to the Illinois Power Agency by

6 July 15 of each year, or such other date as may be required

7 by the Commission or Agency. The load forecasts shall cover

8 the 5-year electricity procurement planning period for the

9 next electricity procurement plan and shall include hourly

10 data representing a high-load, low-load and expected-load

11 scenario for the load of the eligible retail customers. The

12 utility shall provide supporting data and assumptions for

13 each of the scenarios.

14 (2) Beginning in 2008, the Illinois Power Agency shall

15 prepare an electricity ~~a~~ procurement plan by August 15th of

16 each year, or such other date as may be required by the

17 Commission. The electricity procurement plan shall

18 identify the portfolio of demand-response and power and

19 energy products to be procured. Cost-effective

20 demand-response measures shall be procured as set forth in

21 item (iii) of subsection (b) of this Section. Copies of the

22 electricity procurement plan shall be posted and made

23 publicly available on the Agency's and Commission's

24 websites, and copies shall also be provided to each

25 affected electric utility. An affected utility shall have

26 30 days following the date of posting to provide comment to

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1 the Agency on the electricity procurement plan. Other

2 interested entities also may comment on the electricity

3 procurement plan. All comments submitted to the Agency

4 shall be specific, supported by data or other detailed

5 analyses, and, if objecting to all or a portion of the

6 electricity procurement plan, accompanied by specific

7 alternative wording or proposals. All comments shall be

8 posted on the Agency's and Commission's websites. During

9 this 30-day comment period, the Agency shall hold at least

10 one public hearing within each utility's service area for

11 the purpose of receiving public comment on the electricity

12 procurement plan. Within 14 days following the end of the

13 30-day review period, the Agency shall revise the

14 electricity procurement plan as necessary based on the

15 comments received and file the electricity procurement

16 plan with the Commission and post the electricity

17 procurement plan on the websites.

18 (3) Within 5 days after the filing of the electricity

19 procurement plan, any person objecting to the electricity

20 procurement plan shall file an objection with the

21 Commission. Within 10 days after the filing, the Commission

22 shall determine whether a hearing is necessary. The

23 Commission shall enter its order confirming or modifying

24 the electricity procurement plan within 90 days after the

25 filing of the electricity procurement plan by the Illinois

26 Power Agency.

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1 (4) The Commission shall approve the electricity

2 procurement plan, including expressly the forecast used in

3 the electricity procurement plan, if the Commission

4 determines that it will ensure adequate, reliable,

5 affordable, efficient, and environmentally sustainable

6 electric service at the lowest total cost over time, taking

7 into account any benefits of price stability.

8 (e) The procurement process shall include each of the

9 following components:

10 (1) Solicitation, pre-qualification, and registration

11 of bidders. The procurement administrator shall

12 disseminate information to potential bidders to promote a

13 procurement event, notify potential bidders that the

14 procurement administrator may enter into a post-bid price

15 negotiation with bidders that meet the applicable

16 benchmarks, provide supply requirements, and otherwise

17 explain the competitive procurement process. In addition

18 to such other publication as the procurement administrator

19 determines is appropriate, this information shall be

20 posted on the Illinois Power Agency's and the Commission's

21 websites. The procurement administrator shall also

22 administer the prequalification process, including

23 evaluation of credit worthiness, compliance with

24 procurement rules, and agreement to the standard form

25 contract developed pursuant to paragraph (2) of this

26 subsection (e). The procurement administrator shall then

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1 identify and register bidders to participate in the

2 procurement event.

3 (2) Standard contract forms and credit terms and

4 instruments. The procurement administrator, in

5 consultation with the utilities, the Commission, and other

6 interested parties and subject to Commission oversight,

7 shall develop and provide standard contract forms for the

8 supplier contracts that meet generally accepted industry

9 practices. Standard credit terms and instruments that meet

10 generally accepted industry practices shall be similarly

11 developed. The procurement administrator shall make

12 available to the Commission all written comments it

13 receives on the contract forms, credit terms, or

14 instruments. If the procurement administrator cannot reach

15 agreement with the applicable electric utility as to the

16 contract terms and conditions, the procurement

17 administrator must notify the Commission of any disputed

18 terms and the Commission shall resolve the dispute. The

19 terms of the contracts shall not be subject to negotiation

20 by winning bidders, and the bidders must agree to the terms

21 of the contract in advance so that winning bids are

22 selected solely on the basis of price.

23 (3) Establishment of a market-based price benchmark.

24 As part of the development of the procurement process, the

25 procurement administrator, in consultation with the

26 Commission staff, Agency staff, and the procurement

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1 monitor, shall establish benchmarks for evaluating the

2 final prices in the contracts for each of the products that

3 will be procured through the procurement process. The

4 benchmarks shall be based on price data for similar

5 products for the same delivery period and same delivery

6 hub, or other delivery hubs after adjusting for that

7 difference. The price benchmarks may also be adjusted to

8 take into account differences between the information

9 reflected in the underlying data sources and the specific

10 products and procurement process being used to procure

11 power for the Illinois utilities. The benchmarks shall be

12 confidential but shall be provided to, and will be subject

13 to Commission review and approval, prior to a procurement

14 event.

15 (4) Request for proposals competitive procurement

16 process. The procurement administrator shall design and

17 issue a request for proposals to supply electricity in

18 accordance with each utility's electricity procurement

19 plan, as approved by the Commission. The request for

20 proposals shall set forth a procedure for sealed, binding

21 commitment bidding with pay-as-bid settlement, and

22 provision for selection of bids on the basis of price.

23 (5) A plan for implementing contingencies in the event

24 of supplier default or failure of the procurement process

25 to fully meet the expected load requirement due to

26 insufficient supplier participation, Commission rejection

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1 of results, or any other cause.

2 (i) Event of supplier default: In the event of

3 supplier default, the utility shall review the

4 contract of the defaulting supplier to determine if the

5 amount of supply is 200 megawatts or greater, and if

6 there are more than 60 days remaining of the contract

7 term. If both of these conditions are met, and the

8 default results in termination of the contract, the

9 utility shall immediately notify the Illinois Power

10 Agency that a request for proposals must be issued to

11 procure replacement power, and the procurement

12 administrator shall run an additional procurement

13 event. If the contracted supply of the defaulting

14 supplier is less than 200 megawatts or there are less

15 than 60 days remaining of the contract term, the

16 utility shall procure power and energy from the

17 applicable regional transmission organization market,

18 including ancillary services, capacity, and day-ahead

19 or real time energy, or both, for the duration of the

20 contract term to replace the contracted supply;

21 provided, however, that if a needed product is not

22 available through the regional transmission

23 organization market it shall be purchased from the

24 wholesale market.

25 (ii) Failure of the procurement process to fully

26 meet the expected load requirement: If the procurement

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1 process fails to fully meet the expected load

2 requirement due to insufficient supplier participation

3 or due to a Commission rejection of the procurement

4 results, the procurement administrator, the

5 procurement monitor, and the Commission staff shall

6 meet within 10 days to analyze potential causes of low

7 supplier interest or causes for the Commission

8 decision. If changes are identified that would likely

9 result in increased supplier participation, or that

10 would address concerns causing the Commission to

11 reject the results of the prior procurement event, the

12 procurement administrator may implement those changes

13 and rerun the request for proposals process according

14 to a schedule determined by those parties and

15 consistent with Section 1-75 of the Illinois Power

16 Agency Act and this subsection. In any event, a new

17 request for proposals process shall be implemented by

18 the procurement administrator within 90 days after the

19 determination that the procurement process has failed

20 to fully meet the expected load requirement.

21 (iii) In all cases where there is insufficient

22 supply provided under contracts awarded through the

23 procurement process to fully meet the electric

24 utility's load requirement, the utility shall meet the

25 load requirement by procuring power and energy from the

26 applicable regional transmission organization market,

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1 including ancillary services, capacity, and day-ahead

2 or real time energy or both; provided, however, that if

3 a needed product is not available through the regional

4 transmission organization market it shall be purchased

5 from the wholesale market.

6 (6) The procurement process described in this

7 subsection is exempt from the requirements of the Illinois

8 Procurement Code, pursuant to Section 20-10 of that Code.

9 (f) Within 2 business days after opening the sealed bids,

10 the procurement administrator shall submit a confidential

11 report to the Commission. The report shall contain the results

12 of the bidding for each of the products along with the

13 procurement administrator's recommendation for the acceptance

14 and rejection of bids based on the price benchmark criteria and

15 other factors observed in the process. The procurement monitor

16 also shall submit a confidential report to the Commission

17 within 2 business days after opening the sealed bids. The

18 report shall contain the procurement monitor's assessment of

19 bidder behavior in the process as well as an assessment of the

20 procurement administrator's compliance with the procurement

21 process and rules. The Commission shall review the confidential

22 reports submitted by the procurement administrator and

23 procurement monitor, and shall accept or reject the

24 recommendations of the procurement administrator within 2

25 business days after receipt of the reports.

26 (g) Within 3 business days after the Commission decision

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1 approving the results of a procurement event, the utility shall

2 enter into binding contractual arrangements with the winning

3 suppliers using the standard form contracts; except that the

4 utility shall not be required either directly or indirectly to

5 execute the contracts if a tariff that is consistent with

6 subsection (l) of this Section has not been approved and placed

7 into effect for that utility.

8 (h) The names of the successful bidders and the load

9 weighted average of the winning bid prices for each contract

10 type and for each contract term shall be made available to the

11 public at the time of Commission approval of a procurement

12 event. The Commission, the procurement monitor, the

13 procurement administrator, the Illinois Power Agency, and all

14 participants in the procurement process shall maintain the

15 confidentiality of all other supplier and bidding information

16 in a manner consistent with all applicable laws, rules,

17 regulations, and tariffs. Confidential information, including

18 the confidential reports submitted by the procurement

19 administrator and procurement monitor pursuant to subsection

20 (f) of this Section, shall not be made publicly available and

21 shall not be discoverable by any party in any proceeding,

22 absent a compelling demonstration of need, nor shall those

23 reports be admissible in any proceeding other than one for law

24 enforcement purposes.

25 (i) Within 2 business days after a Commission decision

26 approving the results of a procurement event or such other date

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1 as may be required by the Commission from time to time, the

2 utility shall file for informational purposes with the

3 Commission its actual or estimated retail supply charges, as

4 applicable, by customer supply group reflecting the costs

5 associated with the procurement and computed in accordance with

6 the tariffs filed pursuant to subsection (l) of this Section

7 and approved by the Commission.

8 (j) Within 60 days following the effective date of this

9 amendatory Act, each electric utility that on December 31, 2005

10 provided electric service to at least 100,000 customers in

11 Illinois shall prepare and file with the Commission an initial

12 electricity procurement plan, which shall conform in all

13 material respects to the requirements of the electricity

14 procurement plan set forth in subsection (b); provided,

15 however, that the Illinois Power Agency Act shall not apply to

16 the initial electricity procurement plan prepared pursuant to

17 this subsection. The initial electricity procurement plan

18 shall identify the portfolio of power and energy products to be

19 procured and delivered for the period June 2008 through May

20 2009, and shall identify the proposed procurement

21 administrator, who shall have the same experience and expertise

22 as is required of a procurement administrator hired pursuant to

23 Section 1-75 of the Illinois Power Agency Act. Copies of the

24 electricity procurement plan shall be posted and made publicly

25 available on the Commission's website. The initial electricity

26 procurement plan may include contracts for renewable resources

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1 that extend beyond May 2009.

