SB4016 104TH GENERAL ASSEMBLY

LRB104 19715 BDA 33165 b

104TH GENERAL ASSEMBLY
State of Illinois
2025 and 2026
SB4016

Introduced 2/6/2026, by Sen. Ram Villivalam

SYNOPSIS AS INTRODUCED:

See Index

Amends the Environmental Protection Act, Energy Efficient Building Act, Illinois Power Agency Act, Public Utilities Act, and related statutes to establish comprehensive environmental, water, and energy regulations for hyperscale data centers. In the Environmental Protection Act, requires cumulative impact assessments, public notice, and community benefits agreements for data centers; prohibits nondisclosure agreements; and creates the Data Center Community Intervenor Compensation Fund and Hyperscale Data Center Public Benefits and Affordability Fund funded by annual fees based on peak demand. Mandates water resource planning, quarterly water usage reporting, water scarcity plans, and Water Impact Permits with public hearings and renewal every 5 years. Requires compliance with stringent energy codes and annual energy and water reporting to the Illinois Commerce Commission. Expands renewable energy procurement programs, establishes a hyperscale data center self-direct program, and strengthens equity, transparency, and labor standards in clean energy initiatives. Creates the Residential Automated Solar Permitting Platform Act to require municipalities and counties to adopt a residential automated solar permitting platform on or before July 1, 2027, and authorizes persons to file a civil action against a municipality or county in violation.

A BILL FOR

AN ACT concerning safety.

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

Article 1.

Section 1-5. The Environmental Protection Act is amended by changing Sections 39 and 39.5 and by adding Title XIX as follows:

(415 ILCS 5/39) (from Ch. 111 1/2, par. 1039)

(Text of Section before amendment by P.A. 104-458)

Sec. 39. Issuance of permits; procedures.

(a) When the Board has by regulation required a permit for the construction, installation, or operation of any type of facility, equipment, vehicle, vessel, or aircraft, the applicant shall apply to the Agency for such permit and it shall be the duty of the Agency to issue such a permit upon proof by the applicant that the facility, equipment, vehicle, vessel, or aircraft will not cause a violation of this Act or of regulations hereunder. The Agency shall adopt such procedures as are necessary to carry out its duties under this Section. In making its determinations on permit applications under this Section the Agency may consider prior adjudications of noncompliance with this Act by the applicant that involved a release of a contaminant into the environment. In granting permits, the Agency may impose reasonable conditions specifically related to the applicant's past compliance history with this Act as necessary to correct, detect, or prevent noncompliance. The Agency may impose such other conditions as may be necessary to accomplish the purposes of this Act, and as are not inconsistent with the regulations promulgated by the Board hereunder. Except as otherwise provided in this Act, a bond or other security shall not be required as a condition for the issuance of a permit. If the Agency denies any permit under this Section, the Agency shall transmit to the applicant within the time limitations of this Section specific, detailed statements as to the reasons the permit application was denied. Such statements shall include, but not be limited to, the following:

(i) the Sections of this Act which may be violated if the permit were granted;

(ii) the provision of the regulations, promulgated under this Act, which may be violated if the permit were granted;

(iii) the specific type of information, if any, which the Agency deems the applicant did not provide the Agency; and

(iv) a statement of specific reasons why the Act and the regulations might not be met if the permit were granted.

If there is no final action by the Agency within 90 days after the filing of the application for permit, the applicant may deem the permit issued; except that this time period shall be extended to 180 days when (1) notice and opportunity for public hearing are required by State or federal law or regulation, (2) the application which was filed is for any permit to develop a landfill subject to issuance pursuant to this subsection, or (3) the application that was filed is for a MSWLF unit required to issue public notice under subsection (p) of Section 39. The 90-day and 180-day time periods for the Agency to take final action do not apply to NPDES permit applications under subsection (b) of this Section, to RCRA permit applications under subsection (d) of this Section, to UIC permit applications under subsection (e) of this Section, or to CCR surface impoundment applications under subsection (y) of this Section.

The Agency shall publish notice of all final permit determinations for development permits for MSWLF units and for significant permit modifications for lateral expansions for existing MSWLF units one time in a newspaper of general circulation in the county in which the unit is or is proposed to be located.

After January 1, 1994 and until July 1, 1998, operating permits issued under this Section by the Agency for sources of air pollution permitted to emit less than 25 tons per year of any combination of regulated air pollutants, as defined in Section 39.5 of this Act, shall be required to be renewed only upon written request by the Agency consistent with applicable provisions of this Act and regulations promulgated hereunder. Such operating permits shall expire 180 days after the date of such a request. The Board shall revise its regulations for the existing State air pollution operating permit program consistent with this provision by January 1, 1994.

After June 30, 1998, operating permits issued under this Section by the Agency for sources of air pollution that are not subject to Section 39.5 of this Act and are not required to have a federally enforceable State operating permit shall be required to be renewed only upon written request by the Agency consistent with applicable provisions of this Act and its rules. Such operating permits shall expire 180 days after the date of such a request. Before July 1, 1998, the Board shall revise its rules for the existing State air pollution operating permit program consistent with this paragraph and shall adopt rules that require a source to demonstrate that it qualifies for a permit under this paragraph.

(b) The Agency may issue NPDES permits exclusively under this subsection for the discharge of contaminants from point sources into navigable waters, all as defined in the Federal Water Pollution Control Act, as now or hereafter amended, within the jurisdiction of the State, or into any well.

All NPDES permits shall contain those terms and conditions, including, but not limited to, schedules of compliance, which may be required to accomplish the purposes and provisions of this Act.

The Agency may issue general NPDES permits for discharges from categories of point sources which are subject to the same permit limitations and conditions. Such general permits may be issued without individual applications and shall conform to regulations promulgated under Section 402 of the Federal Water Pollution Control Act, as now or hereafter amended.

The Agency may include, among such conditions, effluent limitations and other requirements established under this Act, Board regulations, the Federal Water Pollution Control Act, as now or hereafter amended, and regulations pursuant thereto, and schedules for achieving compliance therewith at the earliest reasonable date.

The Agency shall adopt filing requirements and procedures which are necessary and appropriate for the issuance of NPDES permits, and which are consistent with the Act or regulations adopted by the Board, and with the Federal Water Pollution Control Act, as now or hereafter amended, and regulations pursuant thereto.

The Agency, subject to any conditions which may be prescribed by Board regulations, may issue NPDES permits to allow discharges beyond deadlines established by this Act or by regulations of the Board without the requirement of a variance, subject to the Federal Water Pollution Control Act, as now or hereafter amended, and regulations pursuant thereto.

(c) Except for those facilities owned or operated by sanitary districts organized under the Metropolitan Water Reclamation District Act, no permit for the development or construction of a new pollution control facility may be granted by the Agency unless the applicant submits proof to the Agency that the location of the facility has been approved by the county board of the county if in an unincorporated area, or the governing body of the municipality when in an incorporated area, in which the facility is to be located in accordance with Section 39.2 of this Act. For purposes of this subsection (c), and for purposes of Section 39.2 of this Act, the appropriate county board or governing body of the municipality shall be the county board of the county or the governing body of the municipality in which the facility is to be located as of the date when the application for siting approval is filed.

In the event that siting approval granted pursuant to Section 39.2 has been transferred to a subsequent owner or operator, that subsequent owner or operator may apply to the Agency for, and the Agency may grant, a development or construction permit for the facility for which local siting approval was granted. Upon application to the Agency for a development or construction permit by that subsequent owner or operator, the permit applicant shall cause written notice of the permit application to be served upon the appropriate county board or governing body of the municipality that granted siting approval for that facility and upon any party to the siting proceeding pursuant to which siting approval was granted. In that event, the Agency shall conduct an evaluation of the subsequent owner or operator's prior experience in waste management operations in the manner conducted under subsection (i) of Section 39 of this Act.

Beginning August 20, 1993, if the pollution control facility consists of a hazardous or solid waste disposal facility for which the proposed site is located in an unincorporated area of a county with a population of less than 100,000 and includes all or a portion of a parcel of land that was, on April 1, 1993, adjacent to a municipality having a population of less than 5,000, then the local siting review required under this subsection (c) in conjunction with any permit applied for after that date shall be performed by the governing body of that adjacent municipality rather than the county board of the county in which the proposed site is located; and for the purposes of that local siting review, any references in this Act to the county board shall be deemed to mean the governing body of that adjacent municipality; provided, however, that the provisions of this paragraph shall not apply to any proposed site which was, on April 1, 1993, owned in whole or in part by another municipality.

In the case of a pollution control facility for which a development permit was issued before November 12, 1981, if an operating permit has not been issued by the Agency prior to August 31, 1989 for any portion of the facility, then the Agency may not issue or renew any development permit nor issue an original operating permit for any portion of such facility unless the applicant has submitted proof to the Agency that the location of the facility has been approved by the appropriate county board or municipal governing body pursuant to Section 39.2 of this Act.

After January 1, 1994, if a solid waste disposal facility, any portion for which an operating permit has been issued by the Agency, has not accepted waste disposal for 5 or more consecutive calendar years, before that facility may accept any new or additional waste for disposal, the owner and operator must obtain a new operating permit under this Act for that facility unless the owner and operator have applied to the Agency for a permit authorizing the temporary suspension of waste acceptance. The Agency may not issue a new operation permit under this Act for the facility unless the applicant has submitted proof to the Agency that the location of the facility has been approved or re-approved by the appropriate county board or municipal governing body under Section 39.2 of this Act after the facility ceased accepting waste.

Except for those facilities owned or operated by sanitary districts organized under the Metropolitan Water Reclamation District Act, and except for new pollution control facilities governed by Section 39.2, and except for fossil fuel mining facilities, the granting of a permit under this Act shall not relieve the applicant from meeting and securing all necessary zoning approvals from the unit of government having zoning jurisdiction over the proposed facility.

Before beginning construction on any new sewage treatment plant or sludge drying site to be owned or operated by a sanitary district organized under the Metropolitan Water Reclamation District Act for which a new permit (rather than the renewal or amendment of an existing permit) is required, such sanitary district shall hold a public hearing within the municipality within which the proposed facility is to be located, or within the nearest community if the proposed facility is to be located within an unincorporated area, at which information concerning the proposed facility shall be made available to the public, and members of the public shall be given the opportunity to express their views concerning the proposed facility.

The Agency may issue a permit for a municipal waste transfer station without requiring approval pursuant to Section 39.2 provided that the following demonstration is made:

(1) the municipal waste transfer station was in existence on or before January 1, 1979 and was in continuous operation from January 1, 1979 to January 1, 1993;

(2) the operator submitted a permit application to the Agency to develop and operate the municipal waste transfer station during April of 1994;

(3) the operator can demonstrate that the county board of the county, if the municipal waste transfer station is in an unincorporated area, or the governing body of the municipality, if the station is in an incorporated area, does not object to resumption of the operation of the station; and

(4) the site has local zoning approval.

(d) The Agency may issue RCRA permits exclusively under this subsection to persons owning or operating a facility for the treatment, storage, or disposal of hazardous waste as defined under this Act. Subsection (y) of this Section, rather than this subsection (d), shall apply to permits issued for CCR surface impoundments.

All RCRA permits shall contain those terms and conditions, including, but not limited to, schedules of compliance, which may be required to accomplish the purposes and provisions of this Act. The Agency may include among such conditions standards and other requirements established under this Act, Board regulations, the Resource Conservation and Recovery Act of 1976 (P.L. 94-580), as amended, and regulations pursuant thereto, and may include schedules for achieving compliance therewith as soon as possible. The Agency shall require that a performance bond or other security be provided as a condition for the issuance of a RCRA permit.

In the case of a permit to operate a hazardous waste or PCB incinerator as defined in subsection (k) of Section 44, the Agency shall require, as a condition of the permit, that the operator of the facility perform such analyses of the waste to be incinerated as may be necessary and appropriate to ensure the safe operation of the incinerator.

The Agency shall adopt filing requirements and procedures which are necessary and appropriate for the issuance of RCRA permits, and which are consistent with the Act or regulations adopted by the Board, and with the Resource Conservation and Recovery Act of 1976 (P.L. 94-580), as amended, and regulations pursuant thereto.

The applicant shall make available to the public for inspection all documents submitted by the applicant to the Agency in furtherance of an application, with the exception of trade secrets, at the office of the county board or governing body of the municipality. Such documents may be copied upon payment of the actual cost of reproduction during regular business hours of the local office. The Agency shall issue a written statement concurrent with its grant or denial of the permit explaining the basis for its decision.

(e) The Agency may issue UIC permits exclusively under this subsection to persons owning or operating a facility for the underground injection of contaminants as defined under this Act.

All UIC permits shall contain those terms and conditions, including, but not limited to, schedules of compliance, which may be required to accomplish the purposes and provisions of this Act. The Agency may include among such conditions standards and other requirements established under this Act, Board regulations, the Safe Drinking Water Act (P.L. 93-523), as amended, and regulations pursuant thereto, and may include schedules for achieving compliance therewith. The Agency shall require that a performance bond or other security be provided as a condition for the issuance of a UIC permit.

The Agency shall adopt filing requirements and procedures which are necessary and appropriate for the issuance of UIC permits, and which are consistent with the Act or regulations adopted by the Board, and with the Safe Drinking Water Act (P.L. 93-523), as amended, and regulations pursuant thereto.

The applicant shall make available to the public for inspection all documents submitted by the applicant to the Agency in furtherance of an application, with the exception of trade secrets, at the office of the county board or governing body of the municipality. Such documents may be copied upon payment of the actual cost of reproduction during regular business hours of the local office. The Agency shall issue a written statement concurrent with its grant or denial of the permit explaining the basis for its decision.

(f) In making any determination pursuant to Section 9.1 of this Act:

(1) The Agency shall have authority to make the determination of any question required to be determined by the Clean Air Act, as now or hereafter amended, this Act, or the regulations of the Board, including the determination of the Lowest Achievable Emission Rate, Maximum Achievable Control Technology, or Best Available Control Technology, consistent with the Board's regulations, if any.

(2) The Agency shall adopt requirements as necessary to implement public participation procedures, including, but not limited to, public notice, comment, and an opportunity for hearing, which must accompany the processing of applications for PSD permits. The Agency shall briefly describe and respond to all significant comments on the draft permit raised during the public comment period or during any hearing. The Agency may group related comments together and provide one unified response for each issue raised.

(3) Any complete permit application submitted to the Agency under this subsection for a PSD permit shall be granted or denied by the Agency not later than one year after the filing of such completed application.

(4) The Agency shall, after conferring with the applicant, give written notice to the applicant of its proposed decision on the application, including the terms and conditions of the permit to be issued and the facts, conduct, or other basis upon which the Agency will rely to support its proposed action.

(g) The Agency shall include as conditions upon all permits issued for hazardous waste disposal sites such restrictions upon the future use of such sites as are reasonably necessary to protect public health and the environment, including permanent prohibition of the use of such sites for purposes which may create an unreasonable risk of injury to human health or to the environment. After administrative and judicial challenges to such restrictions have been exhausted, the Agency shall file such restrictions of record in the Office of the Recorder of the county in which the hazardous waste disposal site is located.

(h) A hazardous waste stream may not be deposited in a permitted hazardous waste site unless specific authorization is obtained from the Agency by the generator and disposal site owner and operator for the deposit of that specific hazardous waste stream. The Agency may grant specific authorization for disposal of hazardous waste streams only after the generator has reasonably demonstrated that, considering technological feasibility and economic reasonableness, the hazardous waste cannot be reasonably recycled for reuse, nor incinerated or chemically, physically, or biologically treated so as to neutralize the hazardous waste and render it nonhazardous. In granting authorization under this Section, the Agency may impose such conditions as may be necessary to accomplish the purposes of the Act and are consistent with this Act and regulations promulgated by the Board hereunder. If the Agency refuses to grant authorization under this Section, the applicant may appeal as if the Agency refused to grant a permit, pursuant to the provisions of subsection (a) of Section 40 of this Act. For purposes of this subsection (h), the term "generator" has the meaning given in Section 3.205 of this Act, unless: (1) the hazardous waste is treated, incinerated, or partially recycled for reuse prior to disposal, in which case the last person who treats, incinerates, or partially recycles the hazardous waste prior to disposal is the generator; or (2) the hazardous waste is from a response action, in which case the person performing the response action is the generator. This subsection (h) does not apply to any hazardous waste that is restricted from land disposal under 35 Ill. Adm. Code 728.

(i) Before issuing any RCRA permit, any permit for a waste storage site, sanitary landfill, waste disposal site, waste transfer station, waste treatment facility, waste incinerator, or any waste-transportation operation, any permit or interim authorization for a clean construction or demolition debris fill operation, or any permit required under subsection (d-5) of Section 55, the Agency shall conduct an evaluation of the prospective owner's or operator's prior experience in waste management operations, clean construction or demolition debris fill operations, and tire storage site management. The Agency may deny such a permit, or deny or revoke interim authorization, if the prospective owner or operator or any employee or officer of the prospective owner or operator has a history of:

(1) repeated violations of federal, State, or local laws, regulations, standards, or ordinances in the operation of waste management facilities or sites, clean construction or demolition debris fill operation facilities or sites, or tire storage sites; or

(2) conviction in this or another State of any crime which is a felony under the laws of this State, or conviction of a felony in a federal court; or conviction in this or another state or federal court of any of the following crimes: forgery, official misconduct, bribery, perjury, or knowingly submitting false information under any environmental law, regulation, or permit term or condition; or

(3) proof of gross carelessness or incompetence in handling, storing, processing, transporting, or disposing of waste, clean construction or demolition debris, or used or waste tires, or proof of gross carelessness or incompetence in using clean construction or demolition debris as fill.

(i-5) Before issuing any permit or approving any interim authorization for a clean construction or demolition debris fill operation in which any ownership interest is transferred between January 1, 2005, and the effective date of the prohibition set forth in Section 22.52 of this Act, the Agency shall conduct an evaluation of the operation if any previous activities at the site or facility may have caused or allowed contamination of the site. It shall be the responsibility of the owner or operator seeking the permit or interim authorization to provide to the Agency all of the information necessary for the Agency to conduct its evaluation. The Agency may deny a permit or interim authorization if previous activities at the site may have caused or allowed contamination at the site, unless such contamination is authorized under any permit issued by the Agency.

(j) The issuance under this Act of a permit to engage in the surface mining of any resources other than fossil fuels shall not relieve the permittee from its duty to comply with any applicable local law regulating the commencement, location, or operation of surface mining facilities.

(k) A development permit issued under subsection (a) of Section 39 for any facility or site which is required to have a permit under subsection (d) of Section 21 shall expire at the end of 2 calendar years from the date upon which it was issued, unless within that period the applicant has taken action to develop the facility or the site. In the event that review of the conditions of the development permit is sought pursuant to Section 40 or 41, or permittee is prevented from commencing development of the facility or site by any other litigation beyond the permittee's control, such two-year period shall be deemed to begin on the date upon which such review process or litigation is concluded.

(l) No permit shall be issued by the Agency under this Act for construction or operation of any facility or site located within the boundaries of any setback zone established pursuant to this Act, where such construction or operation is prohibited.

(m) The Agency may issue permits to persons owning or operating a facility for composting landscape waste. In granting such permits, the Agency may impose such conditions as may be necessary to accomplish the purposes of this Act, and as are not inconsistent with applicable regulations promulgated by the Board. Except as otherwise provided in this Act, a bond or other security shall not be required as a condition for the issuance of a permit. If the Agency denies any permit pursuant to this subsection, the Agency shall transmit to the applicant within the time limitations of this subsection specific, detailed statements as to the reasons the permit application was denied. Such statements shall include but not be limited to the following:

(1) the Sections of this Act that may be violated if the permit were granted;

(2) the specific regulations promulgated pursuant to this Act that may be violated if the permit were granted;

(3) the specific information, if any, the Agency deems the applicant did not provide in its application to the Agency; and

(4) a statement of specific reasons why the Act and the regulations might be violated if the permit were granted.

If no final action is taken by the Agency within 90 days after the filing of the application for permit, the applicant may deem the permit issued. Any applicant for a permit may waive the 90-day limitation by filing a written statement with the Agency.

The Agency shall issue permits for such facilities upon receipt of an application that includes a legal description of the site, a topographic map of the site drawn to the scale of 200 feet to the inch or larger, a description of the operation, including the area served, an estimate of the volume of materials to be processed, and documentation that:

(1) the facility includes a setback of at least 200 feet from the nearest potable water supply well;

(2) the facility is located outside the boundary of the 10-year floodplain or the site will be floodproofed;

(3) the facility is located so as to minimize incompatibility with the character of the surrounding area, including at least a 200 foot setback from any residence, and in the case of a facility that is developed or the permitted composting area of which is expanded after November 17, 1991, the composting area is located at least 1/8 mile from the nearest residence (other than a residence located on the same property as the facility);

(4) the design of the facility will prevent any compost material from being placed within 5 feet of the water table, will adequately control runoff from the site, and will collect and manage any leachate that is generated on the site;

(5) the operation of the facility will include appropriate dust and odor control measures, limitations on operating hours, appropriate noise control measures for shredding, chipping and similar equipment, management procedures for composting, containment and disposal of non-compostable wastes, procedures to be used for terminating operations at the site, and recordkeeping sufficient to document the amount of materials received, composted, and otherwise disposed of; and

(6) the operation will be conducted in accordance with any applicable rules adopted by the Board.

The Agency shall issue renewable permits of not longer than 10 years in duration for the composting of landscape wastes, as defined in Section 3.155 of this Act, based on the above requirements.

The operator of any facility permitted under this subsection (m) must submit a written annual statement to the Agency on or before April 1 of each year that includes an estimate of the amount of material, in tons, received for composting.

(n) The Agency shall issue permits jointly with the Department of Transportation for the dredging or deposit of material in Lake Michigan in accordance with Section 18 of the Rivers, Lakes, and Streams Act.

(o) (Blank).

(p) (1) Any person submitting an application for a permit for a new MSWLF unit or for a lateral expansion under subsection (t) of Section 21 of this Act for an existing MSWLF unit that has not received and is not subject to local siting approval under Section 39.2 of this Act shall publish notice of the application in a newspaper of general circulation in the county in which the MSWLF unit is or is proposed to be located. The notice must be published at least 15 days before submission of the permit application to the Agency. The notice shall state the name and address of the applicant, the location of the MSWLF unit or proposed MSWLF unit, the nature and size of the MSWLF unit or proposed MSWLF unit, the nature of the activity proposed, the probable life of the proposed activity, the date the permit application will be submitted, and a statement that persons may file written comments with the Agency concerning the permit application within 30 days after the filing of the permit application unless the time period to submit comments is extended by the Agency.

When a permit applicant submits information to the Agency to supplement a permit application being reviewed by the Agency, the applicant shall not be required to reissue the notice under this subsection.

(2) The Agency shall accept written comments concerning the permit application that are postmarked no later than 30 days after the filing of the permit application, unless the time period to accept comments is extended by the Agency.

(3) Each applicant for a permit described in part (1) of this subsection shall file a copy of the permit application with the county board or governing body of the municipality in which the MSWLF unit is or is proposed to be located at the same time the application is submitted to the Agency. The permit application filed with the county board or governing body of the municipality shall include all documents submitted to or to be submitted to the Agency, except trade secrets as determined under Section 7.1 of this Act. The permit application and other documents on file with the county board or governing body of the municipality shall be made available for public inspection during regular business hours at the office of the county board or the governing body of the municipality and may be copied upon payment of the actual cost of reproduction.

(q) Within 6 months after July 12, 2011 (the effective date of Public Act 97-95), the Agency, in consultation with the regulated community, shall develop a web portal to be posted on its website for the purpose of enhancing review and promoting timely issuance of permits required by this Act. At a minimum, the Agency shall make the following information available on the web portal:

(1) Checklists and guidance relating to the completion of permit applications, developed pursuant to subsection (s) of this Section, which may include, but are not limited to, existing instructions for completing the applications and examples of complete applications. As the Agency develops new checklists and develops guidance, it shall supplement the web portal with those materials.

(2) Within 2 years after July 12, 2011 (the effective date of Public Act 97-95), permit application forms or portions of permit applications that can be completed and saved electronically, and submitted to the Agency electronically with digital signatures.

(3) Within 2 years after July 12, 2011 (the effective date of Public Act 97-95), an online tracking system where an applicant may review the status of its pending application, including the name and contact information of the permit analyst assigned to the application. Until the online tracking system has been developed, the Agency shall post on its website semi-annual permitting efficiency tracking reports that include statistics on the timeframes for Agency action on the following types of permits received after July 12, 2011 (the effective date of Public Act 97-95): air construction permits, new NPDES permits and associated water construction permits, and modifications of major NPDES permits and associated water construction permits. The reports must be posted by February 1 and August 1 each year and shall include:

(A) the number of applications received for each type of permit, the number of applications on which the Agency has taken action, and the number of applications still pending; and

(B) for those applications where the Agency has not taken action in accordance with the timeframes set forth in this Act, the date the application was received and the reasons for any delays, which may include, but shall not be limited to, (i) the application being inadequate or incomplete, (ii) scientific or technical disagreements with the applicant, USEPA, or other local, state, or federal agencies involved in the permitting approval process, (iii) public opposition to the permit, or (iv) Agency staffing shortages. To the extent practicable, the tracking report shall provide approximate dates when cause for delay was identified by the Agency, when the Agency informed the applicant of the problem leading to the delay, and when the applicant remedied the reason for the delay.

(r) Upon the request of the applicant, the Agency shall notify the applicant of the permit analyst assigned to the application upon its receipt.

(s) The Agency is authorized to prepare and distribute guidance documents relating to its administration of this Section and procedural rules implementing this Section. Guidance documents prepared under this subsection shall not be considered rules and shall not be subject to the Illinois Administrative Procedure Act. Such guidance shall not be binding on any party.

(t) Except as otherwise prohibited by federal law or regulation, any person submitting an application for a permit may include with the application suggested permit language for Agency consideration. The Agency is not obligated to use the suggested language or any portion thereof in its permitting decision. If requested by the permit applicant, the Agency shall meet with the applicant to discuss the suggested language.

(u) If requested by the permit applicant, the Agency shall provide the permit applicant with a copy of the draft permit prior to any public review period.

(v) If requested by the permit applicant, the Agency shall provide the permit applicant with a copy of the final permit prior to its issuance.

(w) An air pollution permit shall not be required due to emissions of greenhouse gases, as specified by Section 9.15 of this Act.

(x) If, before the expiration of a State operating permit that is issued pursuant to subsection (a) of this Section and contains federally enforceable conditions limiting the potential to emit of the source to a level below the major source threshold for that source so as to exclude the source from the Clean Air Act Permit Program, the Agency receives a complete application for the renewal of that permit, then all of the terms and conditions of the permit shall remain in effect until final administrative action has been taken on the application for the renewal of the permit.

(y) The Agency may issue permits exclusively under this subsection to persons owning or operating a CCR surface impoundment subject to Section 22.59.

(z) If a mass animal mortality event is declared by the Department of Agriculture in accordance with the Animal Mortality Act:

(1) the owner or operator responsible for the disposal of dead animals is exempted from the following:

(i) obtaining a permit for the construction, installation, or operation of any type of facility or equipment issued in accordance with subsection (a) of this Section;

(ii) obtaining a permit for open burning in accordance with the rules adopted by the Board; and

(iii) registering the disposal of dead animals as an eligible small source with the Agency in accordance with Section 9.14 of this Act;

(2) as applicable, the owner or operator responsible for the disposal of dead animals is required to obtain the following permits:

(i) an NPDES permit in accordance with subsection (b) of this Section;

(ii) a PSD permit or an NA NSR permit in accordance with Section 9.1 of this Act;

(iii) a lifetime State operating permit or a federally enforceable State operating permit, in accordance with subsection (a) of this Section; or

(iv) a CAAPP permit, in accordance with Section 39.5 of this Act.

All CCR surface impoundment permits shall contain those terms and conditions, including, but not limited to, schedules of compliance, which may be required to accomplish the purposes and provisions of this Act, Board regulations, the Illinois Groundwater Protection Act and regulations pursuant thereto, and the Resource Conservation and Recovery Act and regulations pursuant thereto, and may include schedules for achieving compliance therewith as soon as possible.

The Board shall adopt filing requirements and procedures that are necessary and appropriate for the issuance of CCR surface impoundment permits and that are consistent with this Act or regulations adopted by the Board, and with the RCRA, as amended, and regulations pursuant thereto.

The applicant shall make available to the public for inspection all documents submitted by the applicant to the Agency in furtherance of an application, with the exception of trade secrets, on its public internet website as well as at the office of the county board or governing body of the municipality where CCR from the CCR surface impoundment will be permanently disposed. Such documents may be copied upon payment of the actual cost of reproduction during regular business hours of the local office.

The Agency shall issue a written statement concurrent with its grant or denial of the permit explaining the basis for its decision.

(Source: P.A. 101-171, eff. 7-30-19; 102-216, eff. 1-1-22; 102-558, eff. 8-20-21; 102-813, eff. 5-13-22.)

(Text of Section after amendment by P.A. 104-458)

Sec. 39. Issuance of permits; procedures.

(a) When the Board has by regulation required a permit for the construction, installation, or operation of any type of facility, equipment, vehicle, vessel, or aircraft, the applicant shall apply to the Agency for such permit and it shall be the duty of the Agency to issue such a permit upon proof by the applicant that the facility, equipment, vehicle, vessel, or aircraft will not cause a violation of this Act or of regulations hereunder. The Agency shall adopt such procedures as are necessary to carry out its duties under this Section. In making its determinations on permit applications under this Section the Agency may consider prior adjudications of noncompliance with this Act by the applicant that involved a release of a contaminant into the environment. In granting permits, the Agency may impose reasonable conditions specifically related to the applicant's past compliance history with this Act as necessary to correct, detect, or prevent noncompliance. The Agency may impose such other conditions as may be necessary to accomplish the purposes of this Act, and as are not inconsistent with the regulations promulgated by the Board hereunder. Except as otherwise provided in this Act, a bond or other security shall not be required as a condition for the issuance of a permit. If the Agency denies any permit under this Section, the Agency shall transmit to the applicant within the time limitations of this Section specific, detailed statements as to the reasons the permit application was denied. Such statements shall include, but not be limited to, the following:

(i) the Sections of this Act which may be violated if the permit were granted;

(ii) the provision of the regulations, promulgated under this Act, which may be violated if the permit were granted;

(iii) the specific type of information, if any, which the Agency deems the applicant did not provide the Agency; and

(iv) a statement of specific reasons why the Act and the regulations might not be met if the permit were granted.

If there is no final action by the Agency within 90 days after the filing of the application for permit, the applicant may deem the permit issued; except that this time period shall be extended to 180 days when (1) notice and opportunity for public hearing are required by State or federal law or regulation, (2) the application which was filed is for any permit to develop a landfill subject to issuance pursuant to this subsection, or (3) the application that was filed is for a MSWLF unit required to issue public notice under subsection (p) of Section 39. The 90-day and 180-day time periods for the Agency to take final action do not apply to NPDES permit applications under subsection (b) of this Section, to RCRA permit applications under subsection (d) of this Section, to UIC permit applications under subsection (e) of this Section, or to CCR surface impoundment applications under subsection (y) of this Section.

The Agency shall publish notice of all final permit determinations for development permits for MSWLF units and for significant permit modifications for lateral expansions for existing MSWLF units one time in a newspaper of general circulation in the county in which the unit is or is proposed to be located.

After January 1, 1994 and until July 1, 1998, operating permits issued under this Section by the Agency for sources of air pollution permitted to emit less than 25 tons per year of any combination of regulated air pollutants, as defined in Section 39.5 of this Act, shall be required to be renewed only upon written request by the Agency consistent with applicable provisions of this Act and regulations promulgated hereunder. Such operating permits shall expire 180 days after the date of such a request. The Board shall revise its regulations for the existing State air pollution operating permit program consistent with this provision by January 1, 1994.

After June 30, 1998, operating permits issued under this Section by the Agency for sources of air pollution that are not subject to Section 39.5 of this Act and are not required to have a federally enforceable State operating permit shall be required to be renewed only upon written request by the Agency consistent with applicable provisions of this Act and its rules. Such operating permits shall expire 180 days after the date of such a request. Before July 1, 1998, the Board shall revise its rules for the existing State air pollution operating permit program consistent with this paragraph and shall adopt rules that require a source to demonstrate that it qualifies for a permit under this paragraph.

Each air pollution construction permit for diesel powered backup generators to a source that is a data center, as defined in subsection (c) of Section 605-1025 of the Department of Commerce and Economic Opportunity Law of the Civil Administrative Code of Illinois, that is applied for 6 months after the effective date of this amendatory Act of the 104th General Assembly and that is required to have a federally enforceable State operating permit or a Clean Air Act Permit Program permit shall, in addition to any other applicable requirements, require each backup generator to: (i) meet standards at least as protective as Tier 4 standards for non-road diesel engines set out by the United States Environmental Protection Agency in 40 CFR 1039, as it exists on the effective date of this amendatory Act of the 104th General Assembly, and (ii) operate solely as an emergency or standby unit in accordance with 35 Ill. Adm. Code 211.1920, as it exists on the effective date of this amendatory Act of the 104th General Assembly, and (iii) obtain a permit pursuant to either the Illinois Clean Air Act Permit Program or Federally Enforceable State Operating Permit Program. For purposes of item (i), to comply with 40 CFR 1039.665, a qualified emergency situation is one in which the condition of an engine's emission controls poses a significant direct or indirect risk to human life. An example of a direct risk would be an emission control condition that inhibits the performance of an engine being used to rescue a person from a life-threatening situation. An example of an indirect risk would be an emission control condition that inhibits the performance of an engine being used to provide electrical power to a data center that routes "911" emergency response telecommunications. If a diesel powered backup generator becomes out of compliance with the Tier 4 standards for non-road compression-ignition engines during a power outage, the backup generator may (1) continue to operate for up to 24 sequential hours after becoming noncompliant with the Tier 4 standards or (2) operate when compliance is achieved. Notwithstanding any provision of law to the contrary, operation of the backup generator for up to 24 sequential hours after becoming noncompliant with the Tier 4 standards shall not be considered a violation of the permit.

Each air pollution construction permit for natural gas powered backup generators for a source that is a data center, as defined in subsection (c) of Section 605-1025 of the Department of Commerce and Economic Opportunity Law of the Civil Administrative Code of Illinois, that is applied for 6 months after the effective date of this amendatory Act of the 104th General Assembly and that is required to have a federally enforceable State operating permit or a Clean Air Act Permit Program permit shall, in addition to any other applicable requirements, require each backup generator to: (i) meet standards at least as protective as Tier 2 standards for non-road large spark-ignition engines set out by the United States Environmental Protection Agency in 40 CFR 1048, as it exists on the effective date of this amendatory Act of the 104th General Assembly, and (ii) operate solely as an emergency or standby unit in accordance with 35 Ill. Adm. Code 211.1920, as it exists on the effective date of this amendatory Act of the 104th General Assembly, and (iii) obtain a permit pursuant to either the Illinois Clean Air Act Permit program, or Federally Enforceable State Operating Permit program. For purposes of item (i), a qualified emergency situation is one in which the condition of an engine's emission controls poses a significant direct or indirect risk to human life. An example of a direct risk would be an emission control condition that inhibits the performance of an engine being used to rescue a person from a life-threatening situation. An example of an indirect risk would be an emission control condition that inhibits the performance of an engine being used to provide electrical power to a data center that routes "911" emergency response telecommunications.

Each air pollution construction permit for diesel powered or natural gas powered backup generators for a source that is a data center, as defined in subsection (c) of Section 605-1025 of the Department of Commerce and Economic Opportunity Law of the Civil Administrative Code of Illinois, that is applied for 6 months after the effective date of this amendatory Act of the 104th General Assembly, must require the owner or operator of the generators to submit an air quality assessment report to the Agency on an annual basis and post the report on a publicly accessible website. The report shall identify the following:

(1) a detailed assessment of total carbon emissions and total criteria pollutant emissions at the site. "Criteria pollutants" means the 6 pollutants for which the United States Environmental Protection Agency has set National Ambient Air Quality Standards under Section 109 of the Clean Air Act, together with the precursors to those pollutants;

(2) a detailed assessment of all permit violations at the site that have occurred in the past year, if any;

(3) ambient air monitoring data collected from the site consistent with the ambient monitoring requirement for criteria pollutants set out in 40 CFR 58; and

(4) disclosure of any on-site, above ground storage tanks for fuel storage and compliance history with all relevant standards and regulations If a natural gas powered backup generator becomes out of compliance with the Tier 2 standards for non-road large spark-ignition engines during a power outage, the backup generator may (1) continue to operate for up to 24 sequential hours after becoming noncompliant with the Tier 2 standards or (2) operate when compliance is achieved. Notwithstanding any provision of law to the contrary, operation of the backup generator for up to 24 sequential hours after becoming noncompliant with the Tier 2 standards shall not be considered a violation of the permit.

(b) The Agency may issue NPDES permits exclusively under this subsection for the discharge of contaminants from point sources into navigable waters, all as defined in the Federal Water Pollution Control Act, as now or hereafter amended, within the jurisdiction of the State, or into any well.

All NPDES permits shall contain those terms and conditions, including, but not limited to, schedules of compliance, which may be required to accomplish the purposes and provisions of this Act.

The Agency may issue general NPDES permits for discharges from categories of point sources which are subject to the same permit limitations and conditions. Such general permits may be issued without individual applications and shall conform to regulations promulgated under Section 402 of the Federal Water Pollution Control Act, as now or hereafter amended.

The Agency may include, among such conditions, effluent limitations and other requirements established under this Act, Board regulations, the Federal Water Pollution Control Act, as now or hereafter amended, and regulations pursuant thereto, and schedules for achieving compliance therewith at the earliest reasonable date.

The Agency shall adopt filing requirements and procedures which are necessary and appropriate for the issuance of NPDES permits, and which are consistent with the Act or regulations adopted by the Board, and with the Federal Water Pollution Control Act, as now or hereafter amended, and regulations pursuant thereto.

The Agency, subject to any conditions which may be prescribed by Board regulations, may issue NPDES permits to allow discharges beyond deadlines established by this Act or by regulations of the Board without the requirement of a variance, subject to the Federal Water Pollution Control Act, as now or hereafter amended, and regulations pursuant thereto.

(c) Except for those facilities owned or operated by sanitary districts organized under the Metropolitan Water Reclamation District Act, no permit for the development or construction of a new pollution control facility may be granted by the Agency unless the applicant submits proof to the Agency that the location of the facility has been approved by the county board of the county if in an unincorporated area, or the governing body of the municipality when in an incorporated area, in which the facility is to be located in accordance with Section 39.2 of this Act. For purposes of this subsection (c), and for purposes of Section 39.2 of this Act, the appropriate county board or governing body of the municipality shall be the county board of the county or the governing body of the municipality in which the facility is to be located as of the date when the application for siting approval is filed.

In the event that siting approval granted pursuant to Section 39.2 has been transferred to a subsequent owner or operator, that subsequent owner or operator may apply to the Agency for, and the Agency may grant, a development or construction permit for the facility for which local siting approval was granted. Upon application to the Agency for a development or construction permit by that subsequent owner or operator, the permit applicant shall cause written notice of the permit application to be served upon the appropriate county board or governing body of the municipality that granted siting approval for that facility and upon any party to the siting proceeding pursuant to which siting approval was granted. In that event, the Agency shall conduct an evaluation of the subsequent owner or operator's prior experience in waste management operations in the manner conducted under subsection (i) of Section 39 of this Act.

Beginning August 20, 1993, if the pollution control facility consists of a hazardous or solid waste disposal facility for which the proposed site is located in an unincorporated area of a county with a population of less than 100,000 and includes all or a portion of a parcel of land that was, on April 1, 1993, adjacent to a municipality having a population of less than 5,000, then the local siting review required under this subsection (c) in conjunction with any permit applied for after that date shall be performed by the governing body of that adjacent municipality rather than the county board of the county in which the proposed site is located; and for the purposes of that local siting review, any references in this Act to the county board shall be deemed to mean the governing body of that adjacent municipality; provided, however, that the provisions of this paragraph shall not apply to any proposed site which was, on April 1, 1993, owned in whole or in part by another municipality.

In the case of a pollution control facility for which a development permit was issued before November 12, 1981, if an operating permit has not been issued by the Agency prior to August 31, 1989 for any portion of the facility, then the Agency may not issue or renew any development permit nor issue an original operating permit for any portion of such facility unless the applicant has submitted proof to the Agency that the location of the facility has been approved by the appropriate county board or municipal governing body pursuant to Section 39.2 of this Act.

After January 1, 1994, if a solid waste disposal facility, any portion for which an operating permit has been issued by the Agency, has not accepted waste disposal for 5 or more consecutive calendar years, before that facility may accept any new or additional waste for disposal, the owner and operator must obtain a new operating permit under this Act for that facility unless the owner and operator have applied to the Agency for a permit authorizing the temporary suspension of waste acceptance. The Agency may not issue a new operation permit under this Act for the facility unless the applicant has submitted proof to the Agency that the location of the facility has been approved or re-approved by the appropriate county board or municipal governing body under Section 39.2 of this Act after the facility ceased accepting waste.

Except for those facilities owned or operated by sanitary districts organized under the Metropolitan Water Reclamation District Act, and except for new pollution control facilities governed by Section 39.2, and except for fossil fuel mining facilities, the granting of a permit under this Act shall not relieve the applicant from meeting and securing all necessary zoning approvals from the unit of government having zoning jurisdiction over the proposed facility.

Before beginning construction on any new sewage treatment plant or sludge drying site to be owned or operated by a sanitary district organized under the Metropolitan Water Reclamation District Act for which a new permit (rather than the renewal or amendment of an existing permit) is required, such sanitary district shall hold a public hearing within the municipality within which the proposed facility is to be located, or within the nearest community if the proposed facility is to be located within an unincorporated area, at which information concerning the proposed facility shall be made available to the public, and members of the public shall be given the opportunity to express their views concerning the proposed facility.

The Agency may issue a permit for a municipal waste transfer station without requiring approval pursuant to Section 39.2 provided that the following demonstration is made:

(1) the municipal waste transfer station was in existence on or before January 1, 1979 and was in continuous operation from January 1, 1979 to January 1, 1993;

(2) the operator submitted a permit application to the Agency to develop and operate the municipal waste transfer station during April of 1994;

(3) the operator can demonstrate that the county board of the county, if the municipal waste transfer station is in an unincorporated area, or the governing body of the municipality, if the station is in an incorporated area, does not object to resumption of the operation of the station; and

(4) the site has local zoning approval.

(d) The Agency may issue RCRA permits exclusively under this subsection to persons owning or operating a facility for the treatment, storage, or disposal of hazardous waste as defined under this Act. Subsection (y) of this Section, rather than this subsection (d), shall apply to permits issued for CCR surface impoundments.

All RCRA permits shall contain those terms and conditions, including, but not limited to, schedules of compliance, which may be required to accomplish the purposes and provisions of this Act. The Agency may include among such conditions standards and other requirements established under this Act, Board regulations, the Resource Conservation and Recovery Act of 1976 (P.L. 94-580), as amended, and regulations pursuant thereto, and may include schedules for achieving compliance therewith as soon as possible. The Agency shall require that a performance bond or other security be provided as a condition for the issuance of a RCRA permit.

In the case of a permit to operate a hazardous waste or PCB incinerator as defined in subsection (k) of Section 44, the Agency shall require, as a condition of the permit, that the operator of the facility perform such analyses of the waste to be incinerated as may be necessary and appropriate to ensure the safe operation of the incinerator.

The Agency shall adopt filing requirements and procedures which are necessary and appropriate for the issuance of RCRA permits, and which are consistent with the Act or regulations adopted by the Board, and with the Resource Conservation and Recovery Act of 1976 (P.L. 94-580), as amended, and regulations pursuant thereto.

The applicant shall make available to the public for inspection all documents submitted by the applicant to the Agency in furtherance of an application, with the exception of trade secrets, at the office of the county board or governing body of the municipality. Such documents may be copied upon payment of the actual cost of reproduction during regular business hours of the local office. The Agency shall issue a written statement concurrent with its grant or denial of the permit explaining the basis for its decision.

(e) The Agency may issue UIC permits exclusively under this subsection to persons owning or operating a facility for the underground injection of contaminants as defined under this Act.

All UIC permits shall contain those terms and conditions, including, but not limited to, schedules of compliance, which may be required to accomplish the purposes and provisions of this Act. The Agency may include among such conditions standards and other requirements established under this Act, Board regulations, the Safe Drinking Water Act (P.L. 93-523), as amended, and regulations pursuant thereto, and may include schedules for achieving compliance therewith. The Agency shall require that a performance bond or other security be provided as a condition for the issuance of a UIC permit.

The Agency shall adopt filing requirements and procedures which are necessary and appropriate for the issuance of UIC permits, and which are consistent with the Act or regulations adopted by the Board, and with the Safe Drinking Water Act (P.L. 93-523), as amended, and regulations pursuant thereto.

The applicant shall make available to the public for inspection all documents submitted by the applicant to the Agency in furtherance of an application, with the exception of trade secrets, at the office of the county board or governing body of the municipality. Such documents may be copied upon payment of the actual cost of reproduction during regular business hours of the local office. The Agency shall issue a written statement concurrent with its grant or denial of the permit explaining the basis for its decision.

(f) In making any determination pursuant to Section 9.1 of this Act:

(1) The Agency shall have authority to make the determination of any question required to be determined by the Clean Air Act, as now or hereafter amended, this Act, or the regulations of the Board, including the determination of the Lowest Achievable Emission Rate, Maximum Achievable Control Technology, or Best Available Control Technology, consistent with the Board's regulations, if any.

(2) The Agency shall adopt requirements as necessary to implement public participation procedures, including, but not limited to, public notice, comment, and an opportunity for hearing, which must accompany the processing of applications for PSD permits. The Agency shall briefly describe and respond to all significant comments on the draft permit raised during the public comment period or during any hearing. The Agency may group related comments together and provide one unified response for each issue raised.

(3) Any complete permit application submitted to the Agency under this subsection for a PSD permit shall be granted or denied by the Agency not later than one year after the filing of such completed application.

(4) The Agency shall, after conferring with the applicant, give written notice to the applicant of its proposed decision on the application, including the terms and conditions of the permit to be issued and the facts, conduct, or other basis upon which the Agency will rely to support its proposed action.

(g) The Agency shall include as conditions upon all permits issued for hazardous waste disposal sites such restrictions upon the future use of such sites as are reasonably necessary to protect public health and the environment, including permanent prohibition of the use of such sites for purposes which may create an unreasonable risk of injury to human health or to the environment. After administrative and judicial challenges to such restrictions have been exhausted, the Agency shall file such restrictions of record in the Office of the Recorder of the county in which the hazardous waste disposal site is located.

(h) A hazardous waste stream may not be deposited in a permitted hazardous waste site unless specific authorization is obtained from the Agency by the generator and disposal site owner and operator for the deposit of that specific hazardous waste stream. The Agency may grant specific authorization for disposal of hazardous waste streams only after the generator has reasonably demonstrated that, considering technological feasibility and economic reasonableness, the hazardous waste cannot be reasonably recycled for reuse, nor incinerated or chemically, physically, or biologically treated so as to neutralize the hazardous waste and render it nonhazardous. In granting authorization under this Section, the Agency may impose such conditions as may be necessary to accomplish the purposes of the Act and are consistent with this Act and regulations promulgated by the Board hereunder. If the Agency refuses to grant authorization under this Section, the applicant may appeal as if the Agency refused to grant a permit, pursuant to the provisions of subsection (a) of Section 40 of this Act. For purposes of this subsection (h), the term "generator" has the meaning given in Section 3.205 of this Act, unless: (1) the hazardous waste is treated, incinerated, or partially recycled for reuse prior to disposal, in which case the last person who treats, incinerates, or partially recycles the hazardous waste prior to disposal is the generator; or (2) the hazardous waste is from a response action, in which case the person performing the response action is the generator. This subsection (h) does not apply to any hazardous waste that is restricted from land disposal under 35 Ill. Adm. Code 728.

(i) Before issuing any RCRA permit, any permit for a waste storage site, sanitary landfill, waste disposal site, waste transfer station, waste treatment facility, waste incinerator, or any waste-transportation operation, any permit or interim authorization for a clean construction or demolition debris fill operation, or any permit required under subsection (d-5) of Section 55, the Agency shall conduct an evaluation of the prospective owner's or operator's prior experience in waste management operations, clean construction or demolition debris fill operations, and tire storage site management. The Agency may deny such a permit, or deny or revoke interim authorization, if the prospective owner or operator or any employee or officer of the prospective owner or operator has a history of:

(1) repeated violations of federal, State, or local laws, regulations, standards, or ordinances in the operation of waste management facilities or sites, clean construction or demolition debris fill operation facilities or sites, or tire storage sites; or

(2) conviction in this or another State of any crime which is a felony under the laws of this State, or conviction of a felony in a federal court; or conviction in this or another state or federal court of any of the following crimes: forgery, official misconduct, bribery, perjury, or knowingly submitting false information under any environmental law, regulation, or permit term or condition; or

(3) proof of gross carelessness or incompetence in handling, storing, processing, transporting, or disposing of waste, clean construction or demolition debris, or used or waste tires, or proof of gross carelessness or incompetence in using clean construction or demolition debris as fill.

(i-5) Before issuing any permit or approving any interim authorization for a clean construction or demolition debris fill operation in which any ownership interest is transferred between January 1, 2005, and the effective date of the prohibition set forth in Section 22.52 of this Act, the Agency shall conduct an evaluation of the operation if any previous activities at the site or facility may have caused or allowed contamination of the site. It shall be the responsibility of the owner or operator seeking the permit or interim authorization to provide to the Agency all of the information necessary for the Agency to conduct its evaluation. The Agency may deny a permit or interim authorization if previous activities at the site may have caused or allowed contamination at the site, unless such contamination is authorized under any permit issued by the Agency.

(j) The issuance under this Act of a permit to engage in the surface mining of any resources other than fossil fuels shall not relieve the permittee from its duty to comply with any applicable local law regulating the commencement, location, or operation of surface mining facilities.

(k) A development permit issued under subsection (a) of Section 39 for any facility or site which is required to have a permit under subsection (d) of Section 21 shall expire at the end of 2 calendar years from the date upon which it was issued, unless within that period the applicant has taken action to develop the facility or the site. In the event that review of the conditions of the development permit is sought pursuant to Section 40 or 41, or permittee is prevented from commencing development of the facility or site by any other litigation beyond the permittee's control, such two-year period shall be deemed to begin on the date upon which such review process or litigation is concluded.

(l) No permit shall be issued by the Agency under this Act for construction or operation of any facility or site located within the boundaries of any setback zone established pursuant to this Act, where such construction or operation is prohibited.

(m) The Agency may issue permits to persons owning or operating a facility for composting landscape waste. In granting such permits, the Agency may impose such conditions as may be necessary to accomplish the purposes of this Act, and as are not inconsistent with applicable regulations promulgated by the Board. Except as otherwise provided in this Act, a bond or other security shall not be required as a condition for the issuance of a permit. If the Agency denies any permit pursuant to this subsection, the Agency shall transmit to the applicant within the time limitations of this subsection specific, detailed statements as to the reasons the permit application was denied. Such statements shall include but not be limited to the following:

(1) the Sections of this Act that may be violated if the permit were granted;

(2) the specific regulations promulgated pursuant to this Act that may be violated if the permit were granted;

(3) the specific information, if any, the Agency deems the applicant did not provide in its application to the Agency; and

(4) a statement of specific reasons why the Act and the regulations might be violated if the permit were granted.

If no final action is taken by the Agency within 90 days after the filing of the application for permit, the applicant may deem the permit issued. Any applicant for a permit may waive the 90-day limitation by filing a written statement with the Agency.

The Agency shall issue permits for such facilities upon receipt of an application that includes a legal description of the site, a topographic map of the site drawn to the scale of 200 feet to the inch or larger, a description of the operation, including the area served, an estimate of the volume of materials to be processed, and documentation that:

(1) the facility includes a setback of at least 200 feet from the nearest potable water supply well;

(2) the facility is located outside the boundary of the 10-year floodplain or the site will be floodproofed;

(3) the facility is located so as to minimize incompatibility with the character of the surrounding area, including at least a 200 foot setback from any residence, and in the case of a facility that is developed or the permitted composting area of which is expanded after November 17, 1991, the composting area is located at least 1/8 mile from the nearest residence (other than a residence located on the same property as the facility);

(4) the design of the facility will prevent any compost material from being placed within 5 feet of the water table, will adequately control runoff from the site, and will collect and manage any leachate that is generated on the site;

(5) the operation of the facility will include appropriate dust and odor control measures, limitations on operating hours, appropriate noise control measures for shredding, chipping and similar equipment, management procedures for composting, containment and disposal of non-compostable wastes, procedures to be used for terminating operations at the site, and recordkeeping sufficient to document the amount of materials received, composted, and otherwise disposed of; and

(6) the operation will be conducted in accordance with any applicable rules adopted by the Board.

The Agency shall issue renewable permits of not longer than 10 years in duration for the composting of landscape wastes, as defined in Section 3.155 of this Act, based on the above requirements.

The operator of any facility permitted under this subsection (m) must submit a written annual statement to the Agency on or before April 1 of each year that includes an estimate of the amount of material, in tons, received for composting.

(n) The Agency shall issue permits jointly with the Department of Transportation for the dredging or deposit of material in Lake Michigan in accordance with Section 18 of the Rivers, Lakes, and Streams Act.

(o) (Blank).

(p) (1) Any person submitting an application for a permit for a new MSWLF unit or for a lateral expansion under subsection (t) of Section 21 of this Act for an existing MSWLF unit that has not received and is not subject to local siting approval under Section 39.2 of this Act shall publish notice of the application in a newspaper of general circulation in the county in which the MSWLF unit is or is proposed to be located. The notice must be published at least 15 days before submission of the permit application to the Agency. The notice shall state the name and address of the applicant, the location of the MSWLF unit or proposed MSWLF unit, the nature and size of the MSWLF unit or proposed MSWLF unit, the nature of the activity proposed, the probable life of the proposed activity, the date the permit application will be submitted, and a statement that persons may file written comments with the Agency concerning the permit application within 30 days after the filing of the permit application unless the time period to submit comments is extended by the Agency.

When a permit applicant submits information to the Agency to supplement a permit application being reviewed by the Agency, the applicant shall not be required to reissue the notice under this subsection.

(2) The Agency shall accept written comments concerning the permit application that are postmarked no later than 30 days after the filing of the permit application, unless the time period to accept comments is extended by the Agency.

(3) Each applicant for a permit described in part (1) of this subsection shall file a copy of the permit application with the county board or governing body of the municipality in which the MSWLF unit is or is proposed to be located at the same time the application is submitted to the Agency. The permit application filed with the county board or governing body of the municipality shall include all documents submitted to or to be submitted to the Agency, except trade secrets as determined under Section 7.1 of this Act. The permit application and other documents on file with the county board or governing body of the municipality shall be made available for public inspection during regular business hours at the office of the county board or the governing body of the municipality and may be copied upon payment of the actual cost of reproduction.

(q) Within 6 months after July 12, 2011 (the effective date of Public Act 97-95), the Agency, in consultation with the regulated community, shall develop a web portal to be posted on its website for the purpose of enhancing review and promoting timely issuance of permits required by this Act. At a minimum, the Agency shall make the following information available on the web portal:

(1) Checklists and guidance relating to the completion of permit applications, developed pursuant to subsection (s) of this Section, which may include, but are not limited to, existing instructions for completing the applications and examples of complete applications. As the Agency develops new checklists and develops guidance, it shall supplement the web portal with those materials.

(2) Within 2 years after July 12, 2011 (the effective date of Public Act 97-95), permit application forms or portions of permit applications that can be completed and saved electronically, and submitted to the Agency electronically with digital signatures.

(3) Within 2 years after July 12, 2011 (the effective date of Public Act 97-95), an online tracking system where an applicant may review the status of its pending application, including the name and contact information of the permit analyst assigned to the application. Until the online tracking system has been developed, the Agency shall post on its website semi-annual permitting efficiency tracking reports that include statistics on the timeframes for Agency action on the following types of permits received after July 12, 2011 (the effective date of Public Act 97-95): air construction permits, new NPDES permits and associated water construction permits, and modifications of major NPDES permits and associated water construction permits. The reports must be posted by February 1 and August 1 each year and shall include:

(A) the number of applications received for each type of permit, the number of applications on which the Agency has taken action, and the number of applications still pending; and

(B) for those applications where the Agency has not taken action in accordance with the timeframes set forth in this Act, the date the application was received and the reasons for any delays, which may include, but shall not be limited to, (i) the application being inadequate or incomplete, (ii) scientific or technical disagreements with the applicant, USEPA, or other local, state, or federal agencies involved in the permitting approval process, (iii) public opposition to the permit, or (iv) Agency staffing shortages. To the extent practicable, the tracking report shall provide approximate dates when cause for delay was identified by the Agency, when the Agency informed the applicant of the problem leading to the delay, and when the applicant remedied the reason for the delay.

(r) Upon the request of the applicant, the Agency shall notify the applicant of the permit analyst assigned to the application upon its receipt.

(s) The Agency is authorized to prepare and distribute guidance documents relating to its administration of this Section and procedural rules implementing this Section. Guidance documents prepared under this subsection shall not be considered rules and shall not be subject to the Illinois Administrative Procedure Act. Such guidance shall not be binding on any party.

(t) Except as otherwise prohibited by federal law or regulation, any person submitting an application for a permit may include with the application suggested permit language for Agency consideration. The Agency is not obligated to use the suggested language or any portion thereof in its permitting decision. If requested by the permit applicant, the Agency shall meet with the applicant to discuss the suggested language.

(u) If requested by the permit applicant, the Agency shall provide the permit applicant with a copy of the draft permit prior to any public review period.

(v) If requested by the permit applicant, the Agency shall provide the permit applicant with a copy of the final permit prior to its issuance.

(w) An air pollution permit shall not be required due to emissions of greenhouse gases, as specified by Section 9.15 of this Act.

(x) If, before the expiration of a State operating permit that is issued pursuant to subsection (a) of this Section and contains federally enforceable conditions limiting the potential to emit of the source to a level below the major source threshold for that source so as to exclude the source from the Clean Air Act Permit Program, the Agency receives a complete application for the renewal of that permit, then all of the terms and conditions of the permit shall remain in effect until final administrative action has been taken on the application for the renewal of the permit.

(y) The Agency may issue permits exclusively under this subsection to persons owning or operating a CCR surface impoundment subject to Section 22.59.

(z) If a mass animal mortality event is declared by the Department of Agriculture in accordance with the Animal Mortality Act:

(1) the owner or operator responsible for the disposal of dead animals is exempted from the following:

(i) obtaining a permit for the construction, installation, or operation of any type of facility or equipment issued in accordance with subsection (a) of this Section;

(ii) obtaining a permit for open burning in accordance with the rules adopted by the Board; and

(iii) registering the disposal of dead animals as an eligible small source with the Agency in accordance with Section 9.14 of this Act;

(2) as applicable, the owner or operator responsible for the disposal of dead animals is required to obtain the following permits:

(i) an NPDES permit in accordance with subsection (b) of this Section;

(ii) a PSD permit or an NA NSR permit in accordance with Section 9.1 of this Act;

(iii) a lifetime State operating permit or a federally enforceable State operating permit, in accordance with subsection (a) of this Section; or

(iv) a CAAPP permit, in accordance with Section 39.5 of this Act.

All CCR surface impoundment permits shall contain those terms and conditions, including, but not limited to, schedules of compliance, which may be required to accomplish the purposes and provisions of this Act, Board regulations, the Illinois Groundwater Protection Act and regulations pursuant thereto, and the Resource Conservation and Recovery Act and regulations pursuant thereto, and may include schedules for achieving compliance therewith as soon as possible.

The Board shall adopt filing requirements and procedures that are necessary and appropriate for the issuance of CCR surface impoundment permits and that are consistent with this Act or regulations adopted by the Board, and with the RCRA, as amended, and regulations pursuant thereto.

The applicant shall make available to the public for inspection all documents submitted by the applicant to the Agency in furtherance of an application, with the exception of trade secrets, on its public internet website as well as at the office of the county board or governing body of the municipality where CCR from the CCR surface impoundment will be permanently disposed. Such documents may be copied upon payment of the actual cost of reproduction during regular business hours of the local office.

The Agency shall issue a written statement concurrent with its grant or denial of the permit explaining the basis for its decision.

(Source: P.A. 104-458, eff. 6-1-26.)

(415 ILCS 5/39.5) (from Ch. 111 1/2, par. 1039.5)

Sec. 39.5. Clean Air Act Permit Program.

1. Definitions. For purposes of this Section:

"Administrative permit amendment" means a permit revision subject to subsection 13 of this Section.

"Affected source for acid deposition" means a source that includes one or more affected units under Title IV of the Clean Air Act.

"Affected States" for purposes of formal distribution of a draft CAAPP permit to other States for comments prior to issuance, means all States:

(1) Whose air quality may be affected by the source covered by the draft permit and that are contiguous to Illinois; or

(2) That are within 50 miles of the source.

"Affected unit for acid deposition" shall have the meaning given to the term "affected unit" in the regulations promulgated under Title IV of the Clean Air Act.

"Applicable Clean Air Act requirement" means all of the following as they apply to emissions units in a source (including regulations that have been promulgated or approved by USEPA pursuant to the Clean Air Act which directly impose requirements upon a source and other such federal requirements which have been adopted by the Board. These may include requirements and regulations which have future effective compliance dates. Requirements and regulations will be exempt if USEPA determines that such requirements need not be contained in a Title V permit):

(1) Any standard or other requirement provided for in the applicable state implementation plan approved or promulgated by USEPA under Title I of the Clean Air Act that implements the relevant requirements of the Clean Air Act, including any revisions to the state Implementation Plan promulgated in 40 CFR Part 52, Subparts A and O and other subparts applicable to Illinois. For purposes of this paragraph (1) of this definition, "any standard or other requirement" means only such standards or requirements directly enforceable against an individual source under the Clean Air Act.

(2)(i) Any term or condition of any preconstruction permits issued pursuant to regulations approved or promulgated by USEPA under Title I of the Clean Air Act, including Part C or D of the Clean Air Act.

(ii) Any term or condition as required pursuant to this Section 39.5 of any federally enforceable State operating permit issued pursuant to regulations approved or promulgated by USEPA under Title I of the Clean Air Act, including Part C or D of the Clean Air Act.

(3) Any standard or other requirement under Section 111 of the Clean Air Act, including Section 111(d).

(4) Any standard or other requirement under Section 112 of the Clean Air Act, including any requirement concerning accident prevention under Section 112(r)(7) of the Clean Air Act.

(5) Any standard or other requirement of the acid rain program under Title IV of the Clean Air Act or the regulations promulgated thereunder.

(6) Any requirements established pursuant to Section 504(b) or Section 114(a)(3) of the Clean Air Act.

(7) Any standard or other requirement governing solid waste incineration, under Section 129 of the Clean Air Act.

(8) Any standard or other requirement for consumer and commercial products, under Section 183(e) of the Clean Air Act.

(9) Any standard or other requirement for tank vessels, under Section 183(f) of the Clean Air Act.

(10) Any standard or other requirement of the program to control air pollution from Outer Continental Shelf sources, under Section 328 of the Clean Air Act.

(11) Any standard or other requirement of the regulations promulgated to protect stratospheric ozone under Title VI of the Clean Air Act, unless USEPA has determined that such requirements need not be contained in a Title V permit.

(12) Any national ambient air quality standard or increment or visibility requirement under Part C of Title I of the Clean Air Act, but only as it would apply to temporary sources permitted pursuant to Section 504(e) of the Clean Air Act.

"Applicable requirement" means all applicable Clean Air Act requirements and any other standard, limitation, or other requirement contained in this Act or regulations promulgated under this Act as applicable to sources of air contaminants (including requirements that have future effective compliance dates).

"CAAPP" means the Clean Air Act Permit Program, developed pursuant to Title V of the Clean Air Act.

"CAAPP application" means an application for a CAAPP permit.

"CAAPP Permit" or "permit" (unless the context suggests otherwise) means any permit issued, renewed, amended, modified, or revised pursuant to Title V of the Clean Air Act.

"CAAPP source" means any source for which the owner or operator is required to obtain a CAAPP permit pursuant to subsection 2 of this Section.

"Clean Air Act" means the Clean Air Act, as now and hereafter amended, 42 U.S.C. 7401, et seq.

"Designated representative" has the meaning given to it in Section 402(26) of the Clean Air Act and the regulations promulgated thereunder, which state that the term "designated representative" means a responsible person or official authorized by the owner or operator of a unit to represent the owner or operator in all matters pertaining to the holding, transfer, or disposition of allowances allocated to a unit, and the submission of and compliance with permits, permit applications, and compliance plans for the unit.

"Draft CAAPP permit" means the version of a CAAPP permit for which public notice and an opportunity for public comment and hearing is offered by the Agency.

"Effective date of the CAAPP" means the date that USEPA approves Illinois' CAAPP.

"Emission unit" means any part or activity of a stationary source that emits or has the potential to emit any air pollutant. This term is not meant to alter or affect the definition of the term "unit" for purposes of Title IV of the Clean Air Act.

"Federally enforceable" means enforceable by USEPA.

"Final permit action" means the Agency's granting with conditions, refusal to grant, renewal of, or revision of a CAAPP permit, the Agency's determination of incompleteness of a submitted CAAPP application, or the Agency's failure to act on an application for a permit, permit renewal, or permit revision within the time specified in subsection 13, subsection 14, or paragraph (j) of subsection 5 of this Section.

"General permit" means a permit issued to cover numerous similar sources in accordance with subsection 11 of this Section.

"Major source" means a source for which emissions of one or more air pollutants meet the criteria for major status pursuant to paragraph (c) of subsection 2 of this Section.

"Maximum achievable control technology" or "MACT" means the maximum degree of reductions in emissions deemed achievable under Section 112 of the Clean Air Act.

"Owner or operator" means any person who owns, leases, operates, controls, or supervises a stationary source.

"Permit modification" means a revision to a CAAPP permit that cannot be accomplished under the provisions for administrative permit amendments under subsection 13 of this Section.

"Permit revision" means a permit modification or administrative permit amendment.

"Phase II" means the period of the national acid rain program, established under Title IV of the Clean Air Act, beginning January 1, 2000, and continuing thereafter.

"Phase II acid rain permit" means the portion of a CAAPP permit issued, renewed, modified, or revised by the Agency during Phase II for an affected source for acid deposition.

"Potential to emit" means the maximum capacity of a stationary source to emit any air pollutant under its physical and operational design. Any physical or operational limitation on the capacity of a source to emit an air pollutant, including air pollution control equipment and restrictions on hours of operation or on the type or amount of material combusted, stored, or processed, shall be treated as part of its design if the limitation is enforceable by USEPA. This definition does not alter or affect the use of this term for any other purposes under the Clean Air Act, or the term "capacity factor" as used in Title IV of the Clean Air Act or the regulations promulgated thereunder.

"Preconstruction Permit" or "Construction Permit" means a permit which is to be obtained prior to commencing or beginning actual construction or modification of a source or emissions unit.

"Proposed CAAPP permit" means the version of a CAAPP permit that the Agency proposes to issue and forwards to USEPA for review in compliance with applicable requirements of the Act and regulations promulgated thereunder.

"Regulated air pollutant" means the following:

(1) Nitrogen oxides (NOx) or any volatile organic compound.

(2) Any pollutant for which a national ambient air quality standard has been promulgated.

(3) Any pollutant that is subject to any standard promulgated under Section 111 of the Clean Air Act.

(4) Any Class I or II substance subject to a standard promulgated under or established by Title VI of the Clean Air Act.

(5) Any pollutant subject to a standard promulgated under Section 112 or other requirements established under Section 112 of the Clean Air Act, including Sections 112(g), (j), and (r).

(i) Any pollutant subject to requirements under Section 112(j) of the Clean Air Act. Any pollutant listed under Section 112(b) for which the subject source would be major shall be considered to be regulated 18 months after the date on which USEPA was required to promulgate an applicable standard pursuant to Section 112(e) of the Clean Air Act, if USEPA fails to promulgate such standard.

(ii) Any pollutant for which the requirements of Section 112(g)(2) of the Clean Air Act have been met, but only with respect to the individual source subject to Section 112(g)(2) requirement.

(6) Greenhouse gases.

"Renewal" means the process by which a permit is reissued at the end of its term.

"Responsible official" means one of the following:

(1) For a corporation: a president, secretary, treasurer, or vice-president of the corporation in charge of a principal business function, or any other person who performs similar policy or decision-making functions for the corporation, or a duly authorized representative of such person if the representative is responsible for the overall operation of one or more manufacturing, production, or operating facilities applying for or subject to a permit and either (i) the facilities employ more than 250 persons or have gross annual sales or expenditures exceeding $25 million (in second quarter 1980 dollars), or (ii) the delegation of authority to such representative is approved in advance by the Agency.

(2) For a partnership or sole proprietorship: a general partner or the proprietor, respectively, or in the case of a partnership in which all of the partners are corporations, a duly authorized representative of the partnership if the representative is responsible for the overall operation of one or more manufacturing, production, or operating facilities applying for or subject to a permit and either (i) the facilities employ more than 250 persons or have gross annual sales or expenditures exceeding $25 million (in second quarter 1980 dollars), or (ii) the delegation of authority to such representative is approved in advance by the Agency.

(3) For a municipality, State, federal, or other public agency: either a principal executive officer or ranking elected official. For the purposes of this part, a principal executive officer of a federal agency includes the chief executive officer having responsibility for the overall operations of a principal geographic unit of the agency (e.g., a Regional Administrator of USEPA).

(4) For affected sources for acid deposition:

(i) The designated representative shall be the "responsible official" in so far as actions, standards, requirements, or prohibitions under Title IV of the Clean Air Act or the regulations promulgated thereunder are concerned.

(ii) The designated representative may also be the "responsible official" for any other purposes with respect to air pollution control.

"Section 502(b)(10) changes" means changes that contravene express permit terms. "Section 502(b)(10) changes" do not include changes that would violate applicable requirements or contravene federally enforceable permit terms or conditions that are monitoring (including test methods), recordkeeping, reporting, or compliance certification requirements.

"Solid waste incineration unit" means a distinct operating unit of any facility which combusts any solid waste material from commercial or industrial establishments or the general public (including single and multiple residences, hotels, and motels). The term does not include incinerators or other units required to have a permit under Section 3005 of the Solid Waste Disposal Act. The term also does not include (A) materials recovery facilities (including primary or secondary smelters) which combust waste for the primary purpose of recovering metals, (B) qualifying small power production facilities, as defined in Section 3(17)(C) of the Federal Power Act (16 U.S.C. 769(17)(C)), or qualifying cogeneration facilities, as defined in Section 3(18)(B) of the Federal Power Act (16 U.S.C. 796(18)(B)), which burn homogeneous waste (such as units which burn tires or used oil, but not including refuse-derived fuel) for the production of electric energy or in the case of qualifying cogeneration facilities which burn homogeneous waste for the production of electric energy and steam or forms of useful energy (such as heat) which are used for industrial, commercial, heating, or cooling purposes, or (C) air curtain incinerators provided that such incinerators only burn wood wastes, yard waste, and clean lumber and that such air curtain incinerators comply with opacity limitations to be established by the USEPA by rule.

"Source" means any stationary source (or any group of stationary sources) that is located on one or more contiguous or adjacent properties that are under common control of the same person (or persons under common control) and that belongs to a single major industrial grouping. For the purposes of defining "source," a stationary source or group of stationary sources shall be considered part of a single major industrial grouping if all of the pollutant emitting activities at such source or group of sources located on contiguous or adjacent properties and under common control belong to the same Major Group (i.e., all have the same two-digit code) as described in the Standard Industrial Classification Manual, 1987, or such pollutant emitting activities at a stationary source (or group of stationary sources) located on contiguous or adjacent properties and under common control constitute a support facility. The determination as to whether any group of stationary sources is located on contiguous or adjacent properties, and/or is under common control, and/or whether the pollutant emitting activities at such group of stationary sources constitute a support facility shall be made on a case-by-case basis.

"Stationary source" means any building, structure, facility, or installation that emits or may emit any regulated air pollutant or any pollutant listed under Section 112(b) of the Clean Air Act, except those emissions resulting directly from an internal combustion engine for transportation purposes or from a nonroad engine or nonroad vehicle as defined in Section 216 of the Clean Air Act.

"Subject to regulation" has the meaning given to it in 40 CFR 70.2, as now or hereafter amended.

"Support facility" means any stationary source (or group of stationary sources) that conveys, stores, or otherwise assists to a significant extent in the production of a principal product at another stationary source (or group of stationary sources). A support facility shall be considered to be part of the same source as the stationary source (or group of stationary sources) that it supports regardless of the 2-digit Standard Industrial Classification code for the support facility.

"USEPA" means the Administrator of the United States Environmental Protection Agency (USEPA) or a person designated by the Administrator.

1.1. Exclusion From the CAAPP.

a. An owner or operator of a source which determines that the source could be excluded from the CAAPP may seek such exclusion prior to the date that the CAAPP application for the source is due but in no case later than 9 months after the effective date of the CAAPP through the imposition of federally enforceable conditions limiting the "potential to emit" of the source to a level below the major source threshold for that source as described in paragraph (c) of subsection 2 of this Section, within a State operating permit issued pursuant to subsection (a) of Section 39 of this Act. After such date, an exclusion from the CAAPP may be sought under paragraph (c) of subsection 3 of this Section.

b. An owner or operator of a source seeking exclusion from the CAAPP pursuant to paragraph (a) of this subsection must submit a permit application consistent with the existing State permit program which specifically requests such exclusion through the imposition of such federally enforceable conditions.

c. Upon such request, if the Agency determines that the owner or operator of a source has met the requirements for exclusion pursuant to paragraph (a) of this subsection and other applicable requirements for permit issuance under subsection (a) of Section 39 of this Act, the Agency shall issue a State operating permit for such source under subsection (a) of Section 39 of this Act, as amended, and regulations promulgated thereunder with federally enforceable conditions limiting the "potential to emit" of the source to a level below the major source threshold for that source as described in paragraph (c) of subsection 2 of this Section.

d. The Agency shall provide an owner or operator of a source which may be excluded from the CAAPP pursuant to this subsection with reasonable notice that the owner or operator may seek such exclusion.

e. The Agency shall provide such sources with the necessary permit application forms.

2. Applicability.

a. Sources subject to this Section shall include:

i. Any major source as defined in paragraph (c) of this subsection.

ii. Any source subject to a standard or other requirements promulgated under Section 111 (New Source Performance Standards) or Section 112 (Hazardous Air Pollutants) of the Clean Air Act, except that a source is not required to obtain a permit solely because it is subject to regulations or requirements under Section 112(r) of the Clean Air Act.

iii. Any affected source for acid deposition, as defined in subsection 1 of this Section.

iv. Any other source subject to this Section under the Clean Air Act or regulations promulgated thereunder, or applicable Board regulations.

b. Sources exempted from this Section shall include:

i. All sources listed in paragraph (a) of this subsection that are not major sources, affected sources for acid deposition or solid waste incineration units required to obtain a permit pursuant to Section 129(e) of the Clean Air Act, until the source is required to obtain a CAAPP permit pursuant to the Clean Air Act or regulations promulgated thereunder.

ii. Nonmajor sources subject to a standard or other requirements subsequently promulgated by USEPA under Section 111 or 112 of the Clean Air Act that are determined by USEPA to be exempt at the time a new standard is promulgated.

iii. All sources and source categories that would be required to obtain a permit solely because they are subject to Part 60, Subpart AAA - Standards of Performance for New Residential Wood Heaters (40 CFR Part 60).

iv. All sources and source categories that would be required to obtain a permit solely because they are subject to Part 61, Subpart M - National Emission Standard for Hazardous Air Pollutants for Asbestos, Section 61.145 (40 CFR Part 61).

v. Any other source categories exempted by USEPA regulations pursuant to Section 502(a) of the Clean Air Act.

vi. Major sources of greenhouse gas emissions required to obtain a CAAPP permit under this Section if any of the following occurs:

(A) enactment of federal legislation depriving the Administrator of the USEPA of authority to regulate greenhouse gases under the Clean Air Act;

(B) the issuance of any opinion, ruling, judgment, order, or decree by a federal court depriving the Administrator of the USEPA of authority to regulate greenhouse gases under the Clean Air Act; or

(C) action by the President of the United States or the President's authorized agent, including the Administrator of the USEPA, to repeal or withdraw the Greenhouse Gas Tailoring Rule (75 Fed. Reg. 31514, June 3, 2010).

If any event listed in this subparagraph (vi) occurs, CAAPP permits issued after such event shall not impose permit terms or conditions addressing greenhouse gases during the effectiveness of any event listed in subparagraph (vi). If any event listed in this subparagraph (vi) occurs, any owner or operator with a CAAPP permit that includes terms or conditions addressing greenhouse gases may elect to submit an application to the Agency to address a revision or repeal of such terms or conditions. If any owner or operator submits such an application, the Agency shall expeditiously process the permit application in accordance with applicable laws and regulations. Nothing in this subparagraph (vi) shall relieve an owner or operator of a source from the requirement to obtain a CAAPP permit for its emissions of regulated air pollutants other than greenhouse gases, as required by this Section.

c. For purposes of this Section the term "major source" means any source that is:

i. A major source under Section 112 of the Clean Air Act, which is defined as:

A. For pollutants other than radionuclides, any stationary source or group of stationary sources located within a contiguous area and under common control that emits or has the potential to emit, in the aggregate, 10 tons per year (tpy) or more of any hazardous air pollutant which has been listed pursuant to Section 112(b) of the Clean Air Act, 25 tpy or more of any combination of such hazardous air pollutants, or such lesser quantity as USEPA may establish by rule. Notwithstanding the preceding sentence, emissions from any oil or gas exploration or production well (with its associated equipment) and emissions from any pipeline compressor or pump station shall not be aggregated with emissions from other similar units, whether or not such units are in a contiguous area or under common control, to determine whether such stations are major sources.

B. For radionuclides, "major source" shall have the meaning specified by the USEPA by rule.

ii. A major stationary source of air pollutants, as defined in Section 302 of the Clean Air Act, that directly emits or has the potential to emit, 100 tpy or more of any air pollutant subject to regulation (including any major source of fugitive emissions of any such pollutant, as determined by rule by USEPA). For purposes of this subsection, "fugitive emissions" means those emissions which could not reasonably pass through a stack, chimney, vent, or other functionally equivalent opening. The fugitive emissions of a stationary source shall not be considered in determining whether it is a major stationary source for the purposes of Section 302(j) of the Clean Air Act, unless the source belongs to one of the following categories of stationary source:

A. Coal cleaning plants (with thermal dryers).

B. Kraft pulp mills.

C. Portland cement plants.

D. Primary zinc smelters.

E. Iron and steel mills.

F. Primary aluminum ore reduction plants.

G. Primary copper smelters.

H. Municipal incinerators capable of charging more than 250 tons of refuse per day.

I. Hydrofluoric, sulfuric, or nitric acid plants.

J. Petroleum refineries.

K. Lime plants.

L. Phosphate rock processing plants.

M. Coke oven batteries.

N. Sulfur recovery plants.

O. Carbon black plants (furnace process).

P. Primary lead smelters.

Q. Fuel conversion plants.

R. Sintering plants.

S. Secondary metal production plants.

T. Chemical process plants.

U. Fossil-fuel boilers (or combination thereof) totaling more than 250 million British thermal units per hour heat input.

V. Petroleum storage and transfer units with a total storage capacity exceeding 300,000 barrels.

W. Taconite ore processing plants.

X. Glass fiber processing plants.

Y. Charcoal production plants.

Z. Fossil fuel-fired steam electric plants of more than 250 million British thermal units per hour heat input.

AA. All other stationary source categories, which as of August 7, 1980 are being regulated by a standard promulgated under Section 111 or 112 of the Clean Air Act.

BB. Any other stationary source category designated by USEPA by rule.

iii. A major stationary source as defined in part D of Title I of the Clean Air Act including:

A. For ozone nonattainment areas, sources with the potential to emit 100 tons or more per year of volatile organic compounds or oxides of nitrogen in areas classified as "marginal" or "moderate", 50 tons or more per year in areas classified as "serious", 25 tons or more per year in areas classified as "severe", and 10 tons or more per year in areas classified as "extreme"; except that the references in this clause to 100, 50, 25, and 10 tons per year of nitrogen oxides shall not apply with respect to any source for which USEPA has made a finding, under Section 182(f)(1) or (2) of the Clean Air Act, that requirements otherwise applicable to such source under Section 182(f) of the Clean Air Act do not apply. Such sources shall remain subject to the major source criteria of subparagraph (ii) of paragraph (c) of this subsection.

B. For ozone transport regions established pursuant to Section 184 of the Clean Air Act, sources with the potential to emit 50 tons or more per year of volatile organic compounds (VOCs).

C. For carbon monoxide nonattainment areas (1) that are classified as "serious", and (2) in which stationary sources contribute significantly to carbon monoxide levels as determined under rules issued by USEPA, sources with the potential to emit 50 tons or more per year of carbon monoxide.

D. For particulate matter (PM-10) nonattainment areas classified as "serious", sources with the potential to emit 70 tons or more per year of PM-10.

3. Agency Authority To Issue CAAPP Permits and Federally Enforceable State Operating Permits.

a. The Agency shall issue CAAPP permits under this Section consistent with the Clean Air Act and regulations promulgated thereunder and this Act and regulations promulgated thereunder.

b. The Agency shall issue CAAPP permits for fixed terms of 5 years, except CAAPP permits issued for solid waste incineration units combusting municipal waste which shall be issued for fixed terms of 12 years and except CAAPP permits for affected sources for acid deposition which shall be issued for initial terms to expire on December 31, 1999, and for fixed terms of 5 years thereafter.

c. The Agency shall have the authority to issue a State operating permit for a source under subsection (a) of Section 39 of this Act, as amended, and regulations promulgated thereunder, which includes federally enforceable conditions limiting the "potential to emit" of the source to a level below the major source threshold for that source as described in paragraph (c) of subsection 2 of this Section, thereby excluding the source from the CAAPP, when requested by the applicant pursuant to paragraph (u) of subsection 5 of this Section. The public notice requirements of this Section applicable to CAAPP permits shall also apply to the initial issuance of permits under this paragraph.

d. For purposes of this Act, a permit issued by USEPA under Section 505 of the Clean Air Act, as now and hereafter amended, shall be deemed to be a permit issued by the Agency pursuant to this Section 39.5.

4. Transition.

a. An owner or operator of a CAAPP source shall not be required to renew an existing State operating permit for any emission unit at such CAAPP source once a CAAPP application timely submitted prior to expiration of the State operating permit has been deemed complete. For purposes other than permit renewal, the obligation upon the owner or operator of a CAAPP source to obtain a State operating permit is not removed upon submittal of the complete CAAPP permit application. An owner or operator of a CAAPP source seeking to make a modification to a source prior to the issuance of its CAAPP permit shall be required to obtain a construction permit, operating permit, or both as required for such modification in accordance with the State permit program under subsection (a) of Section 39 of this Act, as amended, and regulations promulgated thereunder. The application for such construction permit, operating permit, or both shall be considered an amendment to the CAAPP application submitted for such source.

b. An owner or operator of a CAAPP source shall continue to operate in accordance with the terms and conditions of its applicable State operating permit notwithstanding the expiration of the State operating permit until the source's CAAPP permit has been issued.

c. An owner or operator of a CAAPP source shall submit its initial CAAPP application to the Agency no later than 12 months after the effective date of the CAAPP. The Agency may request submittal of initial CAAPP applications during this 12-month period according to a schedule set forth within Agency procedures, however, in no event shall the Agency require such submittal earlier than 3 months after such effective date of the CAAPP. An owner or operator may voluntarily submit its initial CAAPP application prior to the date required within this paragraph or applicable procedures, if any, subsequent to the date the Agency submits the CAAPP to USEPA for approval.

d. The Agency shall act on initial CAAPP applications in accordance with paragraph (j) of subsection 5 of this Section.

e. For purposes of this Section, the term "initial CAAPP application" shall mean the first CAAPP application submitted for a source existing as of the effective date of the CAAPP.

f. The Agency shall provide owners or operators of CAAPP sources with at least 3 months advance notice of the date on which their applications are required to be submitted. In determining which sources shall be subject to early submittal, the Agency shall include among its considerations the complexity of the permit application, and the burden that such early submittal will have on the source.

g. The CAAPP permit shall upon becoming effective supersede the State operating permit.

h. The Agency shall have the authority to adopt procedural rules, in accordance with the Illinois Administrative Procedure Act, as the Agency deems necessary, to implement this subsection.

5. Applications and Completeness.

a. An owner or operator of a CAAPP source shall submit its complete CAAPP application consistent with the Act and applicable regulations.

b. An owner or operator of a CAAPP source shall submit a single complete CAAPP application covering all emission units at that source.

c. To be deemed complete, a CAAPP application must provide all information, as requested in Agency application forms, sufficient to evaluate the subject source and its application and to determine all applicable requirements, pursuant to the Clean Air Act, and regulations thereunder, this Act and regulations thereunder. Such Agency application forms shall be finalized and made available prior to the date on which any CAAPP application is required.

d. An owner or operator of a CAAPP source shall submit, as part of its complete CAAPP application, a compliance plan, including a schedule of compliance, describing how each emission unit will comply with all applicable requirements. Any such schedule of compliance shall be supplemental to, and shall not sanction noncompliance with, the applicable requirements on which it is based.

e. Each submitted CAAPP application shall be certified for truth, accuracy, and completeness by a responsible official in accordance with applicable regulations.

f. The Agency shall provide notice to a CAAPP applicant as to whether a submitted CAAPP application is complete. Unless the Agency notifies the applicant of incompleteness, within 60 days after receipt of the CAAPP application, the application shall be deemed complete. The Agency may request additional information as needed to make the completeness determination. The Agency may to the extent practicable provide the applicant with a reasonable opportunity to correct deficiencies prior to a final determination of completeness.

g. If after the determination of completeness the Agency finds that additional information is necessary to evaluate or take final action on the CAAPP application, the Agency may request in writing such information from the source with a reasonable deadline for response.

h. If the owner or operator of a CAAPP source submits a timely and complete CAAPP application, the source's failure to have a CAAPP permit shall not be a violation of this Section until the Agency takes final action on the submitted CAAPP application, provided, however, where the applicant fails to submit the requested information under paragraph (g) of this subsection 5 within the time frame specified by the Agency, this protection shall cease to apply.

i. Any applicant who fails to submit any relevant facts necessary to evaluate the subject source and its CAAPP application or who has submitted incorrect information in a CAAPP application shall, upon becoming aware of such failure or incorrect submittal, submit supplementary facts or correct information to the Agency. In addition, an applicant shall provide to the Agency additional information as necessary to address any requirements which become applicable to the source subsequent to the date the applicant submitted its complete CAAPP application but prior to release of the draft CAAPP permit.

j. The Agency shall issue or deny the CAAPP permit within 18 months after the date of receipt of the complete CAAPP application, with the following exceptions: (i) permits for affected sources for acid deposition shall be issued or denied within 6 months after receipt of a complete application in accordance with subsection 17 of this Section; (ii) the Agency shall act on initial CAAPP applications within 24 months after the date of receipt of the complete CAAPP application; (iii) the Agency shall act on complete applications containing early reduction demonstrations under Section 112(i)(5) of the Clean Air Act within 9 months of receipt of the complete CAAPP application.

Where the Agency does not take final action on the permit within the required time period, the permit shall not be deemed issued; rather, the failure to act shall be treated as a final permit action for purposes of judicial review pursuant to Sections 40.2 and 41 of this Act.

k. The submittal of a complete CAAPP application shall not affect the requirement that any source have a preconstruction permit under Title I of the Clean Air Act.

l. Unless a timely and complete renewal application has been submitted consistent with this subsection, a CAAPP source operating upon the expiration of its CAAPP permit shall be deemed to be operating without a CAAPP permit. Such operation is prohibited under this Act.

m. Permits being renewed shall be subject to the same procedural requirements, including those for public participation and federal review and objection, that apply to original permit issuance.

n. For purposes of permit renewal, a timely application is one that is submitted no less than 9 months prior to the date of permit expiration.

o. The terms and conditions of a CAAPP permit shall remain in effect until the issuance of a CAAPP renewal permit provided a timely and complete CAAPP application has been submitted.

p. The owner or operator of a CAAPP source seeking a permit shield pursuant to paragraph (j) of subsection 7 of this Section shall request such permit shield in the CAAPP application regarding that source.

q. The Agency shall make available to the public all documents submitted by the applicant to the Agency, including each CAAPP application, compliance plan (including the schedule of compliance), and emissions or compliance monitoring report, with the exception of information entitled to confidential treatment pursuant to Section 7 of this Act.

r. The Agency shall use the standardized forms required under Title IV of the Clean Air Act and regulations promulgated thereunder for affected sources for acid deposition.

s. An owner or operator of a CAAPP source may include within its CAAPP application a request for permission to operate during a startup, malfunction, or breakdown consistent with applicable Board regulations.

t. An owner or operator of a CAAPP source, in order to utilize the operational flexibility provided under paragraph (l) of subsection 7 of this Section, must request such use and provide the necessary information within its CAAPP application.

u. An owner or operator of a CAAPP source which seeks exclusion from the CAAPP through the imposition of federally enforceable conditions, pursuant to paragraph (c) of subsection 3 of this Section, must request such exclusion within a CAAPP application submitted consistent with this subsection on or after the date that the CAAPP application for the source is due. Prior to such date, but in no case later than 9 months after the effective date of the CAAPP, such owner or operator may request the imposition of federally enforceable conditions pursuant to paragraph (b) of subsection 1.1 of this Section.

v. CAAPP applications shall contain accurate information on allowable emissions to implement the fee provisions of subsection 18 of this Section.

w. An owner or operator of a CAAPP source shall submit within its CAAPP application emissions information regarding all regulated air pollutants emitted at that source consistent with applicable Agency procedures. Emissions information regarding insignificant activities or emission levels, as determined by the Agency pursuant to Board regulations, may be submitted as a list within the CAAPP application. The Agency shall propose regulations to the Board defining insignificant activities or emission levels, consistent with federal regulations, if any, no later than 18 months after the effective date of Public Act 87-1213, consistent with Section 112(n)(1) of the Clean Air Act. The Board shall adopt final regulations defining insignificant activities or emission levels no later than 9 months after the date of the Agency's proposal.

x. The owner or operator of a new CAAPP source shall submit its complete CAAPP application consistent with this subsection within 12 months after commencing operation of such source. The owner or operator of an existing source that has been excluded from the provisions of this Section under subsection 1.1 or paragraph (c) of subsection 3 of this Section and that becomes subject to the CAAPP solely due to a change in operation at the source shall submit its complete CAAPP application consistent with this subsection at least 180 days before commencing operation in accordance with the change in operation.

y. The Agency shall have the authority to adopt procedural rules, in accordance with the Illinois Administrative Procedure Act, as the Agency deems necessary to implement this subsection.