2 (i) Within 14 days following filing of the initial

3 electricity procurement plan, any person may file a

4 detailed objection with the Commission contesting the

5 electricity procurement plan submitted by the electric

6 utility. All objections to the electric utility's plan

7 shall be specific, supported by data or other detailed

8 analyses. The electric utility may file a response to any

9 objections to its electricity procurement plan within 7

10 days after the date objections are due to be filed. Within

11 7 days after the date the utility's response is due, the

12 Commission shall determine whether a hearing is necessary.

13 If it determines that a hearing is necessary, it shall

14 require the hearing to be completed and issue an order on

15 the electricity procurement plan within 60 days after the

16 filing of the electricity procurement plan by the electric

17 utility.

18 (ii) The order shall approve or modify the electricity

19 procurement plan, approve an independent procurement

20 administrator, and approve or modify the electric

21 utility's tariffs that are proposed with the initial

22 electricity procurement plan. The Commission shall approve

23 the electricity procurement plan if the Commission

24 determines that it will ensure adequate, reliable,

25 affordable, efficient, and environmentally sustainable

26 electric service at the lowest total cost over time, taking

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1 into account any benefits of price stability.

2 (k) In order to promote price stability for residential and

3 small commercial customers during the transition to

4 competition in Illinois, and notwithstanding any other

5 provision of this Act, each electric utility subject to this

6 Section shall enter into one or more multi-year financial swap

7 contracts that become effective on the effective date of this

8 amendatory Act. These contracts may be executed with generators

9 and power marketers, including affiliated interests of the

10 electric utility. These contracts shall be for a term of no

11 more than 5 years and shall, for each respective utility or for

12 any Illinois electric utilities that are affiliated by virtue

13 of a common parent company and that are thereby considered a

14 single electric utility for purposes of this subsection (k),

15 not exceed in the aggregate 3,000 megawatts for any hour of the

16 year. The contracts shall be financial contracts and not energy

17 sales contracts. The contracts shall be executed as

18 transactions under a negotiated master agreement based on the

19 form of master agreement for financial swap contracts sponsored

20 by the International Swaps and Derivatives Association, Inc.

21 and shall be considered pre-existing contracts in the

22 utilities' electricity procurement plans for residential and

23 small commercial customers. Costs incurred pursuant to a

24 contract authorized by this subsection (k) shall be deemed

25 prudently incurred and reasonable in amount and the electric

26 utility shall be entitled to full cost recovery pursuant to the

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1 tariffs filed with the Commission.

2 (k-5) In order to promote price stability for residential

3 and small commercial customers during the infrastructure

4 investment program described in subsection (b) of Section

5 16-108.5 of this Act, and notwithstanding any other provision

6 of this Act or the Illinois Power Agency Act, for each electric

7 utility that serves more than one million retail customers in

8 Illinois, the Illinois Power Agency shall conduct a procurement

9 event within 120 days after October 26, 2011 (the effective

10 date of Public Act 97-616) and may procure contracts for energy

11 and renewable energy credits for the period June 1, 2013

12 through December 31, 2017 that satisfy the requirements of this

13 subsection (k-5), including the benchmarks described in this

14 subsection. These contracts shall be entered into as the result

15 of a competitive procurement event, and, to the extent that any

16 provisions of this Section or the Illinois Power Agency Act do

17 not conflict with this subsection (k-5), such provisions shall

18 apply to the procurement event. The energy contracts shall be

19 for 24 hour by 7 day supply over a term that runs from the first

20 delivery year through December 31, 2017. For a utility that

21 serves over 2 million customers, the energy contracts shall be

22 multi-year with pricing escalating at 2.5% per annum. The

23 energy contracts may be designed as financial swaps or may

24 require physical delivery.

25 Within 30 days of October 26, 2011 (the effective date of

26 Public Act 97-616), each such utility shall submit to the

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1 Agency updated load forecasts for the period June 1, 2013

2 through December 31, 2017. The megawatt volume of the contracts

3 shall be based on the updated load forecasts of the minimum

4 monthly on-peak or off-peak average load requirements shown in

5 the forecasts, taking into account any existing energy

6 contracts in effect as well as the expected migration of the

7 utility's customers to alternative retail electric suppliers.

8 The renewable energy credit volume shall be based on the number

9 of credits that would satisfy the requirements of subsection

10 (c) of Section 1-75 of the Illinois Power Agency Act, subject

11 to the rate impact caps and other provisions of subsection (c)

12 of Section 1-75 of the Illinois Power Agency Act. The

13 evaluation of contract bids in the competitive procurement

14 events for energy and for renewable energy credits shall

15 incorporate price benchmarks set collaboratively by the

16 Agency, the procurement administrator, the staff of the

17 Commission, and the procurement monitor. If the contracts are

18 swap contracts, then they shall be executed as transactions

19 under a negotiated master agreement based on the form of master

20 agreement for financial swap contracts sponsored by the

21 International Swaps and Derivatives Association, Inc. Costs

22 incurred pursuant to a contract authorized by this subsection

23 (k-5) shall be deemed prudently incurred and reasonable in

24 amount and the electric utility shall be entitled to full cost

25 recovery pursuant to the tariffs filed with the Commission.

26 The cost of administering the procurement event described

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1 in this subsection (k-5) shall be paid by the winning supplier

2 or suppliers to the procurement administrator through a

3 supplier fee. In the event that there is no winning supplier

4 for a particular utility, such utility will pay the procurement

5 administrator for the costs associated with the procurement

6 event, and those costs shall not be a recoverable expense.

7 Nothing in this subsection (k-5) is intended to alter the

8 recovery of costs for any other procurement event.

9 (l) An electric utility shall recover its costs incurred

10 under this Section, including, but not limited to, the costs of

11 procuring power and energy demand-response resources under

12 this Section. The utility shall file with the initial

13 electricity procurement plan its proposed tariffs through

14 which its costs of procuring power that are incurred pursuant

15 to a Commission-approved electricity procurement plan and

16 those other costs identified in this subsection (l), will be

17 recovered. The tariffs shall include a formula rate or charge

18 designed to pass through both the costs incurred by the utility

19 in procuring a supply of electric power and energy for the

20 applicable customer classes with no mark-up or return on the

21 price paid by the utility for that supply, plus any just and

22 reasonable costs that the utility incurs in arranging and

23 providing for the supply of electric power and energy. The

24 formula rate or charge shall also contain provisions that

25 ensure that its application does not result in over or under

26 recovery due to changes in customer usage and demand patterns,

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1 and that provide for the correction, on at least an annual

2 basis, of any accounting errors that may occur. A utility shall

3 recover through the tariff all reasonable costs incurred to

4 implement or comply with any electricity procurement plan that

5 is developed and put into effect pursuant to Section 1-75 of

6 the Illinois Power Agency Act and this Section, including any

7 fees assessed by the Illinois Power Agency, costs associated

8 with load balancing, and contingency plan costs. The electric

9 utility shall also recover its full costs of procuring electric

10 supply for which it contracted before the effective date of

11 this Section in conjunction with the provision of full

12 requirements service under fixed-price bundled service tariffs

13 subsequent to December 31, 2006. All such costs shall be deemed

14 to have been prudently incurred. The pass-through tariffs that

15 are filed and approved pursuant to this Section shall not be

16 subject to review under, or in any way limited by, Section

17 16-111(i) of this Act.

18 (m) The Commission has the authority to adopt rules to

19 carry out the provisions of this Section. For the public

20 interest, safety, and welfare, the Commission also has

21 authority to adopt rules to carry out the provisions of this

22 Section on an emergency basis immediately following the

23 effective date of this amendatory Act.

24 (n) Notwithstanding any other provision of this Act, any

25 affiliated electric utilities that submit a single electricity

26 procurement plan covering their combined needs may procure for

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1 those combined needs in conjunction with that plan, and may

2 enter jointly into power supply contracts, purchases, and other

3 procurement arrangements, and allocate capacity and energy and

4 cost responsibility therefor among themselves in proportion to

5 their requirements.

6 (o) On or before June 1 of each year, the Commission shall

7 hold an informal hearing for the purpose of receiving comments

8 on the prior year's procurement process and any recommendations

9 for change.

10 (p) An electric utility subject to this Section may propose

11 to invest, lease, own, or operate an electric generation

12 facility as part of its electricity procurement plan, provided

13 the utility demonstrates that such facility is the least-cost

14 option to provide electric service to eligible retail

15 customers. If the facility is shown to be the least-cost option

16 and is included in an electricity ~~a~~ procurement plan prepared

17 in accordance with Section 1-75 of the Illinois Power Agency

18 Act and this Section, then the electric utility shall make a

19 filing pursuant to Section 8-406 of this Act, and may request

20 of the Commission any statutory relief required thereunder. If

21 the Commission grants all of the necessary approvals for the

22 proposed facility, such supply shall thereafter be considered

23 as a pre-existing contract under subsection (b) of this

24 Section. The Commission shall in any order approving a proposal

25 under this subsection specify how the utility will recover the

26 prudently incurred costs of investing in, leasing, owning, or

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1 operating such generation facility through just and reasonable

2 rates charged to eligible retail customers. Cost recovery for

3 facilities included in the utility's electricity procurement

4 plan pursuant to this subsection shall not be subject to review

5 under or in any way limited by the provisions of Section

6 16-111(i) of this Act. Nothing in this Section is intended to

7 prohibit a utility from filing for a fuel adjustment clause as

8 is otherwise permitted under Section 9-220 of this Act.

9 (q) Notwithstanding any other provisions of this Section,

10 beginning with the 2016 delivery year, the procurement of

11 renewable energy credits in accordance with subdivision (c) of

12 Section 1-75 of the Illinois Power Agency Act shall not be

13 subject to this Section. For the purposes of this Section,

14 "delivery year" has the same meaning as in Section 1-10 of the

15 Illinois Power Agency Act.

16 (Source: P.A. 97-325, eff. 8-12-11; 97-616, eff. 10-26-11;

17 97-813, eff. 7-13-12.)

18 (220 ILCS 5/16-111.5B)

19 Sec. 16-111.5B. Provisions relating to energy efficiency

20 procurement.

21 (a) Beginning in 2012, procurement plans prepared pursuant

22 to Section 16-111.5 of this Act shall be subject to the

23 following additional requirements, except that beginning in

24 2018, any utility that has achieved the performance metrics

25 under paragraph (10) of subsection (f) of Section 16-108.5 of

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1 this Act shall be exempt from this Section:

2 (1) The analysis included pursuant to paragraph (2) of

3 subsection (b) of Section 16-111.5 shall also include the

4 impact of energy efficiency building codes or appliance

5 standards, both current and projected.