6. Prohibitions.

a. It shall be unlawful for any person to violate any terms or conditions of a permit issued under this Section, to operate any CAAPP source except in compliance with a permit issued by the Agency under this Section or to violate any other applicable requirements. All terms and conditions of a permit issued under this Section are enforceable by USEPA and citizens under the Clean Air Act, except those, if any, that are specifically designated as not being federally enforceable in the permit pursuant to paragraph (m) of subsection 7 of this Section.

b. After the applicable CAAPP permit or renewal application submittal date, as specified in subsection 5 of this Section, no person shall operate a CAAPP source without a CAAPP permit unless the complete CAAPP permit or renewal application for such source has been timely submitted to the Agency.

c. No owner or operator of a CAAPP source shall cause or threaten or allow the continued operation of an emission source during malfunction or breakdown of the emission source or related air pollution control equipment if such operation would cause a violation of the standards or limitations applicable to the source, unless the CAAPP permit granted to the source provides for such operation consistent with this Act and applicable Board regulations.

7. Permit Content.

a. All CAAPP permits shall contain emission limitations and standards and other enforceable terms and conditions, including, but not limited to, operational requirements, and schedules for achieving compliance at the earliest reasonable date, which are or will be required to accomplish the purposes and provisions of this Act and to assure compliance with all applicable requirements.

b. The Agency shall include among such conditions applicable monitoring, reporting, recordkeeping, and compliance certification requirements, as authorized by paragraphs (d), (e), and (f) of this subsection, that the Agency deems necessary to assure compliance with the Clean Air Act, the regulations promulgated thereunder, this Act, and applicable Board regulations. When monitoring, reporting, recordkeeping, and compliance certification requirements are specified within the Clean Air Act, regulations promulgated thereunder, this Act, or applicable regulations, such requirements shall be included within the CAAPP permit. The Board shall have authority to promulgate additional regulations where necessary to accomplish the purposes of the Clean Air Act, this Act, and regulations promulgated thereunder.

c. The Agency shall assure, within such conditions, the use of terms, test methods, units, averaging periods, and other statistical conventions consistent with the applicable emission limitations, standards, and other requirements contained in the permit.

d. To meet the requirements of this subsection with respect to monitoring, the permit shall:

i. Incorporate and identify all applicable emissions monitoring and analysis procedures or test methods required under the Clean Air Act, regulations promulgated thereunder, this Act, and applicable Board regulations, including any procedures and methods promulgated by USEPA pursuant to Section 504(b) or Section 114 (a)(3) of the Clean Air Act.

ii. Where the applicable requirement does not require periodic testing or instrumental or noninstrumental monitoring (which may consist of recordkeeping designed to serve as monitoring), require periodic monitoring sufficient to yield reliable data from the relevant time period that is representative of the source's compliance with the permit, as reported pursuant to paragraph (f) of this subsection. The Agency may determine that recordkeeping requirements are sufficient to meet the requirements of this subparagraph.

iii. As necessary, specify requirements concerning the use, maintenance, and when appropriate, installation of monitoring equipment or methods.

e. To meet the requirements of this subsection with respect to recordkeeping, the permit shall incorporate and identify all applicable recordkeeping requirements and require, where applicable, the following:

i. Records of required monitoring information that include the following:

A. The date, place and time of sampling or measurements.

B. The date(s) analyses were performed.

C. The company or entity that performed the analyses.

D. The analytical techniques or methods used.

E. The results of such analyses.

F. The operating conditions as existing at the time of sampling or measurement.

ii. Retention of records of all monitoring data and support information for a period of at least 5 years from the date of the monitoring sample, measurement, report, or application. Support information includes all calibration and maintenance records, original strip-chart recordings for continuous monitoring instrumentation, and copies of all reports required by the permit.

f. To meet the requirements of this subsection with respect to reporting, the permit shall incorporate and identify all applicable reporting requirements and require the following:

i. Submittal of reports of any required monitoring every 6 months. More frequent submittals may be requested by the Agency if such submittals are necessary to assure compliance with this Act or regulations promulgated by the Board thereunder. All instances of deviations from permit requirements must be clearly identified in such reports. All required reports must be certified by a responsible official consistent with subsection 5 of this Section.

ii. Prompt reporting of deviations from permit requirements, including those attributable to upset conditions as defined in the permit, the probable cause of such deviations, and any corrective actions or preventive measures taken.

g. Each CAAPP permit issued under subsection 10 of this Section shall include a condition prohibiting emissions exceeding any allowances that the source lawfully holds under Title IV of the Clean Air Act or the regulations promulgated thereunder, consistent with subsection 17 of this Section and applicable regulations, if any.

h. All CAAPP permits shall state that, where another applicable requirement of the Clean Air Act is more stringent than any applicable requirement of regulations promulgated under Title IV of the Clean Air Act, both provisions shall be incorporated into the permit and shall be State and federally enforceable.

i. Each CAAPP permit issued under subsection 10 of this Section shall include a severability clause to ensure the continued validity of the various permit requirements in the event of a challenge to any portions of the permit.

j. The following shall apply with respect to owners or operators requesting a permit shield:

i. The Agency shall include in a CAAPP permit, when requested by an applicant pursuant to paragraph (p) of subsection 5 of this Section, a provision stating that compliance with the conditions of the permit shall be deemed compliance with applicable requirements which are applicable as of the date of release of the proposed permit, provided that:

A. The applicable requirement is specifically identified within the permit; or

B. The Agency in acting on the CAAPP application or revision determines in writing that other requirements specifically identified are not applicable to the source, and the permit includes that determination or a concise summary thereof.

ii. The permit shall identify the requirements for which the source is shielded. The shield shall not extend to applicable requirements which are promulgated after the date of release of the proposed permit unless the permit has been modified to reflect such new requirements.

iii. A CAAPP permit which does not expressly indicate the existence of a permit shield shall not provide such a shield.

iv. Nothing in this paragraph or in a CAAPP permit shall alter or affect the following:

A. The provisions of Section 303 (emergency powers) of the Clean Air Act, including USEPA's authority under that section.

B. The liability of an owner or operator of a source for any violation of applicable requirements prior to or at the time of permit issuance.

C. The applicable requirements of the acid rain program consistent with Section 408(a) of the Clean Air Act.

D. The ability of USEPA to obtain information from a source pursuant to Section 114 (inspections, monitoring, and entry) of the Clean Air Act.

k. Each CAAPP permit shall include an emergency provision providing an affirmative defense of emergency to an action brought for noncompliance with technology-based emission limitations under a CAAPP permit if the following conditions are met through properly signed, contemporaneous operating logs, or other relevant evidence:

i. An emergency occurred and the permittee can identify the cause(s) of the emergency.

ii. The permitted facility was at the time being properly operated.

iii. The permittee submitted notice of the emergency to the Agency within 2 working days after the time when emission limitations were exceeded due to the emergency. This notice must contain a detailed description of the emergency, any steps taken to mitigate emissions, and corrective actions taken.

iv. During the period of the emergency the permittee took all reasonable steps to minimize levels of emissions that exceeded the emission limitations, standards, or requirements in the permit.

For purposes of this subsection, "emergency" means any situation arising from sudden and reasonably unforeseeable events beyond the control of the source, such as an act of God, that requires immediate corrective action to restore normal operation, and that causes the source to exceed a technology-based emission limitation under the permit, due to unavoidable increases in emissions attributable to the emergency. An emergency shall not include noncompliance to the extent caused by improperly designed equipment, lack of preventative maintenance, careless or improper operation, or operation error.

In any enforcement proceeding, the permittee seeking to establish the occurrence of an emergency has the burden of proof. This provision is in addition to any emergency or upset provision contained in any applicable requirement. This provision does not relieve a permittee of any reporting obligations under existing federal or state laws or regulations.

l. The Agency shall include in each permit issued under subsection 10 of this Section:

i. Terms and conditions for reasonably anticipated operating scenarios identified by the source in its application. The permit terms and conditions for each such operating scenario shall meet all applicable requirements and the requirements of this Section.

A. Under this subparagraph, the source must record in a log at the permitted facility a record of the scenario under which it is operating contemporaneously with making a change from one operating scenario to another.

B. The permit shield described in paragraph (j) of subsection 7 of this Section shall extend to all terms and conditions under each such operating scenario.

ii. Where requested by an applicant, all terms and conditions allowing for trading of emissions increases and decreases between different emission units at the CAAPP source, to the extent that the applicable requirements provide for trading of such emissions increases and decreases without a case-by-case approval of each emissions trade. Such terms and conditions:

A. Shall include all terms required under this subsection to determine compliance;

B. Must meet all applicable requirements;

C. Shall extend the permit shield described in paragraph (j) of subsection 7 of this Section to all terms and conditions that allow such increases and decreases in emissions.

m. The Agency shall specifically designate as not being federally enforceable under the Clean Air Act any terms and conditions included in the permit that are not specifically required under the Clean Air Act or federal regulations promulgated thereunder. Terms or conditions so designated shall be subject to all applicable State requirements, except the requirements of subsection 7 (other than this paragraph, paragraph q of subsection 7, subsections 8 through 11, and subsections 13 through 16 of this Section). The Agency shall, however, include such terms and conditions in the CAAPP permit issued to the source.

n. Each CAAPP permit issued under subsection 10 of this Section shall specify and reference the origin of and authority for each term or condition, and identify any difference in form as compared to the applicable requirement upon which the term or condition is based.

o. Each CAAPP permit issued under subsection 10 of this Section shall include provisions stating the following:

i. Duty to comply. The permittee must comply with all terms and conditions of the CAAPP permit. Any permit noncompliance constitutes a violation of the Clean Air Act and the Act, and is grounds for any or all of the following: enforcement action; permit termination, revocation and reissuance, or modification; or denial of a permit renewal application.

ii. Need to halt or reduce activity not a defense. It shall not be a defense for a permittee in an enforcement action that it would have been necessary to halt or reduce the permitted activity in order to maintain compliance with the conditions of this permit.

iii. Permit actions. The permit may be modified, revoked, reopened, and reissued, or terminated for cause in accordance with the applicable subsections of this Section 39.5. The filing of a request by the permittee for a permit modification, revocation and reissuance, or termination, or of a notification of planned changes or anticipated noncompliance does not stay any permit condition.

iv. Property rights. The permit does not convey any property rights of any sort, or any exclusive privilege.

v. Duty to provide information. The permittee shall furnish to the Agency within a reasonable time specified by the Agency any information that the Agency may request in writing to determine whether cause exists for modifying, revoking and reissuing, or terminating the permit or to determine compliance with the permit. Upon request, the permittee shall also furnish to the Agency copies of records required to be kept by the permit or, for information claimed to be confidential, the permittee may furnish such records directly to USEPA along with a claim of confidentiality.

vi. Duty to pay fees. The permittee must pay fees to the Agency consistent with the fee schedule approved pursuant to subsection 18 of this Section, and submit any information relevant thereto.

vii. Emissions trading. No permit revision shall be required for increases in emissions allowed under any approved economic incentives, marketable permits, emissions trading, and other similar programs or processes for changes that are provided for in the permit and that are authorized by the applicable requirement.

p. Each CAAPP permit issued under subsection 10 of this Section shall contain the following elements with respect to compliance:

i. Compliance certification, testing, monitoring, reporting, and recordkeeping requirements sufficient to assure compliance with the terms and conditions of the permit. Any document (including reports) required by a CAAPP permit shall contain a certification by a responsible official that meets the requirements of subsection 5 of this Section and applicable regulations.

ii. Inspection and entry requirements that necessitate that, upon presentation of credentials and other documents as may be required by law and in accordance with constitutional limitations, the permittee shall allow the Agency, or an authorized representative to perform the following:

A. Enter upon the permittee's premises where a CAAPP source is located or emissions-related activity is conducted, or where records must be kept under the conditions of the permit.

B. Have access to and copy, at reasonable times, any records that must be kept under the conditions of the permit.

C. Inspect at reasonable times any facilities, equipment (including monitoring and air pollution control equipment), practices, or operations regulated or required under the permit.

D. Sample or monitor any substances or parameters at any location:

1. As authorized by the Clean Air Act, at reasonable times, for the purposes of assuring compliance with the CAAPP permit or applicable requirements; or

2. As otherwise authorized by this Act.

iii. A schedule of compliance consistent with subsection 5 of this Section and applicable regulations.

iv. Progress reports consistent with an applicable schedule of compliance pursuant to paragraph (d) of subsection 5 of this Section and applicable regulations to be submitted semiannually, or more frequently if the Agency determines that such more frequent submittals are necessary for compliance with the Act or regulations promulgated by the Board thereunder. Such progress reports shall contain the following:

A. Required dates for achieving the activities, milestones, or compliance required by the schedule of compliance and dates when such activities, milestones, or compliance were achieved.

B. An explanation of why any dates in the schedule of compliance were not or will not be met, and any preventive or corrective measures adopted.

v. Requirements for compliance certification with terms and conditions contained in the permit, including emission limitations, standards, or work practices. Permits shall include each of the following:

A. The frequency (annually or more frequently as specified in any applicable requirement or by the Agency pursuant to written procedures) of submissions of compliance certifications.

B. A means for assessing or monitoring the compliance of the source with its emissions limitations, standards, and work practices.

C. A requirement that the compliance certification include the following:

1. The identification of each term or condition contained in the permit that is the basis of the certification.

2. The compliance status.

3. Whether compliance was continuous or intermittent.

4. The method(s) used for determining the compliance status of the source, both currently and over the reporting period consistent with subsection 7 of this Section.

D. A requirement that all compliance certifications be submitted to the Agency.

E. Additional requirements as may be specified pursuant to Sections 114(a)(3) and 504(b) of the Clean Air Act.

F. Other provisions as the Agency may require.

q. If the owner or operator of CAAPP source can demonstrate in its CAAPP application, including an application for a significant modification, that an alternative emission limit would be equivalent to that contained in the applicable Board regulations, the Agency shall include the alternative emission limit in the CAAPP permit, which shall supersede the emission limit set forth in the applicable Board regulations, and shall include conditions that insure that the resulting emission limit is quantifiable, accountable, enforceable, and based on replicable procedures.

8. Public Notice; Affected State Review.

a. The Agency shall provide notice to the public, including an opportunity for public comment and a hearing, on each draft CAAPP permit for issuance, renewal, or significant modification, subject to Section 7.1 and subsection (a) of Section 7 of this Act.

b. The Agency shall prepare a draft CAAPP permit and a statement that sets forth the legal and factual basis for the draft CAAPP permit conditions, including references to the applicable statutory or regulatory provisions. The Agency shall provide this statement to any person who requests it.

c. The Agency shall give notice of each draft CAAPP permit to the applicant and to any affected State on or before the time that the Agency has provided notice to the public, except as otherwise provided in this Act.

d. The Agency, as part of its submittal of a proposed permit to USEPA (or as soon as possible after the submittal for minor permit modification procedures allowed under subsection 14 of this Section), shall notify USEPA and any affected State in writing of any refusal of the Agency to accept all of the recommendations for the proposed permit that an affected State submitted during the public or affected State review period. The notice shall include the Agency's reasons for not accepting the recommendations. The Agency is not required to accept recommendations that are not based on applicable requirements or the requirements of this Section.

e. The Agency shall make available to the public any CAAPP permit application, compliance plan (including the schedule of compliance), CAAPP permit, and emissions or compliance monitoring report. If an owner or operator of a CAAPP source is required to submit information entitled to protection from disclosure under Section 7.1 and subsection (a) of Section 7 of this Act, the owner or operator shall submit such information separately. The requirements of Section 7.1 and subsection (a) of Section 7 of this Act shall apply to such information, which shall not be included in a CAAPP permit unless required by law. The contents of a CAAPP permit shall not be entitled to protection under Section 7.1 and subsection (a) of Section 7 of this Act.

f. The Agency shall have the authority to adopt procedural rules, in accordance with the Illinois Administrative Procedure Act, as the Agency deems necessary, to implement this subsection.

g. If requested by the permit applicant, the Agency shall provide the permit applicant with a copy of the draft CAAPP permit prior to any public review period. If requested by the permit applicant, the Agency shall provide the permit applicant with a copy of the final CAAPP permit prior to issuance of the CAAPP permit.

9. USEPA Notice and Objection.

a. The Agency shall provide to USEPA for its review a copy of each CAAPP application (including any application for permit modification), statement of basis as provided in paragraph (b) of subsection 8 of this Section, proposed CAAPP permit, CAAPP permit, and, if the Agency does not incorporate any affected State's recommendations on a proposed CAAPP permit, a written statement of this decision and its reasons for not accepting the recommendations, except as otherwise provided in this Act or by agreement with USEPA. To the extent practicable, the preceding information shall be provided in computer readable format compatible with USEPA's national database management system.

b. The Agency shall not issue the proposed CAAPP permit if USEPA objects in writing within 45 days after receipt of the proposed CAAPP permit and all necessary supporting information.

c. If USEPA objects in writing to the issuance of the proposed CAAPP permit within the 45-day period, the Agency shall respond in writing and may revise and resubmit the proposed CAAPP permit in response to the stated objection, to the extent supported by the record, within 90 days after the date of the objection. Prior to submitting a revised permit to USEPA, the Agency shall provide the applicant and any person who participated in the public comment process, pursuant to subsection 8 of this Section, with a 10-day period to comment on any revision which the Agency is proposing to make to the permit in response to USEPA's objection in accordance with Agency procedures.

d. Any USEPA objection under this subsection, according to the Clean Air Act, will include a statement of reasons for the objection and a description of the terms and conditions that must be in the permit, in order to adequately respond to the objections. Grounds for a USEPA objection include the failure of the Agency to: (1) submit the items and notices required under this subsection; (2) submit any other information necessary to adequately review the proposed CAAPP permit; or (3) process the permit under subsection 8 of this Section except for minor permit modifications.

e. If USEPA does not object in writing to issuance of a permit under this subsection, any person may petition USEPA within 60 days after expiration of the 45-day review period to make such objection.

f. If the permit has not yet been issued and USEPA objects to the permit as a result of a petition, the Agency shall not issue the permit until USEPA's objection has been resolved. The Agency shall provide a 10-day comment period in accordance with paragraph c of this subsection. A petition does not, however, stay the effectiveness of a permit or its requirements if the permit was issued after expiration of the 45-day review period and prior to a USEPA objection.

g. If the Agency has issued a permit after expiration of the 45-day review period and prior to receipt of a USEPA objection under this subsection in response to a petition submitted pursuant to paragraph e of this subsection, the Agency may, upon receipt of an objection from USEPA, revise and resubmit the permit to USEPA pursuant to this subsection after providing a 10-day comment period in accordance with paragraph c of this subsection. If the Agency fails to submit a revised permit in response to the objection, USEPA shall modify, terminate, or revoke the permit. In any case, the source will not be in violation of the requirement to have submitted a timely and complete application.

h. The Agency shall have the authority to adopt procedural rules, in accordance with the Illinois Administrative Procedure Act, as the Agency deems necessary, to implement this subsection.

10. Final Agency Action.

a. The Agency shall issue a CAAPP permit, permit modification, or permit renewal if all of the following conditions are met:

i. The applicant has submitted a complete and certified application for a permit, permit modification, or permit renewal consistent with subsections 5 and 14 of this Section, as applicable, and applicable regulations.

ii. The applicant has submitted with its complete application an approvable compliance plan, including a schedule for achieving compliance, consistent with subsection 5 of this Section and applicable regulations.

iii. The applicant has timely paid the fees required pursuant to subsection 18 of this Section and applicable regulations.

iv. The Agency has received a complete CAAPP application and, if necessary, has requested and received additional information from the applicant consistent with subsection 5 of this Section and applicable regulations.

v. The Agency has complied with all applicable provisions regarding public notice and affected State review consistent with subsection 8 of this Section and applicable regulations.

vi. The Agency has provided a copy of each CAAPP application, or summary thereof, pursuant to agreement with USEPA and proposed CAAPP permit required under subsection 9 of this Section to USEPA, and USEPA has not objected to the issuance of the permit in accordance with the Clean Air Act and 40 CFR Part 70.

b. The Agency shall have the authority to deny a CAAPP permit, permit modification, or permit renewal if the applicant has not complied with the requirements of subparagraphs (i) through (iv) of paragraph (a) of this subsection or if USEPA objects to its issuance.

c. i. Prior to denial of a CAAPP permit, permit modification, or permit renewal under this Section, the Agency shall notify the applicant of the possible denial and the reasons for the denial.

ii. Within such notice, the Agency shall specify an appropriate date by which the applicant shall adequately respond to the Agency's notice. Such date shall not exceed 15 days from the date the notification is received by the applicant. The Agency may grant a reasonable extension for good cause shown.

iii. Failure by the applicant to adequately respond by the date specified in the notification or by any granted extension date shall be grounds for denial of the permit.

For purposes of obtaining judicial review under Sections 40.2 and 41 of this Act, the Agency shall provide to USEPA and each applicant, and, upon request, to affected States, any person who participated in the public comment process, and any other person who could obtain judicial review under Sections 40.2 and 41 of this Act, a copy of each CAAPP permit or notification of denial pertaining to that party.

d. The Agency shall have the authority to adopt procedural rules, in accordance with the Illinois Administrative Procedure Act, as the Agency deems necessary, to implement this subsection.

11. General Permits.

a. The Agency may issue a general permit covering numerous similar sources, except for affected sources for acid deposition unless otherwise provided in regulations promulgated under Title IV of the Clean Air Act.

b. The Agency shall identify, in any general permit, criteria by which sources may qualify for the general permit.

c. CAAPP sources that would qualify for a general permit must apply for coverage under the terms of the general permit or must apply for a CAAPP permit consistent with subsection 5 of this Section and applicable regulations.

d. The Agency shall comply with the public comment and hearing provisions of this Section as well as the USEPA and affected State review procedures prior to issuance of a general permit.

e. When granting a subsequent request by a qualifying CAAPP source for coverage under the terms of a general permit, the Agency shall not be required to repeat the public notice and comment procedures. The granting of such request shall not be considered a final permit action for purposes of judicial review.

f. The Agency may not issue a general permit to cover any discrete emission unit at a CAAPP source if another CAAPP permit covers emission units at the source.

g. The Agency shall have the authority to adopt procedural rules, in accordance with the Illinois Administrative Procedure Act, as the Agency deems necessary, to implement this subsection.

12. Operational Flexibility.

a. An owner or operator of a CAAPP source may make changes at the CAAPP source without requiring a prior permit revision, consistent with subparagraphs (i) through (iii) of paragraph (a) of this subsection, so long as the changes are not modifications under any provision of Title I of the Clean Air Act and they do not exceed the emissions allowable under the permit (whether expressed therein as a rate of emissions or in terms of total emissions), provided that the owner or operator of the CAAPP source provides USEPA and the Agency with written notification as required below in advance of the proposed changes, which shall be a minimum of 7 days, unless otherwise provided by the Agency in applicable regulations regarding emergencies. The owner or operator of a CAAPP source and the Agency shall each attach such notice to their copy of the relevant permit.

i. An owner or operator of a CAAPP source may make Section 502 (b) (10) changes without a permit revision, if the changes are not modifications under any provision of Title I of the Clean Air Act and the changes do not exceed the emissions allowable under the permit (whether expressed therein as a rate of emissions or in terms of total emissions).

A. For each such change, the written notification required above shall include a brief description of the change within the source, the date on which the change will occur, any change in emissions, and any permit term or condition that is no longer applicable as a result of the change.

B. The permit shield described in paragraph (j) of subsection 7 of this Section shall not apply to any change made pursuant to this subparagraph.

ii. An owner or operator of a CAAPP source may trade increases and decreases in emissions in the CAAPP source, where the applicable implementation plan provides for such emission trades without requiring a permit revision. This provision is available in those cases where the permit does not already provide for such emissions trading.

A. Under this subparagraph (ii) of paragraph (a) of this subsection, the written notification required above shall include such information as may be required by the provision in the applicable implementation plan authorizing the emissions trade, including, at a minimum, when the proposed changes will occur, a description of each such change, any change in emissions, the permit requirements with which the source will comply using the emissions trading provisions of the applicable implementation plan, and the pollutants emitted subject to the emissions trade. The notice shall also refer to the provisions in the applicable implementation plan with which the source will comply and provide for the emissions trade.

B. The permit shield described in paragraph (j) of subsection 7 of this Section shall not apply to any change made pursuant to subparagraph (ii) of paragraph (a) of this subsection. Compliance with the permit requirements that the source will meet using the emissions trade shall be determined according to the requirements of the applicable implementation plan authorizing the emissions trade.

iii. If requested within a CAAPP application, the Agency shall issue a CAAPP permit which contains terms and conditions, including all terms required under subsection 7 of this Section to determine compliance, allowing for the trading of emissions increases and decreases at the CAAPP source solely for the purpose of complying with a federally enforceable emissions cap that is established in the permit independent of otherwise applicable requirements. The owner or operator of a CAAPP source shall include in its CAAPP application proposed replicable procedures and permit terms that ensure the emissions trades are quantifiable and enforceable. The permit shall also require compliance with all applicable requirements.

A. Under this subparagraph (iii) of paragraph (a), the written notification required above shall state when the change will occur and shall describe the changes in emissions that will result and how these increases and decreases in emissions will comply with the terms and conditions of the permit.

B. The permit shield described in paragraph (j) of subsection 7 of this Section shall extend to terms and conditions that allow such increases and decreases in emissions.

b. An owner or operator of a CAAPP source may make changes that are not addressed or prohibited by the permit, other than those which are subject to any requirements under Title IV of the Clean Air Act or are modifications under any provisions of Title I of the Clean Air Act, without a permit revision, in accordance with the following requirements:

(i) Each such change shall meet all applicable requirements and shall not violate any existing permit term or condition;

(ii) Sources must provide contemporaneous written notice to the Agency and USEPA of each such change, except for changes that qualify as insignificant under provisions adopted by the Agency or the Board. Such written notice shall describe each such change, including the date, any change in emissions, pollutants emitted, and any applicable requirement that would apply as a result of the change;

(iii) The change shall not qualify for the shield described in paragraph (j) of subsection 7 of this Section; and

(iv) The permittee shall keep a record describing changes made at the source that result in emissions of a regulated air pollutant subject to an applicable Clean Air Act requirement, but not otherwise regulated under the permit, and the emissions resulting from those changes.

c. The Agency shall have the authority to adopt procedural rules, in accordance with the Illinois Administrative Procedure Act, as the Agency deems necessary to implement this subsection.

13. Administrative Permit Amendments.

a. The Agency shall take final action on a request for an administrative permit amendment within 60 days after receipt of the request. Neither notice nor an opportunity for public and affected State comment shall be required for the Agency to incorporate such revisions, provided it designates the permit revisions as having been made pursuant to this subsection.

b. The Agency shall submit a copy of the revised permit to USEPA.

c. For purposes of this Section the term "administrative permit amendment" shall be defined as a permit revision that can accomplish one or more of the changes described below:

i. Corrects typographical errors;

ii. Identifies a change in the name, address, or phone number of any person identified in the permit, or provides a similar minor administrative change at the source;

iii. Requires more frequent monitoring or reporting by the permittee;

iv. Allows for a change in ownership or operational control of a source where the Agency determines that no other change in the permit is necessary, provided that a written agreement containing a specific date for transfer of permit responsibility, coverage, and liability between the current and new permittees has been submitted to the Agency;

v. Incorporates into the CAAPP permit the requirements from preconstruction review permits authorized under a USEPA-approved program, provided the program meets procedural and compliance requirements substantially equivalent to those contained in this Section;

vi. (Blank); or

vii. Any other type of change which USEPA has determined as part of the approved CAAPP permit program to be similar to those included in this subsection.

d. The Agency shall, upon taking final action granting a request for an administrative permit amendment, allow coverage by the permit shield in paragraph (j) of subsection 7 of this Section for administrative permit amendments made pursuant to subparagraph (v) of paragraph (c) of this subsection which meet the relevant requirements for significant permit modifications.

e. Permit revisions and modifications, including administrative amendments and automatic amendments (pursuant to Sections 408(b) and 403(d) of the Clean Air Act or regulations promulgated thereunder), for purposes of the acid rain portion of the permit shall be governed by the regulations promulgated under Title IV of the Clean Air Act. Owners or operators of affected sources for acid deposition shall have the flexibility to amend their compliance plans as provided in the regulations promulgated under Title IV of the Clean Air Act.

f. The CAAPP source may implement the changes addressed in the request for an administrative permit amendment immediately upon submittal of the request.

g. The Agency shall have the authority to adopt procedural rules, in accordance with the Illinois Administrative Procedure Act, as the Agency deems necessary, to implement this subsection.

14. Permit Modifications.

a. Minor permit modification procedures.

i. The Agency shall review a permit modification using the "minor permit" modification procedures only for those permit modifications that:

A. Do not violate any applicable requirement;

B. Do not involve significant changes to existing monitoring, reporting, or recordkeeping requirements in the permit;

C. Do not require a case-by-case determination of an emission limitation or other standard, or a source-specific determination of ambient impacts, or a visibility or increment analysis;

D. Do not seek to establish or change a permit term or condition for which there is no corresponding underlying requirement and which avoids an applicable requirement to which the source would otherwise be subject. Such terms and conditions include:

1. A federally enforceable emissions cap assumed to avoid classification as a modification under any provision of Title I of the Clean Air Act; and

2. An alternative emissions limit approved pursuant to regulations promulgated under Section 112(i)(5) of the Clean Air Act;

E. Are not modifications under any provision of Title I of the Clean Air Act; and

F. Are not required to be processed as a significant modification.

ii. Notwithstanding subparagraph (i) of paragraph (a) and subparagraph (ii) of paragraph (b) of this subsection, minor permit modification procedures may be used for permit modifications involving the use of economic incentives, marketable permits, emissions trading, and other similar approaches, to the extent that such minor permit modification procedures are explicitly provided for in an applicable implementation plan or in applicable requirements promulgated by USEPA.

iii. An applicant requesting the use of minor permit modification procedures shall meet the requirements of subsection 5 of this Section and shall include the following in its application:

A. A description of the change, the emissions resulting from the change, and any new applicable requirements that will apply if the change occurs;

B. The source's suggested draft permit;

C. Certification by a responsible official, consistent with paragraph (e) of subsection 5 of this Section and applicable regulations, that the proposed modification meets the criteria for use of minor permit modification procedures and a request that such procedures be used; and

D. Completed forms for the Agency to use to notify USEPA and affected States as required under subsections 8 and 9 of this Section.

iv. Within 5 working days after receipt of a complete permit modification application, the Agency shall notify USEPA and affected States of the requested permit modification in accordance with subsections 8 and 9 of this Section. The Agency promptly shall send any notice required under paragraph (d) of subsection 8 of this Section to USEPA.

v. The Agency may not issue a final permit modification until after the 45-day review period for USEPA or until USEPA has notified the Agency that USEPA will not object to the issuance of the permit modification, whichever comes first, although the Agency can approve the permit modification prior to that time. Within 90 days after the Agency's receipt of an application under the minor permit modification procedures or 15 days after the end of USEPA's 45-day review period under subsection 9 of this Section, whichever is later, the Agency shall:

A. Issue the permit modification as proposed;

B. Deny the permit modification application;

C. Determine that the requested modification does not meet the minor permit modification criteria and should be reviewed under the significant modification procedures; or

D. Revise the draft permit modification and transmit to USEPA the new proposed permit modification as required by subsection 9 of this Section.

vi. Any CAAPP source may make the change proposed in its minor permit modification application immediately after it files such application. After the CAAPP source makes the change allowed by the preceding sentence, and until the Agency takes any of the actions specified in items (A) through (C) of subparagraph (v) of paragraph (a) of this subsection, the source must comply with both the applicable requirements governing the change and the proposed permit terms and conditions. During this time period, the source need not comply with the existing permit terms and conditions it seeks to modify. If the source fails to comply with its proposed permit terms and conditions during this time period, the existing permit terms and conditions which it seeks to modify may be enforced against it.

vii. The permit shield under paragraph (j) of subsection 7 of this Section may not extend to minor permit modifications.

viii. If a construction permit is required, pursuant to subsection (a) of Section 39 of this Act and regulations thereunder, for a change for which the minor permit modification procedures are applicable, the source may request that the processing of the construction permit application be consolidated with the processing of the application for the minor permit modification. In such cases, the provisions of this Section, including those within subsections 5, 8, and 9, shall apply and the Agency shall act on such applications pursuant to subparagraph (v) of paragraph (a) of subsection 14 of this Section. The source may make the proposed change immediately after filing its application for the minor permit modification. Nothing in this subparagraph shall otherwise affect the requirements and procedures applicable to construction permits.

b. Group Processing of Minor Permit Modifications.

i. Where requested by an applicant within its application, the Agency shall process groups of a source's applications for certain modifications eligible for minor permit modification processing in accordance with the provisions of this paragraph (b).

ii. Permit modifications may be processed in accordance with the procedures for group processing, for those modifications:

A. Which meet the criteria for minor permit modification procedures under subparagraph (i) of paragraph (a) of subsection 14 of this Section; and

B. That collectively are below 10 percent of the emissions allowed by the permit for the emissions unit for which change is requested, 20 percent of the applicable definition of major source set forth in subsection 2 of this Section, or 5 tons per year, whichever is least.

iii. An applicant requesting the use of group processing procedures shall meet the requirements of subsection 5 of this Section and shall include the following in its application:

A. A description of the change, the emissions resulting from the change, and any new applicable requirements that will apply if the change occurs.

B. The source's suggested draft permit.

C. Certification by a responsible official consistent with paragraph (e) of subsection 5 of this Section, that the proposed modification meets the criteria for use of group processing procedures and a request that such procedures be used.

D. A list of the source's other pending applications awaiting group processing, and a determination of whether the requested modification, aggregated with these other applications, equals or exceeds the threshold set under item (B) of subparagraph (ii) of paragraph (b) of this subsection.

E. Certification, consistent with paragraph (e) of subsection 5 of this Section, that the source has notified USEPA of the proposed modification. Such notification need only contain a brief description of the requested modification.

F. Completed forms for the Agency to use to notify USEPA and affected states as required under subsections 8 and 9 of this Section.

iv. On a quarterly basis or within 5 business days after receipt of an application demonstrating that the aggregate of a source's pending applications equals or exceeds the threshold level set forth within item (B) of subparagraph (ii) of paragraph (b) of this subsection, whichever is earlier, the Agency shall promptly notify USEPA and affected States of the requested permit modifications in accordance with subsections 8 and 9 of this Section. The Agency shall send any notice required under paragraph (d) of subsection 8 of this Section to USEPA.

v. The provisions of subparagraph (v) of paragraph (a) of this subsection shall apply to modifications eligible for group processing, except that the Agency shall take one of the actions specified in items (A) through (D) of subparagraph (v) of paragraph (a) of this subsection within 180 days after receipt of the application or 15 days after the end of USEPA's 45-day review period under subsection 9 of this Section, whichever is later.

vi. The provisions of subparagraph (vi) of paragraph (a) of this subsection shall apply to modifications for group processing.

vii. The provisions of paragraph (j) of subsection 7 of this Section shall not apply to modifications eligible for group processing.

c. Significant Permit Modifications.

i. Significant modification procedures shall be used for applications requesting significant permit modifications and for those applications that do not qualify as either minor permit modifications or as administrative permit amendments.

ii. Every significant change in existing monitoring permit terms or conditions and every relaxation of reporting or recordkeeping requirements shall be considered significant. A modification shall also be considered significant if in the judgment of the Agency action on an application for modification would require decisions to be made on technically complex issues. Nothing herein shall be construed to preclude the permittee from making changes consistent with this Section that would render existing permit compliance terms and conditions irrelevant.

iii. Significant permit modifications must meet all the requirements of this Section, including those for applications (including completeness review), public participation, review by affected States, and review by USEPA applicable to initial permit issuance and permit renewal. The Agency shall take final action on significant permit modifications within 9 months after receipt of a complete application.

d. The Agency shall have the authority to adopt procedural rules, in accordance with the Illinois Administrative Procedure Act, as the Agency deems necessary, to implement this subsection.

15. Reopenings for Cause by the Agency.

a. Each issued CAAPP permit shall include provisions specifying the conditions under which the permit will be reopened prior to the expiration of the permit. Such revisions shall be made as expeditiously as practicable. A CAAPP permit shall be reopened and revised under any of the following circumstances, in accordance with procedures adopted by the Agency:

i. Additional requirements under the Clean Air Act become applicable to a major CAAPP source for which 3 or more years remain on the original term of the permit. Such a reopening shall be completed not later than 18 months after the promulgation of the applicable requirement. No such revision is required if the effective date of the requirement is later than the date on which the permit is due to expire.

ii. Additional requirements (including excess emissions requirements) become applicable to an affected source for acid deposition under the acid rain program. Excess emissions offset plans shall be deemed to be incorporated into the permit upon approval by USEPA.

iii. The Agency or USEPA determines that the permit contains a material mistake or that inaccurate statements were made in establishing the emissions standards, limitations, or other terms or conditions of the permit.

iv. The Agency or USEPA determines that the permit must be revised or revoked to assure compliance with the applicable requirements.

b. In the event that the Agency determines that there are grounds for revoking a CAAPP permit, for cause, consistent with paragraph a of this subsection, it shall file a petition before the Board setting forth the basis for such revocation. In any such proceeding, the Agency shall have the burden of establishing that the permit should be revoked under the standards set forth in this Act and the Clean Air Act. Any such proceeding shall be conducted pursuant to the Board's procedures for adjudicatory hearings and the Board shall render its decision within 120 days of the filing of the petition. The Agency shall take final action to revoke and reissue a CAAPP permit consistent with the Board's order.

c. Proceedings regarding a reopened CAAPP permit shall follow the same procedures as apply to initial permit issuance and shall affect only those parts of the permit for which cause to reopen exists.

d. Reopenings under paragraph (a) of this subsection shall not be initiated before a notice of such intent is provided to the CAAPP source by the Agency at least 30 days in advance of the date that the permit is to be reopened, except that the Agency may provide a shorter time period in the case of an emergency.

e. The Agency shall have the authority to adopt procedural rules, in accordance with the Illinois Administrative Procedure Act, as the Agency deems necessary, to implement this subsection.

16. Reopenings for Cause by USEPA.

a. When USEPA finds that cause exists to terminate, modify, or revoke and reissue a CAAPP permit pursuant to subsection 15 of this Section, and thereafter notifies the Agency and the permittee of such finding in writing, the Agency shall forward to USEPA and the permittee a proposed determination of termination, modification, or revocation and reissuance as appropriate, in accordance with paragraph (b) of this subsection. The Agency's proposed determination shall be in accordance with the record, the Clean Air Act, regulations promulgated thereunder, this Act and regulations promulgated thereunder. Such proposed determination shall not affect the permit or constitute a final permit action for purposes of this Act or the Administrative Review Law. The Agency shall forward to USEPA such proposed determination within 90 days after receipt of the notification from USEPA. If additional time is necessary to submit the proposed determination, the Agency shall request a 90-day extension from USEPA and shall submit the proposed determination within 180 days after receipt of notification from USEPA.

b. i. Prior to the Agency's submittal to USEPA of a proposed determination to terminate or revoke and reissue the permit, the Agency shall file a petition before the Board setting forth USEPA's objection, the permit record, the Agency's proposed determination, and the justification for its proposed determination. The Board shall conduct a hearing pursuant to the rules prescribed by Section 32 of this Act, and the burden of proof shall be on the Agency.

ii. After due consideration of the written and oral statements, the testimony and arguments that shall be submitted at hearing, the Board shall issue and enter an interim order for the proposed determination, which shall set forth all changes, if any, required in the Agency's proposed determination. The interim order shall comply with the requirements for final orders as set forth in Section 33 of this Act. Issuance of an interim order by the Board under this paragraph, however, shall not affect the permit status and does not constitute a final action for purposes of this Act or the Administrative Review Law.

iii. The Board shall cause a copy of its interim order to be served upon all parties to the proceeding as well as upon USEPA. The Agency shall submit the proposed determination to USEPA in accordance with the Board's Interim Order within 180 days after receipt of the notification from USEPA.

c. USEPA shall review the proposed determination to terminate, modify, or revoke and reissue the permit within 90 days after receipt.

i. When USEPA reviews the proposed determination to terminate or revoke and reissue and does not object, the Board shall, within 7 days after receipt of USEPA's final approval, enter the interim order as a final order. The final order may be appealed as provided by Title XI of this Act. The Agency shall take final action in accordance with the Board's final order.

ii. When USEPA reviews such proposed determination to terminate or revoke and reissue and objects, the Agency shall submit USEPA's objection and the Agency's comments and recommendation on the objection to the Board and permittee. The Board shall review its interim order in response to USEPA's objection and the Agency's comments and recommendation and issue a final order in accordance with Sections 32 and 33 of this Act. The Agency shall, within 90 days after receipt of such objection, respond to USEPA's objection in accordance with the Board's final order.

iii. When USEPA reviews such proposed determination to modify and objects, the Agency shall, within 90 days after receipt of the objection, resolve the objection and modify the permit in accordance with USEPA's objection, based upon the record, the Clean Air Act, regulations promulgated thereunder, this Act, and regulations promulgated thereunder.

d. If the Agency fails to submit the proposed determination pursuant to paragraph a of this subsection or fails to resolve any USEPA objection pursuant to paragraph c of this subsection, USEPA will terminate, modify, or revoke and reissue the permit.

e. The Agency shall have the authority to adopt procedural rules, in accordance with the Illinois Administrative Procedure Act, as the Agency deems necessary, to implement this subsection.

17. Title IV; Acid Rain Provisions.

a. The Agency shall act on initial CAAPP applications for affected sources for acid deposition in accordance with this Section and Title V of the Clean Air Act and regulations promulgated thereunder, except as modified by Title IV of the Clean Air Act and regulations promulgated thereunder. The Agency shall issue initial CAAPP permits to the affected sources for acid deposition which shall become effective no earlier than January 1, 1995, and which shall terminate on December 31, 1999, in accordance with this Section. Subsequent CAAPP permits issued to affected sources for acid deposition shall be issued for a fixed term of 5 years. Title IV of the Clean Air Act and regulations promulgated thereunder, including, but not limited to, 40 CFR Part 72, as now or hereafter amended, are applicable to and enforceable under this Act.

b. A designated representative of an affected source for acid deposition shall submit a timely and complete Phase II acid rain permit application and compliance plan to the Agency, not later than January 1, 1996, that meets the requirements of Titles IV and V of the Clean Air Act and regulations. The Agency shall act on the Phase II acid rain permit application and compliance plan in accordance with this Section and Title V of the Clean Air Act and regulations promulgated thereunder, except as modified by Title IV of the Clean Air Act and regulations promulgated thereunder. The Agency shall issue the Phase II acid rain permit to an affected source for acid deposition no later than December 31, 1997, which shall become effective on January 1, 2000, in accordance with this Section, except as modified by Title IV and regulations promulgated thereunder; provided that the designated representative of the source submitted a timely and complete Phase II permit application and compliance plan to the Agency that meets the requirements of Title IV and V of the Clean Air Act and regulations.

c. Each Phase II acid rain permit issued in accordance with this subsection shall have a fixed term of 5 years. Except as provided in paragraph b above, the Agency shall issue or deny a Phase II acid rain permit within 18 months of receiving a complete Phase II permit application and compliance plan.

d. A designated representative of a new unit, as defined in Section 402 of the Clean Air Act, shall submit a timely and complete Phase II acid rain permit application and compliance plan that meets the requirements of Titles IV and V of the Clean Air Act and its regulations. The Agency shall act on the new unit's Phase II acid rain permit application and compliance plan in accordance with this Section and Title V of the Clean Air Act and its regulations, except as modified by Title IV of the Clean Air Act and its regulations. The Agency shall reopen the new unit's CAAPP permit for cause to incorporate the approved Phase II acid rain permit in accordance with this Section. The Phase II acid rain permit for the new unit shall become effective no later than the date required under Title IV of the Clean Air Act and its regulations.

e. A designated representative of an affected source for acid deposition shall submit a timely and complete Title IV NOx permit application to the Agency, not later than January 1, 1998, that meets the requirements of Titles IV and V of the Clean Air Act and its regulations. The Agency shall reopen the Phase II acid rain permit for cause and incorporate the approved NOx provisions into the Phase II acid rain permit not later than January 1, 1999, in accordance with this Section, except as modified by Title IV of the Clean Air Act and regulations promulgated thereunder. Such reopening shall not affect the term of the Phase II acid rain permit.

f. The designated representative of the affected source for acid deposition shall renew the initial CAAPP permit and Phase II acid rain permit in accordance with this Section and Title V of the Clean Air Act and regulations promulgated thereunder, except as modified by Title IV of the Clean Air Act and regulations promulgated thereunder.

g. In the case of an affected source for acid deposition for which a complete Phase II acid rain permit application and compliance plan are timely received under this subsection, the complete permit application and compliance plan, including amendments thereto, shall be binding on the owner, operator and designated representative, all affected units for acid deposition at the affected source, and any other unit, as defined in Section 402 of the Clean Air Act, governed by the Phase II acid rain permit application and shall be enforceable as an acid rain permit for purposes of Titles IV and V of the Clean Air Act, from the date of submission of the acid rain permit application until a Phase II acid rain permit is issued or denied by the Agency.

h. The Agency shall not include or implement any measure which would interfere with or modify the requirements of Title IV of the Clean Air Act or regulations promulgated thereunder.

i. Nothing in this Section shall be construed as affecting allowances or USEPA's decision regarding an excess emissions offset plan, as set forth in Title IV of the Clean Air Act or regulations promulgated thereunder.

i. No permit revision shall be required for increases in emissions that are authorized by allowances acquired pursuant to the acid rain program, provided that such increases do not require a permit revision under any other applicable requirement.

ii. No limit shall be placed on the number of allowances held by the source. The source may not, however, use allowances as a defense to noncompliance with any other applicable requirement.

iii. Any such allowance shall be accounted for according to the procedures established in regulations promulgated under Title IV of the Clean Air Act.

j. To the extent that the federal regulations promulgated under Title IV, including, but not limited to, 40 CFR Part 72, as now or hereafter amended, are inconsistent with the federal regulations promulgated under Title V, the federal regulations promulgated under Title IV shall take precedence.

k. The USEPA may intervene as a matter of right in any permit appeal involving a Phase II acid rain permit provision or denial of a Phase II acid rain permit.

l. It is unlawful for any owner or operator to violate any terms or conditions of a Phase II acid rain permit issued under this subsection, to operate any affected source for acid deposition except in compliance with a Phase II acid rain permit issued by the Agency under this subsection, or to violate any other applicable requirements.

m. The designated representative of an affected source for acid deposition shall submit to the Agency the data and information submitted quarterly to USEPA, pursuant to 40 CFR 75.64, concurrently with the submission to USEPA. The submission shall be in the same electronic format as specified by USEPA.

n. The Agency shall act on any petition for exemption of a new unit or retired unit, as those terms are defined in Section 402 of the Clean Air Act, from the requirements of the acid rain program in accordance with Title IV of the Clean Air Act and its regulations.

o. The Agency shall have the authority to adopt procedural rules, in accordance with the Illinois Administrative Procedure Act, as the Agency deems necessary to implement this subsection.