6 (2) The procurement plan components described in

7 subsection (b) of Section 16-111.5 shall also include an

8 assessment of opportunities to expand the programs

9 promoting energy efficiency measures that have been

10 offered under plans approved pursuant to Section 8-103 of

11 this Act or to implement additional cost-effective energy

12 efficiency programs or measures.

13 (3) In addition to the information provided pursuant to

14 paragraph (1) of subsection (d) of Section 16-111.5 of this

15 Act, each Illinois utility procuring power pursuant to that

16 Section shall annually provide to the Illinois Power Agency

17 by July 15 of each year, or such other date as may be

18 required by the Commission or Agency, an assessment of

19 cost-effective energy efficiency programs or measures that

20 could be included in the procurement plan. The assessment

21 shall include the following:

22 (A) A comprehensive energy efficiency potential

23 study for the utility's service territory that was

24 completed within the past 3 years.

25 (B) Beginning in 2014, the most recent analysis

26 submitted pursuant to Section 8-103A of this Act and

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1 approved by the Commission under subsection (f) of

2 Section 8-103 of this Act.

3 (C) Identification of new or expanded

4 cost-effective energy efficiency programs or measures

5 that are incremental to those included in energy

6 efficiency and demand-response plans approved by the

7 Commission pursuant to Section 8-103 of this Act and

8 that would be offered to all retail customers whose

9 electric service has not been declared competitive

10 under Section 16-113 of this Act and who are eligible

11 to purchase power and energy from the utility under

12 fixed-price bundled service tariffs, regardless of

13 whether such customers actually do purchase such power

14 and energy from the utility.

15 (D) Analysis showing that the new or expanded

16 cost-effective energy efficiency programs or measures

17 would lead to a reduction in the overall cost of

18 electric service.

19 (E) Analysis of how the cost of procuring

20 additional cost-effective energy efficiency measures

21 compares over the life of the measures to the

22 prevailing cost of comparable supply.

23 (F) An energy savings goal, expressed in

24 megawatt-hours, for the year in which the measures will

25 be implemented.

26 (G) For each expanded or new program, the estimated

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1 amount that the program may reduce the agency's need to

2 procure supply.

3 In preparing such assessments, a utility shall conduct

4 an annual solicitation process for purposes of requesting

5 proposals from third-party vendors, the results of which

6 shall be provided to the Agency as part of the assessment,

7 including documentation of all bids received. The utility

8 shall develop requests for proposals consistent with the

9 manner in which it develops requests for proposals under

10 plans approved pursuant to Section 8-103 of this Act, which

11 considers input from the Agency and interested

12 stakeholders.

13 (4) The Illinois Power Agency shall include in the

14 procurement plan prepared pursuant to paragraph (2) of

15 subsection (d) of Section 16-111.5 of this Act energy

16 efficiency programs and measures it determines are

17 cost-effective and the associated annual energy savings

18 goal included in the annual solicitation process and

19 assessment submitted pursuant to paragraph (3) of this

20 subsection (a).

21 (5) Pursuant to paragraph (4) of subsection (d) of

22 Section 16-111.5 of this Act, the Commission shall also

23 approve the energy efficiency programs and measures

24 included in the procurement plan, including the annual

25 energy savings goal, if the Commission determines they

26 fully capture the potential for all achievable

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1 cost-effective savings, to the extent practicable, and

2 otherwise satisfy the requirements of Section 8-103 of this

3 Act.

4 In the event the Commission approves the procurement of

5 additional energy efficiency, it shall reduce the amount of

6 power to be procured under the procurement plan to reflect

7 the additional energy efficiency and shall direct the

8 utility to undertake the procurement of such energy

9 efficiency, which shall not be subject to the requirements

10 of subsection (e) of Section 16-111.5 of this Act. The

11 utility shall consider input from the Agency and interested

12 stakeholders on the procurement and administration

13 process.

14 (6) An electric utility shall recover its costs

15 incurred under this Section related to the implementation

16 of energy efficiency programs and measures approved by the

17 Commission in its order approving the procurement plan

18 under Section 16-111.5 of this Act, including, but not

19 limited to, all costs associated with complying with this

20 Section and all start-up and administrative costs and the

21 costs for any evaluation, measurement, and verification of

22 the measures, from all retail customers whose electric

23 service has not been declared competitive under Section

24 16-113 of this Act and who are eligible to purchase power

25 and energy from the utility under fixed-price bundled

26 service tariffs, regardless of whether such customers

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1 actually do purchase such power and energy from the utility

2 through the automatic adjustment clause tariff established

3 pursuant to Section 8-103 of this Act, provided, however,

4 that the limitations described in subsection (d) of that

5 Section shall not apply to the costs incurred pursuant to

6 this Section or Section 16-111.7 of this Act.

7 (b) For purposes of this Section, the term "energy

8 efficiency" shall have the meaning set forth in Section 1-10 of

9 the Illinois Power Agency Act, and the term "cost-effective"

10 shall have the meaning set forth in subsection (a) of Section

11 8-103 of this Act.

12 (Source: P.A. 97-616, eff. 10-26-11; 97-824, eff. 7-18-12.)

13 (220 ILCS 5/16-111.5C new)

14 Sec. 16-111.5C. Provisions related to renewable energy

15 credit procurement.

16 (a) Beginning with the planning process to develop a plan

17 or plans for implementation starting in the 2016 delivery year,

18 a long-term renewable resources procurement plan for the

19 procurement of renewable energy credits shall be prepared

20 consistent with the applicable requirements of the Illinois

21 Power Agency Act and this Section. The long-term renewable

22 resources procurement plan and all subsequent revisions shall

23 be subject to review and approval by the Commission according

24 to the provisions set forth in this Section. For the purposes

25 of this Section, "delivery year" has the same meaning as in

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1 Section 1-10 of the Illinois Power Agency Act.

2 (b) The long-term renewable resources planning process

3 shall be conducted as follows:

4 (1) Electric utilities shall provide a range of load

5 forecasts to the Illinois Power Agency within 30 days after

6 the effective date of this amendatory Act of the 99th

7 General Assembly and on July 15 of each year thereafter or

8 upon such other date as may be required by the Commission

9 or Agency. The load forecasts shall cover the procurement

10 planning period through the 2030 delivery year and beyond

11 and shall include a high-load, low-load, and expected-load

12 scenario for the load of all customers taking delivery

13 service from the electric utility. The utility shall

14 provide supporting data and assumptions for each of the

15 scenarios.

16 (2) The Illinois Power Agency shall publish for comment

17 the initial long-term renewable resources plan no later

18 than 120 days after the effective date of this amendatory

19 Act of the 99th General Assembly and shall make revisions

20 to the plan at least every 2 years thereafter. The

21 long-term renewable resources procurement plan shall

22 identify the procurement programs and competitive

23 procurement events consistent with the applicable

24 requirements of the Illinois Power Agency Act and designed

25 to achieve the goals set forth in subdivision (c) of

26 Section 1-75 of that Act. Copies of the long-term renewable

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1 resources procurement plan shall be posted and made

2 publicly available on the Agency's and Commission's

3 websites, and copies shall also be provided to each

4 affected electric utility. An affected utility and other

5 interested parties shall have 30 days following the date of

6 posting to provide comment to the Agency on the procurement

7 plan. All comments submitted to the Agency shall be

8 specific, supported by data or other detailed analyses,

9 and, if objecting to all or a portion of the procurement

10 plan, accompanied by specific alternative wording or

11 proposals. All comments shall be posted on the Agency's and

12 Commission's websites. During this 30-day comment period,

13 the Agency shall hold at least one public hearing within

14 each utility's service area for the purpose of receiving

15 public comment on the long-term renewable resources

16 procurement plan. Within 14 days following the end of the

17 30-day review period, the Agency shall revise the long-term

18 renewable resources procurement plan as necessary based on

19 the comments received and file the plan with the Commission

20 for review and approval.

21 (3) Within 14 days after the filing of the long-term

22 renewable resources procurement plan, any person objecting

23 to the plan shall file an objection with the Commission.

24 Within 21 days after the filing, the Commission shall

25 determine whether a hearing is necessary. The Commission

26 shall enter its order confirming or modifying the

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1 procurement plan within 120 days after the filing of the

2 procurement plan by the Illinois Power Agency.

3 (4) The Commission shall approve the long-term

4 renewable resources procurement plan if the Commission

5 determines that the plan will reasonably and prudently

6 fulfill the relevant requirements of Section 1-56 and

7 subdivision (c) of Section 1-75 of the Illinois Power

8 Agency Act.

9 (c) The Agency or third parties contracted by the Agency

10 shall implement all programs authorized by the Commission in an

11 approved long-term renewable resources procurement plan. For

12 those renewable energy credits subject to procurement through a

13 competitive bid process under the plan, the Agency shall follow

14 the procurement process specified in the provisions relating to

15 electricity procurement in subsections (e) through (i) of

16 Section 16-111.5 of this Act.

17 (d) An electric utility shall recover its costs incurred

18 under this Section, including, but not limited to, the costs of

19 procuring renewable energy credits under this Section, as a

20 utility cost of service under the Illinois Public Utilities

21 Act.

22 (e) The Commission has the authority to adopt rules to

23 carry out the provisions of this Section. For the public

24 interest, safety, and welfare, the Commission also has

25 authority to adopt rules to carry out the provisions of this

26 Section on an emergency basis immediately following the

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1 effective date of this amendatory Act of the 99th General

2 Assembly.

3 (f) On or before July 1 of each year, the Commission shall

4 hold an informal hearing for the purpose of receiving comments

5 on the prior year's procurement process and any recommendations

6 for change.

7 (220 ILCS 5/16-111.7)

8 Sec. 16-111.7. On-bill financing program; electric

9 utilities.

10 (a) The Illinois General Assembly finds that Illinois homes

11 and businesses have the potential to save energy through

12 conservation and cost-effective energy efficiency measures.

13 Programs created pursuant to this Section will allow utility

14 customers to purchase cost-effective energy efficiency

15 measures, including measures set forth in a

16 Commission-approved energy efficiency and demand-response plan

17 under Section 8-103 of this Act, with no required initial

18 upfront payment, and to pay the cost of those products and

19 services over time on their utility bill.

20 (a-5) As used in this Section:

21 "Eligible electric energy efficiency measure" or "measure"

22 means a product or service for which one or more of the

23 following is true:

24 (1) a building energy assessment, performed by an

25 energy auditor who is certified by the Building Performance

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1 Institute or who holds a similar certification, has

2 recommended the product or service as likely to be

3 cost-effective over the course of its installed life for

4 the building in which the measure is to be installed;

5 (2) the projected electricity savings (determined by

6 rates in effect at the time of purchase) are sufficient to

7 cover the costs of implementing the measures, including

8 finance charges and any program fees not recovered pursuant

9 to subsection (g) of this Section;

10 (3) the product or service is included in a

11 Commission-approved energy efficiency and demand-response

12 plan under Section 8-103 of this Act and is cost-effective

13 as that term is defined by that Section; or

14 (4) the product or service is necessary to safely or

15 correctly install to code or industry standard an

16 efficiency measure, including, but not limited to,

17 installation work; changes needed to plumbing or

18 electrical connections; upgrades to wiring or fixtures;

19 removal of hazardous materials; correction of leaks;

20 changes to thermostats, controls or similar devices; and

21 changes to venting or exhaust necessitated by the measure.