18. Fee Provisions.

a. A source subject to this Section or excluded under subsection 1.1 or paragraph (c) of subsection 3 of this Section, shall pay a fee as provided in this paragraph (a) of subsection 18. However, a source that has been excluded from the provisions of this Section under subsection 1.1 or under paragraph (c) of subsection 3 of this Section because the source emits less than 25 tons per year of any combination of regulated air pollutants, except greenhouse gases, shall pay fees in accordance with paragraph (1) of subsection (b) of Section 9.6.

i. The fee for a source allowed to emit less than 100 tons per year of any combination of regulated air pollutants, except greenhouse gases, shall be $1,800 per year, and that fee shall increase, beginning January 1, 2012, to $2,150 per year.

ii. The fee for a source allowed to emit 100 tons or more per year of any combination of regulated air pollutants, except greenhouse gases and those regulated air pollutants excluded in paragraph (f) of this subsection 18, shall be as follows:

A. The Agency shall assess a fee of $18 per ton, per year for the allowable emissions of regulated air pollutants subject to this subparagraph (ii) of paragraph (a) of subsection 18, and that fee shall increase, beginning January 1, 2012, to $21.50 per ton, per year. These fees shall be used by the Agency and the Board to fund the activities required by Title V of the Clean Air Act including such activities as may be carried out by other State or local agencies pursuant to paragraph (d) of this subsection. The amount of such fee shall be based on the information supplied by the applicant in its complete CAAPP permit application or in the CAAPP permit if the permit has been granted and shall be determined by the amount of emissions that the source is allowed to emit annually, provided however, that the maximum fee for a CAAPP permit under this subparagraph (ii) of paragraph (a) of subsection 18 is $250,000, and increases, beginning January 1, 2012, to $294,000. Beginning January 1, 2012, the maximum fee under this subparagraph (ii) of paragraph (a) of subsection 18 for a source that has been excluded under subsection 1.1 of this Section or under paragraph (c) of subsection 3 of this Section is $4,112. The Agency shall provide as part of the permit application form required under subsection 5 of this Section a separate fee calculation form which will allow the applicant to identify the allowable emissions and calculate the fee. In no event shall the Agency raise the amount of allowable emissions requested by the applicant unless such increases are required to demonstrate compliance with terms of a CAAPP permit.

Notwithstanding the above, any applicant may seek a change in its permit which would result in increases in allowable emissions due to an increase in the hours of operation or production rates of an emission unit or units and such a change shall be consistent with the construction permit requirements of the existing State permit program, under subsection (a) of Section 39 of this Act and applicable provisions of this Section. Where a construction permit is required, the Agency shall expeditiously grant such construction permit and shall, if necessary, modify the CAAPP permit based on the same application.

B. The applicant or permittee may pay the fee annually or semiannually for those fees greater than $5,000. However, any applicant paying a fee equal to or greater than $100,000 shall pay the full amount on July 1, for the subsequent fiscal year, or pay 50% of the fee on July 1 and the remaining 50% by the next January 1. The Agency may change any annual billing date upon reasonable notice, but shall prorate the new bill so that the permittee or applicant does not pay more than its required fees for the fee period for which payment is made.

b. (Blank).

c. (Blank).

d. There is hereby created in the State Treasury a special fund to be known as the Clean Air Act Permit Fund (formerly known as the CAA Permit Fund). All Funds collected by the Agency pursuant to this subsection shall be deposited into the Fund. The General Assembly shall appropriate monies from this Fund to the Agency and to the Board to carry out their obligations under this Section. The General Assembly may also authorize monies to be granted by the Agency from this Fund to other State and local agencies which perform duties related to the CAAPP. Interest generated on the monies deposited in this Fund shall be returned to the Fund.

e. The Agency shall have the authority to adopt procedural rules, in accordance with the Illinois Administrative Procedure Act, as the Agency deems necessary to implement this subsection.

f. For purposes of this subsection, the term "regulated air pollutant" shall have the meaning given to it under subsection 1 of this Section but shall exclude the following:

i. carbon monoxide;

ii. any Class I or II substance which is a regulated air pollutant solely because it is listed pursuant to Section 602 of the Clean Air Act; and

iii. any pollutant that is a regulated air pollutant solely because it is subject to a standard or regulation under Section 112(r) of the Clean Air Act based on the emissions allowed in the permit effective in that calendar year, at the time the applicable bill is generated.

19. Air Toxics Provisions.

a. In the event that the USEPA fails to promulgate in a timely manner a standard pursuant to Section 112(d) of the Clean Air Act, the Agency shall have the authority to issue permits, pursuant to Section 112(j) of the Clean Air Act and regulations promulgated thereunder, which contain emission limitations which are equivalent to the emission limitations that would apply to a source if an emission standard had been promulgated in a timely manner by USEPA pursuant to Section 112(d). Provided, however, that the owner or operator of a source shall have the opportunity to submit to the Agency a proposed emission limitation which it determines to be equivalent to the emission limitations that would apply to such source if an emission standard had been promulgated in a timely manner by USEPA. If the Agency refuses to include the emission limitation proposed by the owner or operator in a CAAPP permit, the owner or operator may petition the Board to establish whether the emission limitation proposal submitted by the owner or operator provides for emission limitations which are equivalent to the emission limitations that would apply to the source if the emission standard had been promulgated by USEPA in a timely manner. The Board shall determine whether the emission limitation proposed by the owner or operator or an alternative emission limitation proposed by the Agency provides for the level of control required under Section 112 of the Clean Air Act, or shall otherwise establish an appropriate emission limitation, pursuant to Section 112 of the Clean Air Act.

b. Any Board proceeding brought under paragraph (a) or (e) of this subsection shall be conducted according to the Board's procedures for adjudicatory hearings and the Board shall render its decision within 120 days of the filing of the petition. Any such decision shall be subject to review pursuant to Section 41 of this Act. Where USEPA promulgates an applicable emission standard prior to the issuance of the CAAPP permit, the Agency shall include in the permit the promulgated standard, provided that the source shall have the compliance period provided under Section 112(i) of the Clean Air Act. Where USEPA promulgates an applicable standard subsequent to the issuance of the CAAPP permit, the Agency shall revise such permit upon the next renewal to reflect the promulgated standard, providing a reasonable time for the applicable source to comply with the standard, but no longer than 8 years after the date on which the source is first required to comply with the emissions limitation established under this subsection.

c. The Agency shall have the authority to implement and enforce complete or partial emission standards promulgated by USEPA pursuant to Section 112(d), and standards promulgated by USEPA pursuant to Sections 112(f), 112(h), 112(m), and 112(n), and may accept delegation of authority from USEPA to implement and enforce Section 112(l) and requirements for the prevention and detection of accidental releases pursuant to Section 112(r) of the Clean Air Act.

d. The Agency shall have the authority to issue permits pursuant to Section 112(i)(5) of the Clean Air Act.

e. The Agency has the authority to implement Section 112(g) of the Clean Air Act consistent with the Clean Air Act and federal regulations promulgated thereunder. If the Agency refuses to include the emission limitations proposed in an application submitted by an owner or operator for a case-by-case maximum achievable control technology (MACT) determination, the owner or operator may petition the Board to determine whether the emission limitation proposed by the owner or operator or an alternative emission limitation proposed by the Agency provides for a level of control required by Section 112 of the Clean Air Act, or to otherwise establish an appropriate emission limitation under Section 112 of the Clean Air Act.

20. Small Business.

a. For purposes of this subsection:

"Program" is the Small Business Stationary Source Technical and Environmental Compliance Assistance Program created within this State pursuant to Section 507 of the Clean Air Act and guidance promulgated thereunder, to provide technical assistance and compliance information to small business stationary sources;

"Small Business Assistance Program" is a component of the Program responsible for providing sufficient communications with small businesses through the collection and dissemination of information to small business stationary sources; and

"Small Business Stationary Source" means a stationary source that:

1. is owned or operated by a person that employs 100 or fewer individuals;

2. is a small business concern as defined in the "Small Business Act";

3. is not a major source as that term is defined in subsection 2 of this Section;

4. does not emit 50 tons or more per year of any regulated air pollutant, except greenhouse gases; and

5. emits less than 75 tons per year of all regulated pollutants, except greenhouse gases.

b. The Agency shall adopt and submit to USEPA, after reasonable notice and opportunity for public comment, as a revision to the Illinois state implementation plan, plans for establishing the Program.

c. The Agency shall have the authority to enter into such contracts and agreements as the Agency deems necessary to carry out the purposes of this subsection.

d. The Agency may establish such procedures as it may deem necessary for the purposes of implementing and executing its responsibilities under this subsection.

e. There shall be appointed a Small Business Ombudsman (hereinafter in this subsection referred to as "Ombudsman") to monitor the Small Business Assistance Program. The Ombudsman shall be a nonpartisan designated official, with the ability to independently assess whether the goals of the Program are being met.

f. The State Ombudsman Office shall be located in an existing Ombudsman office within the State or in any State Department.

g. There is hereby created a State Compliance Advisory Panel (hereinafter in this subsection referred to as "Panel") for determining the overall effectiveness of the Small Business Assistance Program within this State.

h. The selection of Panel members shall be by the following method:

1. The Governor shall select two members who are not owners or representatives of owners of small business stationary sources to represent the general public;

2. The Director of the Agency shall select one member to represent the Agency; and

3. The State Legislature shall select four members who are owners or representatives of owners of small business stationary sources. Both the majority and minority leadership in both Houses of the Legislature shall appoint one member of the panel.

i. Panel members should serve without compensation but will receive full reimbursement for expenses including travel and per diem as authorized within this State.

j. The Panel shall select its own Chair by a majority vote. The Chair may meet and consult with the Ombudsman and the head of the Small Business Assistance Program in planning the activities for the Panel.

21. Temporary Sources.

a. The Agency may issue a single permit authorizing emissions from similar operations by the same source owner or operator at multiple temporary locations, except for sources which are affected sources for acid deposition under Title IV of the Clean Air Act.

b. The applicant must demonstrate that the operation is temporary and will involve at least one change of location during the term of the permit.

c. Any such permit shall meet all applicable requirements of this Section and applicable regulations, and include conditions assuring compliance with all applicable requirements at all authorized locations and requirements that the owner or operator notify the Agency at least 10 days in advance of each change in location.

22. Solid Waste Incineration Units.

a. A CAAPP permit for a solid waste incineration unit combusting municipal waste subject to standards promulgated under Section 129(e) of the Clean Air Act shall be issued for a period of 12 years and shall be reviewed every 5 years, unless the Agency requires more frequent review through Agency procedures.

b. During the review in paragraph (a) of this subsection, the Agency shall fully review the previously submitted CAAPP permit application and corresponding reports subsequently submitted to determine whether the source is in compliance with all applicable requirements.

c. If the Agency determines that the source is not in compliance with all applicable requirements it shall revise the CAAPP permit as appropriate.

d. The Agency shall have the authority to adopt procedural rules, in accordance with the Illinois Administrative Procedure Act, as the Agency deems necessary, to implement this subsection.

23. Diesel-Powered and Natural Gas-Powered Backup Generators for Data Centers.

a. A CAAPP permit or Federally Enforceable State Operating Permit (FESOP) for a diesel-powered or natural gas-powered backup generator, as referenced in 415 ILCS 5/39, shall require a public hearing to be conducted in accordance with the Agency's Procedures for Permit and Closure Plan Hearings (35 Ill. Adm. Code 166, Subpart A, Informational Permit and Closure Plan Hearings).

b. The Agency shall have the authority to adopt procedural rules in accordance with the Illinois Administrative Procedure Act to implement this subsection.

(Source: P.A. 104-417, eff. 8-15-25.)

(415 ILCS 5/Art. Tit. XIX heading new)

TITLE XIX. DATA CENTERS

(415 ILCS 5/60 new)

Sec. 60. Definitions. As used in this Title:

"Agency" means the Illinois Environmental Protection Agency.

"Board" means the Illinois Pollution Control Board.

"Community Benefits Agreement" means a legally binding and enforceable agreement between a Community Advisory Board or a Community Coalition and the Developer of a data center for the purpose of ensuring that the Developer provides measurable, enforceable benefits to host communities, protects environmental and cultural resources, and advances equity and justice.

"Community Advisory Board" means a coalition of organizations, residents and local government officials charged with negotiating, monitoring, and enforcing the Community Benefits Agreement with the Developer of the facility. A majority of CAB members shall be residents, workers, and community-based nonprofit organizations from the impacted community. A Community Advisory Board shall not include a data center developer and employees of the developer.

"Community Coalition" means a group of two or more community-based organizations, such as workforce development and training organizations, labor unions, environmental and social justice advocates, local governmental entities, other organizations that represent community interests, and residents of the political subdivision where the data center will be located. Such a coalition must include residents of the political subdivision in which the proposed facility will be located. A Community Coalition shall not include a data center developer or management employees employed by a data center developer.

"Community water supply" has the meaning ascribed to it in Section 3.145 of the Environmental Protection Act.

"Consumptive water use" means a use of water that results in a loss of water to the basin from which it is withdrawn and includes evaporation. Water returned to a different basin from which it was withdrawn is not considered a consumptive use.

"Data center" has the meaning ascribed to it in the Department of Commerce and Economic Opportunity Law.

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

"Direct water use" means water that is used at a data center, including both total withdrawals and consumptive use.

"Indirect water use for energy production" means water that is used in the process of generating energy that is used by a data center.

"Nondisclosure agreement" means an agreement or contract that includes a provision or clause that treats information related to the siting, planning or construction of a data center as confidential, commercial, or financial information that may not be disclosed to any party, person, or entity, except as provided by this Act.

"Total Drinking Water System Capacity" means the average treatment capacity of a community water supply measured in gallons per day.

"Water deliveries" means water that is delivered to a data center from a source that is not directly surface or groundwater.

"Water intake" means water that is taken by the data center for any type of use, including both water withdrawal and water deliveries.

"Water withdrawal" means water that is taken from surface water or groundwater by the data center.

(415 ILCS 5/60.1 new)

Sec. 60.1. Cumulative impact assessment.

(a) No person shall construct, establish, or expand, a data center within the boundaries of any community that is either:

(1) within 3 miles of an Equity Investment Eligible Community, as defined in subsection (f) of Section 9.15 of this Act; or

(2) within the City of Chicago and within 3 miles of any community designated as an Environmental Justice Neighborhood under the City of Chicago's Cumulative Impact Assessment.

(b) The prohibition in subsection (a) of this Section may be waived only under the following conditions:

(1) The Agency has conducted a comprehensive Cumulative Impact Assessment that demonstrates that the project does not pose a disproportionate risk to the health, welfare, or environment of an equity investment eligible community or environmental justice community, as that term is used by the Illinois Power Agency and its Program Administrator in the Illinois Solar for All Program.

(2) Prior to commencing the Cumulative Impact Assessment, the Agency has prepared a detailed cost estimate for the costs required to complete the Cumulative Impact Assessment in accordance with this Section and the Agency has received funds equaling the full amount of that cost estimate from the project applicant;

(3) The Cumulative Impact Assessment conducted by the Agency includes identification of the following:

(A) Information about the applicant facility and any surrounding communities that may be impacted by its construction and operation;

(B) A list of any previous violations of compliance obligations under the Environmental Protection Act made by the applicant;

(C) A list and a map of all other facilities operating pursuant to a permit from Illinois EPA within 3 miles of the applicant facility;

(D) A list and a map of all points of community exposure within 3 miles of a facility to carbon emissions, total criteria pollutant emissions, and co-pollutants resulting from the operation of a data center, including, but not limited to, the on-site generation of electricity;

(E) Sources of exposure or potential exposure to lead through the air, water, or soil;

(F) Sources of exposure or potential exposure to contaminated drinking water supplies;

(G) any source of pollution covered by this Section that no longer exists but that has left residual pollution that has spread beyond its site;

(H) Potential or documented public health effects of carbon emissions and total criteria pollutant emissions resulting from operation of the site;

(I) Potential or documented impacts on health or the environment from the decommissioning of the facility at the end of its operational life;

(J) Potential impacts of the project on the local energy grid, and a showing that reliability and pricing will be improved for the local community through mitigation measures to be taken including grid enhancing technologies;

(K) Potential impacts of the project on public use of the surrounding area, and a showing that local pedestrian and/or bicyclist use will be improved through community enhancements to the local environment;

(L) Identification of all processes to be used, including pollution or environmental control measures and monitoring instrumentation, hours of operation, on-site equipment, traffic routes, number of employees, and all other information relevant to the potential for the new potentially impactful project to contribute to environmental and public health stressors in an environmental justice area of concern; and

(M) A description of the existing and potential benefits to surrounding environmental justice areas of the covered facility's construction and operation. The existence of a legally executed and funded community benefits agreement may be considered as supporting evidence of potential benefits from facility construction and operation.

(4) In conducting the Cumulative Impact Assessment, the Agency has meaningfully consulted and engaged the public, using the criteria set forth in the Illinois EPA Enhanced Public Participation Plan, and has provided informed consent through a transparent process led by local authorities in collaboration with affected residents and local community-based environmental justice organizations, where applicable;

(5) A finding by the Agency that the project will not pose a risk to the health, welfare, or environment of the community.

(c) For all permits associated with the construction or expansion of a data center located within three miles of an Equity Investment Eligible Community, as defined in subsection (f) of Section 9.15 of this Act, or a data center located within the City of Chicago that is located within three miles of any community designated as an Environmental Justice Neighborhood under Chicago's Cumulative Impact Assessment, the Agency shall:

(1) determine the total carbon emissions, total criteria pollutant emissions, total co-pollutant emissions, and hazardous air pollutant emissions of all power sources at the facility;

(2) impose emissions limits adequate to ensure the health and well-being of residents within the three mile radius under circumstances where all power sources are operating simultaneously and at their full potential to emit; and

(3) include an explanation, with supporting data and documentation regarding how the Agency determined the limits required by subsection (2) in a Statement of Basis for the permit.

(415 ILCS 5/60.2 new)

Sec. 60.2. Prohibition on nondisclosure agreements. Notwithstanding any provision of law to the contrary, a governmental unit shall not enter into a nondisclosure agreement regarding the siting, planning, construction, or operation of a data center.

(415 ILCS 5/60.3 new)

Sec. 60.3. Data Center Community Intervenor Compensation Fund. The Data Center Community Intervenor Compensation Fund is hereby created as a special fund in the State treasury to be administered by the Agency. The Fund shall be used by the Agency to make grants subject to the following:

(1) Provision of compensation for community interest representatives that intervene in legal proceedings related to the zoning, siting, permitting, and construction of a data center.

(2) As used in this Section, "community interest representatives" means:

(A) representatives of not-for-profit groups or organizations whose membership includes Illinois residents and that address the community, economic, environmental, or social welfare of Illinois residents, except State government agencies;

(B) residential organizations and representatives of community organizations located within the State;

(C) community Action Agencies; and

(D) municipalities.

(3) A community interest representative is eligible to receive compensation from the Data Center Community Intervenor Compensation Fund for its participation in a legal or government proceeding related to the zoning, siting, permitting, and construction of a data center.

(4) To ensure meaningful participation by community interest representatives, including organizations with limited financial resources, the Agency shall provide compensation from the Data Center Community Intervenor Compensation Fund on an advance and milestone basis, and not solely on a reimbursement basis.

(A) Upon a showing of eligibility and a proposed scope of participation, the Agency shall authorize an initial advance payment to cover reasonable anticipated costs of participation, including but not limited to legal, technical, and expert assistance.

(B) The Agency shall provide additional payments at key stages of the proceeding, including but not limited to:

(i) filing of initial comments or petitions;

(ii) participation in hearings or negotiations; and

(iii) submission of final briefs, reports, or recommendations.

(C) A final accounting of expenses may be required at the conclusion of the proceeding, but receipt of compensation shall not be conditioned on organizations fronting costs in advance.

(D) The Agency shall explore additional methods to ensure that applicants from environmental justice and equity eligible investment communities are not limited in participating due to financial or organizational capacity constraints.

(415 ILCS 5/60.4 new)

Sec. 60.4. Community benefits agreements.

(a) A developer seeking to construct a data center must enter into a legally binding, publicly disclosed Community Benefits Agreement with a Community Advisory Board or a Community Coalition.

(b) Community benefits agreements must prioritize investments that benefit residents of governmental units in which the facility is located. Terms of a Community Benefits Agreement may include, but are not limited to, the following:

(1) workforce development provisions, which may include: programs to advance local career opportunities and investments in workforce training and education, worker recruitment, and worker representation in decision making affecting employment and training;

(2) investment in science, technology, engineering, and math education programs;

(3) investment in environmental benefits, which may include: green space, stormwater and flooding mitigation, tree canopy expansion, green infrastructure, urban heat mitigation, noise, lighting, visual mitigation measures beyond legal minimums, and investment in community walkability and safety;

(4) investment in community improvements, which may include green space donation, construction or rehabilitation of new or existing community centers, daycare centers, and health centers, investment in public parks, warming or cooling centers, affordable housing development, home repair and retrofits, enhanced safety crossings, and bike and hiking paths;

(5) investments that fully remediate any contaminated land that may pose an environmental or health hazard to the surrounding community; and

(6) investments in soil, air, and water quality monitoring.

(c) Developers must create and fund a Community Benefit Fund in an amount as agreed upon by the parties.

(d) The Community Benefit Fund shall be operated and managed by the Community Advisory Board or Community Coalition that is party to the agreement.

(e) No developer may be part of, nor have authority over, a Community Advisory Board. No developer, and no management employee of a developer, may participate in a Community Coalition.

(f) A Community Advisory Board may be formed and appointed by the municipal government in which the data center is located. If the data center is located in an unincorporated area, the county government may form and appoint a Community Advisory Board.

(415 ILCS 5/60.5 new)

Sec. 60.5. Community reporting website.

(a) Developers seeking to construct a data center within the State must maintain and update, on a quarterly basis, a publicly accessible website that provides information regarding the status and impact of the site. The website must include, but is not limited to, information regarding:

(1) project water use and efficiency measures;

(2) total carbon emissions, total criteria pollutant emissions, and total co-pollutant emissions;

(3) ambient air quality monitoring data required as part of the site's CAAPP permit or federally enforceable State operating permit;

(4) community benefit agreement status, provisions, and investments made as a result of the Agreement;

(5) Community Benefit Fund allocations;

(6) progress towards any impact mitigation requirements set out in this Title; and

(7) quarterly disclosures regarding the workforce needs associated with the project, the workforce composition of the project, including job classifications, employment duration, wage ranges, benefits, and the proportion of the workforce that resides within the county in which the project is located, and the proportion of the workforce that resides in the State.

(b) The Community Advisory Board shall establish and periodically update the reporting metrics, data fields, and presentation standards for the website.

(c) Reporting on any required mitigation measures must include a standardized status summary through the website that includes measure-specific metrics and documentation, including reports detailing mitigation actions.

(d) The Developer shall participate in no fewer than two public meetings in any calendar year for a period of five years beginning with the operation of the site, convened in coordination with the Community Advisory Committee or Community Coalition, to review website information, compliance status, and community concerns. Meetings shall be accessible to the public and include reasonable accommodations for language access, disability access, and participation by working families.

(415 ILCS 5/60.6 new)

Sec. 60.6. Public notice requirements.

(a) Developers seeking to construct a data center within the State must, within 30 days of applying for any permit related to the zoning, permitting, siting, and construction of a data center, provide notice to community stakeholders and community members, at minimum, by:

(1) providing a description of the developer's intent to construct a data center to the office of each unit of local government covering the site;

(2) providing direct notice via first class mail to landowners within a 5 mile radius of the site;

(3) providing public notice once a week for 2 consecutive weeks in the newspaper of the largest circulation within the county in which the site is located; and

(4) offering written notice for posting in all public libraries located within the municipality in which the data center will be located.

(b) Developers must file proof of such notice with the Agency.

(415 ILCS 5/60.7 new)

Sec. 60.7. Hyperscale Data Center Public Benefits and Affordability Fund.

(a) The Hyperscale Data Center Public Benefits and Affordability Fund is established as a special fund in the State Treasury. The Department of Commerce and Economic Opportunity and the Illinois Environmental Protection Agency shall administer the fund. The agencies shall use money appropriated from the Fund for purposes outlined in this Section. In this Section, "the agencies" means the Department of Commerce and Economic Opportunity and the Illinois Environmental Protection Agency; and "the Fund" means the Hyperscale Data Center Public Benefits and Affordability Fund.

(b) At the discretion of the agencies, the Fund shall be used to enhance the following programs:

(1) Programs administered by the Department of Commerce and Economic Opportunity that are to be enhanced through the Fund are limited to the following, pursuant to the Energy Assistance Act:

(A) Low-Income Home Energy Assistance Program (LIHEAP);

(B) Illinois Utility Disconnection Avoidance Program (UDAP); and

(C) Illinois Home Weatherization Assistance Program (IHWAP).

(i) Money from the Fund shall be prioritized for the following major measures:

(a) health and safety upgrades, as defined in the Public Utilities Act;

(b) energy savings equipment that uniquely reduces peak demands, including but not limited to cold climate heat pumps, highly efficient air conditioning, and smart thermostats;

(c) comprehensive weatherization measures such as air sealing and building envelope improvements;

(d) emergency summer cooling program.

(ii) No funding shall be used on gas-consuming equipment, even when said measure also reduces electric consumption.

(2) Programs administered by the Illinois Environmental Protection Agency that are to be enhanced through the Fund are limited to the following:

(A) The Environmental Justice Grant Fund, pursuant to Section 59.15 of the Environmental Protection Act.

(B) The Data Center Community Intervenor Compensation Fund.

(C) New or existing air monitoring programs that measure air pollutants emitted by data centers, as well as water pollutant protection programs. These include, but are not limited to, community water supply modifications to address non-compliance issues, wastewater treatment plant modifications, lead service line replacement projects, nature-based solutions, stormwater management, and green infrastructure upgrades.

Within the programs outlined in subsection (b) of this Section, money spent from the Fund must prioritize the following:

(3) Money spent shall be prioritized within census tracts where hyperscale data center customers paying into the Fund are located as well as adjacent census tracts.

(4) Money spent shall be prioritized to assist low-income electric customers, as defined in the Public Utilities Act, in the alleviation of energy burdens and protections against environmental hazards caused by hyperscale data centers.

(5) The agencies shall consult with entities including, but not limited to, Community Action Agencies, community-based nonprofits, municipalities, and/or eligible organizations representing areas of environmental justice concern on how the Fund shall be prioritized and spent.

In distributing money collected by the Fund, no less than 33% and no more than 50% of the Fund shall be spent on programs administered by the Agency, and no less than 50% and no more than 67% shall be spent on programs administered by the Department.

(c) On a schedule prescribed by the Illinois Commerce Commission, each hyperscale data center customer shall make a payment to the fund in accordance with the following schedule based on peak demand and inclusive of the facility's peak demand forecast provided to the utility, expressed in megawatts (MW):

(1) A fee of $2,000,000 per year for peak demands of 50MW-99.9MW;

(2) A fee of $4,000,000 per year for peak demands of 100MW - 249.9MW;

(3) A fee of $6,000,000 per year for peak demands of 250MW - 499.9MW;

(4) A fee of $8,000,000 per year for peak demands of 500MW - 749.9MW;

(5) A fee of $10,000,000 per year for peak demands of 750MW - 999.9MW; and

(6) A fee of $12,000,000 per year for peak demands of 1,000MW or greater.

The payment structure shall automatically be increased or decreased, as applicable, by a percentage equal to the percentage change in the Consumer Price Index-U during the preceding 12-month calendar year. In this subsection, "Consumer Price Index-U" means the index published by the Bureau of Labor Statistics of the United States Department of Labor that measures the average change in prices of goods and services purchased by all urban consumers, United States city average, all items, 1982-84 = 100.

(d) The Department of Commerce and Economic Opportunity and the Illinois Environmental Protection Agency shall adopt rules necessary to implement this Section.

(415 ILCS 5/60.8 new)

Sec. 60.8. Water resources plan.

(a) No later than 6 months after the effective date of this Act, the owner or operator of a data center shall produce a water resources plan containing all of the following information:

(1) a description of the data center, including location, identification of owner and operator, and a detailed description of the business to be conducted at the site;

(2) a detailed accounting of the data center's expected water intake expressed in gallons per day and total volume, including maximum and average daily demand, maximum and average monthly demand, and average 12-month consecutive period; the plan shall also distinguish between withdrawal and deliveries; if water intake demand is expected to vary over the operating life of the facility, the plan shall describe the phases of growth or expansion, identify trigger points at which additional water demand will occur, and quantify expected increases under full-build-out and peak operation scenarios;

(3) a detailed explanation of each direct water use, including, but not limited to cooling systems, humidification, potable and sanitary uses, fire suppression and emergency systems, and commissioning, testing, and maintenance operations; for each use, identify input water quality requirements, whether it is wholly or in-part a consumptive water use and if so, the average volume consumed per day, whether the use is continuous, intermittent, or seasonal, and opportunities for reuse or closed-loop systems;

(4) a water use efficiency cooling alternatives analysis that examines the impact of the data center's proposed cooling method on the data center's consumptive water usage as compared to a wide variety of alternative methods; the owner or operator of the data center shall include in the analysis an evaluation of water use at the data center and at the site of energy generation, an evaluation of the impact of water use on the source water and scarcity, and consider closed loop cooling as one of the alternatives;

(5) a detailed estimate of the indirect water use for energy production with explanations of energy use by generation type and water use by generation type;

(6) for each water source to be used by the data center:

(A) a description of the anticipated sources of water;

(B) any agreements or contracts to supply water from the source to the data center;

(C) a description of the existing uses and users of the water source, including but not limited to drinking water and ecological uses;

(D) a detailed assessment of the data center's impacts to each water use, such as aquifer drawdown or river reductions, and to the users, such as rate changes and drought scarcity, due to the data center's usage (i) immediately following the data center's initial operations, (ii) at the end of the data center's expected operational life, and (iii) during a drought or other similar event;

(E) if the source is a community water supply:

(i) the percent of the community water supply's total drinking water system capacity the data center is expected to use;

(ii) the sources of the community water supply's water;

(iii) a list of any modifications to the community water supply required as a result of providing water to the data center;

(iv) the anticipated annual increased operating and capital costs accruing to the community water supply as a result of the data center, as calculated using the American Water Works Association (AWWA) M1 Cost of Service model or a similar methodology;

(v) a cost-of-service study for the community water supply, consistent with the American Water Works Association (AWWA) M1 Cost of Service model or equivalent and completed within the last 5 years; if no such cost-of-service study exists, the data center shall incur all costs for the production of a cost-of-service study on behalf of the community water supply; and

(vi) a list of non-compliance or violations of the community water supply with the Safe Drinking Water Act and the Clean Water Act for the last 5 years, any modifications necessary to bring the community water supply into compliance, and the estimated costs of those modifications;

(F) if the source is treated wastewater from a wastewater treatment plant:

(i) the receiving water body of the wastewater treatment plant discharge; and

(ii) if the wastewater treatment plant discharges to a flowing water body, the percentage of 7Q10 flow that is treated wastewater before the data center begins operation;

(iii) a list of any modifications to the wastewater treatment plant required as a result of providing water to the data center; and

(iv) the anticipated annual increased operating and capital costs accruing to the wastewater treatment plant, as calculated by a wastewater cost-of-service study;

(v) a cost-of-service study for the receiving treated wastewater from the wastewater treatment plant completed within the last 5 years; if no such cost-of-service studies exist, the data center shall incur all costs for the production of a cost-of-service study on behalf of the community water supply; and

(vi) a list of non-compliance or violations of the wastewater treatment plant with the Safe Drinking Water Act and the Clean Water Act, as applicable, for the last 5 years, any modifications necessary to bring the wastewater treatment plant into compliance, and the costs of those modifications; and

(G) if the source is direct pumping from surface water or groundwater:

(i) a description of the water body, such as name, location, surface water or groundwater, characteristic size such as average flow rates or volume;

(ii) a description of how the water will be extracted, including any methods of pumping used by the data center and the maximum and expected daily pumping rates for the pumps used by the data center;

(iii) a description of how the water will be transported to the data center;

(7) identification of all water discharges from the data center; for each discharge:

(A) anticipated volumes in gallons per day and total volume for the average day, average month, and average 12-month period;

(B) whether and how the data center will treat the water prior to discharge, including thermal treatments, and a description of any byproducts of the water treatment and their disposal;

(C) anticipated pollutants or contaminants in the discharge, including concentration effects;

(D) a list of applicable discharge permits, the status of those permits, and permit identification numbers; and

(E) for discharges into a wastewater treatment plant, include:

(i) which wastewater treatment plant is receiving the water;

(ii) a list of any modifications to the wastewater treatment plant required to receive and treat water from the data center;

(iii) the anticipated annual increased operating and capital costs accruing to the wastewater treatment plant, as calculated by a wastewater cost-of-service study;

(iv) a cost-of-service study for the receiving treated wastewater from the wastewater treatment plant completed within the last 5 years; if no such cost-of-service studies exist, the data center shall incur all costs for the production of a cost-of-service study on behalf of the community water supply; and

(v) a list of non-compliance or violations of the wastewater treatment plant for the last 5 years and any modifications necessary to bring it into compliance;

(8) for data centers using evaporative cooling, all contaminants that might be expected in the vapor, including particulates, chemical constituents, and any biological contaminants;

(9) the data center's policy for sustainable water use and water conservation, including the data center's plans to conserve, reuse, and replace water, including, but not limited to, the following measures: using water efficient fixtures and practices; treating, infiltrating, and harvesting rainwater; recycling water before discharging; partnering with external stakeholders to use discharged water for other purposes; using treated wastewater where possible for data center operations; supporting restoration in local watersheds; and using a non-evaporative cooling system; and

(10) any other information the Agency may request.

(b) The owner or operator of a data center shall submit the water resources plan to the Agency and post on its publicly accessible website.

(415 ILCS 5/60.9 new)

Sec. 60.9. Water usage reporting.

(a) No later than 6 months after the effective date of this Act, the owner or operator of a data center shall begin tracking the following water parameters and include the parameters in a water usage report:

(1) water intake, water withdrawals, and water deliveries;

(2) consumptive water usage, both total and by usage type;

(3) water discharges, both total and by discharge point; and

(4) the indirect water use for energy production.

(b) The water parameters shall be reported by:

(1) the day with the highest amount of water use in a month in total gallons;

(2) monthly volume in total gallons and gallons per day; and

(3) annual volume in total gallons and gallons per day.

(c) The water usage reports shall also identify any reported values that differ from the estimates in the water resources plan and explanations for any differences.

(d) Not later than the tenth of January, April, July, and October each year after tracking begins, the data center owner or operator shall submit to the Agency and post on its publicly accessible website an up-to-date water usage report.

(e) No later than 6 months after the effective date of this Act, the Agency shall develop a standardized reporting form that will produce machine-readable spreadsheets that the data center will utilize to report their water usage.

(f) For data centers with an active Water Impact Permit, if the Agency determines that a data center's water usage reporting differs substantially from its water resources plan, it may require the data center to obtain a new Water Resources Impact Report from the Illinois State Water Survey.

(415 ILCS 5/60.10 new)

Sec. 60.10. Water Resources Impact Report.

(a) No later than 6 months after the effective date of this Act, the owner or operator of the data center shall submit the water resources plan to the Illinois State Water Survey and pay the Illinois State Water Survey a fee for service to produce a Water Resources Impact Report. The Water Resources Impact Report shall describe the anticipated effects of the data center on its water sources, including:

(1) local and regional water quantity, availability, sustainability, and water shortage response;

(2) groundwater, surface water quality and ecological uses;

(3) flood risk and stormwater dynamics; and

(4) any other hydrologic or water-resource impacts the Survey deems relevant.

(b) The Illinois State Water Survey shall transmit a completed report, with a summary and recommendations, to the Agency and the data center. The data center shall post the water impact report to a publicly available website. The Agency shall consider the Water Resources Impact Report when considering a Water Impact Permit.

(c) After the rulemaking by the Agency regarding Water Impact Permits, the Illinois State Water Survey shall provide the information within a timeframe established by the rulemaking.

(d) The Illinois State Water Survey may use a portion of the service fee to support development of a publicly accessible water availability dashboard to support the public in understanding impacts of a data center on water availability and help assess whether a data center is likely to cause an adverse resource impact. The dashboard shall assess how much water will be depleted from nearby source waters. It shall also determine if the data center's water usage is likely to cause an adverse impact on the ecosystem.

(415 ILCS 5/60.11 new)

Sec. 60.11. Water Scarcity Plan.

(a) No later than 6 months after the effective date of this Act, the data center owner or operator shall develop and maintain a Water Scarcity Plan demonstrating how the data center will reduce, modify, or curtail water use under conditions of water scarcity or supply disruption.

(b) The Water Scarcity Plan must include the following:

(1) The Water Scarcity Plan shall specify measures to be implemented under 25, 50, and 100-year drought scenarios, using drought-of-record and hydrologic analyses consistent with State drought planning guidance, including staged reductions in withdrawals, nonessential water-use curtailment, internal recycling and reuse, thermal-load reductions, and, where necessary, temporary load shedding or relocation;

(2) Upon declaration of a drought stage by the State, or by a local government consistent with State guidance, the data center shall implement the corresponding measures in its approved Water Scarcity Plan and shall report implementation status and withdrawal data to the Agency at intervals established by Agency rule;

(3) The Agency may issue orders requiring the data center to implement or modify drought-response measures during declared drought states.

(c) The data center owner or operator shall submit the Water Scarcity Plan to the Agency and post the Plan on its publicly accessible website.

(415 ILCS 5/60.12 new)

Sec. 60.12. Public website. The owner or operator of a data center shall post all water resource plans, water usage reporting, Water Scarcity Plans, Water Impact Permit applications with supporting documentation, and any Agency approval of the plans or applications on a publicly accessible website.

(415 ILCS 5/60.13 new)

Sec. 60.13. Water Impact Permit.

(a) Beginning on the effective date of rules adopted under this Act related to water regulation, and notwithstanding any other provision of law, no person shall operate a data center without a valid Water Impact Permit issued by the Agency under this Act. Under the program, the Agency may issue, deny, suspend, or revoke a Water Impact Permit, as applicable.

(b) As part of a Water Impact Permit application, a data center owner or operator shall submit to the Agency all of the following:

(1) a water resources plan that has been created or updated in the last 3 years;

(2) all water usage reports to date;

(3) a Water Resources Impact Report that has been created or updated in the last 3 years;

(4) a Water Scarcity Plan that has been created or updated in the last 3 years;

(5) if sourcing water from a community water supply or wastewater treatment plant, a cost-of-service study and proof that rates paid are equivalent to the rate identified in the cost-of-service study;

(6) if discharging water to a wastewater treatment plant, a cost-of-service study and proof that rates paid to the wastewater treatment plant are equivalent to the rate identified in the cost-of-service study; and

(7) anything else determined to be critical to the Agency's evaluation determined by the rulemaking.

(c) The Agency shall evaluate the information supplied under the Water Resources Plan along with public comments described in this subsection and shall respond in writing, which may be electronically transmitted. Not later than 6 months after receipt of a Water Impact Permit application, the Agency shall issue a Water Impact Permit if it finds all of the following:

(1) the submission is complete and satisfies the requirements of this Section;

(2) the Agency has determined, in reviewing the permit application and the Illinois State Water Survey Water Resources Impact Report, that the data center will not cause an adverse resource impact;

(3) the data center has demonstrated it will cover the cost of any modifications at a community water supply identified in the cost-of-service study in the Water Resources Plan;

(4) the data center has demonstrated it will cover the cost of any upgrades at a wastewater treatment plant identified in the cost-of-service study in the Water Resources Plan;

(5) for data centers proposed to be constructed on and after the effective date of rules adopted under this Section, the data center is using a cooling method that is at least as water efficient as closed loop cooling;

(6) the data center meets the minimum water-efficiency and conservation standards developed in the rulemaking;

(7) the data center has submitted water impact fees; and

(8) any other Agency determinations described in the rulemaking.

(d) The data center owner or operator shall respond to any Agency request for additional information necessary to assist the Agency's assessment.

(e) In evaluating the Water Impact Permit application, the Agency may consult with the Illinois Department of Public Health, the Illinois Department of Agriculture, the Illinois Department of Natural Resources, the Illinois State Water Survey and other State and federal agencies, as applicable.

(f) Before approving a Water Impact Permit, the Agency shall issue a public notice of the data center's draft Water Impact Permit on the Agency's website with a 45 day comment period. The Agency shall hold at least 2 public hearings during the 45 day window, with interpretation or other accommodations provided upon request. The public notice shall include an opportunity for public comments and shall contain the date, time, and location of the public hearings as decided by the Agency. At least one session shall be in person, in the same county or census tract where the data center is proposed to be located and as near as possible to accommodate the public interest. The hearings must be open to the public and recorded by stenographic or mechanical means. The Agency shall make available on its website copies of all comments received and consider those comments when rendering its permit decision.

(g) Approved Water Impact Permits are valid for 5 years from the approval date.

(h) The owner or operator of a data center that wishes to continue operation after the expiration of the Water Impact Permit must submit an application to renew a Water Impact Permit to the Agency 6 months prior to the expiration of the existing permit.

(1) The renewal application shall include and update the information required under this Section, including the non-refundable application fee.

(2) The terms and conditions of an expiring permit remain effective and enforceable against the owner or operator of a data center until the Agency takes final action on the pending permit application, only if:

(A) the permit applicant has submitted a timely application under subsection (h); and

(B) the Agency, through no fault of the permittee, does not issue a new permit on or before the expiration date of the previous permit.

(i) At any time, if the Agency finds that a data center has caused or is likely to cause an adverse resource impact, the Agency may issue an order requiring the data center to suspend operation until the owner or operator can demonstrate that no such adverse resource impact has been caused or will be caused by its continued operation. The Agency may suspend, deny, or revoke a permit or permit application, as applicable, if an adverse resource impact has been caused or is likely to be caused by the data center's operations.

(415 ILCS 5/60.14 new)

Sec. 60.14. Water impact fees.

(a) The owner or operator of a data center shall pay the following fees:

(1) annual fees to the Agency, beginning on July 1, 2026, of $20,000, increasing to $60,000 after the rulemaking; and

(2) fee for service of $50,000 to the Illinois State Water Survey for each Water Resources Impact Report.

(b) All fees collected by the Agency under this Section shall be deposited into the Environmental Protection Permit and Inspection Fund.

(415 ILCS 5/60.15 new)

Sec. 60.15. Rulemaking.

(a) Not later than 8 months after the effective date of this amendatory Act of the 104th General Assembly, the Agency shall propose, and, not later than one year after receipt of the Agency's proposal, the Board shall adopt, rules establishing Water Impact Permits. The rules must, at a minimum establish:

(1) a definition of "adverse resource impact" that prohibits excessive depletion of source waters, including groundwater, stream, lake, and river flows such that ecological uses and drinking water are protected; in developing the definition, the Board shall consider human health impacts, drinking water quantity, threatened and endangered species and other species most vulnerable to low stream flow, and the timeframe of impacts of withdrawal;

(2) standards for review and approval by the Agency of Water Impact Permit applications in addition to the standards required by the Water Impact Permit;

(3) procedures for the Agency's prioritization of permitting of data centers following the completion of this rulemaking;

(4) the process and standards for identifying when the water usage report indicates a substantial deviation from the water resources plan, and the requirements for actions taken after a substantial deviation, including modification of the permit and a new Water Resources Impact Report;

(5) the process and standards for permit revision when a data center has a substantial change in its operation or configuration; and

(6) minimum water-efficiency and conservation standards for data centers.