22 "Small commercial customer" means, for an electric utility

23 serving more than 3,000,000 retail customers, those customers

24 having peak demand of less than 100 kilowatts, and, for an

25 electric utility serving less than 3,000,000 retail customers,

26 those customers having peak demand of less than 150 kilowatts;

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1 provided, however, that in the event the Commission, after

2 August 27, 2013 (the effective date of Public Act 98-586),

3 approves changes to a utility's tariffs that reflect new or

4 revised demand criteria for the utility's customer rate

5 classifications, then the utility may file a petition with the

6 Commission to revise the applicable definition of a small

7 commercial customer to reflect the new or revised demand

8 criteria for the purposes of this Section. After notice and

9 hearing, the Commission shall enter an order approving, or

10 approving with modification, the revised definition within 60

11 days after the utility files the petition.

12 (b) Notwithstanding any other provision of this Act, an

13 electric utility serving more than 100,000 customers on January

14 1, 2009 shall offer a Commission-approved on-bill financing

15 program ("program") that allows its eligible retail customers,

16 as that term is defined in Section 16-111.5 of this Act, who

17 own a residential single family home, duplex, or other

18 residential building with 4 or less units, or condominium at

19 which the electric service is being provided (i) to borrow

20 funds from a third party lender in order to purchase electric

21 energy efficiency measures approved under the program for

22 installation in such home or condominium without any required

23 upfront payment and (ii) to pay back such funds over time

24 through the electric utility's bill. Based upon the process

25 described in subsection (b-5) of this Section, small commercial

26 customers who own the premises at which electric service is

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1 being provided may be included in such program. After receiving

2 a request from an electric utility for approval of a proposed

3 program and tariffs pursuant to this Section, the Commission

4 shall render its decision within 120 days. If no decision is

5 rendered within 120 days, then the request shall be deemed to

6 be approved.

7 Beginning no later than December 31, 2013, an electric

8 utility subject to this subsection (b) shall also offer its

9 program to eligible retail customers that own multifamily

10 residential or mixed-use buildings ~~with no more than 50~~

11 ~~residential units~~, provided, however, that such customers must

12 either be a residential customer or small commercial customer

13 and may not use the program in such a way that repayment of the

14 cost of energy efficiency measures is made through tenants'

15 utility bills. ~~An electric utility may impose a per site loan~~

16 ~~limit not to exceed $150,000.~~ The program, and loans issued

17 thereunder, shall only be offered to customers of the utility

18 that meet the requirements of this Section and that also have

19 an electric service account at the premises where the energy

20 efficiency measures being financed shall be installed.

21 Beginning no later than December 31, 2015, an electric

22 utility subject to this subsection (b) shall also offer its

23 program to eligible retail customers that are Unit Owners'

24 Associations, as defined in subsection (o) of Section 2 of the

25 Condominium Property Act, or Master Associations, as defined in

26 subsection (u) of Section 2 of the Condominium Property Act;

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1 however, such customers must either be residential customers or

2 small commercial customers and may not use the program in such

3 a way that repayment of the cost of energy efficiency measures

4 is made through unit owners' utility bills. The program and

5 loans issued under the program shall only be offered to

6 customers of the utility that meet the requirements of this

7 Section and that also have an electric service account at the

8 premises where the energy efficiency measures being financed

9 shall be installed.

10 ~~For purposes of this Section, "small commercial customer"~~

11 ~~means, for an electric utility serving more than 3,000,000~~

12 ~~retail customers, those customers having peak demand of less~~

13 ~~than 100 kilowatts, and, for an electric utility serving less~~

14 ~~than 3,000,000 retail customers, those customers having peak~~

15 ~~demand of less than 150 kilowatts; provided, however, that in~~

16 ~~the event the Commission, after the effective date of this~~

17 ~~amendatory Act of the 98th General Assembly, approves changes~~

18 ~~to a utility's tariffs that reflects new or revised demand~~

19 ~~criteria for the utility's customer rate classifications, then~~

20 ~~the utility may file a petition with the Commission to revise~~

21 ~~the applicable definition of a small commercial customer to~~

22 ~~reflect the new or revised demand criteria for the purposes of~~

23 ~~this Section. After notice and hearing, the Commission shall~~

24 ~~enter an order approving, or approving with modification, the~~

25 ~~revised definition within 60 days after the utility files the~~

26 ~~petition.~~

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1 (b-5) Within 30 days after the effective date of this

2 amendatory Act of the 96th General Assembly, the Commission

3 shall convene a workshop process during which interested

4 participants may discuss issues related to the program,

5 including program design, eligible electric energy efficiency

6 measures, vendor qualifications, and a methodology for

7 ensuring ongoing compliance with such qualifications,

8 financing, sample documents such as request for proposals,

9 contracts and agreements, dispute resolution, pre-installment

10 and post-installment verification, and evaluation. The

11 workshop process shall be completed within 150 days after the

12 effective date of this amendatory Act of the 96th General

13 Assembly.

14 (c) Not later than 60 days following completion of the

15 workshop process described in subsection (b-5) of this Section,

16 each electric utility subject to subsection (b) of this Section

17 shall submit a proposed program to the Commission that contains

18 the following components:

19 (1) A description of how the program will determine if

20 measures to be financed are eligible electric energy

21 efficiency measures, as defined in subsection (b) of this

22 Section. ~~A list of recommended electric energy efficiency~~

23 ~~measures that will be eligible for on-bill financing. An~~

24 ~~eligible electric energy efficiency measure ("measure")~~

25 ~~shall be a product or service for which one or more of the~~

26 ~~following is true:~~

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1 ~~(A) (blank);~~

2 ~~(B) the projected electricity savings (determined~~

3 ~~by rates in effect at the time of purchase) are~~

4 ~~sufficient to cover the costs of implementing the~~

5 ~~measures, including finance charges and any program~~

6 ~~fees not recovered pursuant to subsection (f) of this~~

7 ~~Section; or~~

8 ~~(C) the product or service is included in a~~

9 ~~Commission-approved energy efficiency and~~

10 ~~demand-response plan under Section 8-103 of this Act.~~

11 (2) The electric utility shall issue a request for

12 proposals ("RFP") to lenders for purposes of providing

13 financing to participants to pay for approved measures.

14 Lenders may be for-profit or not-for-profit institutions

15 which can accept, manage, and lend utility funds consistent

16 with applicable financial regulations. The RFP criteria

17 shall include, but not be limited to, the interest rate,

18 origination fees, and credit terms. The utility shall

19 select the winning bidders based on its evaluation of these

20 criteria, with a preference for those bids containing the

21 rates, fees, and terms most favorable to participants;

22 (3) The utility shall work with the lenders selected

23 pursuant to the RFP process, and with vendors, to establish

24 the terms and processes pursuant to which a participant can

25 purchase eligible electric energy efficiency measures

26 using the financing obtained from the lender. The vendor

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1 shall explain and offer the approved financing packaging to

2 those customers identified in subsection (b) of this

3 Section and shall assist customers in applying for

4 financing. As part of the process, vendors shall also

5 provide to participants information about any other

6 incentives that may be available for the measures.

7 (4) The lender shall determine loan eligibility by

8 first examining customer utility bill payment history,

9 unless untimely to do so, and then by conducting ~~conduct~~

10 credit checks or undertaking ~~undertake~~ other appropriate

11 measures to limit credit risk, and shall review and approve

12 or deny financing applications submitted by customers

13 identified in subsection (b) of this Section. If a customer

14 is not approved for financing as a result of a credit

15 check, the lender shall determine whether to approve or

16 deny financing by considering the customer's utility bill

17 repayment history and the bill reductions likely from the

18 energy efficiency measures to be financed and other

19 appropriate measures. Following the lender's approval of

20 financing and the participant's purchase of the measure or

21 measures, the lender shall forward payment information to

22 the electric utility, and the utility shall add as a

23 separate line item on the participant's utility bill a

24 charge showing the amount due under the program each month.

25 (5) A loan issued to a participant pursuant to the

26 program shall be the sole responsibility of the

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1 participant, and any dispute that may arise concerning the

2 loan's terms, conditions, or charges shall be resolved

3 between the participant and lender. Upon transfer of the

4 property title for the premises at which the participant

5 receives electric service from the utility or the

6 participant's request to terminate service at such

7 premises, the participant shall pay in full its electric

8 utility bill, including all amounts due under the program,

9 provided that this obligation may be modified as provided

10 in subsection (g) of this Section. Amounts due under the

11 program shall be deemed amounts owed for residential and,

12 as appropriate, small commercial electric service.

13 (6) The electric utility shall remit payment in full to

14 the lender each month on behalf of the participant. In the

15 event a participant defaults on payment of its electric

16 utility bill, the electric utility shall continue to remit

17 all payments due under the program to the lender, up to the

18 larger of $10,000,000 or 50% of the total allowable

19 outstanding amount financed under paragraph (7) of this

20 subsection (c), and the utility shall be entitled to

21 recover all costs related to a participant's nonpayment, up

22 to the larger of $10,000,000 or 50% of the total allowable

23 outstanding amount financed under paragraph (7) of this

24 subsection (c), through the automatic adjustment clause

25 tariff established pursuant to Section 16-111.8 of this

26 Act. In addition, the electric utility shall retain a

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1 security interest in the measure or measures purchased

2 under the program, and the utility retains its right to

3 disconnect a participant that defaults on the payment of

4 its utility bill.

5 (7) The total annual outstanding amount financed under

6 the program in this subsection and subsection (c-5) of this

7 Section shall not exceed $20,000,000 ~~$2.5 million~~ for an

8 electric utility or electric utilities under a single

9 holding company, provided that the electric utility or

10 electric utilities may petition the Commission for an

11 increase in such amount. A utility may meet the annual

12 obligation using funds repaid through this program or

13 through additional contributions.

14 (c-5) Within 120 days after the effective date of this

15 amendatory Act of the 98th General Assembly, each electric

16 utility subject to the requirements of this Section shall

17 submit an informational filing to the Commission that describes

18 its plan for implementing the provisions of this amendatory Act

19 of the 98th General Assembly on or before December 31, 2013.

20 Such filing shall also describe how the electric utility shall

21 coordinate its program with any gas utility or utilities that

22 provide gas service to buildings within the electric utility's

23 service territory so that it is practical and feasible for the

24 owner of a multifamily building to make a single application to

25 access loans for both gas and electric energy efficiency

26 measures in any individual building.