Such standards may include maximum allowable withdrawal intensity (such as gallons per kilowatt-hour), requirements for use of closed loop, air-cooled hybrid, or other high-efficiency cooling technologies where feasible, and requirements for on-site reuse of treated wastewater where practicable and consistent with public health standards.

(415 ILCS 5/60.16 new)

Sec. 60.16. Data Center Water Use Advisory Council.

(a) The Data Center Water Use Advisory Council is hereby created within the Agency.

(b) The Council shall consist of the following voting members appointed by the Governor with the advice and consent of the Senate, chosen to ensure diverse geographic representation:

(1) the Director of the Agency, or his or her designee, who shall serve as chairperson;

(2) the Director of the Illinois State Water Survey, or his or her designee;

(3) One member representing business and manufacturing interests;

(4) Four members representing community water supplies from geographically diverse regions of the State, with at least one representing a private water supply and at least one a public water supply;

(5) One member representing local units of government dependent on surface water for drinking water;

(6) One member representing local units of government dependent on groundwater for drinking water;

(7) One member representing a statewide angler association;

(8) One member representing a statewide agricultural organization;

(9) One member representing a wetlands conservation organization;

(10) One member representing a statewide conservation organization;

(11) One member representing an environmental organization;

(12) One member representing a water authority;

(13) One member who is a resident of an environmental justice community;

(14) One member representing a consumer advocacy organization;

(15) One member representing a data center developer;

(16) One member representing a statewide wastewater treatment organization;

(17) One member representing a public health organization; and

The President of the Senate, the Minority Leader of the Senate, the Speaker of the House of Representatives, and the Minority Leader of the House of Representatives shall each appoint 2 nonvoting members of the Council.

(c) The Council shall:

(1) make recommendations to the Agency and the Illinois State Water Survey and the General Assembly on the implementation of this Section, including all of the following:

(A) strategies for collection, verification, and use of data, including geology, aquifer characteristics, and groundwater and surface water hydrology;

(B) improvement, verification, regionalization, and integration of models used in the water availability dashboard and site-specific review, including models developed by private and public entities, organizations, or individuals;

(C) identification of research, public-private partnerships, training, and changes to the water availability dashboard needed to improve the Agency's ability to implement this Section and the water availability dashboard;

(2) study and make recommendations, as needed or as requested by the relevant standing committees of the General Assembly or the Agency, regarding the development and refinement of the water availability dashboard;

(3) make recommendations on reconciling conflicts in State laws related to the use of the waters of the State; and

(4) at least every 2 years after the effective date of this Section, provide a report to the General Assembly primarily related to natural resources and the environment that makes recommendations regarding how the permitting process could be improved; the report shall contain specific recommendations on the use of the water availability dashboard, a site-specific review process, the permitting process, the staffing, budgetary, software, and other resources required by the Agency to successfully implement this Section.

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

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

Article 5.

Section 5-5. The Energy Efficient Building Act is amended by changing Section 30 and by adding Section 60 as follows:

(20 ILCS 3125/30)

Sec. 30. Enforcement. The Board, in consultation with the Agency, shall determine procedures for compliance with the Code. These procedures may include but need not be limited to certification by a national, State, or local accredited energy conservation program or inspections from private Code-certified inspectors using the Code. For purposes of the Illinois Stretch Energy Code under Section 55, the Board shall allow and encourage, as an alternative compliance mechanism, project certification by a nationally recognized nonprofit certification organization specializing in high-performance passive buildings and offering climate-specific building energy standards that require equal or better energy performance than the Illinois Stretch Energy Code. For the purposes of hyperscale data center energy codes under Section 60, the Board, in consultation with the Agency, shall determine procedures for compliance with the most stringent energy code available to comply with the Code.

(Source: P.A. 102-444, eff. 8-20-21; 102-662, eff. 9-15-21; 102-813, eff. 5-13-22.)

(20 ILCS 3125/60 new)

Sec. 60. Hyperscale data centers. Hyperscale data centers shall comply with the energy code requirements specified in whichever of the following is most stringent:

(1) the latest published edition of the International Code Council's International Energy Conservation Code;

(2) the latest published edition of ASHRAE 90.4, Sections 6 and 8; or

(3) Illinois-specific data center energy code requirements adopted through the State rulemaking process, including, but not limited to, Mechanical Load Component (MLC) and Electrical Load Component (ELC) requirements.

Section 5-10. The Illinois Power Agency Act is amended by changing Sections 1-5 and 1-75 as follows:

(20 ILCS 3855/1-5)

Sec. 1-5. Legislative declarations and findings. The General Assembly finds and declares:

(1) The health, welfare, and prosperity of all Illinois residents require the provision of adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time, taking into account any benefits of price stability.

(1.5) To provide the highest quality of life for the residents of Illinois and to provide for a clean and healthy environment, it is the policy of this State to rapidly transition to 100% clean energy by 2050.

(2) (Blank).

(3) (Blank).

(4) It is necessary to improve the process of procuring electricity to serve Illinois residents, to promote investment in energy efficiency and demand-response measures, and to maintain and support development of clean coal technologies, generation resources that operate at all hours of the day and under all weather conditions, zero emission facilities, and renewable resources.

(5) Procuring a diverse electricity supply portfolio will ensure the lowest total cost over time for adequate, reliable, efficient, and environmentally sustainable electric service.

(6) Including renewable resources and zero emission credits from zero emission facilities in that portfolio will reduce long-term direct and indirect costs to consumers by decreasing environmental impacts and by avoiding or delaying the need for new generation, transmission, and distribution infrastructure. Developing new renewable energy resources in Illinois, including brownfield solar projects and community solar projects, will help to diversify Illinois electricity supply, avoid and reduce pollution, reduce peak demand, and enhance public health and well-being of Illinois residents.

(7) Developing community solar projects in Illinois will help to expand access to renewable energy resources to more Illinois residents.

(8) Developing brownfield solar projects in Illinois will help return blighted or contaminated land to productive use while enhancing public health and the well-being of Illinois residents, including those in environmental justice communities.

(9) Energy efficiency, demand-response measures, zero emission energy, and renewable energy are resources currently underused in Illinois. These resources should be used, when cost effective, to reduce costs to consumers, improve reliability, and improve environmental quality and public health.

(10) The State should encourage the use of advanced clean coal technologies that capture and sequester carbon dioxide emissions to advance environmental protection goals and to demonstrate the viability of coal and coal-derived fuels in a carbon-constrained economy.

(10.5) The State should encourage the development of interregional high voltage direct current (HVDC) transmission lines that benefit Illinois. All ratepayers in the State served by the regional transmission organization where the HVDC converter station is interconnected benefit from the long-term price stability and market access provided by interregional HVDC transmission facilities. The benefits to Illinois include: reduction in wholesale power prices; access to lower-cost markets; enabling the integration of additional renewable generating units within the State through near instantaneous dispatchability and the provision of ancillary services; creating good-paying union jobs in Illinois; and, enhancing grid reliability and climate resilience via HVDC facilities that are installed underground.

(10.6) The health, welfare, and safety of the people of the State are advanced by developing new HVDC transmission lines predominantly along transportation rights-of-way, with an HVDC converter station that is located in the service territory of a public utility as defined in Section 3-105 of the Public Utilities Act serving more than 3,000,000 retail customers, and with a project labor agreement as defined in Section 1-10 of this Act.

(11) The General Assembly enacted Public Act 96-0795 to reform the State's purchasing processes, recognizing that government procurement is susceptible to abuse if structural and procedural safeguards are not in place to ensure independence, insulation, oversight, and transparency.

(12) The principles that underlie the procurement reform legislation apply also in the context of power purchasing.

(13) To ensure that the benefits of installing renewable resources are available to all Illinois residents and located across the State, subject to appropriation, it is necessary for the Agency to provide public information and educational resources on how residents can benefit from the expansion of renewable energy in Illinois and participate in the Illinois Solar for All Program established in Section 1-56, the Adjustable Block program established in Section 1-75, the job training programs established by paragraph (1) of subsection (a) of Section 16-108.12 of the Public Utilities Act, and the programs and resources established by the Energy Transition Act.

The General Assembly therefore finds that it is necessary to create the Illinois Power Agency and that the goals and objectives of that Agency are to accomplish each of the following:

(A) Develop electricity procurement plans to ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time, taking into account any benefits of price stability, for electric utilities that on December 31, 2005 provided electric service to at least 100,000 customers in Illinois and for small multi-jurisdictional electric utilities that (i) on December 31, 2005 served less than 100,000 customers in Illinois and (ii) request a procurement plan for their Illinois jurisdictional load. The procurement plan shall be updated on an annual basis and shall include renewable energy resources and, beginning with the delivery year commencing June 1, 2017, zero emission credits from zero emission facilities sufficient to achieve the standards specified in this Act.

(B) Conduct the competitive procurement processes identified in this Act.

(C) Develop electric generation and co-generation facilities that use indigenous coal or renewable resources, or both, financed with bonds issued by the Illinois Finance Authority.

(D) Supply electricity from the Agency's facilities at cost to one or more of the following: municipal electric systems, governmental aggregators, or rural electric cooperatives in Illinois.

(E) Ensure that the process of power procurement is conducted in an ethical and transparent fashion, immune from improper influence.

(F) Continue to review its policies and practices to determine how best to meet its mission of providing the lowest cost power to the greatest number of people, at any given point in time, in accordance with applicable law.

(G) Operate in a structurally insulated, independent, and transparent fashion so that nothing impedes the Agency's mission to secure power at the best prices the market will bear, provided that the Agency meets all applicable legal requirements.

(H) Implement renewable energy procurement and training programs throughout the State to diversify Illinois electricity supply, improve reliability, avoid and reduce pollution, reduce peak demand, and enhance public health and well-being of Illinois residents, including low-income residents.

(Source: P.A. 102-662, eff. 9-15-21.)

(20 ILCS 3855/1-75)

(Text of Section before amendment by P.A. 104-458)

Sec. 1-75. Planning and Procurement Bureau. The Planning and Procurement Bureau has the following duties and responsibilities:

(a) The Planning and Procurement Bureau shall each year, beginning in 2008, develop procurement plans and conduct competitive procurement processes in accordance with the requirements of Section 16-111.5 of the Public Utilities Act for the eligible retail customers of electric utilities that on December 31, 2005 provided electric service to at least 100,000 customers in Illinois. Beginning with the delivery year commencing on June 1, 2017, the Planning and Procurement Bureau shall develop plans and processes for the procurement of zero emission credits from zero emission facilities in accordance with the requirements of subsection (d-5) of this Section. Beginning on the effective date of this amendatory Act of the 102nd General Assembly, the Planning and Procurement Bureau shall develop plans and processes for the procurement of carbon mitigation credits from carbon-free energy resources in accordance with the requirements of subsection (d-10) of this Section. The Planning and Procurement Bureau shall also develop procurement plans and conduct competitive procurement processes in accordance with the requirements of Section 16-111.5 of the Public Utilities Act for the eligible retail customers of small multi-jurisdictional electric utilities that (i) on December 31, 2005 served less than 100,000 customers in Illinois and (ii) request a procurement plan for their Illinois jurisdictional load. This Section shall not apply to a small multi-jurisdictional utility until such time as a small multi-jurisdictional utility requests the Agency to prepare a procurement plan for their Illinois jurisdictional load. For the purposes of this Section, the term "eligible retail customers" has the same definition as found in Section 16-111.5(a) of the Public Utilities Act.

Beginning with the plan or plans to be implemented in the 2017 delivery year, the Agency shall no longer include the procurement of renewable energy resources in the annual procurement plans required by this subsection (a), except as provided in subsection (q) of Section 16-111.5 of the Public Utilities Act, and shall instead develop a long-term renewable resources procurement plan in accordance with subsection (c) of this Section and Section 16-111.5 of the Public Utilities Act.

In accordance with subsection (c-5) of this Section, the Planning and Procurement Bureau shall oversee the procurement by electric utilities that served more than 300,000 retail customers in this State as of January 1, 2019 of renewable energy credits from new utility-scale solar projects to be installed, along with energy storage facilities, at or adjacent to the sites of electric generating facilities that, as of January 1, 2016, burned coal as their primary fuel source.

(1) The Agency shall each year, beginning in 2008, as needed, issue a request for qualifications for experts or expert consulting firms to develop the procurement plans in accordance with Section 16-111.5 of the Public Utilities Act. In order to qualify an expert or expert consulting firm must have:

(A) direct previous experience assembling large-scale power supply plans or portfolios for end-use customers;

(B) an advanced degree in economics, mathematics, engineering, risk management, or a related area of study;

(C) 10 years of experience in the electricity sector, including managing supply risk;

(D) expertise in wholesale electricity market rules, including those established by the Federal Energy Regulatory Commission and regional transmission organizations;

(E) expertise in credit protocols and familiarity with contract protocols;

(F) adequate resources to perform and fulfill the required functions and responsibilities; and

(G) the absence of a conflict of interest and inappropriate bias for or against potential bidders or the affected electric utilities.

(2) The Agency shall each year, as needed, issue a request for qualifications for a procurement administrator to conduct the competitive procurement processes in accordance with Section 16-111.5 of the Public Utilities Act. In order to qualify an expert or expert consulting firm must have:

(A) direct previous experience administering a large-scale competitive procurement process;

(B) an advanced degree in economics, mathematics, engineering, or a related area of study;

(C) 10 years of experience in the electricity sector, including risk management experience;

(D) expertise in wholesale electricity market rules, including those established by the Federal Energy Regulatory Commission and regional transmission organizations;

(E) expertise in credit and contract protocols;

(F) adequate resources to perform and fulfill the required functions and responsibilities; and

(G) the absence of a conflict of interest and inappropriate bias for or against potential bidders or the affected electric utilities.

(3) The Agency shall provide affected utilities and other interested parties with the lists of qualified experts or expert consulting firms identified through the request for qualifications processes that are under consideration to develop the procurement plans and to serve as the procurement administrator. The Agency shall also provide each qualified expert's or expert consulting firm's response to the request for qualifications. All information provided under this subparagraph shall also be provided to the Commission. The Agency may provide by rule for fees associated with supplying the information to utilities and other interested parties. These parties shall, within 5 business days, notify the Agency in writing if they object to any experts or expert consulting firms on the lists. Objections shall be based on:

(A) failure to satisfy qualification criteria;

(B) identification of a conflict of interest; or

(C) evidence of inappropriate bias for or against potential bidders or the affected utilities.

The Agency shall remove experts or expert consulting firms from the lists within 10 days if there is a reasonable basis for an objection and provide the updated lists to the affected utilities and other interested parties. If the Agency fails to remove an expert or expert consulting firm from a list, an objecting party may seek review by the Commission within 5 days thereafter by filing a petition, and the Commission shall render a ruling on the petition within 10 days. There is no right of appeal of the Commission's ruling.

(4) The Agency shall issue requests for proposals to the qualified experts or expert consulting firms to develop a procurement plan for the affected utilities and to serve as procurement administrator.

(5) The Agency shall select an expert or expert consulting firm to develop procurement plans based on the proposals submitted and shall award contracts of up to 5 years to those selected.

(6) The Agency shall select an expert or expert consulting firm, with approval of the Commission, to serve as procurement administrator based on the proposals submitted. If the Commission rejects, within 5 days, the Agency's selection, the Agency shall submit another recommendation within 3 days based on the proposals submitted. The Agency shall award a 5-year contract to the expert or expert consulting firm so selected with Commission approval.

(b) The experts or expert consulting firms retained by the Agency shall, as appropriate, prepare procurement plans, and conduct a competitive procurement process as prescribed in Section 16-111.5 of the Public Utilities Act, to ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time, taking into account any benefits of price stability, for eligible retail customers of electric utilities that on December 31, 2005 provided electric service to at least 100,000 customers in the State of Illinois, and for eligible Illinois retail customers of small multi-jurisdictional electric utilities that (i) on December 31, 2005 served less than 100,000 customers in Illinois and (ii) request a procurement plan for their Illinois jurisdictional load.

(c) Renewable portfolio standard.

(1)(A) The Agency shall develop a long-term renewable resources procurement plan that shall include procurement programs and competitive procurement events necessary to meet the goals set forth in this subsection (c). The initial long-term renewable resources procurement plan shall be released for comment no later than 160 days after June 1, 2017 (the effective date of Public Act 99-906). The Agency shall review, and may revise on an expedited basis, the long-term renewable resources procurement plan at least every 2 years, which shall be conducted in conjunction with the procurement plan under Section 16-111.5 of the Public Utilities Act to the extent practicable to minimize administrative expense. No later than 120 days after the effective date of this amendatory Act of the 103rd General Assembly, the Agency shall release for comment a revision to the long-term renewable resources procurement plan, updating elements of the most recently approved plan as needed to comply with this amendatory Act of the 103rd General Assembly, and any long-term renewable resources procurement plan update published by the Agency but not yet approved by the Illinois Commerce Commission shall be withdrawn. The long-term renewable resources procurement plans shall be subject to review and approval by the Commission under Section 16-111.5 of the Public Utilities Act.

(B) Subject to subparagraph (F) of this paragraph (1), the long-term renewable resources procurement plan shall attempt to meet the goals for procurement of renewable energy credits at levels of at least the following overall percentages: 13% by the 2017 delivery year; increasing by at least 1.5% each delivery year thereafter to at least 25% by the 2025 delivery year; increasing by at least 3% each delivery year thereafter to at least 40% by the 2030 delivery year, and continuing at no less than 40% for each delivery year thereafter. The Agency shall attempt to procure 50% by delivery year 2040. The Agency shall determine the annual increase between delivery year 2030 and delivery year 2040, if any, taking into account energy demand, other energy resources, and other public policy goals. In the event of a conflict between these goals and the new wind, new photovoltaic, and hydropower procurement requirements described in items (i) through (iii) of subparagraph (C) of this paragraph (1), the long-term plan shall prioritize compliance with the new wind, new photovoltaic, and hydropower procurement requirements described in items (i) through (iii) of subparagraph (C) of this paragraph (1) over the annual percentage targets described in this subparagraph (B). The Agency shall not comply with the annual percentage targets described in this subparagraph (B) by procuring renewable energy credits that are unlikely to lead to the development of new renewable resources or new, modernized, or retooled hydropower facilities.

For the delivery year beginning June 1, 2017, the procurement plan shall attempt to include, subject to the prioritization outlined in this subparagraph (B), cost-effective renewable energy resources equal to at least 13% of each utility's load for eligible retail customers and 13% of the applicable portion of each utility's load for retail customers who are not eligible retail customers, which applicable portion shall equal 50% of the utility's load for retail customers who are not eligible retail customers on February 28, 2017.

For the delivery year beginning June 1, 2018, the procurement plan shall attempt to include, subject to the prioritization outlined in this subparagraph (B), cost-effective renewable energy resources equal to at least 14.5% of each utility's load for eligible retail customers and 14.5% of the applicable portion of each utility's load for retail customers who are not eligible retail customers, which applicable portion shall equal 75% of the utility's load for retail customers who are not eligible retail customers on February 28, 2017.

For the delivery year beginning June 1, 2019, and for each year thereafter, the procurement plans shall attempt to include, subject to the prioritization outlined in this subparagraph (B), cost-effective renewable energy resources equal to a minimum percentage of each utility's load for all retail customers as follows: 16% by June 1, 2019; increasing by 1.5% each year thereafter to 25% by June 1, 2025; and 25% by June 1, 2026; increasing by at least 3% each delivery year thereafter to at least 40% by the 2030 delivery year, and continuing at no less than 40% for each delivery year thereafter. The Agency shall attempt to procure 50% by delivery year 2040. The Agency shall determine the annual increase between delivery year 2030 and delivery year 2040, if any, taking into account energy demand, other energy resources, and other public policy goals.

For each delivery year, the Agency shall first recognize each utility's obligations for that delivery year under existing contracts. Any renewable energy credits under existing contracts, including renewable energy credits as part of renewable energy resources, shall be used to meet the goals set forth in this subsection (c) for the delivery year.

(C) The long-term renewable resources procurement plan described in subparagraph (A) of this paragraph (1) shall include the procurement of renewable energy credits from new projects pursuant to the following terms:

(i) At least 10,000,000 renewable energy credits delivered annually by the end of the 2021 delivery year, and increasing ratably to reach 45,000,000 renewable energy credits delivered annually from new wind and solar projects, from repowered wind projects, or from retooled hydropower facilities by the end of delivery year 2030 such that the goals in subparagraph (B) of this paragraph (1) are met entirely by procurements of renewable energy credits from new wind and photovoltaic projects. Of that amount, to the extent possible, the Agency shall endeavor to procure 45% from new and repowered wind and hydropower projects and shall procure at least 55% from photovoltaic projects. Of the amount to be procured from photovoltaic projects, the Agency shall procure: at least 50% from solar photovoltaic projects using the program outlined in subparagraph (K) of this paragraph (1) from distributed renewable energy generation devices or community renewable generation projects; at least 47% from utility-scale solar projects; at least 3% from brownfield site photovoltaic projects that are not community renewable generation projects. The Agency may propose adjustments to these percentages, including establishing percentage-based goals for the procurement of renewable energy credits from modernized or retooled hydropower facilities and repowered wind projects, through its long-term renewable resources plan described in subparagraph (A) of this paragraph (1) as necessary based on developer interest, market conditions, budget considerations, resource adequacy needs, or other factors.

In developing the long-term renewable resources procurement plan, the Agency shall consider other approaches, in addition to competitive procurements, that can be used to procure renewable energy credits from brownfield site photovoltaic projects and thereby help return blighted or contaminated land to productive use while enhancing public health and the well-being of Illinois residents, including those in environmental justice communities, as defined using existing methodologies and findings used by the Agency and its Administrator in its Illinois Solar for All Program. The Agency shall also consider other approaches, in addition to competitive procurements, to procure renewable energy credits from new and existing hydropower facilities to support the development and maintenance of these facilities. The Agency shall explore options to convert existing dams but shall not consider approaches to develop new dams where they do not already exist. To encourage the continued operation of utility-scale wind projects, the Agency shall consider and may propose other approaches in addition to competitive procurements to procure renewable energy credits from repowered wind projects.

(ii) In any given delivery year, if forecasted expenses are less than the maximum budget available under subparagraph (E) of this paragraph (1), the Agency shall continue to procure new renewable energy credits until that budget is exhausted in the manner outlined in item (i) of this subparagraph (C).

(iii) For purposes of this Section:

"New wind projects" means wind renewable energy facilities that are energized after June 1, 2017 for the delivery year commencing June 1, 2017.

"New photovoltaic projects" means photovoltaic renewable energy facilities that are energized after June 1, 2017. Photovoltaic projects developed under Section 1-56 of this Act shall not apply towards the new photovoltaic project requirements in this subparagraph (C).

"Repowered wind projects" means utility-scale wind projects featuring the removal, replacement, or expansion of turbines at an existing project site, as defined in the long-term renewable resources procurement plan, after the effective date of this amendatory Act of the 103rd General Assembly. Renewable energy credit contract awards used to support repowered wind projects shall only cover the incremental increase in facility electricity production resultant from repowering.

For purposes of calculating whether the Agency has procured enough new wind and solar renewable energy credits required by this subparagraph (C), renewable energy facilities that have a multi-year renewable energy credit delivery contract with the utility through at least delivery year 2030 shall be considered new, however no renewable energy credits from contracts entered into before June 1, 2021 shall be used to calculate whether the Agency has procured the correct proportion of new wind and new solar contracts described in this subparagraph (C) for delivery year 2021 and thereafter.

(D) Renewable energy credits shall be cost effective. For purposes of this subsection (c), "cost effective" means that the costs of procuring renewable energy resources do not cause the limit stated in subparagraph (E) of this paragraph (1) to be exceeded and, for renewable energy credits procured through a competitive procurement event, do not exceed benchmarks based on market prices for like products in the region. For purposes of this subsection (c), "like products" means contracts for renewable energy credits from the same or substantially similar technology, same or substantially similar vintage (new or existing), the same or substantially similar quantity, and the same or substantially similar contract length and structure. Benchmarks shall reflect development, financing, or related costs resulting from requirements imposed through other provisions of State law, including, but not limited to, requirements in subparagraphs (P) and (Q) of this paragraph (1) and the Renewable Energy Facilities Agricultural Impact Mitigation Act. Confidential benchmarks shall be developed by the procurement administrator, in consultation with the Commission staff, Agency staff, and the procurement monitor and shall be subject to Commission review and approval. If price benchmarks for like products in the region are not available, the procurement administrator shall establish price benchmarks based on publicly available data on regional technology costs and expected current and future regional energy prices. The benchmarks in this Section shall not be used to curtail or otherwise reduce contractual obligations entered into by or through the Agency prior to June 1, 2017 (the effective date of Public Act 99-906).

(E) For purposes of this subsection (c), the required procurement of cost-effective renewable energy resources for a particular year commencing prior to June 1, 2017 shall be measured as a percentage of the actual amount of electricity (megawatt-hours) supplied by the electric utility to eligible retail customers in the delivery year ending immediately prior to the procurement, and, for delivery years commencing on and after June 1, 2017, the required procurement of cost-effective renewable energy resources for a particular year shall be measured as a percentage of the actual amount of electricity (megawatt-hours) delivered by the electric utility in the delivery year ending immediately prior to the procurement, to all retail customers in its service territory. For purposes of this subsection (c), the amount paid per kilowatthour means the total amount paid for electric service expressed on a per kilowatthour basis. For purposes of this subsection (c), the total amount paid for electric service includes without limitation amounts paid for supply, transmission, capacity, distribution, surcharges, and add-on taxes.

Notwithstanding the requirements of this subsection (c), and except as provided in subparagraph (E-5) of paragraph (1) of this subsection (c), the total of renewable energy resources procured under the procurement plan for any single year shall be subject to the limitations of this subparagraph (E). Such procurement shall be reduced for all retail customers based on the amount necessary to limit the annual estimated average net increase due to the costs of these resources included in the amounts paid by eligible retail customers in connection with electric service to no more than 4.25% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009. To arrive at a maximum dollar amount of renewable energy resources to be procured for the particular delivery year, the resulting per kilowatthour amount shall be applied to the actual amount of kilowatthours of electricity delivered, or applicable portion of such amount as specified in paragraph (1) of this subsection (c), as applicable, by the electric utility in the delivery year immediately prior to the procurement to all retail customers in its service territory. The calculations required by this subparagraph (E) shall be made only once for each delivery year at the time that the renewable energy resources are procured. Once the determination as to the amount of renewable energy resources to procure is made based on the calculations set forth in this subparagraph (E) and the contracts procuring those amounts are executed between the seller and applicable electric utility, no subsequent rate impact determinations shall be made and no adjustments to those contract amounts shall be allowed. As provided in subparagraph (E-5) of paragraph (1) of this subsection (c), the seller shall be entitled to full, prompt, and uninterrupted payment under the applicable contract notwithstanding the application of this subparagraph (E), and all costs incurred under such contracts shall be fully recoverable by the electric utility as provided in this Section.

(E-5) If, for a particular delivery year, the limitation on the amount of renewable energy resources to be procured, as calculated pursuant to subparagraph (E) of paragraph (1) of this subsection (c), would result in an insufficient collection of funds to fully pay amounts due to a seller under existing contracts executed under this Section or executed under Section 1-56 of this Act, then the following provisions shall apply to ensure full and uninterrupted payment is made to such seller or sellers:

(i) If the electric utility has retained unspent funds in an interest-bearing account as prescribed in subsection (k) of Section 16-108 of the Public Utilities Act, then the utility shall use those funds to remit full payment to the sellers to ensure prompt and uninterrupted payment of existing contractual obligation.

(ii) If the funds described in item (i) of this subparagraph (E-5) are insufficient to satisfy all existing contractual obligations, then the electric utility shall, nonetheless, remit full payment to the sellers to ensure prompt and uninterrupted payment of existing contractual obligations, provided that the full costs shall be recoverable by the utility in accordance with part (ee) of item (iv) of this subsection (E-5).

(iii) The Agency shall promptly notify the Commission that existing contractual obligations are reasonably expected to exceed the maximum collection authorized under subparagraph (E) of paragraph (1) of this subsection (c) for the applicable delivery year. The Agency shall also explain and confirm how the operation of items (i) and (ii) of this subparagraph (E-5) ensures that the electric utility will continue to make prompt and uninterrupted payment under existing contractual obligations. The Agency shall provide this information to the Commission through a notice filed in the Commission docket approving the Agency's operative Long-Term Renewable Resources Procurement Plan that includes the applicable delivery year.

(iv) The Agency shall suspend or reduce new contract awards for the procurement of renewable energy credits until an Agency determination is made under subparagraph (E) that additional procurements would not cause the rate impact limitation of subparagraph (E) to be exceeded. At least once annually after the notice provided for in item (iii) of this subparagraph (E-5) is made, the Agency shall analyze existing contract obligations, projected prices for indexed renewable energy credit contracts executed under item (v) of subparagraph (G) of paragraph (1) of subsection (c) of Section 1-75 of this Act, and expected collections authorized under subparagraph (E) to determine whether and to what extent the limitations of subparagraph (E) would be exceeded by additional renewable energy credit procurement contract awards.

(aa) If the Agency determines that additional renewable energy credit procurement contract awards could be made without exceeding the limitations of subparagraph (E), then the procurements shall be authorized at a scale determined not to exceed the limitations of subparagraph (E) in a manner consistent with the priorities of this Section.

(bb) If the Agency determines that additional renewable energy credit procurement contract awards cannot be made without exceeding the limitations of subparagraph (E), then the Agency shall suspend any new contract awards for the procurement of renewable energy credits until a new rate impact determination is made under subparagraph (E).

(cc) Agency determinations made under this item (iv) shall be detailed and comprehensive and, if not made through the Agency's Long-Term Renewable Resources Procurement Plan, shall be filed as a compliance filing in the most recent docketed proceeding approving the Agency's Long-Term Renewable Resources Procurement Plan.

(dd) With respect to the procurement of renewable energy credits authorized through programs administered under subsection (b) of Section 1-56 and subparagraphs (K) through (M) of paragraph (1) of subsection (k) of Section 1-75 of this Act, the award of contracts for the procurement of renewable energy credits shall be suspended or reduced only at the conclusion of the program year in which the notice provided for under item (iii) of this subparagraph (E-5) is made.

(ee) The contract shall provide that, so long as at least one of: (i) the cost recovery mechanisms referenced in subsection (k) of Section 16-108 and subsection (l) of Section 16-111.5 of the Public Utilities Act remains in full force without limitation or (ii) the utility is otherwise authorized and or entitled to full, prompt, and uninterrupted recovery of its costs through any other mechanism, then such seller shall be entitled to full, prompt, and uninterrupted payment under the applicable contract notwithstanding the application of this subparagraph (E).

(F) If the limitation on the amount of renewable energy resources procured in subparagraph (E) of this paragraph (1) prevents the Agency from meeting all of the goals in this subsection (c), the Agency's long-term plan shall prioritize compliance with the requirements of this subsection (c) regarding renewable energy credits in the following order:

(i) renewable energy credits under existing contractual obligations as of June 1, 2021;

(i-5) funding for the Illinois Solar for All Program, as described in subparagraph (O) of this paragraph (1);

(ii) renewable energy credits necessary to comply with the new wind and new photovoltaic procurement requirements described in items (i) through (iii) of subparagraph (C) of this paragraph (1); and

(iii) renewable energy credits necessary to meet the remaining requirements of this subsection (c).

(G) The following provisions shall apply to the Agency's procurement of renewable energy credits under this subsection (c):

(i) Notwithstanding whether a long-term renewable resources procurement plan has been approved, the Agency shall conduct an initial forward procurement for renewable energy credits from new utility-scale wind projects within 160 days after June 1, 2017 (the effective date of Public Act 99-906). For the purposes of this initial forward procurement, the Agency shall solicit 15-year contracts for delivery of 1,000,000 renewable energy credits delivered annually from new utility-scale wind projects to begin delivery on June 1, 2019, if available, but not later than June 1, 2021, unless the project has delays in the establishment of an operating interconnection with the applicable transmission or distribution system as a result of the actions or inactions of the transmission or distribution provider, or other causes for force majeure as outlined in the procurement contract, in which case, not later than June 1, 2022. Payments to suppliers of renewable energy credits shall commence upon delivery. Renewable energy credits procured under this initial procurement shall be included in the Agency's long-term plan and shall apply to all renewable energy goals in this subsection (c).

(ii) Notwithstanding whether a long-term renewable resources procurement plan has been approved, the Agency shall conduct an initial forward procurement for renewable energy credits from new utility-scale solar projects and brownfield site photovoltaic projects within one year after June 1, 2017 (the effective date of Public Act 99-906). For the purposes of this initial forward procurement, the Agency shall solicit 15-year contracts for delivery of 1,000,000 renewable energy credits delivered annually from new utility-scale solar projects and brownfield site photovoltaic projects to begin delivery on June 1, 2019, if available, but not later than June 1, 2021, unless the project has delays in the establishment of an operating interconnection with the applicable transmission or distribution system as a result of the actions or inactions of the transmission or distribution provider, or other causes for force majeure as outlined in the procurement contract, in which case, not later than June 1, 2022. The Agency may structure this initial procurement in one or more discrete procurement events. Payments to suppliers of renewable energy credits shall commence upon delivery. Renewable energy credits procured under this initial procurement shall be included in the Agency's long-term plan and shall apply to all renewable energy goals in this subsection (c).

(iii) Notwithstanding whether the Commission has approved the periodic long-term renewable resources procurement plan revision described in Section 16-111.5 of the Public Utilities Act, the Agency shall conduct at least one subsequent forward procurement for renewable energy credits from new utility-scale wind projects, new utility-scale solar projects, and new brownfield site photovoltaic projects within 240 days after the effective date of this amendatory Act of the 102nd General Assembly in quantities necessary to meet the requirements of subparagraph (C) of this paragraph (1) through the delivery year beginning June 1, 2021.

(iv) Notwithstanding whether the Commission has approved the periodic long-term renewable resources procurement plan revision described in Section 16-111.5 of the Public Utilities Act, the Agency shall open capacity for each category in the Adjustable Block program within 90 days after the effective date of this amendatory Act of the 102nd General Assembly manner:

(1) The Agency shall open the first block of annual capacity for the category described in item (i) of subparagraph (K) of this paragraph (1). The first block of annual capacity for item (i) shall be for at least 75 megawatts of total nameplate capacity. The price of the renewable energy credit for this block of capacity shall be 4% less than the price of the last open block in this category. Projects on a waitlist shall be awarded contracts first in the order in which they appear on the waitlist. Notwithstanding anything to the contrary, for those renewable energy credits that qualify and are procured under this subitem (1) of this item (iv), the renewable energy credit delivery contract value shall be paid in full, based on the estimated generation during the first 15 years of operation, by the contracting utilities at the time that the facility producing the renewable energy credits is interconnected at the distribution system level of the utility and verified as energized and in compliance by the Program Administrator. The electric utility shall receive and retire all renewable energy credits generated by the project for the first 15 years of operation. Renewable energy credits generated by the project thereafter shall not be transferred under the renewable energy credit delivery contract with the counterparty electric utility.

(2) The Agency shall open the first block of annual capacity for the category described in item (ii) of subparagraph (K) of this paragraph (1). The first block of annual capacity for item (ii) shall be for at least 75 megawatts of total nameplate capacity.

(A) The price of the renewable energy credit for any project on a waitlist for this category before the opening of this block shall be 4% less than the price of the last open block in this category. Projects on the waitlist shall be awarded contracts first in the order in which they appear on the waitlist. Any projects that are less than or equal to 25 kilowatts in size on the waitlist for this capacity shall be moved to the waitlist for paragraph (1) of this item (iv). Notwithstanding anything to the contrary, projects that were on the waitlist prior to opening of this block shall not be required to be in compliance with the requirements of subparagraph (Q) of this paragraph (1) of this subsection (c). Notwithstanding anything to the contrary, for those renewable energy credits procured from projects that were on the waitlist for this category before the opening of this block 20% of the renewable energy credit delivery contract value, based on the estimated generation during the first 15 years of operation, shall be paid by the contracting utilities at the time that the facility producing the renewable energy credits is interconnected at the distribution system level of the utility and verified as energized by the Program Administrator. The remaining portion shall be paid ratably over the subsequent 4-year period. The electric utility shall receive and retire all renewable energy credits generated by the project during the first 15 years of operation. Renewable energy credits generated by the project thereafter shall not be transferred under the renewable energy credit delivery contract with the counterparty electric utility.

(B) The price of renewable energy credits for any project not on the waitlist for this category before the opening of the block shall be determined and published by the Agency. Projects not on a waitlist as of the opening of this block shall be subject to the requirements of subparagraph (Q) of this paragraph (1), as applicable. Projects not on a waitlist as of the opening of this block shall be subject to the contract provisions outlined in item (iii) of subparagraph (L) of this paragraph (1). The Agency shall strive to publish updated prices and an updated renewable energy credit delivery contract as quickly as possible.

(3) For opening the first 2 blocks of annual capacity for projects participating in item (iii) of subparagraph (K) of paragraph (1) of subsection (c), projects shall be selected exclusively from those projects on the ordinal waitlists of community renewable generation projects established by the Agency based on the status of those ordinal waitlists as of December 31, 2020, and only those projects previously determined to be eligible for the Agency's April 2019 community solar project selection process.

The first 2 blocks of annual capacity for item (iii) shall be for 250 megawatts of total nameplate capacity, with both blocks opening simultaneously under the schedule outlined in the paragraphs below. Projects shall be selected as follows:

(A) The geographic balance of selected projects shall follow the Group classification found in the Agency's Revised Long-Term Renewable Resources Procurement Plan, with 70% of capacity allocated to projects on the Group B waitlist and 30% of capacity allocated to projects on the Group A waitlist.

(B) Contract awards for waitlisted projects shall be allocated proportionate to the total nameplate capacity amount across both ordinal waitlists associated with that applicant firm or its affiliates, subject to the following conditions.

(i) Each applicant firm having a waitlisted project eligible for selection shall receive no less than 500 kilowatts in awarded capacity across all groups, and no approved vendor may receive more than 20% of each Group's waitlist allocation.

(ii) Each applicant firm, upon receiving an award of program capacity proportionate to its waitlisted capacity, may then determine which waitlisted projects it chooses to be selected for a contract award up to that capacity amount.

(iii) Assuming all other program requirements are met, applicant firms may adjust the nameplate capacity of applicant projects without losing waitlist eligibility, so long as no project is greater than 2,000 kilowatts in size.

(iv) Assuming all other program requirements are met, applicant firms may adjust the expected production associated with applicant projects, subject to verification by the Program Administrator.

(C) After a review of affiliate information and the current ordinal waitlists, the Agency shall announce the nameplate capacity award amounts associated with applicant firms no later than 90 days after the effective date of this amendatory Act of the 102nd General Assembly.

(D) Applicant firms shall submit their portfolio of projects used to satisfy those contract awards no less than 90 days after the Agency's announcement. The total nameplate capacity of all projects used to satisfy that portfolio shall be no greater than the Agency's nameplate capacity award amount associated with that applicant firm. An applicant firm may decline, in whole or in part, its nameplate capacity award without penalty, with such unmet capacity rolled over to the next block opening for project selection under item (iii) of subparagraph (K) of this subsection (c). Any projects not included in an applicant firm's portfolio may reapply without prejudice upon the next block reopening for project selection under item (iii) of subparagraph (K) of this subsection (c).

(E) The renewable energy credit delivery contract shall be subject to the contract and payment terms outlined in item (iv) of subparagraph (L) of this subsection (c). Contract instruments used for this subparagraph shall contain the following terms:

(i) Renewable energy credit prices shall be fixed, without further adjustment under any other provision of this Act or for any other reason, at 10% lower than prices applicable to the last open block for this category, inclusive of any adders available for achieving a minimum of 50% of subscribers to the project's nameplate capacity being residential or small commercial customers with subscriptions of below 25 kilowatts in size;

(ii) A requirement that a minimum of 50% of subscribers to the project's nameplate capacity be residential or small commercial customers with subscriptions of below 25 kilowatts in size;

(iii) Permission for the ability of a contract holder to substitute projects with other waitlisted projects without penalty should a project receive a non-binding estimate of costs to construct the interconnection facilities and any required distribution upgrades associated with that project of greater than 30 cents per watt AC of that project's nameplate capacity. In developing the applicable contract instrument, the Agency may consider whether other circumstances outside of the control of the applicant firm should also warrant project substitution rights.

The Agency shall publish a finalized updated renewable energy credit delivery contract developed consistent with these terms and conditions no less than 30 days before applicant firms must submit their portfolio of projects pursuant to item (D).

(F) To be eligible for an award, the applicant firm shall certify that not less than prevailing wage, as determined pursuant to the Illinois Prevailing Wage Act, was or will be paid to employees who are engaged in construction activities associated with a selected project.

(4) The Agency shall open the first block of annual capacity for the category described in item (iv) of subparagraph (K) of this paragraph (1). The first block of annual capacity for item (iv) shall be for at least 50 megawatts of total nameplate capacity. Renewable energy credit prices shall be fixed, without further adjustment under any other provision of this Act or for any other reason, at the price in the last open block in the category described in item (ii) of subparagraph (K) of this paragraph (1). Pricing for future blocks of annual capacity for this category may be adjusted in the Agency's second revision to its Long-Term Renewable Resources Procurement Plan. Projects in this category shall be subject to the contract terms outlined in item (iv) of subparagraph (L) of this paragraph (1).

(5) The Agency shall open the equivalent of 2 years of annual capacity for the category described in item (v) of subparagraph (K) of this paragraph (1). The first block of annual capacity for item (v) shall be for at least 10 megawatts of total nameplate capacity. Notwithstanding the provisions of item (v) of subparagraph (K) of this paragraph (1), for the purpose of this initial block, the agency shall accept new project applications intended to increase the diversity of areas hosting community solar projects, the business models of projects, and the size of projects, as described by the Agency in its long-term renewable resources procurement plan that is approved as of the effective date of this amendatory Act of the 102nd General Assembly. Projects in this category shall be subject to the contract terms outlined in item (iii) of subsection (L) of this paragraph (1).

(6) The Agency shall open the first blocks of annual capacity for the category described in item (vi) of subparagraph (K) of this paragraph (1), with allocations of capacity within the block generally matching the historical share of block capacity allocated between the category described in items (i) and (ii) of subparagraph (K) of this paragraph (1). The first two blocks of annual capacity for item (vi) shall be for at least 75 megawatts of total nameplate capacity. The price of renewable energy credits for the blocks of capacity shall be 4% less than the price of the last open blocks in the categories described in items (i) and (ii) of subparagraph (K) of this paragraph (1). Pricing for future blocks of annual capacity for this category may be adjusted in the Agency's second revision to its Long-Term Renewable Resources Procurement Plan. Projects in this category shall be subject to the applicable contract terms outlined in items (ii) and (iii) of subparagraph (L) of this paragraph (1).

(v) Upon the effective date of this amendatory Act of the 102nd General Assembly, for all competitive procurements and any procurements of renewable energy credit from new utility-scale wind and new utility-scale photovoltaic projects, the Agency shall procure indexed renewable energy credits and direct respondents to offer a strike price.

(1) The purchase price of the indexed renewable energy credit payment shall be calculated for each settlement period. That payment, for any settlement period, shall be equal to the difference resulting from subtracting the strike price from the index price for that settlement period. If this difference results in a negative number, the indexed REC counterparty shall owe the seller the absolute value multiplied by the quantity of energy produced in the relevant settlement period. If this difference results in a positive number, the seller shall owe the indexed REC counterparty this amount multiplied by the quantity of energy produced in the relevant settlement period.

(2) Parties shall cash settle every month, summing up all settlements (both positive and negative, if applicable) for the prior month.

(3) To ensure funding in the annual budget established under subparagraph (E) for indexed renewable energy credit procurements for each year of the term of such contracts, which must have a minimum tenure of 20 calendar years, the procurement administrator, Agency, Commission staff, and procurement monitor shall quantify the annual cost of the contract by utilizing an industry-standard, third-party forward price curve for energy at the appropriate hub or load zone, including the estimated magnitude and timing of the price effects related to federal carbon controls. Each forward price curve shall contain a specific value of the forecasted market price of electricity for each annual delivery year of the contract. For procurement planning purposes, the impact on the annual budget for the cost of indexed renewable energy credits for each delivery year shall be determined as the expected annual contract expenditure for that year, equaling the difference between (i) the sum across all relevant contracts of the applicable strike price multiplied by contract quantity and (ii) the sum across all relevant contracts of the forward price curve for the applicable load zone for that year multiplied by contract quantity. The contracting utility shall not assume an obligation in excess of the estimated annual cost of the contracts for indexed renewable energy credits. Forward curves shall be revised on an annual basis as updated forward price curves are released and filed with the Commission in the proceeding approving the Agency's most recent long-term renewable resources procurement plan. If the expected contract spend is higher or lower than the total quantity of contracts multiplied by the forward price curve value for that year, the forward price curve shall be updated by the procurement administrator, in consultation with the Agency, Commission staff, and procurement monitors, using then-currently available price forecast data and additional budget dollars shall be obligated or reobligated as appropriate.