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1 Within 60 days after the effective date of this amendatory

2 Act of the 99th General Assembly, each electric utility subject

3 to the requirements of this Section shall submit a filing to

4 the Commission that describes its plan for implementing the

5 provisions of this amendatory Act of the 99th General Assembly

6 on or before December 31, 2015. The Commission shall seek

7 public comment on the utility's plan and shall issue an order

8 approving or disapproving each plan within 120 days of its

9 submission. If the Commission disapproves a plan, the

10 Commission shall, within 30 days, describe in detail the

11 reasons for the disapproval and describe a path by which the

12 utility may file a revised draft of the plan to address the

13 Commission's concerns satisfactorily.

14 (d) A program approved by the Commission shall also include

15 the following criteria and guidelines for such program:

16 (1) guidelines for financing of measures installed

17 under a program, including, but not limited to, RFP

18 criteria and limits on both individual loan amounts and the

19 duration of the loans;

20 (2) criteria and standards for identifying and

21 approving measures;

22 (3) qualifications of vendors that will market or

23 install measures, as well as a methodology for ensuring

24 ongoing compliance with such qualifications;

25 (4) sample contracts and agreements necessary to

26 implement the measures and program; and

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1 (5) the types of data and information that utilities

2 and vendors participating in the program shall collect for

3 purposes of preparing the reports required under

4 subsection (g) of this Section.

5 (e) The proposed program submitted by each electric utility

6 shall be consistent with the provisions of this Section that

7 define operational, financial and billing arrangements between

8 and among program participants, vendors, lenders, and the

9 electric utility.

10 (f) An electric utility shall recover all of the prudently

11 incurred costs of offering a program approved by the Commission

12 pursuant to this Section, including, but not limited to, all

13 start-up and administrative costs and the costs for program

14 evaluation. All prudently incurred costs under this Section

15 shall be recovered from the residential and small commercial

16 retail customer classes eligible to participate in the program

17 through the automatic adjustment clause tariff established

18 pursuant to Section 8-103 of this Act.

19 (g) An independent evaluation of a program shall be

20 conducted after 3 years of the program's operation. The

21 electric utility shall retain an independent evaluator who

22 shall evaluate the effects of the measures installed under the

23 program and the overall operation of the program, including,

24 but not limited to, customer eligibility criteria and whether

25 the payment obligation for permanent electric energy

26 efficiency measures that will continue to provide benefits of

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1 energy savings should attach to the meter location. As part of

2 the evaluation process, the evaluator shall also solicit

3 feedback from participants and interested stakeholders. The

4 evaluator shall issue a report to the Commission on its

5 findings no later than 4 years after the date on which the

6 program commenced, and the Commission shall issue a report to

7 the Governor and General Assembly including a summary of the

8 information described in this Section as well as its

9 recommendations as to whether the program should be

10 discontinued, continued with modification or modifications or

11 continued without modification, provided that any recommended

12 modifications shall only apply prospectively and to measures

13 not yet installed or financed. The Commission's report shall

14 discuss changes to the program that were not considered in the

15 independent evaluation, if any.

16 (h) An electric utility offering a Commission-approved

17 program pursuant to this Section shall not be required to

18 comply with any other statute, order, rule, or regulation of

19 this State that may relate to the offering of such program,

20 provided that nothing in this Section is intended to limit the

21 electric utility's obligation to comply with this Act and the

22 Commission's orders, rules, and regulations, including Part

23 280 of Title 83 of the Illinois Administrative Code.

24 (i) The source of a utility customer's electric supply

25 shall not disqualify a customer from participation in the

26 utility's on-bill financing program. Customers of alternative

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1 retail electric suppliers may participate in the program under

2 the same terms and conditions applicable to the utility's

3 supply customers.

4 (Source: P.A. 97-616, eff. 10-26-11; 98-586, eff. 8-27-13.)

5 (220 ILCS 5/16-115D)

6 Sec. 16-115D. Renewable portfolio standard for alternative

7 retail electric suppliers and electric utilities operating

8 outside their service territories.

9 (a) In conjunction with energy deliveries under contracts

10 with customers for the period through May 31, 2016, an ~~An~~

11 alternative retail electric supplier shall be responsible for

12 procuring cost-effective renewable energy resources as

13 required under item (5) of subsection (d) of Section 16-115 of

14 this Act as outlined herein:

15 (1) The definition of renewable energy resources

16 contained in Section 1-10 of the Illinois Power Agency Act

17 applies to all renewable energy resources required to be

18 procured by alternative retail electric suppliers.

19 (2) The quantity of renewable energy resources shall be

20 measured as a percentage of the actual amount of metered

21 electricity (megawatt-hours) delivered by the alternative

22 retail electric supplier to Illinois retail customers

23 during the 12-month period June 1 through May 31,

24 commencing June 1, 2009, and the comparable 12-month period

25 in each year thereafter except as provided in item (6) of

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1 this subsection (a).

2 (3) The quantity of renewable energy resources shall be

3 in amounts at least equal to the annual percentages set

4 forth in item (1) of subsection (c) of Section 1-75 of the

5 Illinois Power Agency Act. At least 60% of the renewable

6 energy resources procured pursuant to items (1) through (3)

7 of subsection (b) of this Section shall come from wind

8 generation and, starting June 1, 2015, at least 6% of the

9 renewable energy resources procured pursuant to items (1)

10 through (3) of subsection (b) of this Section shall come

11 from solar photovoltaics. If, in any given year, an

12 alternative retail electric supplier does not purchase at

13 least these levels of renewable energy resources, then the

14 alternative retail electric supplier shall make

15 alternative compliance payments, as described in

16 subsection (d) of this Section.

17 (4) The quantity and source of renewable energy

18 resources shall be independently verified through the PJM

19 Environmental Information System Generation Attribute

20 Tracking System (PJM-GATS) or the Midwest Renewable Energy

21 Tracking System (M-RETS), which shall document the

22 location of generation, resource type, month, and year of

23 generation for all qualifying renewable energy resources

24 that an alternative retail electric supplier uses to comply

25 with this Section. No later than June 1, 2009, the Illinois

26 Power Agency shall provide PJM-GATS, M-RETS, and

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1 alternative retail electric suppliers with all information

2 necessary to identify resources located in Illinois,

3 within states that adjoin Illinois or within portions of

4 the PJM and MISO footprint in the United States that

5 qualify under the definition of renewable energy resources

6 in Section 1-10 of the Illinois Power Agency Act for

7 compliance with this Section 16-115D. Alternative retail

8 electric suppliers shall not be subject to the requirements

9 in item (3) of subsection (c) of Section 1-75 of the

10 Illinois Power Agency Act.

11 (5) All renewable energy credits used to comply with

12 this Section shall be permanently retired.

13 (6) The required procurement of renewable energy

14 resources by an alternative retail electric supplier shall

15 apply to all metered electricity delivered to Illinois

16 retail customers by the alternative retail electric

17 supplier pursuant to contracts executed or extended after

18 March 15, 2009.

19 (b) For deliveries to customers through May 31, 2016, an ~~An~~

20 alternative retail electric supplier shall comply with the

21 renewable energy portfolio standards by making an alternative

22 compliance payment, as described in subsection (d) of this

23 Section, to cover at least one-half of the alternative retail

24 electric supplier's compliance obligation and any one or

25 combination of the following means to cover the remainder of

26 the alternative retail electric supplier's compliance

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1 obligation:

2 (1) Generating electricity using renewable energy

3 resources identified pursuant to item (4) of subsection (a)

4 of this Section.

5 (2) Purchasing electricity generated using renewable

6 energy resources identified pursuant to item (4) of

7 subsection (a) of this Section through an energy contract.

8 (3) Purchasing renewable energy credits from renewable

9 energy resources identified pursuant to item (4) of

10 subsection (a) of this Section.

11 (4) Making an alternative compliance payment as

12 described in subsection (d) of this Section.

13 (c) Use of renewable energy credits.

14 (1) Renewable energy credits that are not used by an

15 alternative retail electric supplier to comply with a

16 renewable portfolio standard in a compliance year may be

17 banked and carried forward up to 2 12-month compliance

18 periods after the compliance period in which the credit was

19 generated for the purpose of complying with a renewable

20 portfolio standard in those 2 subsequent compliance

21 periods. For the 2009-2010 and 2010-2011 compliance

22 periods, an alternative retail electric supplier may use

23 renewable credits generated after December 31, 2008 and

24 before June 1, 2009 to comply with this Section.

25 (2) An alternative retail electric supplier is

26 responsible for demonstrating that a renewable energy

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1 credit used to comply with a renewable portfolio standard

2 is derived from a renewable energy resource and that the

3 alternative retail electric supplier has not used, traded,

4 sold, or otherwise transferred the credit.

5 (3) The same renewable energy credit may be used by an

6 alternative retail electric supplier to comply with a

7 federal renewable portfolio standard and a renewable

8 portfolio standard established under this Act. An

9 alternative retail electric supplier that uses a renewable

10 energy credit to comply with a renewable portfolio standard

11 imposed by any other state may not use the same credit to

12 comply with a renewable portfolio standard established

13 under this Act.

14 (d) Alternative compliance payments.

15 (1) The Commission shall establish and post on its

16 website, within 5 business days after entering an order

17 approving a procurement plan pursuant to Section 1-75 of

18 the Illinois Power Agency Act, maximum alternative

19 compliance payment rates, expressed on a per kilowatt-hour

20 basis, that will be applicable in the first compliance

21 period following the plan approval. A separate maximum

22 alternative compliance payment rate shall be established

23 for the service territory of each electric utility that is

24 subject to subsection (c) of Section 1-75 of the Illinois

25 Power Agency Act. Each maximum alternative compliance

26 payment rate shall be equal to the maximum allowable annual

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1 estimated average net increase due to the costs of the

2 utility's purchase of renewable energy resources included

3 in the amounts paid by eligible retail customers in

4 connection with electric service, as described in item (2)

5 of subsection (c) of Section 1-75 of the Illinois Power

6 Agency Act for the compliance period, and as established in

7 the approved procurement plan. Following each procurement

8 event through which renewable energy resources are

9 purchased for one or more of these utilities for the

10 compliance period, the Commission shall establish and post

11 on its website estimates of the alternative compliance

12 payment rates, expressed on a per kilowatt-hour basis, that

13 shall apply for that compliance period. Posting of the

14 estimates shall occur no later than 10 business days

15 following the procurement event, however, the Commission

16 shall not be required to establish and post such estimates

17 more often than once per calendar month. By July 1 of each

18 year, the Commission shall establish and post on its

19 website the actual alternative compliance payment rates

20 for the preceding compliance year. For compliance years

21 beginning prior to June 1, 2014, each alternative

22 compliance payment rate shall be equal to the total amount

23 of dollars that the utility contracted to spend on

24 renewable resources, excepting the additional incremental

25 cost attributable to solar resources, for the compliance

26 period divided by the forecasted load of eligible retail

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1 customers, at the customers' meters, as previously

2 established in the Commission-approved procurement plan

3 for that compliance year. For compliance years commencing

4 on or after June 1, 2014, each alternative compliance

5 payment rate shall be equal to the total amount of dollars

6 that the utility contracted to spend on all renewable

7 resources for the compliance period divided by the

8 forecasted load of eligible retail customers, at the

9 customers' meters, as previously established in the

10 Commission-approved procurement plan for that compliance

11 year. The actual alternative compliance payment rates may

12 not exceed the maximum alternative compliance payment

13 rates established for the compliance period. For purposes

14 of this subsection (d), the term "eligible retail

15 customers" has the same meaning as found in Section

16 16-111.5 of this Act.