(4) To ensure that indexed renewable energy credit prices remain predictable and affordable, the Agency may consider the institution of a price collar on REC prices paid under indexed renewable energy credit procurements establishing floor and ceiling REC prices applicable to indexed REC contract prices. Any price collars applicable to indexed REC procurements shall be proposed by the Agency through its long-term renewable resources procurement plan.

(vi) All procurements under this subparagraph (G), including the procurement of renewable energy credits from hydropower facilities, shall comply with the geographic requirements in subparagraph (I) of this paragraph (1) and shall follow the procurement processes and procedures described in this Section and Section 16-111.5 of the Public Utilities Act to the extent practicable, and these processes and procedures may be expedited to accommodate the schedule established by this subparagraph (G).

(vii) On and after the effective date of this amendatory Act of the 103rd General Assembly, for all procurements of renewable energy credits from hydropower facilities, the Agency shall establish contract terms designed to optimize existing hydropower facilities through modernization or retooling and establish new hydropower facilities at existing dams. Procurements made under this item (vii) shall prioritize projects located in designated environmental justice communities, as defined in subsection (b) of Section 1-56 of this Act, or in projects located in units of local government with median incomes that do not exceed 82% of the median income of the State.

(H) The procurement of renewable energy resources for a given delivery year shall be reduced as described in this subparagraph (H) if an alternative retail electric supplier meets the requirements described in this subparagraph (H).

(i) Within 45 days after June 1, 2017 (the effective date of Public Act 99-906), an alternative retail electric supplier or its successor shall submit an informational filing to the Illinois Commerce Commission certifying that, as of December 31, 2015, the alternative retail electric supplier owned one or more electric generating facilities that generates renewable energy resources as defined in Section 1-10 of this Act, provided that such facilities are not powered by wind or photovoltaics, and the facilities generate one renewable energy credit for each megawatthour of energy produced from the facility.

The informational filing shall identify each facility that was eligible to satisfy the alternative retail electric supplier's obligations under Section 16-115D of the Public Utilities Act as described in this item (i).

(ii) For a given delivery year, the alternative retail electric supplier may elect to supply its retail customers with renewable energy credits from the facility or facilities described in item (i) of this subparagraph (H) that continue to be owned by the alternative retail electric supplier.

(iii) The alternative retail electric supplier shall notify the Agency and the applicable utility, no later than February 28 of the year preceding the applicable delivery year or 15 days after June 1, 2017 (the effective date of Public Act 99-906), whichever is later, of its election under item (ii) of this subparagraph (H) to supply renewable energy credits to retail customers of the utility. Such election shall identify the amount of renewable energy credits to be supplied by the alternative retail electric supplier to the utility's retail customers and the source of the renewable energy credits identified in the informational filing as described in item (i) of this subparagraph (H), subject to the following limitations:

For the delivery year beginning June 1, 2018, the maximum amount of renewable energy credits to be supplied by an alternative retail electric supplier under this subparagraph (H) shall be 68% multiplied by 25% multiplied by 14.5% multiplied by the amount of metered electricity (megawatt-hours) delivered by the alternative retail electric supplier to Illinois retail customers during the delivery year ending May 31, 2016.

For delivery years beginning June 1, 2019 and each year thereafter, the maximum amount of renewable energy credits to be supplied by an alternative retail electric supplier under this subparagraph (H) shall be 68% multiplied by 50% multiplied by 16% multiplied by the amount of metered electricity (megawatt-hours) delivered by the alternative retail electric supplier to Illinois retail customers during the delivery year ending May 31, 2016, provided that the 16% value shall increase by 1.5% each delivery year thereafter to 25% by the delivery year beginning June 1, 2025, and thereafter the 25% value shall apply to each delivery year.

For each delivery year, the total amount of renewable energy credits supplied by all alternative retail electric suppliers under this subparagraph (H) shall not exceed 9% of the Illinois target renewable energy credit quantity. The Illinois target renewable energy credit quantity for the delivery year beginning June 1, 2018 is 14.5% multiplied by the total amount of metered electricity (megawatt-hours) delivered in the delivery year immediately preceding that delivery year, provided that the 14.5% shall increase by 1.5% each delivery year thereafter to 25% by the delivery year beginning June 1, 2025, and thereafter the 25% value shall apply to each delivery year.

If the requirements set forth in items (i) through (iii) of this subparagraph (H) are met, the charges that would otherwise be applicable to the retail customers of the alternative retail electric supplier under paragraph (6) of this subsection (c) for the applicable delivery year shall be reduced by the ratio of the quantity of renewable energy credits supplied by the alternative retail electric supplier compared to that supplier's target renewable energy credit quantity. The supplier's target renewable energy credit quantity for the delivery year beginning June 1, 2018 is 14.5% multiplied by the total amount of metered electricity (megawatt-hours) delivered by the alternative retail supplier in that delivery year, provided that the 14.5% shall increase by 1.5% each delivery year thereafter to 25% by the delivery year beginning June 1, 2025, and thereafter the 25% value shall apply to each delivery year.

On or before April 1 of each year, the Agency shall annually publish a report on its website that identifies the aggregate amount of renewable energy credits supplied by alternative retail electric suppliers under this subparagraph (H).

(I) The Agency shall design its long-term renewable energy procurement plan to maximize the State's interest in the health, safety, and welfare of its residents, including but not limited to minimizing sulfur dioxide, nitrogen oxide, particulate matter and other pollution that adversely affects public health in this State, increasing fuel and resource diversity in this State, enhancing the reliability and resiliency of the electricity distribution system in this State, meeting goals to limit carbon dioxide emissions under federal or State law, and contributing to a cleaner and healthier environment for the citizens of this State. In order to further these legislative purposes, renewable energy credits shall be eligible to be counted toward the renewable energy requirements of this subsection (c) if they are generated from facilities located in this State. The Agency may qualify renewable energy credits from facilities located in states adjacent to Illinois or renewable energy credits associated with the electricity generated by a utility-scale wind energy facility or utility-scale photovoltaic facility and transmitted by a qualifying direct current project described in subsection (b-5) of Section 8-406 of the Public Utilities Act to a delivery point on the electric transmission grid located in this State or a state adjacent to Illinois, if the generator demonstrates and the Agency determines that the operation of such facility or facilities will help promote the State's interest in the health, safety, and welfare of its residents based on the public interest criteria described above. For the purposes of this Section, renewable resources that are delivered via a high voltage direct current converter station located in Illinois shall be deemed generated in Illinois at the time and location the energy is converted to alternating current by the high voltage direct current converter station if the high voltage direct current transmission line: (i) after the effective date of this amendatory Act of the 102nd General Assembly, was constructed with a project labor agreement; (ii) is capable of transmitting electricity at 525kv; (iii) has an Illinois converter station located and interconnected in the region of the PJM Interconnection, LLC; (iv) does not operate as a public utility; and (v) if the high voltage direct current transmission line was energized after June 1, 2023. To ensure that the public interest criteria are applied to the procurement and given full effect, the Agency's long-term procurement plan shall describe in detail how each public interest factor shall be considered and weighted for facilities located in states adjacent to Illinois.

(J) In order to promote the competitive development of renewable energy resources in furtherance of the State's interest in the health, safety, and welfare of its residents, renewable energy credits shall not be eligible to be counted toward the renewable energy requirements of this subsection (c) if they are sourced from a generating unit whose costs were being recovered through rates regulated by this State or any other state or states on or after January 1, 2017. Each contract executed to purchase renewable energy credits under this subsection (c) shall provide for the contract's termination if the costs of the generating unit supplying the renewable energy credits subsequently begin to be recovered through rates regulated by this State or any other state or states; and each contract shall further provide that, in that event, the supplier of the credits must return 110% of all payments received under the contract. Amounts returned under the requirements of this subparagraph (J) shall be retained by the utility and all of these amounts shall be used for the procurement of additional renewable energy credits from new wind or new photovoltaic resources as defined in this subsection (c). The long-term plan shall provide that these renewable energy credits shall be procured in the next procurement event.

Notwithstanding the limitations of this subparagraph (J), renewable energy credits sourced from generating units that are constructed, purchased, owned, or leased by an electric utility as part of an approved project, program, or pilot under Section 1-56 of this Act shall be eligible to be counted toward the renewable energy requirements of this subsection (c), regardless of how the costs of these units are recovered. As long as a generating unit or an identifiable portion of a generating unit has not had and does not have its costs recovered through rates regulated by this State or any other state, HVDC renewable energy credits associated with that generating unit or identifiable portion thereof shall be eligible to be counted toward the renewable energy requirements of this subsection (c).

(K) The long-term renewable resources procurement plan developed by the Agency in accordance with subparagraph (A) of this paragraph (1) shall include an Adjustable Block program for the procurement of renewable energy credits from new photovoltaic projects that are distributed renewable energy generation devices or new photovoltaic community renewable generation projects. The Adjustable Block program shall be generally designed to provide for the steady, predictable, and sustainable growth of new solar photovoltaic development in Illinois. To this end, the Adjustable Block program shall provide a transparent annual schedule of prices and quantities to enable the photovoltaic market to scale up and for renewable energy credit prices to adjust at a predictable rate over time. The prices set by the Adjustable Block program can be reflected as a set value or as the product of a formula.

The Adjustable Block program shall include for each category of eligible projects for each delivery year: a single block of nameplate capacity, a price for renewable energy credits within that block, and the terms and conditions for securing a spot on a waitlist once the block is fully committed or reserved. Except as outlined below, the waitlist of projects in a given year will carry over to apply to the subsequent year when another block is opened. Only projects energized on or after June 1, 2017 shall be eligible for the Adjustable Block program. For each category for each delivery year the Agency shall determine the amount of generation capacity in each block, and the purchase price for each block, provided that the purchase price provided and the total amount of generation in all blocks for all categories shall be sufficient to meet the goals in this subsection (c). The Agency shall strive to issue a single block sized to provide for stability and market growth. The Agency shall establish program eligibility requirements that ensure that projects that enter the program are sufficiently mature to indicate a demonstrable path to completion. The Agency may periodically review its prior decisions establishing the amount of generation capacity in each block, and the purchase price for each block, and may propose, on an expedited basis, changes to these previously set values, including but not limited to redistributing these amounts and the available funds as necessary and appropriate, subject to Commission approval as part of the periodic plan revision process described in Section 16-111.5 of the Public Utilities Act. The Agency may define different block sizes, purchase prices, or other distinct terms and conditions for projects located in different utility service territories if the Agency deems it necessary to meet the goals in this subsection (c).

The Adjustable Block program shall include the following categories in at least the following amounts:

(i) At least 20% from distributed renewable energy generation devices with a nameplate capacity of no more than 25 kilowatts.

(ii) At least 20% from distributed renewable energy generation devices with a nameplate capacity of more than 25 kilowatts and no more than 5,000 kilowatts. The Agency may create sub-categories within this category to account for the differences between projects for small commercial customers, large commercial customers, and public or non-profit customers.

(iii) At least 30% from photovoltaic community renewable generation projects. Capacity for this category for the first 2 delivery years after the effective date of this amendatory Act of the 102nd General Assembly shall be allocated to waitlist projects as provided in paragraph (3) of item (iv) of subparagraph (G). Starting in the third delivery year after the effective date of this amendatory Act of the 102nd General Assembly or earlier if the Agency determines there is additional capacity needed for to meet previous delivery year requirements, the following shall apply:

(1) the Agency shall select projects on a first-come, first-serve basis, however the Agency may suggest additional methods to prioritize projects that are submitted at the same time;

(2) projects shall have subscriptions of 25 kW or less for at least 50% of the facility's nameplate capacity and the Agency shall price the renewable energy credits with that as a factor;

(3) projects shall not be colocated with one or more other community renewable generation projects, as defined in the Agency's first revised long-term renewable resources procurement plan approved by the Commission on February 18, 2020, such that the aggregate nameplate capacity exceeds 5,000 kilowatts; and

(4) projects greater than 2 MW may not apply until after the approval of the Agency's revised Long-Term Renewable Resources Procurement Plan after the effective date of this amendatory Act of the 102nd General Assembly.

(iv) At least 15% from distributed renewable generation devices or photovoltaic community renewable generation projects installed on public school land. The Agency may create subcategories within this category to account for the differences between project size or location. Projects located within environmental justice communities or within Organizational Units that fall within Tier 1 or Tier 2 shall be given priority. Each of the Agency's periodic updates to its long-term renewable resources procurement plan to incorporate the procurement described in this subparagraph (iv) shall also include the proposed quantities or blocks, pricing, and contract terms applicable to the procurement as indicated herein. In each such update and procurement, the Agency shall set the renewable energy credit price and establish payment terms for the renewable energy credits procured pursuant to this subparagraph (iv) that make it feasible and affordable for public schools to install photovoltaic distributed renewable energy devices on their premises, including, but not limited to, those public schools subject to the prioritization provisions of this subparagraph. For the purposes of this item (iv):

"Environmental Justice Community" shall have the same meaning set forth in the Agency's long-term renewable resources procurement plan;

"Organization Unit", "Tier 1" and "Tier 2" shall have the meanings set for in Section 18-8.15 of the School Code;

"Public schools" shall have the meaning set forth in Section 1-3 of the School Code and includes public institutions of higher education, as defined in the Board of Higher Education Act.

(v) At least 5% from community-driven community solar projects intended to provide more direct and tangible connection and benefits to the communities which they serve or in which they operate and, additionally, to increase the variety of community solar locations, models, and options in Illinois. As part of its long-term renewable resources procurement plan, the Agency shall develop selection criteria for projects participating in this category. Nothing in this Section shall preclude the Agency from creating a selection process that maximizes community ownership and community benefits in selecting projects to receive renewable energy credits. Selection criteria shall include:

(1) community ownership or community wealth-building;

(2) additional direct and indirect community benefit, beyond project participation as a subscriber, including, but not limited to, economic, environmental, social, cultural, and physical benefits;

(3) meaningful involvement in project organization and development by community members or nonprofit organizations or public entities located in or serving the community;

(4) engagement in project operations and management by nonprofit organizations, public entities, or community members; and

(5) whether a project is developed in response to a site-specific RFP developed by community members or a nonprofit organization or public entity located in or serving the community.

Selection criteria may also prioritize projects that:

(1) are developed in collaboration with or to provide complementary opportunities for the Clean Jobs Workforce Network Program, the Illinois Climate Works Preapprenticeship Program, the Returning Residents Clean Jobs Training Program, the Clean Energy Contractor Incubator Program, or the Clean Energy Primes Contractor Accelerator Program;

(2) increase the diversity of locations of community solar projects in Illinois, including by locating in urban areas and population centers;

(3) are located in Equity Investment Eligible Communities;

(4) are not greenfield projects;

(5) serve only local subscribers;

(6) have a nameplate capacity that does not exceed 500 kW;

(7) are developed by an equity eligible contractor; or

(8) otherwise meaningfully advance the goals of providing more direct and tangible connection and benefits to the communities which they serve or in which they operate and increasing the variety of community solar locations, models, and options in Illinois.

For the purposes of this item (v):

"Community" means a social unit in which people come together regularly to effect change; a social unit in which participants are marked by a cooperative spirit, a common purpose, or shared interests or characteristics; or a space understood by its residents to be delineated through geographic boundaries or landmarks.

"Community benefit" means a range of services and activities that provide affirmative, economic, environmental, social, cultural, or physical value to a community; or a mechanism that enables economic development, high-quality employment, and education opportunities for local workers and residents, or formal monitoring and oversight structures such that community members may ensure that those services and activities respond to local knowledge and needs.

"Community ownership" means an arrangement in which an electric generating facility is, or over time will be, in significant part, owned collectively by members of the community to which an electric generating facility provides benefits; members of that community participate in decisions regarding the governance, operation, maintenance, and upgrades of and to that facility; and members of that community benefit from regular use of that facility.

Terms and guidance within these criteria that are not defined in this item (v) shall be defined by the Agency, with stakeholder input, during the development of the Agency's long-term renewable resources procurement plan. The Agency shall develop regular opportunities for projects to submit applications for projects under this category, and develop selection criteria that gives preference to projects that better meet individual criteria as well as projects that address a higher number of criteria.

(vi) At least 10% from distributed renewable energy generation devices, which includes distributed renewable energy devices with a nameplate capacity under 5,000 kilowatts or photovoltaic community renewable generation projects, from applicants that are equity eligible contractors. The Agency may create subcategories within this category to account for the differences between project size and type. The Agency shall propose to increase the percentage in this item (vi) over time to 40% based on factors, including, but not limited to, the number of equity eligible contractors and capacity used in this item (vi) in previous delivery years.

The Agency shall propose a payment structure for contracts executed pursuant to this paragraph under which, upon a demonstration of qualification or need, applicant firms are advanced capital disbursed after contract execution but before the contracted project's energization. The amount or percentage of capital advanced prior to project energization shall be sufficient to both cover any increase in development costs resulting from prevailing wage requirements or project-labor agreements, and designed to overcome barriers in access to capital faced by equity eligible contractors. The amount or percentage of advanced capital may vary by subcategory within this category and by an applicant's demonstration of need, with such levels to be established through the Long-Term Renewable Resources Procurement Plan authorized under subparagraph (A) of paragraph (1) of subsection (c) of this Section.

Contracts developed featuring capital advanced prior to a project's energization shall feature provisions to ensure both the successful development of applicant projects and the delivery of the renewable energy credits for the full term of the contract, including ongoing collateral requirements and other provisions deemed necessary by the Agency, and may include energization timelines longer than for comparable project types. The percentage or amount of capital advanced prior to project energization shall not operate to increase the overall contract value, however contracts executed under this subparagraph may feature renewable energy credit prices higher than those offered to similar projects participating in other categories. Capital advanced prior to energization shall serve to reduce the ratable payments made after energization under items (ii) and (iii) of subparagraph (L) or payments made for each renewable energy credit delivery under item (iv) of subparagraph (L).

(vii) The remaining capacity shall be allocated by the Agency in order to respond to market demand. The Agency shall allocate any discretionary capacity prior to the beginning of each delivery year.

To the extent there is uncontracted capacity from any block in any of categories (i) through (vi) at the end of a delivery year, the Agency shall redistribute that capacity to one or more other categories giving priority to categories with projects on a waitlist. The redistributed capacity shall be added to the annual capacity in the subsequent delivery year, and the price for renewable energy credits shall be the price for the new delivery year. Redistributed capacity shall not be considered redistributed when determining whether the goals in this subsection (K) have been met.

Notwithstanding anything to the contrary, as the Agency increases the capacity in item (vi) to 40% over time, the Agency may reduce the capacity of items (i) through (v) proportionate to the capacity of the categories of projects in item (vi), to achieve a balance of project types.

The Adjustable Block program shall be designed to ensure that renewable energy credits are procured from projects in diverse locations and are not concentrated in a few regional areas.

(L) Notwithstanding provisions for advancing capital prior to project energization found in item (vi) of subparagraph (K), the procurement of photovoltaic renewable energy credits under items (i) through (vi) of subparagraph (K) of this paragraph (1) shall otherwise be subject to the following contract and payment terms:

(i) (Blank).

(ii) For those renewable energy credits that qualify and are procured under item (i) of subparagraph (K) of this paragraph (1), and any similar category projects that are procured under item (vi) of subparagraph (K) of this paragraph (1) that qualify and are procured under item (vi), the contract length shall be 15 years. The renewable energy credit delivery contract value shall be paid in full, based on the estimated generation during the first 15 years of operation, by the contracting utilities at the time that the facility producing the renewable energy credits is interconnected at the distribution system level of the utility and verified as energized and compliant by the Program Administrator. The electric utility shall receive and retire all renewable energy credits generated by the project for the first 15 years of operation. Renewable energy credits generated by the project thereafter shall not be transferred under the renewable energy credit delivery contract with the counterparty electric utility.

(iii) For those renewable energy credits that qualify and are procured under item (ii) and (v) of subparagraph (K) of this paragraph (1) and any like projects similar category that qualify and are procured under item (vi), the contract length shall be 15 years. 15% of the renewable energy credit delivery contract value, based on the estimated generation during the first 15 years of operation, shall be paid by the contracting utilities at the time that the facility producing the renewable energy credits is interconnected at the distribution system level of the utility and verified as energized and compliant by the Program Administrator. The remaining portion shall be paid ratably over the subsequent 6-year period. The electric utility shall receive and retire all renewable energy credits generated by the project for the first 15 years of operation. Renewable energy credits generated by the project thereafter shall not be transferred under the renewable energy credit delivery contract with the counterparty electric utility.

(iv) For those renewable energy credits that qualify and are procured under items (iii) and (iv) of subparagraph (K) of this paragraph (1), and any like projects that qualify and are procured under item (vi), the renewable energy credit delivery contract length shall be 20 years and shall be paid over the delivery term, not to exceed during each delivery year the contract price multiplied by the estimated annual renewable energy credit generation amount. If generation of renewable energy credits during a delivery year exceeds the estimated annual generation amount, the excess renewable energy credits shall be carried forward to future delivery years and shall not expire during the delivery term. If generation of renewable energy credits during a delivery year, including carried forward excess renewable energy credits, if any, is less than the estimated annual generation amount, payments during such delivery year will not exceed the quantity generated plus the quantity carried forward multiplied by the contract price. The electric utility shall receive all renewable energy credits generated by the project during the first 20 years of operation and retire all renewable energy credits paid for under this item (iv) and return at the end of the delivery term all renewable energy credits that were not paid for. Renewable energy credits generated by the project thereafter shall not be transferred under the renewable energy credit delivery contract with the counterparty electric utility. Notwithstanding the preceding, for those projects participating under item (iii) of subparagraph (K), the contract price for a delivery year shall be based on subscription levels as measured on the higher of the first business day of the delivery year or the first business day 6 months after the first business day of the delivery year. Subscription of 90% of nameplate capacity or greater shall be deemed to be fully subscribed for the purposes of this item (iv). For projects receiving a 20-year delivery contract, REC prices shall be adjusted downward for consistency with the incentive levels previously determined to be necessary to support projects under 15-year delivery contracts, taking into consideration any additional new requirements placed on the projects, including, but not limited to, labor standards.

(v) Each contract shall include provisions to ensure the delivery of the estimated quantity of renewable energy credits and ongoing collateral requirements and other provisions deemed appropriate by the Agency.

(vi) The utility shall be the counterparty to the contracts executed under this subparagraph (L) that are approved by the Commission under the process described in Section 16-111.5 of the Public Utilities Act. No contract shall be executed for an amount that is less than one renewable energy credit per year.

(vii) If, at any time, approved applications for the Adjustable Block program exceed funds collected by the electric utility or would cause the Agency to exceed the limitation described in subparagraph (E) of this paragraph (1) on the amount of renewable energy resources that may be procured, then the Agency may consider future uncommitted funds to be reserved for these contracts on a first-come, first-served basis.

(viii) Nothing in this Section shall require the utility to advance any payment or pay any amounts that exceed the actual amount of revenues anticipated to be collected by the utility under paragraph (6) of this subsection (c) and subsection (k) of Section 16-108 of the Public Utilities Act inclusive of eligible funds collected in prior years and alternative compliance payments for use by the utility.

(ix) Notwithstanding other requirements of this subparagraph (L), no modification shall be required to Adjustable Block program contracts if they were already executed prior to the establishment, approval, and implementation of new contract forms as a result of this amendatory Act of the 102nd General Assembly.

(x) Contracts may be assignable, but only to entities first deemed by the Agency to have met program terms and requirements applicable to direct program participation. In developing contracts for the delivery of renewable energy credits, the Agency shall be permitted to establish fees applicable to each contract assignment.

(M) The Agency shall be authorized to retain one or more experts or expert consulting firms to develop, administer, implement, operate, and evaluate the Adjustable Block program described in subparagraph (K) of this paragraph (1), and the Agency shall retain the consultant or consultants in the same manner, to the extent practicable, as the Agency retains others to administer provisions of this Act, including, but not limited to, the procurement administrator. The selection of experts and expert consulting firms and the procurement process described in this subparagraph (M) are exempt from the requirements of Section 20-10 of the Illinois Procurement Code, under Section 20-10 of that Code. The Agency shall strive to minimize administrative expenses in the implementation of the Adjustable Block program.

The Program Administrator may charge application fees to participating firms to cover the cost of program administration. Any application fee amounts shall initially be determined through the long-term renewable resources procurement plan, and modifications to any application fee that deviate more than 25% from the Commission's approved value must be approved by the Commission as a long-term plan revision under Section 16-111.5 of the Public Utilities Act. The Agency shall consider stakeholder feedback when making adjustments to application fees and shall notify stakeholders in advance of any planned changes.

In addition to covering the costs of program administration, the Agency, in conjunction with its Program Administrator, may also use the proceeds of such fees charged to participating firms to support public education and ongoing regional and national coordination with nonprofit organizations, public bodies, and others engaged in the implementation of renewable energy incentive programs or similar initiatives. This work may include developing papers and reports, hosting regional and national conferences, and other work deemed necessary by the Agency to position the State of Illinois as a national leader in renewable energy incentive program development and administration.

The Agency and its consultant or consultants shall monitor block activity, share program activity with stakeholders and conduct quarterly meetings to discuss program activity and market conditions. If necessary, the Agency may make prospective administrative adjustments to the Adjustable Block program design, such as making adjustments to purchase prices as necessary to achieve the goals of this subsection (c). Program modifications to any block price that do not deviate from the Commission's approved value by more than 10% shall take effect immediately and are not subject to Commission review and approval. Program modifications to any block price that deviate more than 10% from the Commission's approved value must be approved by the Commission as a long-term plan amendment under Section 16-111.5 of the Public Utilities Act. The Agency shall consider stakeholder feedback when making adjustments to the Adjustable Block design and shall notify stakeholders in advance of any planned changes.

The Agency and its program administrators for both the Adjustable Block program and the Illinois Solar for All Program, consistent with the requirements of this subsection (c) and subsection (b) of Section 1-56 of this Act, shall propose the Adjustable Block program terms, conditions, and requirements, including the prices to be paid for renewable energy credits, where applicable, and requirements applicable to participating entities and project applications, through the development, review, and approval of the Agency's long-term renewable resources procurement plan described in this subsection (c) and paragraph (5) of subsection (b) of Section 16-111.5 of the Public Utilities Act. Terms, conditions, and requirements for program participation shall include the following:

(i) The Agency shall establish a registration process for entities seeking to qualify for program-administered incentive funding and establish baseline qualifications for vendor approval. The Agency must maintain a list of approved entities on each program's website, and may revoke a vendor's ability to receive program-administered incentive funding status upon a determination that the vendor failed to comply with contract terms, the law, or other program requirements.

(ii) The Agency shall establish program requirements and minimum contract terms to ensure projects are properly installed and produce their expected amounts of energy. Program requirements may include on-site inspections and photo documentation of projects under construction. The Agency may require repairs, alterations, or additions to remedy any material deficiencies discovered. Vendors who have a disproportionately high number of deficient systems may lose their eligibility to continue to receive State-administered incentive funding through Agency programs and procurements.

(iii) To discourage deceptive marketing or other bad faith business practices, the Agency may require direct program participants, including agents operating on their behalf, to provide standardized disclosures to a customer prior to that customer's execution of a contract for the development of a distributed generation system or a subscription to a community solar project.

(iv) The Agency shall establish one or multiple Consumer Complaints Centers to accept complaints regarding businesses that participate in, or otherwise benefit from, State-administered incentive funding through Agency-administered programs. The Agency shall maintain a public database of complaints with any confidential or particularly sensitive information redacted from public entries.

(v) Through a filing in the proceeding for the approval of its long-term renewable energy resources procurement plan, the Agency shall provide an annual written report to the Illinois Commerce Commission documenting the frequency and nature of complaints and any enforcement actions taken in response to those complaints.

(vi) The Agency shall schedule regular meetings with representatives of the Office of the Attorney General, the Illinois Commerce Commission, consumer protection groups, and other interested stakeholders to share relevant information about consumer protection, project compliance, and complaints received.

(vii) To the extent that complaints received implicate the jurisdiction of the Office of the Attorney General, the Illinois Commerce Commission, or local, State, or federal law enforcement, the Agency shall also refer complaints to those entities as appropriate.

(N) The Agency shall establish the terms, conditions, and program requirements for photovoltaic community renewable generation projects with a goal to expand access to a broader group of energy consumers, to ensure robust participation opportunities for residential and small commercial customers and those who cannot install renewable energy on their own properties. Subject to reasonable limitations, any plan approved by the Commission shall allow subscriptions to community renewable generation projects to be portable and transferable. For purposes of this subparagraph (N), "portable" means that subscriptions may be retained by the subscriber even if the subscriber relocates or changes its address within the same utility service territory; and "transferable" means that a subscriber may assign or sell subscriptions to another person within the same utility service territory.

Through the development of its long-term renewable resources procurement plan, the Agency may consider whether community renewable generation projects utilizing technologies other than photovoltaics should be supported through State-administered incentive funding, and may issue requests for information to gauge market demand.

Electric utilities shall provide a monetary credit to a subscriber's subsequent bill for service for the proportional output of a community renewable generation project attributable to that subscriber as specified in Section 16-107.5 of the Public Utilities Act.

The Agency shall purchase renewable energy credits from subscribed shares of photovoltaic community renewable generation projects through the Adjustable Block program described in subparagraph (K) of this paragraph (1) or through the Illinois Solar for All Program described in Section 1-56 of this Act. The electric utility shall purchase any unsubscribed energy from community renewable generation projects that are Qualifying Facilities ("QF") under the electric utility's tariff for purchasing the output from QFs under Public Utilities Regulatory Policies Act of 1978.

The owners of and any subscribers to a community renewable generation project shall not be considered public utilities or alternative retail electricity suppliers under the Public Utilities Act solely as a result of their interest in or subscription to a community renewable generation project and shall not be required to become an alternative retail electric supplier by participating in a community renewable generation project with a public utility.

(O) For the delivery year beginning June 1, 2018, the long-term renewable resources procurement plan required by this subsection (c) shall provide for the Agency to procure contracts to continue offering the Illinois Solar for All Program described in subsection (b) of Section 1-56 of this Act, and the contracts approved by the Commission shall be executed by the utilities that are subject to this subsection (c). The long-term renewable resources procurement plan shall allocate up to $50,000,000 per delivery year to fund the programs, and the plan shall determine the amount of funding to be apportioned to the programs identified in subsection (b) of Section 1-56 of this Act; provided that for the delivery years beginning June 1, 2021, June 1, 2022, and June 1, 2023, the long-term renewable resources procurement plan may average the annual budgets over a 3-year period to account for program ramp-up. For the delivery years beginning June 1, 2021, June 1, 2024, June 1, 2027, and June 1, 2030 and additional $10,000,000 shall be provided to the Department of Commerce and Economic Opportunity to implement the workforce development programs and reporting as outlined in Section 16-108.12 of the Public Utilities Act. In making the determinations required under this subparagraph (O), the Commission shall consider the experience and performance under the programs and any evaluation reports. The Commission shall also provide for an independent evaluation of those programs on a periodic basis that are funded under this subparagraph (O).

(P) All programs and procurements under this subsection (c) shall be designed to encourage participating projects to use a diverse and equitable workforce and a diverse set of contractors, including minority-owned businesses, disadvantaged businesses, trade unions, graduates of any workforce training programs administered under this Act, and small businesses.

The Agency shall develop a method to optimize procurement of renewable energy credits from proposed utility-scale projects that are located in communities eligible to receive Energy Transition Community Grants pursuant to Section 10-20 of the Energy Community Reinvestment Act. If this requirement conflicts with other provisions of law or the Agency determines that full compliance with the requirements of this subparagraph (P) would be unreasonably costly or administratively impractical, the Agency is to propose alternative approaches to achieve development of renewable energy resources in communities eligible to receive Energy Transition Community Grants pursuant to Section 10-20 of the Energy Community Reinvestment Act or seek an exemption from this requirement from the Commission.

(Q) Each facility listed in subitems (i) through (ix) of item (1) of this subparagraph (Q) for which a renewable energy credit delivery contract is signed after the effective date of this amendatory Act of the 102nd General Assembly is subject to the following requirements through the Agency's long-term renewable resources procurement plan:

(1) Each facility shall be subject to the prevailing wage requirements included in the Prevailing Wage Act. The Agency shall require verification that all construction performed on the facility by the renewable energy credit delivery contract holder, its contractors, or its subcontractors relating to construction of the facility is performed by construction employees receiving an amount for that work equal to or greater than the general prevailing rate, as that term is defined in Section 3 of the Prevailing Wage Act. For purposes of this item (1), "house of worship" means property that is both (1) used exclusively by a religious society or body of persons as a place for religious exercise or religious worship and (2) recognized as exempt from taxation pursuant to Section 15-40 of the Property Tax Code. This item (1) shall apply to any the following:

(i) all new utility-scale wind projects;

(ii) all new utility-scale photovoltaic projects and repowered wind projects;

(iii) all new brownfield photovoltaic projects;

(iv) all new photovoltaic community renewable energy facilities that qualify for item (iii) of subparagraph (K) of this paragraph (1);

(v) all new community driven community photovoltaic projects that qualify for item (v) of subparagraph (K) of this paragraph (1);

(vi) all new photovoltaic projects on public school land that qualify for item (iv) of subparagraph (K) of this paragraph (1);

(vii) all new photovoltaic distributed renewable energy generation devices that (1) qualify for item (i) of subparagraph (K) of this paragraph (1); (2) are not projects that serve single-family or multi-family residential buildings; and (3) are not houses of worship where the aggregate capacity including collocated projects would not exceed 100 kilowatts;

(viii) all new photovoltaic distributed renewable energy generation devices that (1) qualify for item (ii) of subparagraph (K) of this paragraph (1); (2) are not projects that serve single-family or multi-family residential buildings; and (3) are not houses of worship where the aggregate capacity including collocated projects would not exceed 100 kilowatts;

(ix) all new, modernized, or retooled hydropower facilities.

(2) Renewable energy credits procured from new utility-scale wind projects, new utility-scale solar projects, new brownfield solar projects, repowered wind projects, and retooled hydropower facilities pursuant to Agency procurement events occurring after the effective date of this amendatory Act of the 102nd General Assembly must be from facilities built by general contractors that must enter into a project labor agreement, as defined by this Act, prior to construction. The project labor agreement shall be filed with the Director in accordance with procedures established by the Agency through its long-term renewable resources procurement plan. Any information submitted to the Agency in this item (2) shall be considered commercially sensitive information. At a minimum, the project labor agreement must provide the names, addresses, and occupations of the owner of the plant and the individuals representing the labor organization employees participating in the project labor agreement consistent with the Project Labor Agreements Act. The agreement must also specify the terms and conditions as defined by this Act.

(3) It is the intent of this Section to ensure that economic development occurs across Illinois communities, that emerging businesses may grow, and that there is improved access to the clean energy economy by persons who have greater economic burdens to success. The Agency shall take into consideration the unique cost of compliance of this subparagraph (Q) that might be borne by equity eligible contractors, shall include such costs when determining the price of renewable energy credits in the Adjustable Block program, and shall take such costs into consideration in a nondiscriminatory manner when comparing bids for competitive procurements. The Agency shall consider costs associated with compliance whether in the development, financing, or construction of projects. The Agency shall periodically review the assumptions in these costs and may adjust prices, in compliance with subparagraph (M) of this paragraph (1).

(R) In its long-term renewable resources procurement plan, the Agency shall establish a self-direct renewable portfolio standard compliance program for eligible self-direct customers that purchase renewable energy credits from utility-scale wind and solar projects through long-term agreements for purchase of renewable energy credits as described in this Section. Such long-term agreements may include the purchase of energy or other products on a physical or financial basis and may involve an alternative retail electric supplier as defined in Section 16-102 of the Public Utilities Act. This program shall take effect in the delivery year commencing June 1, 2023.

(1) For the purposes of this subparagraph:

"Eligible self-direct customer" means any retail customers of an electric utility that serves 3,000,000 or more retail customers in the State and whose total highest 30-minute demand was more than 10,000 kilowatts, or any retail customers of an electric utility that serves less than 3,000,000 retail customers but more than 500,000 retail customers in the State and whose total highest 15-minute demand was more than 10,000 kilowatts.

"Retail customer" has the meaning set forth in Section 16-102 of the Public Utilities Act and multiple retail customer accounts under the same corporate parent may aggregate their account demands to meet the 10,000 kilowatt threshold. The criteria for determining whether this subparagraph is applicable to a retail customer shall be based on the 12 consecutive billing periods prior to the start of the year in which the application is filed.

(2) For renewable energy credits to count toward the self-direct renewable portfolio standard compliance program, they must:

(i) qualify as renewable energy credits as defined in Section 1-10 of this Act;

(ii) be sourced from one or more renewable energy generating facilities that comply with the geographic requirements as set forth in subparagraph (I) of paragraph (1) of subsection (c) as interpreted through the Agency's long-term renewable resources procurement plan, or, where applicable, the geographic requirements that governed utility-scale renewable energy credits at the time the eligible self-direct customer entered into the applicable renewable energy credit purchase agreement;

(iii) be procured through long-term contracts with term lengths of at least 10 years either directly with the renewable energy generating facility or through a bundled power purchase agreement, a virtual power purchase agreement, an agreement between the renewable generating facility, an alternative retail electric supplier, and the customer, or such other structure as is permissible under this subparagraph (R);

(iv) be equivalent in volume to at least 40% of the eligible self-direct customer's usage, determined annually by the eligible self-direct customer's usage during the previous delivery year, measured to the nearest megawatt-hour;

(v) be retired by or on behalf of the large energy customer;

(vi) be sourced from new utility-scale wind projects or new utility-scale solar projects; and

(vii) if the contracts for renewable energy credits are entered into after the effective date of this amendatory Act of the 102nd General Assembly, the new utility-scale wind projects or new utility-scale solar projects must comply with the requirements established in subparagraphs (P) and (Q) of paragraph (1) of this subsection (c) and subsection (c-10).

(3) The self-direct renewable portfolio standard compliance program shall be designed to allow eligible self-direct customers to procure new renewable energy credits from new utility-scale wind projects or new utility-scale photovoltaic projects. The Agency shall annually determine the amount of utility-scale renewable energy credits it will include each year from the self-direct renewable portfolio standard compliance program, subject to receiving qualifying applications. In making this determination, the Agency shall evaluate publicly available analyses and studies of the potential market size for utility-scale renewable energy long-term purchase agreements by commercial and industrial energy customers and make that report publicly available. If demand for participation in the self-direct renewable portfolio standard compliance program exceeds availability, the Agency shall ensure participation is evenly split between commercial and industrial users to the extent there is sufficient demand from both customer classes. Each renewable energy credit procured pursuant to this subparagraph (R) by a self-direct customer shall reduce the total volume of renewable energy credits the Agency is otherwise required to procure from new utility-scale projects pursuant to subparagraph (C) of paragraph (1) of this subsection (c) on behalf of contracting utilities where the eligible self-direct customer is located. The self-direct customer shall file an annual compliance report with the Agency pursuant to terms established by the Agency through its long-term renewable resources procurement plan to be eligible for participation in this program. Customers must provide the Agency with their most recent electricity billing statements or other information deemed necessary by the Agency to demonstrate they are an eligible self-direct customer.

(4) The Commission shall approve a reduction in the volumetric charges collected pursuant to Section 16-108 of the Public Utilities Act for approved eligible self-direct customers equivalent to the anticipated cost of renewable energy credit deliveries under contracts for new utility-scale wind and new utility-scale solar entered for each delivery year after the large energy customer begins retiring eligible new utility scale renewable energy credits for self-compliance. The self-direct credit amount shall be determined annually and is equal to the estimated portion of the cost authorized by subparagraph (E) of paragraph (1) of this subsection (c) that supported the annual procurement of utility-scale renewable energy credits in the prior delivery year using a methodology described in the long-term renewable resources procurement plan, expressed on a per kilowatthour basis, and does not include (i) costs associated with any contracts entered into before the delivery year in which the customer files the initial compliance report to be eligible for participation in the self-direct program, and (ii) costs associated with procuring renewable energy credits through existing and future contracts through the Adjustable Block Program, subsection (c-5) of this Section 1-75, and the Solar for All Program. The Agency shall assist the Commission in determining the current and future costs. The Agency must determine the self-direct credit amount for new and existing eligible self-direct customers and submit this to the Commission in an annual compliance filing. The Commission must approve the self-direct credit amount by June 1, 2023 and June 1 of each delivery year thereafter.

(5) Customers described in this subparagraph (R) shall apply, on a form developed by the Agency, to the Agency to be designated as a self-direct eligible customer. Once the Agency determines that a self-direct customer is eligible for participation in the program, the self-direct customer will remain eligible until the end of the term of the contract. Thereafter, application may be made not less than 12 months before the filing date of the long-term renewable resources procurement plan described in this Act. At a minimum, such application shall contain the following:

(i) the customer's certification that, at the time of the customer's application, the customer qualifies to be a self-direct eligible customer, including documents demonstrating that qualification;

(ii) the customer's certification that the customer has entered into or will enter into by the beginning of the applicable procurement year, one or more bilateral contracts for new wind projects or new photovoltaic projects, including supporting documentation;

(iii) certification that the contract or contracts for new renewable energy resources are long-term contracts with term lengths of at least 10 years, including supporting documentation;

(iv) certification of the quantities of renewable energy credits that the customer will purchase each year under such contract or contracts, including supporting documentation;

(v) proof that the contract is sufficient to produce renewable energy credits to be equivalent in volume to at least 40% of the large energy customer's usage from the previous delivery year, measured to the nearest megawatt-hour; and

(vi) certification that the customer intends to maintain the contract for the duration of the length of the contract.

(6) If a customer receives the self-direct credit but fails to properly procure and retire renewable energy credits as required under this subparagraph (R), the Commission, on petition from the Agency and after notice and hearing, may direct such customer's utility to recover the cost of the wrongfully received self-direct credits plus interest through an adder to charges assessed pursuant to Section 16-108 of the Public Utilities Act. Self-direct customers who knowingly fail to properly procure and retire renewable energy credits and do not notify the Agency are ineligible for continued participation in the self-direct renewable portfolio standard compliance program.

(2) (Blank).

(3) (Blank).

(4) The electric utility shall retire all renewable energy credits used to comply with the standard.

(5) Beginning with the 2010 delivery year and ending June 1, 2017, an electric utility subject to this subsection (c) shall apply the lesser of the maximum alternative compliance payment rate or the most recent estimated alternative compliance payment rate for its service territory for the corresponding compliance period, established pursuant to subsection (d) of Section 16-115D of the Public Utilities Act to its retail customers that take service pursuant to the electric utility's hourly pricing tariff or tariffs. The electric utility shall retain all amounts collected as a result of the application of the alternative compliance payment rate or rates to such customers, and, beginning in 2011, the utility shall include in the information provided under item (1) of subsection (d) of Section 16-111.5 of the Public Utilities Act the amounts collected under the alternative compliance payment rate or rates for the prior year ending May 31. Notwithstanding any limitation on the procurement of renewable energy resources imposed by item (2) of this subsection (c), the Agency shall increase its spending on the purchase of renewable energy resources to be procured by the electric utility for the next plan year by an amount equal to the amounts collected by the utility under the alternative compliance payment rate or rates in the prior year ending May 31.

(6) The electric utility shall be entitled to recover all of its costs associated with the procurement of renewable energy credits under plans approved under this Section and Section 16-111.5 of the Public Utilities Act. These costs shall include associated reasonable expenses for implementing the procurement programs, including, but not limited to, the costs of administering and evaluating the Adjustable Block program, through an automatic adjustment clause tariff in accordance with subsection (k) of Section 16-108 of the Public Utilities Act.

(7) Renewable energy credits procured from new photovoltaic projects or new distributed renewable energy generation devices under this Section after June 1, 2017 (the effective date of Public Act 99-906) must be procured from devices installed by a qualified person in compliance with the requirements of Section 16-128A of the Public Utilities Act and any rules or regulations adopted thereunder.

In meeting the renewable energy requirements of this subsection (c), to the extent feasible and consistent with State and federal law, the renewable energy credit procurements, Adjustable Block solar program, and community renewable generation program shall provide employment opportunities for all segments of the population and workforce, including minority-owned and female-owned business enterprises, and shall not, consistent with State and federal law, discriminate based on race or socioeconomic status.

(c-5) Procurement of renewable energy credits from new renewable energy facilities installed at or adjacent to the sites of electric generating facilities that burn or burned coal as their primary fuel source.

(1) In addition to the procurement of renewable energy credits pursuant to long-term renewable resources procurement plans in accordance with subsection (c) of this Section and Section 16-111.5 of the Public Utilities Act, the Agency shall conduct procurement events in accordance with this subsection (c-5) for the procurement by electric utilities that served more than 300,000 retail customers in this State as of January 1, 2019 of renewable energy credits from new renewable energy facilities to be installed at or adjacent to the sites of electric generating facilities that, as of January 1, 2016, burned coal as their primary fuel source and meet the other criteria specified in this subsection (c-5). For purposes of this subsection (c-5), "new renewable energy facility" means a new utility-scale solar project as defined in this Section 1-75. The renewable energy credits procured pursuant to this subsection (c-5) may be included or counted for purposes of compliance with the amounts of renewable energy credits required to be procured pursuant to subsection (c) of this Section to the extent that there are otherwise shortfalls in compliance with such requirements. The procurement of renewable energy credits by electric utilities pursuant to this subsection (c-5) shall be funded solely by revenues collected from the Coal to Solar and Energy Storage Initiative Charge provided for in this subsection (c-5) and subsection (i-5) of Section 16-108 of the Public Utilities Act, shall not be funded by revenues collected through any of the other funding mechanisms provided for in subsection (c) of this Section, and shall not be subject to the limitation imposed by subsection (c) on charges to retail customers for costs to procure renewable energy resources pursuant to subsection (c), and shall not be subject to any other requirements or limitations of subsection (c).