17 (2) In any given compliance year, an alternative retail

18 electric supplier may elect to use alternative compliance

19 payments to comply with all or a part of the applicable

20 renewable portfolio standard. In the event that an

21 alternative retail electric supplier elects to make

22 alternative compliance payments to comply with all or a

23 part of the applicable renewable portfolio standard, such

24 payments shall be made by September 1, 2010 for the period

25 of June 1, 2009 to May 1, 2010 and by September 1 of each

26 year thereafter for the subsequent compliance period, in

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1 the manner and form as determined by the Commission. Any

2 election by an alternative retail electric supplier to use

3 alternative compliance payments is subject to review by the

4 Commission under subsection (e) of this Section.

5 (3) An alternative retail electric supplier's

6 alternative compliance payments shall be computed

7 separately for each electric utility's service territory

8 within which the alternative retail electric supplier

9 provided retail service during the compliance period,

10 provided that the electric utility was subject to

11 subsection (c) of Section 1-75 of the Illinois Power Agency

12 Act. For each service territory, the alternative retail

13 electric supplier's alternative compliance payment shall

14 be equal to (i) the actual alternative compliance payment

15 rate established in item (1) of this subsection (d),

16 multiplied by (ii) the actual amount of metered electricity

17 delivered by the alternative retail electric supplier to

18 retail customers within the service territory during the

19 compliance period, multiplied by (iii) the result of one

20 minus the ratios of the quantity of renewable energy

21 resources used by the alternative retail electric supplier

22 to comply with the requirements of this Section within the

23 service territory to the product of the percentage of

24 renewable energy resources required under item (3) of

25 subsection (a) of this Section and the actual amount of

26 metered electricity delivered by the alternative retail

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1 electric supplier to retail customers within the service

2 territory during the compliance period.

3 (4) All alternative compliance payments by alternative

4 retail electric suppliers shall be deposited in the

5 Illinois Power Agency Renewable Energy Resources Fund and

6 used to purchase renewable energy credits, in accordance

7 with Section 1-56 of the Illinois Power Agency Act.

8 Beginning April 1, 2012 and by April 1 of each year

9 thereafter, the Illinois Power Agency shall submit an

10 annual report to the General Assembly, the Commission, and

11 alternative retail electric suppliers that shall include,

12 but not be limited to:

13 (A) the total amount of alternative compliance

14 payments received in aggregate from alternative retail

15 electric suppliers by planning year for all previous

16 planning years in which the alternative compliance

17 payment was in effect;

18 (B) the amount of those payments utilized to

19 purchased renewable energy credits itemized by the

20 date of each procurement in which the payments were

21 utilized; and

22 (C) the unused and remaining balance in the Agency

23 Renewable Energy Resources Fund attributable to those

24 payments.

25 (5) The Commission, in consultation with the Illinois

26 Power Agency, shall establish a process or proceeding to

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1 consider the impact of a federal renewable portfolio

2 standard, if enacted, on the operation of the alternative

3 compliance mechanism, which shall include, but not be

4 limited to, developing, to the extent permitted by the

5 applicable federal statute, an appropriate methodology to

6 apportion renewable energy credits retired as a result of

7 alternative compliance payments made in accordance with

8 this Section. The Commission shall commence any such

9 process or proceeding within 35 days after enactment of a

10 federal renewable portfolio standard.

11 (e) Each alternative retail electric supplier shall, by

12 September 1, 2010 and by September 1 of each year thereafter,

13 prepare and submit to the Commission a report, in a format to

14 be specified by the Commission on or before December 31, 2009,

15 that provides information certifying compliance by the

16 alternative retail electric supplier with this Section,

17 including copies of all PJM-GATS and M-RETS reports, and

18 documentation relating to banking, retiring renewable energy

19 credits, and any other information that the Commission

20 determines necessary to ensure compliance with this Section. An

21 alternative retail electric supplier may file commercially or

22 financially sensitive information or trade secrets with the

23 Commission as provided under the rules of the Commission. To be

24 filed confidentially, the information shall be accompanied by

25 an affidavit that sets forth both the reasons for the

26 confidentiality and a public synopsis of the information.

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1 (f) The Commission may initiate a contested case to review

2 allegations that the alternative retail electric supplier has

3 violated this Section, including an order issued or rule

4 promulgated under this Section. In any such proceeding, the

5 alternative retail electric supplier shall have the burden of

6 proof. If the Commission finds, after notice and hearing, that

7 an alternative retail electric supplier has violated this

8 Section, then the Commission shall issue an order requiring the

9 alternative retail electric supplier to:

10 (1) immediately comply with this Section; and

11 (2) if the violation involves a failure to procure the

12 requisite quantity of renewable energy resources or pay the

13 applicable alternative compliance payment by the annual

14 deadline, the Commission shall require the alternative

15 retail electric supplier to double the applicable

16 alternative compliance payment that would otherwise be

17 required to bring the alternative retail electric supplier

18 into compliance with this Section.

19 If an alternative retail electric supplier fails to comply

20 with the renewable energy resource portfolio requirement in

21 this Section more than once in a 5-year period, then the

22 Commission shall revoke the alternative electric supplier's

23 certificate of service authority. The Commission shall not

24 accept an application for a certificate of service authority

25 from an alternative retail electric supplier that has lost

26 certification under this subsection (f), or any corporate

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1 affiliate thereof, for at least one year after the date of

2 revocation.

3 (g) All of the provisions of this Section apply to electric

4 utilities operating outside their service area except under

5 item (2) of subsection (a) of this Section the quantity of

6 renewable energy resources shall be measured as a percentage of

7 the actual amount of electricity (megawatt-hours) supplied in

8 the State outside of the utility's service territory during the

9 12-month period June 1 through May 31, commencing June 1, 2009,

10 and the comparable 12-month period in each year thereafter

11 except as provided in item (6) of subsection (a) of this

12 Section.

13 If any such utility fails to procure the requisite quantity

14 of renewable energy resources by the annual deadline, then the

15 Commission shall require the utility to double the alternative

16 compliance payment that would otherwise be required to bring

17 the utility into compliance with this Section.

18 If any such utility fails to comply with the renewable

19 energy resource portfolio requirement in this Section more than

20 once in a 5-year period, then the Commission shall order the

21 utility to cease all sales outside of the utility's service

22 territory for a period of at least one year.

23 (h) The provisions of this Section and the provisions of

24 subsection (d) of Section 16-115 of this Act relating to

25 procurement of renewable energy resources shall not apply to an

26 alternative retail electric supplier that operates a combined

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1 heat and power system in this State or that has a corporate

2 affiliate that operates such a combined heat and power system

3 in this State that supplies electricity primarily to or for the

4 benefit of: (i) facilities owned by the supplier, its

5 subsidiary, or other corporate affiliate; (ii) facilities

6 electrically integrated with the electrical system of

7 facilities owned by the supplier, its subsidiary, or other

8 corporate affiliate; or (iii) facilities that are adjacent to

9 the site on which the combined heat and power system is

10 located.

11 (i) The obligations specified in this Section of

12 alternative retail electric suppliers and electric utilities

13 operating outside their service territories to procure

14 renewable energy resources, make alternative compliance

15 payments, and file annual reports, and the obligations of the

16 Commission to determine and post alternative compliance

17 payment rates, shall terminate effective with the filing of

18 reports and full payments made by alternative retail electric

19 suppliers for energy deliveries to customers for the period

20 ending May 31, 2016, provided that alternative retail electric

21 suppliers and electric utilities operating outside their

22 service territories shall be obligated to make all alternative

23 compliance payments that they were obligated to pay for periods

24 through and including May 31, 2016 but were not paid as of that

25 date and to file all required reports for periods prior to June

26 1, 2016. The Commission shall continue to enforce the payment

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1 of unpaid alternative compliance payments after May 31, 2016 in

2 accordance with subsections (f) and (g) of this Section. All

3 alternative compliance payments made after May 31, 2016 shall

4 be deposited in the Illinois Power Agency Renewable Energy

5 Resources Fund and used to purchase renewable energy credits in

6 accordance with Section 1-56 of the Illinois Power Agency Act.

7 (Source: P.A. 96-33, eff. 7-10-09; 96-159, eff. 8-10-09;

8 96-1437, eff. 8-17-10; 97-658, eff. 1-13-12.)

9 (220 ILCS 5/19-140)

10 Sec. 19-140. On-bill financing program; gas utilities.

11 (a) The Illinois General Assembly finds that Illinois homes

12 and businesses have the potential to save energy through

13 conservation and cost-effective energy efficiency measures.

14 Programs created pursuant to this Section will allow utility

15 customers to purchase cost-effective energy efficiency

16 measures, including measures set forth in a

17 Commission-approved energy efficiency plan under Section 8-104

18 of this Act, with no required initial upfront payment, and to

19 pay the cost of those products and services over time on their

20 utility bill.

21 (a-5) As used in this Section:

22 "Eligible gas energy efficiency measure" or "measure"

23 means a product or service for which one or more of the

24 following is true:

25 (1) a building energy assessment, performed by an

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1 energy auditor who is certified by the Building Performance

2 Institute or who holds a similar certification, has

3 recommended the product or service as likely to be

4 cost-effective over the course of its installed life for

5 the building in which the measure is to be installed;

6 (2) the projected gas savings (determined by rates in

7 effect at the time of purchase) are sufficient to cover the

8 costs of implementing the measures, including finance

9 charges and any program fees not recovered pursuant to

10 subsection (f) of this Section;

11 (3) the product or service is included in a

12 Commission-approved energy efficiency and demand-response

13 plan under Section 8-104 of this Act and is cost-effective

14 as that term is defined by that Section; or

15 (4) the product or service is necessary to safely or

16 correctly install to code or industry standard an

17 efficiency measure, including, but not limited to

18 installation work, changes needed to plumbing or

19 electrical connections, upgrades to wiring or fixtures,

20 removal of hazardous materials, correction of leaks,

21 changes to thermostats, controls, or similar devices, and

22 changes to venting or exhaust necessitated by the measure.

23 "Small commercial customer" for a gas utility shall be

24 defined in that gas utility's filing that is made under

25 subsection (c-5) of this Section.