(2) The Agency shall conduct 2 procurement events to select owners of electric generating facilities meeting the eligibility criteria specified in this subsection (c-5) to enter into long-term contracts to sell renewable energy credits to electric utilities serving more than 300,000 retail customers in this State as of January 1, 2019. The first procurement event shall be conducted no later than March 31, 2022, unless the Agency elects to delay it, until no later than May 1, 2022, due to its overall volume of work, and shall be to select owners of electric generating facilities located in this State and south of federal Interstate Highway 80 that meet the eligibility criteria specified in this subsection (c-5). The second procurement event shall be conducted no sooner than September 30, 2022 and no later than October 31, 2022 and shall be to select owners of electric generating facilities located anywhere in this State that meet the eligibility criteria specified in this subsection (c-5). The Agency shall establish and announce a time period, which shall begin no later than 30 days prior to the scheduled date for the procurement event, during which applicants may submit applications to be selected as suppliers of renewable energy credits pursuant to this subsection (c-5). The eligibility criteria for selection as a supplier of renewable energy credits pursuant to this subsection (c-5) shall be as follows:

(A) The applicant owns an electric generating facility located in this State that: (i) as of January 1, 2016, burned coal as its primary fuel to generate electricity; and (ii) has, or had prior to retirement, an electric generating capacity of at least 150 megawatts. The electric generating facility can be either: (i) retired as of the date of the procurement event; or (ii) still operating as of the date of the procurement event.

(B) The applicant is not (i) an electric cooperative as defined in Section 3-119 of the Public Utilities Act, or (ii) an entity described in subsection (b)(1) of Section 3-105 of the Public Utilities Act, or an association or consortium of or an entity owned by entities described in (i) or (ii); and the coal-fueled electric generating facility was at one time owned, in whole or in part, by a public utility as defined in Section 3-105 of the Public Utilities Act.

(C) If participating in the first procurement event, the applicant proposes and commits to construct and operate, at the site, and if necessary for sufficient space on property adjacent to the existing property, at which the electric generating facility identified in paragraph (A) is located: (i) a new renewable energy facility of at least 20 megawatts but no more than 100 megawatts of electric generating capacity, and (ii) an energy storage facility having a storage capacity equal to at least 2 megawatts and at most 10 megawatts. If participating in the second procurement event, the applicant proposes and commits to construct and operate, at the site, and if necessary for sufficient space on property adjacent to the existing property, at which the electric generating facility identified in paragraph (A) is located: (i) a new renewable energy facility of at least 5 megawatts but no more than 20 megawatts of electric generating capacity, and (ii) an energy storage facility having a storage capacity equal to at least 0.5 megawatts and at most one megawatt.

(D) The applicant agrees that the new renewable energy facility and the energy storage facility will be constructed or installed by a qualified entity or entities in compliance with the requirements of subsection (g) of Section 16-128A of the Public Utilities Act and any rules adopted thereunder.

(E) The applicant agrees that personnel operating the new renewable energy facility and the energy storage facility will have the requisite skills, knowledge, training, experience, and competence, which may be demonstrated by completion or current participation and ultimate completion by employees of an accredited or otherwise recognized apprenticeship program for the employee's particular craft, trade, or skill, including through training and education courses and opportunities offered by the owner to employees of the coal-fueled electric generating facility or by previous employment experience performing the employee's particular work skill or function.

(F) The applicant commits that not less than the prevailing wage, as determined pursuant to the Prevailing Wage Act, will be paid to the applicant's employees engaged in construction activities associated with the new renewable energy facility and the new energy storage facility and to the employees of applicant's contractors engaged in construction activities associated with the new renewable energy facility and the new energy storage facility, and that, on or before the commercial operation date of the new renewable energy facility, the applicant shall file a report with the Agency certifying that the requirements of this subparagraph (F) have been met.

(G) The applicant commits that if selected, it will negotiate a project labor agreement for the construction of the new renewable energy facility and associated energy storage facility that includes provisions requiring the parties to the agreement to work together to establish diversity threshold requirements and to ensure best efforts to meet diversity targets, improve diversity at the applicable job site, create diverse apprenticeship opportunities, and create opportunities to employ former coal-fired power plant workers.

(H) The applicant commits to enter into a contract or contracts for the applicable duration to provide specified numbers of renewable energy credits each year from the new renewable energy facility to electric utilities that served more than 300,000 retail customers in this State as of January 1, 2019, at a price of $30 per renewable energy credit. The price per renewable energy credit shall be fixed at $30 for the applicable duration and the renewable energy credits shall not be indexed renewable energy credits as provided for in item (v) of subparagraph (G) of paragraph (1) of subsection (c) of Section 1-75 of this Act. The applicable duration of each contract shall be 20 years, unless the applicant is physically interconnected to the PJM Interconnection, LLC transmission grid and had a generating capacity of at least 1,200 megawatts as of January 1, 2021, in which case the applicable duration of the contract shall be 15 years.

(I) The applicant's application is certified by an officer of the applicant and by an officer of the applicant's ultimate parent company, if any.

(3) An applicant may submit applications to contract to supply renewable energy credits from more than one new renewable energy facility to be constructed at or adjacent to one or more qualifying electric generating facilities owned by the applicant. The Agency may select new renewable energy facilities to be located at or adjacent to the sites of more than one qualifying electric generation facility owned by an applicant to contract with electric utilities to supply renewable energy credits from such facilities.

(4) The Agency shall assess fees to each applicant to recover the Agency's costs incurred in receiving and evaluating applications, conducting the procurement event, developing contracts for sale, delivery and purchase of renewable energy credits, and monitoring the administration of such contracts, as provided for in this subsection (c-5), including fees paid to a procurement administrator retained by the Agency for one or more of these purposes.

(5) The Agency shall select the applicants and the new renewable energy facilities to contract with electric utilities to supply renewable energy credits in accordance with this subsection (c-5). In the first procurement event, the Agency shall select applicants and new renewable energy facilities to supply renewable energy credits, at a price of $30 per renewable energy credit, aggregating to no less than 400,000 renewable energy credits per year for the applicable duration, assuming sufficient qualifying applications to supply, in the aggregate, at least that amount of renewable energy credits per year; and not more than 580,000 renewable energy credits per year for the applicable duration. In the second procurement event, the Agency shall select applicants and new renewable energy facilities to supply renewable energy credits, at a price of $30 per renewable energy credit, aggregating to no more than 625,000 renewable energy credits per year less the amount of renewable energy credits each year contracted for as a result of the first procurement event, for the applicable durations. The number of renewable energy credits to be procured as specified in this paragraph (5) shall not be reduced based on renewable energy credits procured in the self-direct renewable energy credit compliance program established pursuant to subparagraph (R) of paragraph (1) of subsection (c) of Section 1-75.

(6) The obligation to purchase renewable energy credits from the applicants and their new renewable energy facilities selected by the Agency shall be allocated to the electric utilities based on their respective percentages of kilowatthours delivered to delivery services customers to the aggregate kilowatthour deliveries by the electric utilities to delivery services customers for the year ended December 31, 2021. In order to achieve these allocation percentages between or among the electric utilities, the Agency shall require each applicant that is selected in the procurement event to enter into a contract with each electric utility for the sale and purchase of renewable energy credits from each new renewable energy facility to be constructed and operated by the applicant, with the sale and purchase obligations under the contracts to aggregate to the total number of renewable energy credits per year to be supplied by the applicant from the new renewable energy facility.

(7) The Agency shall submit its proposed selection of applicants, new renewable energy facilities to be constructed, and renewable energy credit amounts for each procurement event to the Commission for approval. The Commission shall, within 2 business days after receipt of the Agency's proposed selections, approve the proposed selections if it determines that the applicants and the new renewable energy facilities to be constructed meet the selection criteria set forth in this subsection (c-5) and that the Agency seeks approval for contracts of applicable durations aggregating to no more than the maximum amount of renewable energy credits per year authorized by this subsection (c-5) for the procurement event, at a price of $30 per renewable energy credit.

(8) The Agency, in conjunction with its procurement administrator if one is retained, the electric utilities, and potential applicants for contracts to produce and supply renewable energy credits pursuant to this subsection (c-5), shall develop a standard form contract for the sale, delivery and purchase of renewable energy credits pursuant to this subsection (c-5). Each contract resulting from the first procurement event shall allow for a commercial operation date for the new renewable energy facility of either June 1, 2023 or June 1, 2024, with such dates subject to adjustment as provided in this paragraph. Each contract resulting from the second procurement event shall provide for a commercial operation date on June 1 next occurring up to 48 months after execution of the contract. Each contract shall provide that the owner shall receive payments for renewable energy credits for the applicable durations beginning with the commercial operation date of the new renewable energy facility. The form contract shall provide for adjustments to the commercial operation and payment start dates as needed due to any delays in completing the procurement and contracting processes, in finalizing interconnection agreements and installing interconnection facilities, and in obtaining other necessary governmental permits and approvals. The form contract shall be, to the maximum extent possible, consistent with standard electric industry contracts for sale, delivery, and purchase of renewable energy credits while taking into account the specific requirements of this subsection (c-5). The form contract shall provide for over-delivery and under-delivery of renewable energy credits within reasonable ranges during each 12-month period and penalty, default, and enforcement provisions for failure of the selling party to deliver renewable energy credits as specified in the contract and to comply with the requirements of this subsection (c-5). The standard form contract shall specify that all renewable energy credits delivered to the electric utility pursuant to the contract shall be retired. The Agency shall make the proposed contracts available for a reasonable period for comment by potential applicants, and shall publish the final form contract at least 30 days before the date of the first procurement event.

(9) Coal to Solar and Energy Storage Initiative Charge.

(A) By no later than July 1, 2022, each electric utility that served more than 300,000 retail customers in this State as of January 1, 2019 shall file a tariff with the Commission for the billing and collection of a Coal to Solar and Energy Storage Initiative Charge in accordance with subsection (i-5) of Section 16-108 of the Public Utilities Act, with such tariff to be effective, following review and approval or modification by the Commission, beginning January 1, 2023. The tariff shall provide for the calculation and setting of the electric utility's Coal to Solar and Energy Storage Initiative Charge to collect revenues estimated to be sufficient, in the aggregate, (i) to enable the electric utility to pay for the renewable energy credits it has contracted to purchase in the delivery year beginning June 1, 2023 and each delivery year thereafter from new renewable energy facilities located at the sites of qualifying electric generating facilities, and (ii) to fund the grant payments to be made in each delivery year by the Department of Commerce and Economic Opportunity, or any successor department or agency, which shall be referred to in this subsection (c-5) as the Department, pursuant to paragraph (10) of this subsection (c-5). The electric utility's tariff shall provide for the billing and collection of the Coal to Solar and Energy Storage Initiative Charge on each kilowatthour of electricity delivered to its delivery services customers within its service territory and shall provide for an annual reconciliation of revenues collected with actual costs, in accordance with subsection (i-5) of Section 16-108 of the Public Utilities Act.

(B) Each electric utility shall remit on a monthly basis to the State Treasurer, for deposit in the Coal to Solar and Energy Storage Initiative Fund provided for in this subsection (c-5), the electric utility's collections of the Coal to Solar and Energy Storage Initiative Charge in the amount estimated to be needed by the Department for grant payments pursuant to grant contracts entered into by the Department pursuant to paragraph (10) of this subsection (c-5).

(10) Coal to Solar and Energy Storage Initiative Fund.

(A) The Coal to Solar and Energy Storage Initiative Fund is established as a special fund in the State treasury. The Coal to Solar and Energy Storage Initiative Fund is authorized to receive, by statutory deposit, that portion specified in item (B) of paragraph (9) of this subsection (c-5) of moneys collected by electric utilities through imposition of the Coal to Solar and Energy Storage Initiative Charge required by this subsection (c-5). The Coal to Solar and Energy Storage Initiative Fund shall be administered by the Department to provide grants to support the installation and operation of energy storage facilities at the sites of qualifying electric generating facilities meeting the criteria specified in this paragraph (10).

(B) The Coal to Solar and Energy Storage Initiative Fund shall not be subject to sweeps, administrative charges, or chargebacks, including, but not limited to, those authorized under Section 8h of the State Finance Act, that would in any way result in the transfer of those funds from the Coal to Solar and Energy Storage Initiative Fund to any other fund of this State or in having any such funds utilized for any purpose other than the express purposes set forth in this paragraph (10).

(C) The Department shall utilize up to $280,500,000 in the Coal to Solar and Energy Storage Initiative Fund for grants, assuming sufficient qualifying applicants, to support installation of energy storage facilities at the sites of up to 3 qualifying electric generating facilities located in the Midcontinent Independent System Operator, Inc., region in Illinois and the sites of up to 2 qualifying electric generating facilities located in the PJM Interconnection, LLC region in Illinois that meet the criteria set forth in this subparagraph (C). The criteria for receipt of a grant pursuant to this subparagraph (C) are as follows:

(1) the electric generating facility at the site has, or had prior to retirement, an electric generating capacity of at least 150 megawatts;

(2) the electric generating facility burns (or burned prior to retirement) coal as its primary source of fuel;

(3) if the electric generating facility is retired, it was retired subsequent to January 1, 2016;

(4) the owner of the electric generating facility has not been selected by the Agency pursuant to this subsection (c-5) of this Section to enter into a contract to sell renewable energy credits to one or more electric utilities from a new renewable energy facility located or to be located at or adjacent to the site at which the electric generating facility is located;

(5) the electric generating facility located at the site was at one time owned, in whole or in part, by a public utility as defined in Section 3-105 of the Public Utilities Act;

(6) the electric generating facility at the site is not owned by (i) an electric cooperative as defined in Section 3-119 of the Public Utilities Act, or (ii) an entity described in subsection (b)(1) of Section 3-105 of the Public Utilities Act, or an association or consortium of or an entity owned by entities described in items (i) or (ii);

(7) the proposed energy storage facility at the site will have energy storage capacity of at least 37 megawatts;

(8) the owner commits to place the energy storage facility into commercial operation on either June 1, 2023, June 1, 2024, or June 1, 2025, with such date subject to adjustment as needed due to any delays in completing the grant contracting process, in finalizing interconnection agreements and in installing interconnection facilities, and in obtaining necessary governmental permits and approvals;

(9) the owner agrees that the new energy storage facility will be constructed or installed by a qualified entity or entities consistent with the requirements of subsection (g) of Section 16-128A of the Public Utilities Act and any rules adopted under that Section;

(10) the owner agrees that personnel operating the energy storage facility will have the requisite skills, knowledge, training, experience, and competence, which may be demonstrated by completion or current participation and ultimate completion by employees of an accredited or otherwise recognized apprenticeship program for the employee's particular craft, trade, or skill, including through training and education courses and opportunities offered by the owner to employees of the coal-fueled electric generating facility or by previous employment experience performing the employee's particular work skill or function;

(11) the owner commits that not less than the prevailing wage, as determined pursuant to the Prevailing Wage Act, will be paid to the owner's employees engaged in construction activities associated with the new energy storage facility and to the employees of the owner's contractors engaged in construction activities associated with the new energy storage facility, and that, on or before the commercial operation date of the new energy storage facility, the owner shall file a report with the Department certifying that the requirements of this subparagraph (11) have been met; and

(12) the owner commits that if selected to receive a grant, it will negotiate a project labor agreement for the construction of the new energy storage facility that includes provisions requiring the parties to the agreement to work together to establish diversity threshold requirements and to ensure best efforts to meet diversity targets, improve diversity at the applicable job site, create diverse apprenticeship opportunities, and create opportunities to employ former coal-fired power plant workers.

The Department shall accept applications for this grant program until March 31, 2022 and shall announce the award of grants no later than June 1, 2022. The Department shall make the grant payments to a recipient in equal annual amounts for 10 years following the date the energy storage facility is placed into commercial operation. The annual grant payments to a qualifying energy storage facility shall be $110,000 per megawatt of energy storage capacity, with total annual grant payments pursuant to this subparagraph (C) for qualifying energy storage facilities not to exceed $28,050,000 in any year.

(D) Grants of funding for energy storage facilities pursuant to subparagraph (C) of this paragraph (10), from the Coal to Solar and Energy Storage Initiative Fund, shall be memorialized in grant contracts between the Department and the recipient. The grant contracts shall specify the date or dates in each year on which the annual grant payments shall be paid.

(E) All disbursements from the Coal to Solar and Energy Storage Initiative Fund shall be made only upon warrants of the Comptroller drawn upon the Treasurer as custodian of the Fund upon vouchers signed by the Director of the Department or by the person or persons designated by the Director of the Department for that purpose. The Comptroller is authorized to draw the warrants upon vouchers so signed. The Treasurer shall accept all written warrants so signed and shall be released from liability for all payments made on those warrants.

(11) Diversity, equity, and inclusion plans.

(A) Each applicant selected in a procurement event to contract to supply renewable energy credits in accordance with this subsection (c-5) and each owner selected by the Department to receive a grant or grants to support the construction and operation of a new energy storage facility or facilities in accordance with this subsection (c-5) shall, within 60 days following the Commission's approval of the applicant to contract to supply renewable energy credits or within 60 days following execution of a grant contract with the Department, as applicable, submit to the Commission a diversity, equity, and inclusion plan setting forth the applicant's or owner's numeric goals for the diversity composition of its supplier entities for the new renewable energy facility or new energy storage facility, as applicable, which shall be referred to for purposes of this paragraph (11) as the project, and the applicant's or owner's action plan and schedule for achieving those goals.

(B) For purposes of this paragraph (11), diversity composition shall be based on the percentage, which shall be a minimum of 25%, of eligible expenditures for contract awards for materials and services (which shall be defined in the plan) to business enterprises owned by minority persons, women, or persons with disabilities as defined in Section 2 of the Business Enterprise for Minorities, Women, and Persons with Disabilities Act, to LGBTQ business enterprises, to veteran-owned business enterprises, and to business enterprises located in environmental justice communities. The diversity composition goals of the plan may include eligible expenditures in areas for vendor or supplier opportunities in addition to development and construction of the project, and may exclude from eligible expenditures materials and services with limited market availability, limited production and availability from suppliers in the United States, such as solar panels and storage batteries, and material and services that are subject to critical energy infrastructure or cybersecurity requirements or restrictions. The plan may provide that the diversity composition goals may be met through Tier 1 Direct or Tier 2 subcontracting expenditures or a combination thereof for the project.

(C) The plan shall provide for, but not be limited to: (i) internal initiatives, including multi-tier initiatives, by the applicant or owner, or by its engineering, procurement and construction contractor if one is used for the project, which for purposes of this paragraph (11) shall be referred to as the EPC contractor, to enable diverse businesses to be considered fairly for selection to provide materials and services; (ii) requirements for the applicant or owner or its EPC contractor to proactively solicit and utilize diverse businesses to provide materials and services; and (iii) requirements for the applicant or owner or its EPC contractor to hire a diverse workforce for the project. The plan shall include a description of the applicant's or owner's diversity recruiting efforts both for the project and for other areas of the applicant's or owner's business operations. The plan shall provide for the imposition of financial penalties on the applicant's or owner's EPC contractor for failure to exercise best efforts to comply with and execute the EPC contractor's diversity obligations under the plan. The plan may provide for the applicant or owner to set aside a portion of the work on the project to serve as an incubation program for qualified businesses, as specified in the plan, owned by minority persons, women, persons with disabilities, LGBTQ persons, and veterans, and businesses located in environmental justice communities, seeking to enter the renewable energy industry.

(D) The applicant or owner may submit a revised or updated plan to the Commission from time to time as circumstances warrant. The applicant or owner shall file annual reports with the Commission detailing the applicant's or owner's progress in implementing its plan and achieving its goals and any modifications the applicant or owner has made to its plan to better achieve its diversity, equity and inclusion goals. The applicant or owner shall file a final report on the fifth June 1 following the commercial operation date of the new renewable energy resource or new energy storage facility, but the applicant or owner shall thereafter continue to be subject to applicable reporting requirements of Section 5-117 of the Public Utilities Act.

(c-10) Equity accountability system. It is the purpose of this subsection (c-10) to create an equity accountability system, which includes the minimum equity standards for all renewable energy procurements, the equity category of the Adjustable Block Program, and the equity prioritization for noncompetitive procurements, that is successful in advancing priority access to the clean energy economy for businesses and workers from communities that have been excluded from economic opportunities in the energy sector, have been subject to disproportionate levels of pollution, and have disproportionately experienced negative public health outcomes. Further, it is the purpose of this subsection to ensure that this equity accountability system is successful in advancing equity across Illinois by providing access to the clean energy economy for businesses and workers from communities that have been historically excluded from economic opportunities in the energy sector, have been subject to disproportionate levels of pollution, and have disproportionately experienced negative public health outcomes.

(1) Minimum equity standards. The Agency shall create programs with the purpose of increasing access to and development of equity eligible contractors, who are prime contractors and subcontractors, across all of the programs it manages. All applications for renewable energy credit procurements shall comply with specific minimum equity commitments. Starting in the delivery year immediately following the next long-term renewable resources procurement plan, at least 10% of the project workforce for each entity participating in a procurement program outlined in this subsection (c-10) must be done by equity eligible persons or equity eligible contractors. The Agency shall increase the minimum percentage each delivery year thereafter by increments that ensure a statewide average of 30% of the project workforce for each entity participating in a procurement program is done by equity eligible persons or equity eligible contractors by 2030. The Agency shall propose a schedule of percentage increases to the minimum equity standards in its draft revised renewable energy resources procurement plan submitted to the Commission for approval pursuant to paragraph (5) of subsection (b) of Section 16-111.5 of the Public Utilities Act. In determining these annual increases, the Agency shall have the discretion to establish different minimum equity standards for different types of procurements and different regions of the State if the Agency finds that doing so will further the purposes of this subsection (c-10). The proposed schedule of annual increases shall be revisited and updated on an annual basis. Revisions shall be developed with stakeholder input, including from equity eligible persons, equity eligible contractors, clean energy industry representatives, and community-based organizations that work with such persons and contractors.

(A) At the start of each delivery year, the Agency shall require a compliance plan from each entity participating in a procurement program of subsection (c) of this Section that demonstrates how they will achieve compliance with the minimum equity standard percentage for work completed in that delivery year. If an entity applies for its approved vendor or designee status between delivery years, the Agency shall require a compliance plan at the time of application.

(B) Halfway through each delivery year, the Agency shall require each entity participating in a procurement program to confirm that it will achieve compliance in that delivery year, when applicable. The Agency may offer corrective action plans to entities that are not on track to achieve compliance.

(C) At the end of each delivery year, each entity participating and completing work in that delivery year in a procurement program of subsection (c) shall submit a report to the Agency that demonstrates how it achieved compliance with the minimum equity standards percentage for that delivery year.

(D) The Agency shall prohibit participation in procurement programs by an approved vendor or designee, as applicable, or entities with which an approved vendor or designee, as applicable, shares a common parent company if an approved vendor or designee, as applicable, failed to meet the minimum equity standards for the prior delivery year. Waivers approved for lack of equity eligible persons or equity eligible contractors in a geographic area of a project shall not count against the approved vendor or designee. The Agency shall offer a corrective action plan for any such entities to assist them in obtaining compliance and shall allow continued access to procurement programs upon an approved vendor or designee demonstrating compliance.

(E) The Agency shall pursue efficiencies achieved by combining with other approved vendor or designee reporting.

(2) Equity accountability system within the Adjustable Block program. The equity category described in item (vi) of subparagraph (K) of subsection (c) is only available to applicants that are equity eligible contractors.

(3) Equity accountability system within competitive procurements. Through its long-term renewable resources procurement plan, the Agency shall develop requirements for ensuring that competitive procurement processes, including utility-scale solar, utility-scale wind, and brownfield site photovoltaic projects, advance the equity goals of this subsection (c-10). Subject to Commission approval, the Agency shall develop bid application requirements and a bid evaluation methodology for ensuring that utilization of equity eligible contractors, whether as bidders or as participants on project development, is optimized, including requiring that winning or successful applicants for utility-scale projects are or will partner with equity eligible contractors and giving preference to bids through which a higher portion of contract value flows to equity eligible contractors. To the extent practicable, entities participating in competitive procurements shall also be required to meet all the equity accountability requirements for approved vendors and their designees under this subsection (c-10). In developing these requirements, the Agency shall also consider whether equity goals can be further advanced through additional measures.

(4) In the first revision to the long-term renewable energy resources procurement plan and each revision thereafter, the Agency shall include the following:

(A) The current status and number of equity eligible contractors listed in the Energy Workforce Equity Database designed in subsection (c-25), including the number of equity eligible contractors with current certifications as issued by the Agency.

(B) A mechanism for measuring, tracking, and reporting project workforce at the approved vendor or designee level, as applicable, which shall include a measurement methodology and records to be made available for audit by the Agency or the Program Administrator.

(C) A program for approved vendors, designees, eligible persons, and equity eligible contractors to receive trainings, guidance, and other support from the Agency or its designee regarding the equity category outlined in item (vi) of subparagraph (K) of paragraph (1) of subsection (c) and in meeting the minimum equity standards of this subsection (c-10).

(D) A process for certifying equity eligible contractors and equity eligible persons. The certification process shall coordinate with the Energy Workforce Equity Database set forth in subsection (c-25).

(E) An application for waiver of the minimum equity standards of this subsection, which the Agency shall have the discretion to grant in rare circumstances. The Agency may grant such a waiver where the applicant provides evidence of significant efforts toward meeting the minimum equity commitment, including: use of the Energy Workforce Equity Database; efforts to hire or contract with entities that hire eligible persons; and efforts to establish contracting relationships with eligible contractors. The Agency shall support applicants in understanding the Energy Workforce Equity Database and other resources for pursuing compliance of the minimum equity standards. Waivers shall be project-specific, unless the Agency deems it necessary to grant a waiver across a portfolio of projects, and in effect for no longer than one year. Any waiver extension or subsequent waiver request from an applicant shall be subject to the requirements of this Section and shall specify efforts made to reach compliance. When considering whether to grant a waiver, and to what extent, the Agency shall consider the degree to which similarly situated applicants have been able to meet these minimum equity commitments. For repeated waiver requests for specific lack of eligible persons or eligible contractors available, the Agency shall make recommendations to target recruitment to add such eligible persons or eligible contractors to the database.

(5) The Agency shall collect information about work on projects or portfolios of projects subject to these minimum equity standards to ensure compliance with this subsection (c-10). Reporting in furtherance of this requirement may be combined with other annual reporting requirements. Such reporting shall include proof of certification of each equity eligible contractor or equity eligible person during the applicable time period.

(6) The Agency shall keep confidential all information and communication that provides private or personal information.

(7) Modifications to the equity accountability system. As part of the update of the long-term renewable resources procurement plan to be initiated in 2023, or sooner if the Agency deems necessary, the Agency shall determine the extent to which the equity accountability system described in this subsection (c-10) has advanced the goals of this amendatory Act of the 102nd General Assembly, including through the inclusion of equity eligible persons and equity eligible contractors in renewable energy credit projects. If the Agency finds that the equity accountability system has failed to meet those goals to its fullest potential, the Agency may revise the following criteria for future Agency procurements: (A) the percentage of project workforce, or other appropriate workforce measure, certified as equity eligible persons or equity eligible contractors; (B) definitions for equity investment eligible persons and equity investment eligible community; and (C) such other modifications necessary to advance the goals of this amendatory Act of the 102nd General Assembly effectively. Such revised criteria may also establish distinct equity accountability systems for different types of procurements or different regions of the State if the Agency finds that doing so will further the purposes of such programs. Revisions shall be developed with stakeholder input, including from equity eligible persons, equity eligible contractors, and community-based organizations that work with such persons and contractors.

(c-15) Racial discrimination elimination powers and process.

(1) Purpose. It is the purpose of this subsection to empower the Agency and other State actors to remedy racial discrimination in Illinois' clean energy economy as effectively and expediently as possible, including through the use of race-conscious remedies, such as race-conscious contracting and hiring goals, as consistent with State and federal law.

(2) Racial disparity and discrimination review process.

(A) Within one year after awarding contracts using the equity actions processes established in this Section, the Agency shall publish a report evaluating the effectiveness of the equity actions point criteria of this Section in increasing participation of equity eligible persons and equity eligible contractors. The report shall disaggregate participating workers and contractors by race and ethnicity. The report shall be forwarded to the Governor, the General Assembly, and the Illinois Commerce Commission and be made available to the public.

(B) As soon as is practicable thereafter, the Agency, in consultation with the Department of Commerce and Economic Opportunity, Department of Labor, and other agencies that may be relevant, shall commission and publish a disparity and availability study that measures the presence and impact of discrimination on minority businesses and workers in Illinois' clean energy economy. The Agency may hire consultants and experts to conduct the disparity and availability study, with the retention of those consultants and experts exempt from the requirements of Section 20-10 of the Illinois Procurement Code. The Illinois Power Agency shall forward a copy of its findings and recommendations to the Governor, the General Assembly, and the Illinois Commerce Commission. If the disparity and availability study establishes a strong basis in evidence that there is discrimination in Illinois' clean energy economy, the Agency, Department of Commerce and Economic Opportunity, Department of Labor, Department of Corrections, and other appropriate agencies shall take appropriate remedial actions, including race-conscious remedial actions as consistent with State and federal law, to effectively remedy this discrimination. Such remedies may include modification of the equity accountability system as described in subsection (c-10).

(c-20) Program data collection.

(1) Purpose. Data collection, data analysis, and reporting are critical to ensure that the benefits of the clean energy economy provided to Illinois residents and businesses are equitably distributed across the State. The Agency shall collect data from program applicants in order to track and improve equitable distribution of benefits across Illinois communities for all procurements the Agency conducts. The Agency shall use this data to, among other things, measure any potential impact of racial discrimination on the distribution of benefits and provide information necessary to correct any discrimination through methods consistent with State and federal law.

(2) Agency collection of program data. The Agency shall collect demographic and geographic data for each entity awarded contracts under any Agency-administered program.

(3) Required information to be collected. The Agency shall collect the following information from applicants and program participants where applicable:

(A) demographic information, including racial or ethnic identity for real persons employed, contracted, or subcontracted through the program and owners of businesses or entities that apply to receive renewable energy credits from the Agency;

(B) geographic location of the residency of real persons employed, contracted, or subcontracted through the program and geographic location of the headquarters of the business or entity that applies to receive renewable energy credits from the Agency; and

(C) any other information the Agency determines is necessary for the purpose of achieving the purpose of this subsection.

(4) Publication of collected information. The Agency shall publish, at least annually, information on the demographics of program participants on an aggregate basis.

(5) Nothing in this subsection shall be interpreted to limit the authority of the Agency, or other agency or department of the State, to require or collect demographic information from applicants of other State programs.

(c-25) Energy Workforce Equity Database.

(1) The Agency, in consultation with the Department of Commerce and Economic Opportunity, shall create an Energy Workforce Equity Database, and may contract with a third party to do so ("database program administrator"). If the Department decides to contract with a third party, that third party shall be exempt from the requirements of Section 20-10 of the Illinois Procurement Code. The Energy Workforce Equity Database shall be a searchable database of suppliers, vendors, and subcontractors for clean energy industries that is:

(A) publicly accessible;

(B) easy for people to find and use;

(C) organized by company specialty or field;

(D) region-specific; and

(E) populated with information including, but not limited to, contacts for suppliers, vendors, or subcontractors who are minority and women-owned business enterprise certified or who participate or have participated in any of the programs described in this Act.

(2) The Agency shall create an easily accessible, public facing online tool using the database information that includes, at a minimum, the following:

(A) a map of environmental justice and equity investment eligible communities;

(B) job postings and recruiting opportunities;

(C) a means by which recruiting clean energy companies can find and interact with current or former participants of clean energy workforce training programs;

(D) information on workforce training service providers and training opportunities available to prospective workers;

(E) renewable energy company diversity reporting;

(F) a list of equity eligible contractors with their contact information, types of work performed, and locations worked in;

(G) reporting on outcomes of the programs described in the workforce programs of the Energy Transition Act, including information such as, but not limited to, retention rate, graduation rate, and placement rates of trainees; and

(H) information about the Jobs and Environmental Justice Grant Program, the Clean Energy Jobs and Justice Fund, and other sources of capital.

(3) The Agency shall ensure the database is regularly updated to ensure information is current and shall coordinate with the Department of Commerce and Economic Opportunity to ensure that it includes information on individuals and entities that are or have participated in the Clean Jobs Workforce Network Program, Clean Energy Contractor Incubator Program, Returning Residents Clean Jobs Training Program, or Clean Energy Primes Contractor Accelerator Program.

(c-30) Enforcement of minimum equity standards. All entities seeking renewable energy credits must submit an annual report to demonstrate compliance with each of the equity commitments required under subsection (c-10). If the Agency concludes the entity has not met or maintained its minimum equity standards required under the applicable subparagraphs under subsection (c-10), the Agency shall deny the entity's ability to participate in procurement programs in subsection (c), including by withholding approved vendor or designee status. The Agency may require the entity to enter into a corrective action plan. An entity that is not recertified for failing to meet required equity actions in subparagraph (c-10) may reapply once they have a corrective action plan and achieve compliance with the minimum equity standards.

(d) Clean coal portfolio standard.

(1) The procurement plans shall include electricity generated using clean coal. Each utility shall enter into one or more sourcing agreements with the initial clean coal facility, as provided in paragraph (3) of this subsection (d), covering electricity generated by the initial clean coal facility representing at least 5% of each utility's total supply to serve the load of eligible retail customers in 2015 and each year thereafter, as described in paragraph (3) of this subsection (d), subject to the limits specified in paragraph (2) of this subsection (d). It is the goal of the State that by January 1, 2025, 25% of the electricity used in the State shall be generated by cost-effective clean coal facilities. For purposes of this subsection (d), "cost-effective" means that the expenditures pursuant to such sourcing agreements do not cause the limit stated in paragraph (2) of this subsection (d) to be exceeded and do not exceed cost-based benchmarks, which shall be developed to assess all expenditures pursuant to such sourcing agreements covering electricity generated by clean coal facilities, other than the initial clean coal facility, by the procurement administrator, in consultation with the Commission staff, Agency staff, and the procurement monitor and shall be subject to Commission review and approval.

A utility party to a sourcing agreement shall immediately retire any emission credits that it receives in connection with the electricity covered by such agreement.

Utilities shall maintain adequate records documenting the purchases under the sourcing agreement to comply with this subsection (d) and shall file an accounting with the load forecast that must be filed with the Agency by July 15 of each year, in accordance with subsection (d) of Section 16-111.5 of the Public Utilities Act.

A utility shall be deemed to have complied with the clean coal portfolio standard specified in this subsection (d) if the utility enters into a sourcing agreement as required by this subsection (d).

(2) For purposes of this subsection (d), the required execution of sourcing agreements with the initial clean coal facility for a particular year shall be measured as a percentage of the actual amount of electricity (megawatt-hours) supplied by the electric utility to eligible retail customers in the planning year ending immediately prior to the agreement's execution. For purposes of this subsection (d), the amount paid per kilowatthour means the total amount paid for electric service expressed on a per kilowatthour basis. For purposes of this subsection (d), the total amount paid for electric service includes without limitation amounts paid for supply, transmission, distribution, surcharges and add-on taxes.

Notwithstanding the requirements of this subsection (d), the total amount paid under sourcing agreements with clean coal facilities pursuant to the procurement plan for any given year shall be reduced by an amount necessary to limit the annual estimated average net increase due to the costs of these resources included in the amounts paid by eligible retail customers in connection with electric service to:

(A) in 2010, no more than 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009;

(B) in 2011, the greater of an additional 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2010 or 1% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009;

(C) in 2012, the greater of an additional 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2011 or 1.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009;

(D) in 2013, the greater of an additional 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2012 or 2% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009; and

(E) thereafter, the total amount paid under sourcing agreements with clean coal facilities pursuant to the procurement plan for any single year shall be reduced by an amount necessary to limit the estimated average net increase due to the cost of these resources included in the amounts paid by eligible retail customers in connection with electric service to no more than the greater of (i) 2.015% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009 or (ii) the incremental amount per kilowatthour paid for these resources in 2013. These requirements may be altered only as provided by statute.

No later than June 30, 2015, the Commission shall review the limitation on the total amount paid under sourcing agreements, if any, with clean coal facilities pursuant to this subsection (d) and report to the General Assembly its findings as to whether that limitation unduly constrains the amount of electricity generated by cost-effective clean coal facilities that is covered by sourcing agreements.

(3) Initial clean coal facility. In order to promote development of clean coal facilities in Illinois, each electric utility subject to this Section shall execute a sourcing agreement to source electricity from a proposed clean coal facility in Illinois (the "initial clean coal facility") that will have a nameplate capacity of at least 500 MW when commercial operation commences, that has a final Clean Air Act permit on June 1, 2009 (the effective date of Public Act 95-1027), and that will meet the definition of clean coal facility in Section 1-10 of this Act when commercial operation commences. The sourcing agreements with this initial clean coal facility shall be subject to both approval of the initial clean coal facility by the General Assembly and satisfaction of the requirements of paragraph (4) of this subsection (d) and shall be executed within 90 days after any such approval by the General Assembly. The Agency and the Commission shall have authority to inspect all books and records associated with the initial clean coal facility during the term of such a sourcing agreement. A utility's sourcing agreement for electricity produced by the initial clean coal facility shall include:

(A) a formula contractual price (the "contract price") approved pursuant to paragraph (4) of this subsection (d), which shall:

(i) be determined using a cost of service methodology employing either a level or deferred capital recovery component, based on a capital structure consisting of 45% equity and 55% debt, and a return on equity as may be approved by the Federal Energy Regulatory Commission, which in any case may not exceed the lower of 11.5% or the rate of return approved by the General Assembly pursuant to paragraph (4) of this subsection (d); and

(ii) provide that all miscellaneous net revenue, including but not limited to net revenue from the sale of emission allowances, if any, substitute natural gas, if any, grants or other support provided by the State of Illinois or the United States Government, firm transmission rights, if any, by-products produced by the facility, energy or capacity derived from the facility and not covered by a sourcing agreement pursuant to paragraph (3) of this subsection (d) or item (5) of subsection (d) of Section 16-115 of the Public Utilities Act, whether generated from the synthesis gas derived from coal, from SNG, or from natural gas, shall be credited against the revenue requirement for this initial clean coal facility;

(B) power purchase provisions, which shall:

(i) provide that the utility party to such sourcing agreement shall pay the contract price for electricity delivered under such sourcing agreement;

(ii) require delivery of electricity to the regional transmission organization market of the utility that is party to such sourcing agreement;

(iii) require the utility party to such sourcing agreement to buy from the initial clean coal facility in each hour an amount of energy equal to all clean coal energy made available from the initial clean coal facility during such hour times a fraction, the numerator of which is such utility's retail market sales of electricity (expressed in kilowatthours sold) in the State during the prior calendar month and the denominator of which is the total retail market sales of electricity (expressed in kilowatthours sold) in the State by utilities during such prior month and the sales of electricity (expressed in kilowatthours sold) in the State by alternative retail electric suppliers during such prior month that are subject to the requirements of this subsection (d) and paragraph (5) of subsection (d) of Section 16-115 of the Public Utilities Act, provided that the amount purchased by the utility in any year will be limited by paragraph (2) of this subsection (d); and

(iv) be considered pre-existing contracts in such utility's procurement plans for eligible retail customers;

(C) contract for differences provisions, which shall:

(i) require the utility party to such sourcing agreement to contract with the initial clean coal facility in each hour with respect to an amount of energy equal to all clean coal energy made available from the initial clean coal facility during such hour times a fraction, the numerator of which is such utility's retail market sales of electricity (expressed in kilowatthours sold) in the utility's service territory in the State during the prior calendar month and the denominator of which is the total retail market sales of electricity (expressed in kilowatthours sold) in the State by utilities during such prior month and the sales of electricity (expressed in kilowatthours sold) in the State by alternative retail electric suppliers during such prior month that are subject to the requirements of this subsection (d) and paragraph (5) of subsection (d) of Section 16-115 of the Public Utilities Act, provided that the amount paid by the utility in any year will be limited by paragraph (2) of this subsection (d);

(ii) provide that the utility's payment obligation in respect of the quantity of electricity determined pursuant to the preceding clause (i) shall be limited to an amount equal to (1) the difference between the contract price determined pursuant to subparagraph (A) of paragraph (3) of this subsection (d) and the day-ahead price for electricity delivered to the regional transmission organization market of the utility that is party to such sourcing agreement (or any successor delivery point at which such utility's supply obligations are financially settled on an hourly basis) (the "reference price") on the day preceding the day on which the electricity is delivered to the initial clean coal facility busbar, multiplied by (2) the quantity of electricity determined pursuant to the preceding clause (i); and

(iii) not require the utility to take physical delivery of the electricity produced by the facility;

(D) general provisions, which shall:

(i) specify a term of no more than 30 years, commencing on the commercial operation date of the facility;

(ii) provide that utilities shall maintain adequate records documenting purchases under the sourcing agreements entered into to comply with this subsection (d) and shall file an accounting with the load forecast that must be filed with the Agency by July 15 of each year, in accordance with subsection (d) of Section 16-111.5 of the Public Utilities Act;

(iii) provide that all costs associated with the initial clean coal facility will be periodically reported to the Federal Energy Regulatory Commission and to purchasers in accordance with applicable laws governing cost-based wholesale power contracts;

(iv) permit the Illinois Power Agency to assume ownership of the initial clean coal facility, without monetary consideration and otherwise on reasonable terms acceptable to the Agency, if the Agency so requests no less than 3 years prior to the end of the stated contract term;

(v) require the owner of the initial clean coal facility to provide documentation to the Commission each year, starting in the facility's first year of commercial operation, accurately reporting the quantity of carbon emissions from the facility that have been captured and sequestered and report any quantities of carbon released from the site or sites at which carbon emissions were sequestered in prior years, based on continuous monitoring of such sites. If, in any year after the first year of commercial operation, the owner of the facility fails to demonstrate that the initial clean coal facility captured and sequestered at least 50% of the total carbon emissions that the facility would otherwise emit or that sequestration of emissions from prior years has failed, resulting in the release of carbon dioxide into the atmosphere, the owner of the facility must offset excess emissions. Any such carbon offsets must be permanent, additional, verifiable, real, located within the State of Illinois, and legally and practicably enforceable. The cost of such offsets for the facility that are not recoverable shall not exceed $15 million in any given year. No costs of any such purchases of carbon offsets may be recovered from a utility or its customers. All carbon offsets purchased for this purpose and any carbon emission credits associated with sequestration of carbon from the facility must be permanently retired. The initial clean coal facility shall not forfeit its designation as a clean coal facility if the facility fails to fully comply with the applicable carbon sequestration requirements in any given year, provided the requisite offsets are purchased. However, the Attorney General, on behalf of the People of the State of Illinois, may specifically enforce the facility's sequestration requirement and the other terms of this contract provision. Compliance with the sequestration requirements and offset purchase requirements specified in paragraph (3) of this subsection (d) shall be reviewed annually by an independent expert retained by the owner of the initial clean coal facility, with the advance written approval of the Attorney General. The Commission may, in the course of the review specified in item (vii), reduce the allowable return on equity for the facility if the facility willfully fails to comply with the carbon capture and sequestration requirements set forth in this item (v);

(vi) include limits on, and accordingly provide for modification of, the amount the utility is required to source under the sourcing agreement consistent with paragraph (2) of this subsection (d);

(vii) require Commission review: (1) to determine the justness, reasonableness, and prudence of the inputs to the formula referenced in subparagraphs (A)(i) through (A)(iii) of paragraph (3) of this subsection (d), prior to an adjustment in those inputs including, without limitation, the capital structure and return on equity, fuel costs, and other operations and maintenance costs and (2) to approve the costs to be passed through to customers under the sourcing agreement by which the utility satisfies its statutory obligations. Commission review shall occur no less than every 3 years, regardless of whether any adjustments have been proposed, and shall be completed within 9 months;

(viii) limit the utility's obligation to such amount as the utility is allowed to recover through tariffs filed with the Commission, provided that neither the clean coal facility nor the utility waives any right to assert federal pre-emption or any other argument in response to a purported disallowance of recovery costs;

(ix) limit the utility's or alternative retail electric supplier's obligation to incur any liability until such time as the facility is in commercial operation and generating power and energy and such power and energy is being delivered to the facility busbar;

(x) provide that the owner or owners of the initial clean coal facility, which is the counterparty to such sourcing agreement, shall have the right from time to time to elect whether the obligations of the utility party thereto shall be governed by the power purchase provisions or the contract for differences provisions;

(xi) append documentation showing that the formula rate and contract, insofar as they relate to the power purchase provisions, have been approved by the Federal Energy Regulatory Commission pursuant to Section 205 of the Federal Power Act;

(xii) provide that any changes to the terms of the contract, insofar as such changes relate to the power purchase provisions, are subject to review under the public interest standard applied by the Federal Energy Regulatory Commission pursuant to Sections 205 and 206 of the Federal Power Act; and

(xiii) conform with customary lender requirements in power purchase agreements used as the basis for financing non-utility generators.