26 (b) Notwithstanding any other provision of this Act, a gas

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1 utility serving more than 100,000 customers on January 1, 2009

2 shall offer a Commission-approved on-bill financing program

3 ("program") that allows its retail customers who own a

4 residential single family home, duplex, or other residential

5 building with 4 or less units, or condominium at which the gas

6 service is being provided (i) to borrow funds from a third

7 party lender in order to purchase gas energy efficiency

8 measures approved under the program for installation in such

9 home or condominium without any required upfront payment and

10 (ii) to pay back such funds over time through the gas utility's

11 bill. Based upon the process described in subsection (b-5) of

12 this Section, small commercial customers who own the premises

13 at which gas service is being provided may be included in such

14 program. After receiving a request from a gas utility for

15 approval of a proposed program and tariffs pursuant to this

16 Section, the Commission shall render its decision within 120

17 days. If no decision is rendered within 120 days, then the

18 request shall be deemed to be approved. Beginning no later than

19 December 31, 2013, a gas utility subject to this subsection (b)

20 shall also offer its program to eligible retail customers that

21 own a multifamily residential or mixed-use building ~~with no~~

22 ~~more than 50 residential units~~, provided, however, that such

23 customer must either be a residential customer or small

24 commercial customer and may not use the program in such a way

25 that repayment of the cost of energy efficiency measures is

26 made through tenants' utility bills. ~~A gas utility may impose a~~

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1 ~~per site loan limit not to exceed $150,000.~~ The program, and

2 loans issued thereunder, shall only be offered to customers of

3 the utility that meet the requirements of this Section and that

4 also have a gas service account at the premises where the

5 energy efficiency measures being financed shall be installed.

6 Beginning no later than December 31, 2015, a gas utility

7 subject to this subsection (b) shall also offer its program to

8 eligible retail customers that are Unit Owners' Associations,

9 as defined in subsection (o) of Section 2 of the Condominium

10 Property Act, or Master Associations, as defined in subsection

11 (u) of Section 2 of the Condominium Property Act; however, such

12 customers must either be a residential customer or small

13 commercial customer and may not use the program in such a way

14 that repayment of the cost of energy efficiency measures is

15 made through unit owners' utility bills. The program and loans

16 issued under the program shall only be offered to customers of

17 the utility that meet the requirements of this Section and that

18 also have a gas service account at the premises where the

19 energy efficiency measures being financed shall be installed.

20 ~~For purposes of this Section, a small commercial customer~~

21 ~~for a gas utility shall be defined in that gas utility's~~

22 ~~informational filing that is made under subsection (c-5) of~~

23 ~~this Section.~~

24 (b-5) Within 30 days after the effective date of this

25 amendatory Act of the 96th General Assembly, the Commission

26 shall convene a workshop process during which interested

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1 participants may discuss issues related to the program,

2 including program design, eligible gas energy efficiency

3 measures, vendor qualifications, and a methodology for

4 ensuring ongoing compliance with such qualifications,

5 financing, sample documents such as request for proposals,

6 contracts and agreements, dispute resolution, pre-installment

7 and post-installment verification, and evaluation. The

8 workshop process shall be completed within 150 days after the

9 effective date of this amendatory Act of the 96th General

10 Assembly.

11 (c) Not later than 60 days following completion of the

12 workshop process described in subsection (b-5) of this Section,

13 each gas utility subject to subsection (b) of this Section

14 shall submit a proposed program to the Commission that contains

15 the following components:

16 (1) A description of how the program will determine if

17 measures to be financed are eligible electric energy

18 efficiency measures, as defined in subsection (a-5) of this

19 Section. ~~A list of recommended gas energy efficiency~~

20 ~~measures that will be eligible for on-bill financing. An~~

21 ~~eligible gas energy efficiency measure ("measure") shall~~

22 ~~be a product or service for which one or more of the~~

23 ~~following is true:~~

24 ~~(A) (blank);~~

25 ~~(B) the projected gas savings (determined by rates~~

26 ~~in effect at the time of purchase) are sufficient to~~

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1 ~~cover the costs of implementing the measures,~~

2 ~~including finance charges and any program fees not~~

3 ~~recovered pursuant to subsection (f) of this Section;~~

4 ~~or~~

5 ~~(C) the product or service is included in a~~

6 ~~Commission-approved energy efficiency plan under~~

7 ~~Section 8-104 of this Act.~~

8 (2) The gas utility shall issue a request for proposals

9 ("RFP") to lenders for purposes of providing financing to

10 participants to pay for approved measures. The RFP criteria

11 shall include, but not be limited to, the interest rate,

12 origination fees, and credit terms. The utility shall

13 select the winning bidders based on its evaluation of these

14 criteria, with a preference for those bids containing the

15 rates, fees, and terms most favorable to participants.

16 (3) The utility shall work with the lenders selected

17 pursuant to the RFP process, and with vendors, to establish

18 the terms and processes pursuant to which a participant can

19 purchase eligible gas energy efficiency measures using the

20 financing obtained from the lender. The vendor shall

21 explain and offer the approved financing packaging to those

22 customers identified in subsection (b) of this Section and

23 shall assist customers in applying for financing. As part

24 of such process, vendors shall also provide to participants

25 information about any other incentives that may be

26 available for the measures.

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1 (4) The lender shall conduct credit checks or undertake

2 other appropriate measures to limit credit risk, and shall

3 review and approve or deny financing applications

4 submitted by customers identified in subsection (b) of this

5 Section. If a customer is not approved for financing as a

6 result of a credit check, the lender shall determine

7 whether to approve or deny financing by considering the

8 customer's utility bill repayment history and the bill

9 reductions likely from the energy efficiency measures to be

10 financed and other appropriate measures. Following the

11 lender's approval of financing and the participant's

12 purchase of the measure or measures, the lender shall

13 forward payment information to the gas utility, and the

14 utility shall add as a separate line item on the

15 participant's utility bill a charge showing the amount due

16 under the program each month.

17 (5) A loan issued to a participant pursuant to the

18 program shall be the sole responsibility of the

19 participant, and any dispute that may arise concerning the

20 loan's terms, conditions, or charges shall be resolved

21 between the participant and lender. Upon transfer of the

22 property title for the premises at which the participant

23 receives gas service from the utility or the participant's

24 request to terminate service at such premises, the

25 participant shall pay in full its gas utility bill,

26 including all amounts due under the program, provided that

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1 this obligation may be modified as provided in subsection

2 (g) of this Section. Amounts due under the program shall be

3 deemed amounts owed for residential and, as appropriate,

4 small commercial gas service.

5 (6) The gas utility shall remit payment in full to the

6 lender each month on behalf of the participant. In the

7 event a participant defaults on payment of its gas utility

8 bill, the gas utility shall continue to remit all payments

9 due under the program to the lender, up to the larger of

10 $10,000,000 or 50% of the total allowable outstanding

11 amount financed under paragraph (7) of this subsection (c),

12 and the utility shall be entitled to recover all costs

13 related to a participant's nonpayment, up to the larger of

14 $10,000,000 or 50% of the total allowable outstanding

15 amount financed under paragraph (7) of this subsection (c),

16 through the automatic adjustment clause tariff established

17 pursuant to Section 19-145 of this Act. In addition, the

18 gas utility shall retain a security interest in the measure

19 or measures purchased under the program, and the utility

20 retains its right to disconnect a participant that defaults

21 on the payment of its utility bill.

22 (7) The total outstanding amount financed under the

23 program in this subsection and subsection (c-5) of this

24 Section shall not exceed $20,000,000 ~~$2.5 million~~ for a gas

25 utility or gas utilities under a single holding company,

26 provided that the gas utility or gas utilities may petition

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1 the Commission for an increase in such amount.

2 (c-5) Within 120 days after the effective date of this

3 amendatory Act of the 98th General Assembly, each covered gas

4 utility shall submit an informational filing to the Commission

5 that describes its plan for implementing the provisions of this

6 amendatory Act of the 98th General Assembly on or before

7 December 31, 2013. A gas utility subject to this Section shall

8 cooperate with any electric utility that provides electric

9 service to buildings within the gas utility's service territory

10 so that it is practical and feasible for the owner of a

11 multifamily building to make a single application to access

12 loans for both gas and electric energy efficiency measures in

13 any individual building.

14 Within 60 days after the effective date of this amendatory

15 Act of the 99th General Assembly, each electric utility subject

16 to the requirements of this Section shall submit a filing to

17 the Commission that describes its plan for implementing the

18 provisions of this amendatory Act of the 99th General Assembly

19 on or before December 31, 2015. The Commission shall seek

20 public comment on the utility's plan and shall issue an order

21 approving or disapproving each plan within 120 days of its

22 submission. If the Commission disapproves a plan, the

23 Commission shall, within 30 days, describe in detail the

24 reasons for the disapproval and describe a path by which the

25 utility may file a revised draft of the plan to address the

26 Commission's concerns satisfactorily.

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1 (d) A program approved by the Commission shall also include

2 the following criteria and guidelines for such program:

3 (1) guidelines for financing of measures installed

4 under a program, including, but not limited to, RFP

5 criteria and limits on both individual loan amounts and the

6 duration of the loans;

7 (2) criteria and standards for identifying and

8 approving measures;

9 (3) qualifications of vendors that will market or

10 install measures, as well as a methodology for ensuring

11 ongoing compliance with such qualifications;

12 (4) sample contracts and agreements necessary to

13 implement the measures and program; and

14 (5) the types of data and information that utilities

15 and vendors participating in the program shall collect for

16 purposes of preparing the reports required under

17 subsection (g) of this Section.

18 (e) The proposed program submitted by each gas utility

19 shall be consistent with the provisions of this Section that

20 define operational, financial, and billing arrangements

21 between and among program participants, vendors, lenders, and

22 the gas utility.

23 (f) A gas utility shall recover all of the prudently

24 incurred costs of offering a program approved by the Commission

25 pursuant to this Section, including, but not limited to, all

26 start-up and administrative costs and the costs for program

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1 evaluation. All prudently incurred costs under this Section

2 shall be recovered from the residential and small commercial

3 retail customer classes eligible to participate in the program

4 through the automatic adjustment clause tariff established

5 pursuant to Section 8-104 of this Act.

6 (g) An independent evaluation of a program shall be

7 conducted after 3 years of the program's operation. The gas

8 utility shall retain an independent evaluator who shall

9 evaluate the effects of the measures installed under the

10 program and the overall operation of the program, including,

11 but not limited to, customer eligibility criteria and whether

12 the payment obligation for permanent gas energy efficiency

13 measures that will continue to provide benefits of energy

14 savings should attach to the meter location. As part of the

15 evaluation process, the evaluator shall also solicit feedback

16 from participants and interested stakeholders. The evaluator

17 shall issue a report to the Commission on its findings no later

18 than 4 years after the date on which the program commenced, and

19 the Commission shall issue a report to the Governor and General

20 Assembly including a summary of the information described in

21 this Section as well as its recommendations as to whether the

22 program should be discontinued, continued with modification or

23 modifications or continued without modification, provided that

24 any recommended modifications shall only apply prospectively

25 and to measures not yet installed or financed. The Commission's

26 report shall discuss changes to the program that were not

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1 considered in the independent evaluation, if any.

2 (h) A gas utility offering a Commission-approved program

3 pursuant to this Section shall not be required to comply with

4 any other statute, order, rule, or regulation of this State

5 that may relate to the offering of such program, provided that

6 nothing in this Section is intended to limit the gas utility's

7 obligation to comply with this Act and the Commission's orders,

8 rules, and regulations, including Part 280 of Title 83 of the

9 Illinois Administrative Code.

10 (i) The source of a utility customer's gas supply shall not

11 disqualify a customer from participation in the utility's

12 on-bill financing program. Customers of alternative gas

13 suppliers may participate in the program under the same terms

14 and conditions applicable to the utility's supply customers.

15 (Source: P.A. 98-586, eff. 8-27-13.)

16 Section 15. The Environmental Protection Act is amended by

17 changing Section 9.1 as follows:

18 (415 ILCS 5/9.1) (from Ch. 111 1/2, par. 1009.1)

19 Sec. 9.1. (a) The General Assembly finds that the federal

20 Clean Air Act, as amended, and regulations adopted pursuant

21 thereto establish complex and detailed provisions for

22 State-federal cooperation in the field of air pollution

23 control, provide for a Prevention of Significant Deterioration

24 program to regulate the issuance of preconstruction permits to

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1 insure that economic growth will occur in a manner consistent

2 with the preservation of existing clean air resources, and also

3 provide for plan requirements for nonattainment areas to

4 regulate the construction, modification and operation of

5 sources of air pollution to insure that economic growth will

6 occur in a manner consistent with the goal of achieving the

7 national ambient air quality standards, and that the General

8 Assembly cannot conveniently or advantageously set forth in

9 this Act all the requirements of such federal Act or all

10 regulations which may be established thereunder.

11 It is the purpose of this Section to avoid the existence of

12 duplicative, overlapping or conflicting State and federal

13 regulatory systems.

14 (b) The provisions of Section 111 of the federal Clean Air

15 Act (42 USC 7411), as amended, relating to standards of

16 performance for new stationary sources, and Section 112 of the

17 federal Clean Air Act (42 USC 7412), as amended, relating to

18 the establishment of national emission standards for hazardous

19 air pollutants are applicable in this State and are enforceable

20 under this Act. Any such enforcement shall be stayed consistent

21 with any stay granted in any federal judicial action to review

22 such standards. Enforcement shall be consistent with the

23 results of any such judicial review.

24 (b-5) (1) Upon the promulgation by the U.S. Environmental

25 Protection Agency (USEPA) of a final rule regulating carbon

26 dioxide emissions from existing electric generating units

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1 under 42 U.S.C. 7411(d) that allows for mass-based compliance

2 and maintains state flexibility to achieve compliance using

3 market-based tools (USEPA Rule), the Illinois Environmental

4 Protection Agency shall develop a state implementation plan

5 (Plan) to comply with the requirements of the USEPA rule by

6 creating a market-based system to reduce carbon dioxide and

7 create a revenue stream to be used by the State of Illinois

8 consistent with paragraphs (2) through (4) of this subsection

9 (b-5).

10 (2) The Illinois Environmental Protection Agency (Agency)

11 is authorized to create and implement a cap and invest program

12 or similar market mechanism (Program) to comply with the USEPA

13 rule, after undertaking a robust and open stakeholder process

14 and a comprehensive analysis and modeling of the impact of such

15 a program on Illinois' energy system, ratepayers, and

16 communities.

17 (A) The Illinois Environmental Protection Agency shall

18 adopt rules to implement the Program consistent with this

19 Act.

20 (B) A comprehensive market-based program shall, at a

21 minimum, achieve the carbon emissions reductions required

22 to meet Illinois' mass-based goal under its Plan and create

23 a mechanism to achieve additional emissions reductions

24 from the power sector when implemented in conjunction with

25 other State policies, including Illinois' Renewable Energy

26 Standard and Energy Efficiency Resource Standard.

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1 (C) The Illinois Environmental Protection Agency is

2 authorized to evaluate, establish, implement, and manage

3 an annual cap on CO2 emissions and administer an auction

4 program to sell power sector CO2 allowances in a

5 market-based program consistent with this Act and the USEPA

6 rule. The Program shall include a minimum emissions

7 allowance price calibrated to ensure compliance with the

8 State's obligations under the USEPA rule.

9 (D) The Agency shall make every effort to participate

10 in a regional program and regional allowance auctions with

11 other states if it results in greater carbon dioxide

12 emission reductions at a lower cost for Illinois' residents

13 over time. The Agency may conduct Illinois-only auctions if

14 such auctions are found to be in the best interests of

15 Illinois ratepayers, as determined by the Agency, and after

16 consultation with the Illinois Commerce Commission, taking

17 into account the impact on the State's goals under the

18 USEPA rule, State residents' health, and ratepayers.

19 Participation in a regional program does not relieve the

20 Agency of its obligations to comply with the provisions of

21 this Act.

22 (E) The Agency shall perform an environmental justice

23 analysis of its Plan to ensure compliance with the USEPA

24 rule and Federal Executive Order No. 12898, including a

25 cumulative impacts assessment as part of its environmental

26 impact assessment of the Program, following existing USEPA

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1 methodologies.

2 (F) The Agency shall develop, in coordination with the

3 Illinois Environmental Justice Commission, through an open

4 and inclusive stakeholder process, a list of Environmental

5 Justice Communities, defined as distinct geographic areas

6 of low-income and minority communities that are

7 disproportionately impacted by power plant pollution and

8 co-pollutant emissions.

9 (G) Any Program shall address and mitigate the

10 displacement of Illinois carbon dioxide emissions to other

11 states as well as establish appropriate spatial

12 restrictions on allowance trading to avoid the creation of

13 co-pollutant hotspots or areas with high concentrations of

14 co-pollutants, defined in terms of cumulative impacts.

15 (H) After a Program is in place, the Agency shall

16 require existing electric generating units located in

17 low-income and minority communities to install and

18 maintain monitors that provide detailed information on

19 co-pollutant emissions tied to the purchase of allowances

20 under the program. Information on these trading

21 transactions and reports on emission levels shall be

22 available to the public.

23 (I) The authority in this subsection (b-5) is

24 restricted to verifiable carbon dioxide emissions

25 allowances and credits within the power sector and does not

26 permit inclusion of carbon emissions allowances, credits,

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1 or offsets from other sectors of the economy.

2 (3) The Illinois Environmental Protection Agency is

3 authorized to invest the auction proceeds under this Act in

4 strategies to meet the State's goal under the USEPA rule,

5 create jobs in the State's renewable energy and energy

6 efficiency industries (as defined in the Illinois Power Agency

7 Act), enable workers' transition to renewable energy jobs, and

8 mitigate adverse health and economic impacts of fossil

9 fuel-fired power plants on minority and low-income

10 communities, in a manner consistent with this Act.

11 (A) A minimum of 65% of the revenue the Agency receives

12 from the Program (Revenue) shall be directed to the

13 Illinois Power Agency to spend on new energy efficiency and

14 renewable energy investments anywhere in the State. At

15 least 20% of this portion must be invested to support

16 energy efficiency and renewable energy investments in

17 low-income communities and low-income households, where

18 preference shall be given to investments in communities

19 designated as Environmental Justice Communities, followed

20 by investments in communities where power plants are or

21 have been located. A portion of these funds shall support

22 energy efficiency and renewable energy projects designed

23 to assist public institutions, including, but not limited

24 to, hospitals, health care facilities, long-term care

25 facilities, schools, preschools, daycare facilities, and

26 wastewater and drinking water treatment plant operators,

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1 with reducing their operating costs.

2 (B) A minimum of 5% of the Revenue shall be directed to

3 the Low Income Home Energy Assistance Program for bill

4 assistance.

5 (C) A minimum of 5% of the Revenue shall be directed to

6 assist workers in the fossil fuel-fired power plant

7 industry to transition to renewable energy and energy

8 efficiency jobs.

9 (D) A minimum of 10% of the Revenue shall be directed

10 to communities in which power plants are or have been

11 located to mitigate the adverse health and economic impacts

12 of power plants on those communities. Priority shall be

13 given to areas that are designated non-attainment for any

14 criteria pollutant under the Clean Air Act.

15 (E) A maximum of 5% of the Revenue shall be reserved

16 for program administration, pollutant and co-pollutant

17 monitoring as required under item (H) of paragraph (2) of

18 this subsection (b-5), to invest in innovative strategies

19 to reduce carbon emissions in the power sector, mitigate

20 the impacts of climate change, and to increase public

21 awareness of the impacts of climate change.

22 (4) In the development and operation of the Program, the

23 Illinois Environmental Protection Agency is prohibited from

24 doing the following:

25 (A) Implementing any program that leads to the

26 degradation of air quality, or significantly hindering the

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1 attainment of other air quality standards under this Act.

2 (B) Allocating CO2 allowances to sources covered under

3 the Program for free.

4 (C) Approving of any CO2 credits for emission

5 reductions, allowances, or offsets from outside the scope

6 of the Program.

7 (c) The Board may adopt regulations establishing permit

8 programs meeting the requirements of Sections 165 and 173 of

9 the Clean Air Act (42 USC 7475 and 42 USC 7503) as amended. The

10 Agency may adopt procedures for the administration of such

11 programs.

12 (d) No person shall:

13 (1) violate any provisions of Sections 111, 112, 165 or

14 173 of the Clean Air Act, as now or hereafter amended, or

15 federal regulations adopted pursuant thereto; or

16 (2) construct, install, modify or operate any

17 equipment, building, facility, source or installation

18 which is subject to regulation under Sections 111, 112, 165

19 or 173 of the Clean Air Act, as now or hereafter amended,

20 except in compliance with the requirements of such Sections

21 and federal regulations adopted pursuant thereto, and no

22 such action shall be undertaken (A) without a permit

23 granted by the Agency whenever a permit is required

24 pursuant to (i) this Act or Board regulations or (ii)

25 Section 111, 112, 165, or 173 of the Clean Air Act or

26 federal regulations adopted pursuant thereto or (B) in

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1 violation of any conditions imposed by such permit. Any

2 denial of such a permit or any conditions imposed in such a

3 permit shall be reviewable by the Board in accordance with

4 Section 40 of this Act.

5 (e) The Board shall exempt from regulation under the State

6 Implementation Plan for ozone the volatile organic compounds

7 which have been determined by the U.S. Environmental Protection

8 Agency to be exempt from regulation under state implementation

9 plans for ozone due to negligible photochemical reactivity. In

10 accordance with subsection (b) of Section 7.2, the Board shall

11 adopt regulations identical in substance to the U.S.

12 Environmental Protection Agency exemptions or deletion of

13 exemptions published in policy statements on the control of

14 volatile organic compounds in the Federal Register by amending

15 the list of exemptions to the Board's definition of volatile

16 organic material found at 35 Ill. Adm. Code Part 211. The

17 provisions and requirements of Title VII of this Act shall not

18 apply to regulations adopted under this subsection. Section

19 5-35 of the Illinois Administrative Procedure Act, relating to

20 procedures for rulemaking, does not apply to regulations

21 adopted under this subsection. However, the Board shall provide

22 for notice, a hearing if required by the U.S. Environmental

23 Protection Agency, and public comment before adopted rules are

24 filed with the Secretary of State. The Board may consolidate

25 into a single rulemaking under this subsection all such federal

26 policy statements published in the Federal Register within a

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1 period of time not to exceed 6 months.

2 (f) (Blank).

3 (Source: P.A. 97-95, eff. 7-12-11; 98-284, eff. 8-9-13.)

4 Section 99. Effective date. This Act takes effect upon

5 becoming law.

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INDEX

Statutes amended in order of appearance