(4) Effective date of sourcing agreements with the initial clean coal facility. Any proposed sourcing agreement with the initial clean coal facility shall not become effective unless the following reports are prepared and submitted and authorizations and approvals obtained:

(i) Facility cost report. The owner of the initial clean coal facility shall submit to the Commission, the Agency, and the General Assembly a front-end engineering and design study, a facility cost report, method of financing (including but not limited to structure and associated costs), and an operating and maintenance cost quote for the facility (collectively "facility cost report"), which shall be prepared in accordance with the requirements of this paragraph (4) of subsection (d) of this Section, and shall provide the Commission and the Agency access to the work papers, relied upon documents, and any other backup documentation related to the facility cost report.

(ii) Commission report. Within 6 months following receipt of the facility cost report, the Commission, in consultation with the Agency, shall submit a report to the General Assembly setting forth its analysis of the facility cost report. Such report shall include, but not be limited to, a comparison of the costs associated with electricity generated by the initial clean coal facility to the costs associated with electricity generated by other types of generation facilities, an analysis of the rate impacts on residential and small business customers over the life of the sourcing agreements, and an analysis of the likelihood that the initial clean coal facility will commence commercial operation by and be delivering power to the facility's busbar by 2016. To assist in the preparation of its report, the Commission, in consultation with the Agency, may hire one or more experts or consultants, the costs of which shall be paid for by the owner of the initial clean coal facility. The Commission and Agency may begin the process of selecting such experts or consultants prior to receipt of the facility cost report.

(iii) General Assembly approval. The proposed sourcing agreements shall not take effect unless, based on the facility cost report and the Commission's report, the General Assembly enacts authorizing legislation approving (A) the projected price, stated in cents per kilowatthour, to be charged for electricity generated by the initial clean coal facility, (B) the projected impact on residential and small business customers' bills over the life of the sourcing agreements, and (C) the maximum allowable return on equity for the project; and

(iv) Commission review. If the General Assembly enacts authorizing legislation pursuant to subparagraph (iii) approving a sourcing agreement, the Commission shall, within 90 days of such enactment, complete a review of such sourcing agreement. During such time period, the Commission shall implement any directive of the General Assembly, resolve any disputes between the parties to the sourcing agreement concerning the terms of such agreement, approve the form of such agreement, and issue an order finding that the sourcing agreement is prudent and reasonable.

The facility cost report shall be prepared as follows:

(A) The facility cost report shall be prepared by duly licensed engineering and construction firms detailing the estimated capital costs payable to one or more contractors or suppliers for the engineering, procurement and construction of the components comprising the initial clean coal facility and the estimated costs of operation and maintenance of the facility. The facility cost report shall include:

(i) an estimate of the capital cost of the core plant based on one or more front end engineering and design studies for the gasification island and related facilities. The core plant shall include all civil, structural, mechanical, electrical, control, and safety systems.

(ii) an estimate of the capital cost of the balance of the plant, including any capital costs associated with sequestration of carbon dioxide emissions and all interconnects and interfaces required to operate the facility, such as transmission of electricity, construction or backfeed power supply, pipelines to transport substitute natural gas or carbon dioxide, potable water supply, natural gas supply, water supply, water discharge, landfill, access roads, and coal delivery.

The quoted construction costs shall be expressed in nominal dollars as of the date that the quote is prepared and shall include capitalized financing costs during construction, taxes, insurance, and other owner's costs, and an assumed escalation in materials and labor beyond the date as of which the construction cost quote is expressed.

(B) The front end engineering and design study for the gasification island and the cost study for the balance of plant shall include sufficient design work to permit quantification of major categories of materials, commodities and labor hours, and receipt of quotes from vendors of major equipment required to construct and operate the clean coal facility.

(C) The facility cost report shall also include an operating and maintenance cost quote that will provide the estimated cost of delivered fuel, personnel, maintenance contracts, chemicals, catalysts, consumables, spares, and other fixed and variable operations and maintenance costs. The delivered fuel cost estimate will be provided by a recognized third party expert or experts in the fuel and transportation industries. The balance of the operating and maintenance cost quote, excluding delivered fuel costs, will be developed based on the inputs provided by duly licensed engineering and construction firms performing the construction cost quote, potential vendors under long-term service agreements and plant operating agreements, or recognized third party plant operator or operators.

The operating and maintenance cost quote (including the cost of the front end engineering and design study) shall be expressed in nominal dollars as of the date that the quote is prepared and shall include taxes, insurance, and other owner's costs, and an assumed escalation in materials and labor beyond the date as of which the operating and maintenance cost quote is expressed.

(D) The facility cost report shall also include an analysis of the initial clean coal facility's ability to deliver power and energy into the applicable regional transmission organization markets and an analysis of the expected capacity factor for the initial clean coal facility.

(E) Amounts paid to third parties unrelated to the owner or owners of the initial clean coal facility to prepare the core plant construction cost quote, including the front end engineering and design study, and the operating and maintenance cost quote will be reimbursed through Coal Development Bonds.

(5) Re-powering and retrofitting coal-fired power plants previously owned by Illinois utilities to qualify as clean coal facilities. During the 2009 procurement planning process and thereafter, the Agency and the Commission shall consider sourcing agreements covering electricity generated by power plants that were previously owned by Illinois utilities and that have been or will be converted into clean coal facilities, as defined by Section 1-10 of this Act. Pursuant to such procurement planning process, the owners of such facilities may propose to the Agency sourcing agreements with utilities and alternative retail electric suppliers required to comply with subsection (d) of this Section and item (5) of subsection (d) of Section 16-115 of the Public Utilities Act, covering electricity generated by such facilities. In the case of sourcing agreements that are power purchase agreements, the contract price for electricity sales shall be established on a cost of service basis. In the case of sourcing agreements that are contracts for differences, the contract price from which the reference price is subtracted shall be established on a cost of service basis. The Agency and the Commission may approve any such utility sourcing agreements that do not exceed cost-based benchmarks developed by the procurement administrator, in consultation with the Commission staff, Agency staff and the procurement monitor, subject to Commission review and approval. The Commission shall have authority to inspect all books and records associated with these clean coal facilities during the term of any such contract.

(6) Costs incurred under this subsection (d) or pursuant to a contract entered into under this subsection (d) shall be deemed prudently incurred and reasonable in amount and the electric utility shall be entitled to full cost recovery pursuant to the tariffs filed with the Commission.

(d-5) Zero emission standard.

(1) Beginning with the delivery year commencing on June 1, 2017, the Agency shall, for electric utilities that serve at least 100,000 retail customers in this State, procure contracts with zero emission facilities that are reasonably capable of generating cost-effective zero emission credits in an amount approximately equal to 16% of the actual amount of electricity delivered by each electric utility to retail customers in the State during calendar year 2014. For an electric utility serving fewer than 100,000 retail customers in this State that requested, under Section 16-111.5 of the Public Utilities Act, that the Agency procure power and energy for all or a portion of the utility's Illinois load for the delivery year commencing June 1, 2016, the Agency shall procure contracts with zero emission facilities that are reasonably capable of generating cost-effective zero emission credits in an amount approximately equal to 16% of the portion of power and energy to be procured by the Agency for the utility. The duration of the contracts procured under this subsection (d-5) shall be for a term of 10 years ending May 31, 2027. The quantity of zero emission credits to be procured under the contracts shall be all of the zero emission credits generated by the zero emission facility in each delivery year; however, if the zero emission facility is owned by more than one entity, then the quantity of zero emission credits to be procured under the contracts shall be the amount of zero emission credits that are generated from the portion of the zero emission facility that is owned by the winning supplier.

The 16% value identified in this paragraph (1) is the average of the percentage targets in subparagraph (B) of paragraph (1) of subsection (c) of this Section for the 5 delivery years beginning June 1, 2017.

The procurement process shall be subject to the following provisions:

(A) Those zero emission facilities that intend to participate in the procurement shall submit to the Agency the following eligibility information for each zero emission facility on or before the date established by the Agency:

(i) the in-service date and remaining useful life of the zero emission facility;

(ii) the amount of power generated annually for each of the years 2005 through 2015, and the projected zero emission credits to be generated over the remaining useful life of the zero emission facility, which shall be used to determine the capability of each facility;

(iii) the annual zero emission facility cost projections, expressed on a per megawatthour basis, over the next 6 delivery years, which shall include the following: operation and maintenance expenses; fully allocated overhead costs, which shall be allocated using the methodology developed by the Institute for Nuclear Power Operations; fuel expenditures; non-fuel capital expenditures; spent fuel expenditures; a return on working capital; the cost of operational and market risks that could be avoided by ceasing operation; and any other costs necessary for continued operations, provided that "necessary" means, for purposes of this item (iii), that the costs could reasonably be avoided only by ceasing operations of the zero emission facility; and

(iv) a commitment to continue operating, for the duration of the contract or contracts executed under the procurement held under this subsection (d-5), the zero emission facility that produces the zero emission credits to be procured in the procurement.

The information described in item (iii) of this subparagraph (A) may be submitted on a confidential basis and shall be treated and maintained by the Agency, the procurement administrator, and the Commission as confidential and proprietary and exempt from disclosure under subparagraphs (a) and (g) of paragraph (1) of Section 7 of the Freedom of Information Act. The Office of Attorney General shall have access to, and maintain the confidentiality of, such information pursuant to Section 6.5 of the Attorney General Act.

(B) The price for each zero emission credit procured under this subsection (d-5) for each delivery year shall be in an amount that equals the Social Cost of Carbon, expressed on a price per megawatthour basis. However, to ensure that the procurement remains affordable to retail customers in this State if electricity prices increase, the price in an applicable delivery year shall be reduced below the Social Cost of Carbon by the amount ("Price Adjustment") by which the market price index for the applicable delivery year exceeds the baseline market price index for the consecutive 12-month period ending May 31, 2016. If the Price Adjustment is greater than or equal to the Social Cost of Carbon in an applicable delivery year, then no payments shall be due in that delivery year. The components of this calculation are defined as follows:

(i) Social Cost of Carbon: The Social Cost of Carbon is $16.50 per megawatthour, which is based on the U.S. Interagency Working Group on Social Cost of Carbon's price in the August 2016 Technical Update using a 3% discount rate, adjusted for inflation for each year of the program. Beginning with the delivery year commencing June 1, 2023, the price per megawatthour shall increase by $1 per megawatthour, and continue to increase by an additional $1 per megawatthour each delivery year thereafter.

(ii) Baseline market price index: The baseline market price index for the consecutive 12-month period ending May 31, 2016 is $31.40 per megawatthour, which is based on the sum of (aa) the average day-ahead energy price across all hours of such 12-month period at the PJM Interconnection LLC Northern Illinois Hub, (bb) 50% multiplied by the Base Residual Auction, or its successor, capacity price for the rest of the RTO zone group determined by PJM Interconnection LLC, divided by 24 hours per day, and (cc) 50% multiplied by the Planning Resource Auction, or its successor, capacity price for Zone 4 determined by the Midcontinent Independent System Operator, Inc., divided by 24 hours per day.

(iii) Market price index: The market price index for a delivery year shall be the sum of projected energy prices and projected capacity prices determined as follows:

(aa) Projected energy prices: the projected energy prices for the applicable delivery year shall be calculated once for the year using the forward market price for the PJM Interconnection, LLC Northern Illinois Hub. The forward market price shall be calculated as follows: the energy forward prices for each month of the applicable delivery year averaged for each trade date during the calendar year immediately preceding that delivery year to produce a single energy forward price for the delivery year. The forward market price calculation shall use data published by the Intercontinental Exchange, or its successor.

(bb) Projected capacity prices:

(I) For the delivery years commencing June 1, 2017, June 1, 2018, and June 1, 2019, the projected capacity price shall be equal to the sum of (1) 50% multiplied by the Base Residual Auction, or its successor, price for the rest of the RTO zone group as determined by PJM Interconnection LLC, divided by 24 hours per day and, (2) 50% multiplied by the resource auction price determined in the resource auction administered by the Midcontinent Independent System Operator, Inc., in which the largest percentage of load cleared for Local Resource Zone 4, divided by 24 hours per day, and where such price is determined by the Midcontinent Independent System Operator, Inc.

(II) For the delivery year commencing June 1, 2020, and each year thereafter, the projected capacity price shall be equal to the sum of (1) 50% multiplied by the Base Residual Auction, or its successor, price for the ComEd zone as determined by PJM Interconnection LLC, divided by 24 hours per day, and (2) 50% multiplied by the resource auction price determined in the resource auction administered by the Midcontinent Independent System Operator, Inc., in which the largest percentage of load cleared for Local Resource Zone 4, divided by 24 hours per day, and where such price is determined by the Midcontinent Independent System Operator, Inc.

For purposes of this subsection (d-5):

"Rest of the RTO" and "ComEd Zone" shall have the meaning ascribed to them by PJM Interconnection, LLC.

"RTO" means regional transmission organization.

(C) No later than 45 days after June 1, 2017 (the effective date of Public Act 99-906), the Agency shall publish its proposed zero emission standard procurement plan. The plan shall be consistent with the provisions of this paragraph (1) and shall provide that winning bids shall be selected based on public interest criteria that include, but are not limited to, minimizing carbon dioxide emissions that result from electricity consumed in Illinois and minimizing sulfur dioxide, nitrogen oxide, and particulate matter emissions that adversely affect the citizens of this State. In particular, the selection of winning bids shall take into account the incremental environmental benefits resulting from the procurement, such as any existing environmental benefits that are preserved by the procurements held under Public Act 99-906 and would cease to exist if the procurements were not held, including the preservation of zero emission facilities. The plan shall also describe in detail how each public interest factor shall be considered and weighted in the bid selection process to ensure that the public interest criteria are applied to the procurement and given full effect.

For purposes of developing the plan, the Agency shall consider any reports issued by a State agency, board, or commission under House Resolution 1146 of the 98th General Assembly and paragraph (4) of subsection (d) of this Section, as well as publicly available analyses and studies performed by or for regional transmission organizations that serve the State and their independent market monitors.

Upon publishing of the zero emission standard procurement plan, copies of the plan shall be posted and made publicly available on the Agency's website. All interested parties shall have 10 days following the date of posting to provide comment to the Agency on the plan. All comments shall be posted to the Agency's website. Following the end of the comment period, but no more than 60 days later than June 1, 2017 (the effective date of Public Act 99-906), the Agency shall revise the plan as necessary based on the comments received and file its zero emission standard procurement plan with the Commission.

If the Commission determines that the plan will result in the procurement of cost-effective zero emission credits, then the Commission shall, after notice and hearing, but no later than 45 days after the Agency filed the plan, approve the plan or approve with modification. For purposes of this subsection (d-5), "cost effective" means the projected costs of procuring zero emission credits from zero emission facilities do not cause the limit stated in paragraph (2) of this subsection to be exceeded.

(C-5) As part of the Commission's review and acceptance or rejection of the procurement results, the Commission shall, in its public notice of successful bidders:

(i) identify how the winning bids satisfy the public interest criteria described in subparagraph (C) of this paragraph (1) of minimizing carbon dioxide emissions that result from electricity consumed in Illinois and minimizing sulfur dioxide, nitrogen oxide, and particulate matter emissions that adversely affect the citizens of this State;

(ii) specifically address how the selection of winning bids takes into account the incremental environmental benefits resulting from the procurement, including any existing environmental benefits that are preserved by the procurements held under Public Act 99-906 and would have ceased to exist if the procurements had not been held, such as the preservation of zero emission facilities;

(iii) quantify the environmental benefit of preserving the resources identified in item (ii) of this subparagraph (C-5), including the following:

(aa) the value of avoided greenhouse gas emissions measured as the product of the zero emission facilities' output over the contract term multiplied by the U.S. Environmental Protection Agency eGrid subregion carbon dioxide emission rate and the U.S. Interagency Working Group on Social Cost of Carbon's price in the August 2016 Technical Update using a 3% discount rate, adjusted for inflation for each delivery year; and

(bb) the costs of replacement with other zero carbon dioxide resources, including wind and photovoltaic, based upon the simple average of the following:

(I) the price, or if there is more than one price, the average of the prices, paid for renewable energy credits from new utility-scale wind projects in the procurement events specified in item (i) of subparagraph (G) of paragraph (1) of subsection (c) of this Section; and

(II) the price, or if there is more than one price, the average of the prices, paid for renewable energy credits from new utility-scale solar projects and brownfield site photovoltaic projects in the procurement events specified in item (ii) of subparagraph (G) of paragraph (1) of subsection (c) of this Section and, after January 1, 2015, renewable energy credits from photovoltaic distributed generation projects in procurement events held under subsection (c) of this Section.

Each utility shall enter into binding contractual arrangements with the winning suppliers.

The procurement described in this subsection (d-5), including, but not limited to, the execution of all contracts procured, shall be completed no later than May 10, 2017. Based on the effective date of Public Act 99-906, the Agency and Commission may, as appropriate, modify the various dates and timelines under this subparagraph and subparagraphs (C) and (D) of this paragraph (1). The procurement and plan approval processes required by this subsection (d-5) shall be conducted in conjunction with the procurement and plan approval processes required by subsection (c) of this Section and Section 16-111.5 of the Public Utilities Act, to the extent practicable. Notwithstanding whether a procurement event is conducted under Section 16-111.5 of the Public Utilities Act, the Agency shall immediately initiate a procurement process on June 1, 2017 (the effective date of Public Act 99-906).

(D) Following the procurement event described in this paragraph (1) and consistent with subparagraph (B) of this paragraph (1), the Agency shall calculate the payments to be made under each contract for the next delivery year based on the market price index for that delivery year. The Agency shall publish the payment calculations no later than May 25, 2017 and every May 25 thereafter.

(E) Notwithstanding the requirements of this subsection (d-5), the contracts executed under this subsection (d-5) shall provide that the zero emission facility may, as applicable, suspend or terminate performance under the contracts in the following instances:

(i) A zero emission facility shall be excused from its performance under the contract for any cause beyond the control of the resource, including, but not restricted to, acts of God, flood, drought, earthquake, storm, fire, lightning, epidemic, war, riot, civil disturbance or disobedience, labor dispute, labor or material shortage, sabotage, acts of public enemy, explosions, orders, regulations or restrictions imposed by governmental, military, or lawfully established civilian authorities, which, in any of the foregoing cases, by exercise of commercially reasonable efforts the zero emission facility could not reasonably have been expected to avoid, and which, by the exercise of commercially reasonable efforts, it has been unable to overcome. In such event, the zero emission facility shall be excused from performance for the duration of the event, including, but not limited to, delivery of zero emission credits, and no payment shall be due to the zero emission facility during the duration of the event.

(ii) A zero emission facility shall be permitted to terminate the contract if legislation is enacted into law by the General Assembly that imposes or authorizes a new tax, special assessment, or fee on the generation of electricity, the ownership or leasehold of a generating unit, or the privilege or occupation of such generation, ownership, or leasehold of generation units by a zero emission facility. However, the provisions of this item (ii) do not apply to any generally applicable tax, special assessment or fee, or requirements imposed by federal law.

(iii) A zero emission facility shall be permitted to terminate the contract in the event that the resource requires capital expenditures in excess of $40,000,000 that were neither known nor reasonably foreseeable at the time it executed the contract and that a prudent owner or operator of such resource would not undertake.

(iv) A zero emission facility shall be permitted to terminate the contract in the event the Nuclear Regulatory Commission terminates the resource's license.

(F) If the zero emission facility elects to terminate a contract under subparagraph (E) of this paragraph (1), then the Commission shall reopen the docket in which the Commission approved the zero emission standard procurement plan under subparagraph (C) of this paragraph (1) and, after notice and hearing, enter an order acknowledging the contract termination election if such termination is consistent with the provisions of this subsection (d-5).

(2) For purposes of this subsection (d-5), the amount paid per kilowatthour means the total amount paid for electric service expressed on a per kilowatthour basis. For purposes of this subsection (d-5), the total amount paid for electric service includes, without limitation, amounts paid for supply, transmission, distribution, surcharges, and add-on taxes.

Notwithstanding the requirements of this subsection (d-5), the contracts executed under this subsection (d-5) shall provide that the total of zero emission credits procured under a procurement plan shall be subject to the limitations of this paragraph (2). For each delivery year, the contractual volume receiving payments in such year shall be reduced for all retail customers based on the amount necessary to limit the net increase that delivery year to the costs of those credits included in the amounts paid by eligible retail customers in connection with electric service to no more than 1.65% of the amount paid per kilowatthour by eligible retail customers during the year ending May 31, 2009. The result of this computation shall apply to and reduce the procurement for all retail customers, and all those customers shall pay the same single, uniform cents per kilowatthour charge under subsection (k) of Section 16-108 of the Public Utilities Act. To arrive at a maximum dollar amount of zero emission credits to be paid for the particular delivery year, the resulting per kilowatthour amount shall be applied to the actual amount of kilowatthours of electricity delivered by the electric utility in the delivery year immediately prior to the procurement, to all retail customers in its service territory. Unpaid contractual volume for any delivery year shall be paid in any subsequent delivery year in which such payments can be made without exceeding the amount specified in this paragraph (2). The calculations required by this paragraph (2) shall be made only once for each procurement plan year. Once the determination as to the amount of zero emission credits to be paid is made based on the calculations set forth in this paragraph (2), no subsequent rate impact determinations shall be made and no adjustments to those contract amounts shall be allowed. All costs incurred under those contracts and in implementing this subsection (d-5) shall be recovered by the electric utility as provided in this Section.

No later than June 30, 2019, the Commission shall review the limitation on the amount of zero emission credits procured under this subsection (d-5) and report to the General Assembly its findings as to whether that limitation unduly constrains the procurement of cost-effective zero emission credits.

(3) Six years after the execution of a contract under this subsection (d-5), the Agency shall determine whether the actual zero emission credit payments received by the supplier over the 6-year period exceed the Average ZEC Payment. In addition, at the end of the term of a contract executed under this subsection (d-5), or at the time, if any, a zero emission facility's contract is terminated under subparagraph (E) of paragraph (1) of this subsection (d-5), then the Agency shall determine whether the actual zero emission credit payments received by the supplier over the term of the contract exceed the Average ZEC Payment, after taking into account any amounts previously credited back to the utility under this paragraph (3). If the Agency determines that the actual zero emission credit payments received by the supplier over the relevant period exceed the Average ZEC Payment, then the supplier shall credit the difference back to the utility. The amount of the credit shall be remitted to the applicable electric utility no later than 120 days after the Agency's determination, which the utility shall reflect as a credit on its retail customer bills as soon as practicable; however, the credit remitted to the utility shall not exceed the total amount of payments received by the facility under its contract.

For purposes of this Section, the Average ZEC Payment shall be calculated by multiplying the quantity of zero emission credits delivered under the contract times the average contract price. The average contract price shall be determined by subtracting the amount calculated under subparagraph (B) of this paragraph (3) from the amount calculated under subparagraph (A) of this paragraph (3), as follows:

(A) The average of the Social Cost of Carbon, as defined in subparagraph (B) of paragraph (1) of this subsection (d-5), during the term of the contract.

(B) The average of the market price indices, as defined in subparagraph (B) of paragraph (1) of this subsection (d-5), during the term of the contract, minus the baseline market price index, as defined in subparagraph (B) of paragraph (1) of this subsection (d-5).

If the subtraction yields a negative number, then the Average ZEC Payment shall be zero.

(4) Cost-effective zero emission credits procured from zero emission facilities shall satisfy the applicable definitions set forth in Section 1-10 of this Act.

(5) The electric utility shall retire all zero emission credits used to comply with the requirements of this subsection (d-5).

(6) Electric utilities shall be entitled to recover all of the costs associated with the procurement of zero emission credits through an automatic adjustment clause tariff in accordance with subsection (k) and (m) of Section 16-108 of the Public Utilities Act, and the contracts executed under this subsection (d-5) shall provide that the utilities' payment obligations under such contracts shall be reduced if an adjustment is required under subsection (m) of Section 16-108 of the Public Utilities Act.

(7) This subsection (d-5) shall become inoperative on January 1, 2028.

(d-10) Nuclear Plant Assistance; carbon mitigation credits.

(1) The General Assembly finds:

(A) The health, welfare, and prosperity of all Illinois citizens require that the State of Illinois act to avoid and not increase carbon emissions from electric generation sources while continuing to ensure affordable, stable, and reliable electricity to all citizens.

(B) Absent immediate action by the State to preserve existing carbon-free energy resources, those resources may retire, and the electric generation needs of Illinois' retail customers may be met instead by facilities that emit significant amounts of carbon pollution and other harmful air pollutants at a high social and economic cost until Illinois is able to develop other forms of clean energy.

(C) The General Assembly finds that nuclear power generation is necessary for the State's transition to 100% clean energy, and ensuring continued operation of nuclear plants advances environmental and public health interests through providing carbon-free electricity while reducing the air pollution profile of the Illinois energy generation fleet.

(D) The clean energy attributes of nuclear generation facilities support the State in its efforts to achieve 100% clean energy.

(E) The State currently invests in various forms of clean energy, including, but not limited to, renewable energy, energy efficiency, and low-emission vehicles, among others.

(F) The Environmental Protection Agency commissioned an independent audit which provided a detailed assessment of the financial condition of the Illinois nuclear fleet to evaluate its financial viability and whether the environmental benefits of such resources were at risk. The report identified the risk of losing the environmental benefits of several specific nuclear units. The report also identified that the LaSalle County Generating Station will continue to operate through 2026 and therefore is not eligible to participate in the carbon mitigation credit program.

(G) Nuclear plants provide carbon-free energy, which helps to avoid many health-related negative impacts for Illinois residents.

(H) The procurement of carbon mitigation credits representing the environmental benefits of carbon-free generation will further the State's efforts at achieving 100% clean energy and decarbonizing the electricity sector in a safe, reliable, and affordable manner. Further, the procurement of carbon emission credits will enhance the health and welfare of Illinois residents through decreased reliance on more highly polluting generation.

(I) The General Assembly therefore finds it necessary to establish carbon mitigation credits to ensure decreased reliance on more carbon-intensive energy resources, for transitioning to a fully decarbonized electricity sector, and to help ensure health and welfare of the State's residents.

(2) As used in this subsection:

"Baseline costs" means costs used to establish a customer protection cap that have been evaluated through an independent audit of a carbon-free energy resource conducted by the Environmental Protection Agency that evaluated projected annual costs for operation and maintenance expenses; fully allocated overhead costs, which shall be allocated using the methodology developed by the Institute for Nuclear Power Operations; fuel expenditures; nonfuel capital expenditures; spent fuel expenditures; a return on working capital; the cost of operational and market risks that could be avoided by ceasing operation; and any other costs necessary for continued operations, provided that "necessary" means, for purposes of this definition, that the costs could reasonably be avoided only by ceasing operations of the carbon-free energy resource.

"Carbon mitigation credit" means a tradable credit that represents the carbon emission reduction attributes of one megawatt-hour of energy produced from a carbon-free energy resource.

"Carbon-free energy resource" means a generation facility that: (1) is fueled by nuclear power; and (2) is interconnected to PJM Interconnection, LLC.

(3) Procurement.

(A) Beginning with the delivery year commencing on June 1, 2022, the Agency shall, for electric utilities serving at least 3,000,000 retail customers in the State, seek to procure contracts for no more than approximately 54,500,000 cost-effective carbon mitigation credits from carbon-free energy resources because such credits are necessary to support current levels of carbon-free energy generation and ensure the State meets its carbon dioxide emissions reduction goals. The Agency shall not make a partial award of a contract for carbon mitigation credits covering a fractional amount of a carbon-free energy resource's projected output.

(B) Each carbon-free energy resource that intends to participate in a procurement shall be required to submit to the Agency the following information for the resource on or before the date established by the Agency:

(i) the in-service date and remaining useful life of the carbon-free energy resource;

(ii) the amount of power generated annually for each of the past 10 years, which shall be used to determine the capability of each facility;

(iii) a commitment to be reflected in any contract entered into pursuant to this subsection (d-10) to continue operating the carbon-free energy resource at a capacity factor of at least 88% annually on average for the duration of the contract or contracts executed under the procurement held under this subsection (d-10), except in an instance described in subparagraph (E) of paragraph (1) of subsection (d-5) of this Section or made impracticable as a result of compliance with law or regulation;

(iv) financial need and the risk of loss of the environmental benefits of such resource, which shall include the following information:

(I) the carbon-free energy resource's cost projections, expressed on a per megawatt-hour basis, over the next 5 delivery years, which shall include the following: operation and maintenance expenses; fully allocated overhead costs, which shall be allocated using the methodology developed by the Institute for Nuclear Power Operations; fuel expenditures; nonfuel capital expenditures; spent fuel expenditures; a return on working capital; the cost of operational and market risks that could be avoided by ceasing operation; and any other costs necessary for continued operations, provided that "necessary" means, for purposes of this subitem (I), that the costs could reasonably be avoided only by ceasing operations of the carbon-free energy resource; and

(II) the carbon-free energy resource's revenue projections, including energy, capacity, ancillary services, any other direct State support, known or anticipated federal attribute credits, known or anticipated tax credits, and any other direct federal support.

The information described in this subparagraph (B) may be submitted on a confidential basis and shall be treated and maintained by the Agency, the procurement administrator, and the Commission as confidential and proprietary and exempt from disclosure under subparagraphs (a) and (g) of paragraph (1) of Section 7 of the Freedom of Information Act. The Office of the Attorney General shall have access to, and maintain the confidentiality of, such information pursuant to Section 6.5 of the Attorney General Act.

(C) The Agency shall solicit bids for the contracts described in this subsection (d-10) from carbon-free energy resources that have satisfied the requirements of subparagraph (B) of this paragraph (3). The contracts procured pursuant to a procurement event shall reflect, and be subject to, the following terms, requirements, and limitations:

(i) Contracts are for delivery of carbon mitigation credits, and are not energy or capacity sales contracts requiring physical delivery. Pursuant to item (iii), contract payments shall fully deduct the value of any monetized federal production tax credits, credits issued pursuant to a federal clean energy standard, and other federal credits if applicable.

(ii) Contracts for carbon mitigation credits shall commence with the delivery year beginning on June 1, 2022 and shall be for a term of 5 delivery years concluding on May 31, 2027.

(iii) The price per carbon mitigation credit to be paid under a contract for a given delivery year shall be equal to an accepted bid price less the sum of:

(I) one of the following energy price indices, selected by the bidder at the time of the bid for the term of the contract:

(aa) the weighted-average hourly day-ahead price for the applicable delivery year at the busbar of all resources procured pursuant to this subsection (d-10), weighted by actual production from the resources; or

(bb) the projected energy price for the PJM Interconnection, LLC Northern Illinois Hub for the applicable delivery year determined according to subitem (aa) of item (iii) of subparagraph (B) of paragraph (1) of subsection (d-5).

(II) the Base Residual Auction Capacity Price for the ComEd zone as determined by PJM Interconnection, LLC, divided by 24 hours per day, for the applicable delivery year for the first 3 delivery years, and then any subsequent delivery years unless the PJM Interconnection, LLC applies the Minimum Offer Price Rule to participating carbon-free energy resources because they supply carbon mitigation credits pursuant to this Section at which time, upon notice by the carbon-free energy resource to the Commission and subject to the Commission's confirmation, the value under this subitem shall be zero, as further described in the carbon mitigation credit procurement plan; and

(III) any value of monetized federal tax credits, direct payments, or similar subsidy provided to the carbon-free energy resource from any unit of government that is not already reflected in energy prices.

If the price-per-megawatt-hour calculation performed under item (iii) of this subparagraph (C) for a given delivery year results in a net positive value, then the electric utility counterparty to the contract shall multiply such net value by the applicable contract quantity and remit the amount to the supplier.

To protect retail customers from retail rate impacts that may arise upon the initiation of carbon policy changes, if the price-per-megawatt-hour calculation performed under item (iii) of this subparagraph (C) for a given delivery year results in a net negative value, then the supplier counterparty to the contract shall multiply such net value by the applicable contract quantity and remit such amount to the electric utility counterparty. The electric utility shall reflect such amounts remitted by suppliers as a credit on its retail customer bills as soon as practicable.

(iv) To ensure that retail customers in Northern Illinois do not pay more for carbon mitigation credits than the value such credits provide, and notwithstanding the provisions of this subsection (d-10), the Agency shall not accept bids for contracts that exceed a customer protection cap equal to the baseline costs of carbon-free energy resources.

The baseline costs for the applicable year shall be the following:

(I) For the delivery year beginning June 1, 2022, the baseline costs shall be an amount equal to $30.30 per megawatt-hour.

(II) For the delivery year beginning June 1, 2023, the baseline costs shall be an amount equal to $32.50 per megawatt-hour.

(III) For the delivery year beginning June 1, 2024, the baseline costs shall be an amount equal to $33.43 per megawatt-hour.

(IV) For the delivery year beginning June 1, 2025, the baseline costs shall be an amount equal to $33.50 per megawatt-hour.

(V) For the delivery year beginning June 1, 2026, the baseline costs shall be an amount equal to $34.50 per megawatt-hour.

An Environmental Protection Agency consultant forecast, included in a report issued April 14, 2021, projects that a carbon-free energy resource has the opportunity to earn on average approximately $30.28 per megawatt-hour, for the sale of energy and capacity during the time period between 2022 and 2027. Therefore, the sale of carbon mitigation credits provides the opportunity to receive an additional amount per megawatt-hour in addition to the projected prices for energy and capacity.

Although actual energy and capacity prices may vary from year-to-year, the General Assembly finds that this customer protection cap will help ensure that the cost of carbon mitigation credits will be less than its value, based upon the social cost of carbon identified in the Technical Support Document issued in February 2021 by the U.S. Interagency Working Group on Social Cost of Greenhouse Gases and the PJM Interconnection, LLC carbon dioxide marginal emission rate for 2020, and that a carbon-free energy resource receiving payment for carbon mitigation credits receives no more than necessary to keep those units in operation.

(D) No later than 7 days after the effective date of this amendatory Act of the 102nd General Assembly, the Agency shall publish its proposed carbon mitigation credit procurement plan. The Plan shall provide that winning bids shall be selected by taking into consideration which resources best match public interest criteria that include, but are not limited to, minimizing carbon dioxide emissions that result from electricity consumed in Illinois and minimizing sulfur dioxide, nitrogen oxide, and particulate matter emissions that adversely affect the citizens of this State. The selection of winning bids shall also take into account the incremental environmental benefits resulting from the procurement or procurements, such as any existing environmental benefits that are preserved by a procurement held under this subsection (d-10) and would cease to exist if the procurement were not held, including the preservation of carbon-free energy resources. For those bidders having the same public interest criteria score, the relative ranking of such bidders shall be determined by price. The Plan shall describe in detail how each public interest factor shall be considered and weighted in the bid selection process to ensure that the public interest criteria are applied to the procurement. The Plan shall, to the extent practical and permissible by federal law, ensure that successful bidders make commercially reasonable efforts to apply for federal tax credits, direct payments, or similar subsidy programs that support carbon-free generation and for which the successful bidder is eligible. Upon publishing of the carbon mitigation credit procurement plan, copies of the plan shall be posted and made publicly available on the Agency's website. All interested parties shall have 7 days following the date of posting to provide comment to the Agency on the plan. All comments shall be posted to the Agency's website. Following the end of the comment period, but no more than 19 days later than the effective date of this amendatory Act of the 102nd General Assembly, the Agency shall revise the plan as necessary based on the comments received and file its carbon mitigation credit procurement plan with the Commission.

(E) If the Commission determines that the plan is likely to result in the procurement of cost-effective carbon mitigation credits, then the Commission shall, after notice and hearing and opportunity for comment, but no later than 42 days after the Agency filed the plan, approve the plan or approve it with modification. For purposes of this subsection (d-10), "cost-effective" means carbon mitigation credits that are procured from carbon-free energy resources at prices that are within the limits specified in this paragraph (3). As part of the Commission's review and acceptance or rejection of the procurement results, the Commission shall, in its public notice of successful bidders:

(i) identify how the selected carbon-free energy resources satisfy the public interest criteria described in this paragraph (3) of minimizing carbon dioxide emissions that result from electricity consumed in Illinois and minimizing sulfur dioxide, nitrogen oxide, and particulate matter emissions that adversely affect the citizens of this State;

(ii) specifically address how the selection of carbon-free energy resources takes into account the incremental environmental benefits resulting from the procurement, including any existing environmental benefits that are preserved by the procurements held under this amendatory Act of the 102nd General Assembly and would have ceased to exist if the procurements had not been held, such as the preservation of carbon-free energy resources;

(iii) quantify the environmental benefit of preserving the carbon-free energy resources procured pursuant to this subsection (d-10), including the following:

(I) an assessment value of avoided greenhouse gas emissions measured as the product of the carbon-free energy resources' output over the contract term, using generally accepted methodologies for the valuation of avoided emissions; and

(II) an assessment of costs of replacement with other carbon-free energy resources and renewable energy resources, including wind and photovoltaic generation, based upon an assessment of the prices paid for renewable energy credits through programs and procurements conducted pursuant to subsection (c) of Section 1-75 of this Act, and the additional storage necessary to produce the same or similar capability of matching customer usage patterns.

(F) The procurements described in this paragraph (3), including, but not limited to, the execution of all contracts procured, shall be completed no later than December 3, 2021. The procurement and plan approval processes required by this paragraph (3) shall be conducted in conjunction with the procurement and plan approval processes required by Section 16-111.5 of the Public Utilities Act, to the extent practicable. However, the Agency and Commission may, as appropriate, modify the various dates and timelines under this subparagraph and subparagraphs (D) and (E) of this paragraph (3) to meet the December 3, 2021 contract execution deadline. Following the completion of such procurements, and consistent with this paragraph (3), the Agency shall calculate the payments to be made under each contract in a timely fashion.

(F-1) Costs incurred by the electric utility pursuant to a contract authorized by this subsection (d-10) shall be deemed prudently incurred and reasonable in amount, and the electric utility shall be entitled to full cost recovery pursuant to a tariff or tariffs filed with the Commission.

(G) The counterparty electric utility shall retire all carbon mitigation credits used to comply with the requirements of this subsection (d-10).

(H) If a carbon-free energy resource is sold to another owner, the rights, obligations, and commitments under this subsection (d-10) shall continue to the subsequent owner.

(I) This subsection (d-10) shall become inoperative on January 1, 2028.

(e) The draft procurement plans are subject to public comment, as required by Section 16-111.5 of the Public Utilities Act.

(f) The Agency shall submit the final procurement plan to the Commission. The Agency shall revise a procurement plan if the Commission determines that it does not meet the standards set forth in Section 16-111.5 of the Public Utilities Act.

(g) The Agency shall assess fees to each affected utility to recover the costs incurred in preparation of the annual procurement plan for the utility.

(h) The Agency shall assess fees to each bidder to recover the costs incurred in connection with a competitive procurement process.

(i) A renewable energy credit, carbon emission credit, zero emission credit, or carbon mitigation credit can only be used once to comply with a single portfolio or other standard as set forth in subsection (c), subsection (d), or subsection (d-5) of this Section, respectively. A renewable energy credit, carbon emission credit, zero emission credit, or carbon mitigation credit cannot be used to satisfy the requirements of more than one standard. If more than one type of credit is issued for the same megawatt hour of energy, only one credit can be used to satisfy the requirements of a single standard. After such use, the credit must be retired together with any other credits issued for the same megawatt hour of energy.

(Source: P.A. 102-662, eff. 9-15-21; 103-380, eff. 1-1-24; 103-580, eff. 12-8-23; 103-1066, eff. 2-20-25.)

(Text of Section after amendment by P.A. 104-458)

Sec. 1-75. Planning and Procurement Bureau. The Planning and Procurement Bureau has the following duties and responsibilities:

(a) The Planning and Procurement Bureau shall each year, beginning in 2008, develop procurement plans and conduct competitive procurement processes in accordance with the requirements of Section 16-111.5 of the Public Utilities Act for the eligible retail customers of electric utilities that on December 31, 2005 provided electric service to at least 100,000 customers in Illinois. Beginning with the delivery year commencing on June 1, 2017, the Planning and Procurement Bureau shall develop plans and processes for the procurement of zero emission credits from zero emission facilities in accordance with the requirements of subsection (d-5) of this Section. Beginning on the effective date of this amendatory Act of the 102nd General Assembly, the Planning and Procurement Bureau shall develop plans and processes for the procurement of carbon mitigation credits from carbon-free energy resources in accordance with the requirements of subsection (d-10) of this Section. The Planning and Procurement Bureau shall also develop procurement plans and conduct competitive procurement processes in accordance with the requirements of Section 16-111.5 of the Public Utilities Act for the eligible retail customers of small multi-jurisdictional electric utilities that (i) on December 31, 2005 served less than 100,000 customers in Illinois and (ii) request a procurement plan for their Illinois jurisdictional load. This Section shall not apply to a small multi-jurisdictional utility until such time as a small multi-jurisdictional utility requests the Agency to prepare a procurement plan for their Illinois jurisdictional load. For the purposes of this Section, the term "eligible retail customers" has the same definition as found in Section 16-111.5(a) of the Public Utilities Act.

Beginning with the plan or plans to be implemented in the 2017 delivery year, the Agency shall no longer include the procurement of renewable energy resources in the annual procurement plans required by this subsection (a), except as provided in subsection (q) of Section 16-111.5 of the Public Utilities Act, and shall instead develop a long-term renewable resources procurement plan in accordance with subsection (c) of this Section and Section 16-111.5 of the Public Utilities Act.

In accordance with subsection (c-5) of this Section, the Planning and Procurement Bureau shall oversee the procurement by electric utilities that served more than 300,000 retail customers in this State as of January 1, 2019 of renewable energy credits from new utility-scale solar projects to be installed, along with energy storage facilities, at or adjacent to the sites of electric generating facilities that, as of January 1, 2016, burned coal as their primary fuel source.

(1) The Agency shall each year, beginning in 2008, as needed, issue a request for qualifications for experts or expert consulting firms to develop the procurement plans in accordance with Section 16-111.5 of the Public Utilities Act. In order to qualify an expert or expert consulting firm must have:

(A) direct previous experience assembling large-scale power supply plans or portfolios for end-use customers;

(B) an advanced degree in economics, mathematics, engineering, risk management, or a related area of study;

(C) 10 years of experience in the electricity sector, including managing supply risk;

(D) expertise in wholesale electricity market rules, including those established by the Federal Energy Regulatory Commission and regional transmission organizations;

(E) expertise in credit protocols and familiarity with contract protocols;

(F) adequate resources to perform and fulfill the required functions and responsibilities; and

(G) the absence of a conflict of interest and inappropriate bias for or against potential bidders or the affected electric utilities.

(2) The Agency shall each year, as needed, issue a request for qualifications for a procurement administrator to conduct the competitive procurement processes in accordance with Section 16-111.5 of the Public Utilities Act. In order to qualify an expert or expert consulting firm must have:

(A) direct previous experience administering a large-scale competitive procurement process;

(B) an advanced degree in economics, mathematics, engineering, or a related area of study;

(C) 10 years of experience in the electricity sector, including risk management experience;

(D) expertise in wholesale electricity market rules, including those established by the Federal Energy Regulatory Commission and regional transmission organizations;

(E) expertise in credit and contract protocols;

(F) adequate resources to perform and fulfill the required functions and responsibilities; and

(G) the absence of a conflict of interest and inappropriate bias for or against potential bidders or the affected electric utilities.

(3) The Agency shall provide affected utilities and other interested parties with the lists of qualified experts or expert consulting firms identified through the request for qualifications processes that are under consideration to develop the procurement plans and to serve as the procurement administrator. The Agency shall also provide each qualified expert's or expert consulting firm's response to the request for qualifications. All information provided under this subparagraph shall also be provided to the Commission. The Agency may provide by rule for fees associated with supplying the information to utilities and other interested parties. These parties shall, within 5 business days, notify the Agency in writing if they object to any experts or expert consulting firms on the lists. Objections shall be based on:

(A) failure to satisfy qualification criteria;

(B) identification of a conflict of interest; or

(C) evidence of inappropriate bias for or against potential bidders or the affected utilities.

The Agency shall remove experts or expert consulting firms from the lists within 10 days if there is a reasonable basis for an objection and provide the updated lists to the affected utilities and other interested parties. If the Agency fails to remove an expert or expert consulting firm from a list, an objecting party may seek review by the Commission within 5 days thereafter by filing a petition, and the Commission shall render a ruling on the petition within 10 days. There is no right of appeal of the Commission's ruling.

(4) The Agency shall issue requests for proposals to the qualified experts or expert consulting firms to develop a procurement plan for the affected utilities and to serve as procurement administrator.

(5) The Agency shall select an expert or expert consulting firm to develop procurement plans based on the proposals submitted and shall award contracts of up to 5 years to those selected.

(6) The Agency shall select an expert or expert consulting firm, with approval of the Commission, to serve as procurement administrator based on the proposals submitted. If the Commission rejects, within 5 days, the Agency's selection, the Agency shall submit another recommendation within 3 days based on the proposals submitted. The Agency shall award a 5-year contract to the expert or expert consulting firm so selected with Commission approval.

(b) The experts or expert consulting firms retained by the Agency shall, as appropriate, prepare procurement plans, and conduct a competitive procurement process as prescribed in Section 16-111.5 of the Public Utilities Act, to ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time, taking into account any benefits of price stability, for eligible retail customers of electric utilities that on December 31, 2005 provided electric service to at least 100,000 customers in the State of Illinois, and for eligible Illinois retail customers of small multi-jurisdictional electric utilities that (i) on December 31, 2005 served less than 100,000 customers in Illinois and (ii) request a procurement plan for their Illinois jurisdictional load.

(c) Renewable portfolio standard.

(1)(A) The Agency shall develop a long-term renewable resources procurement plan that shall include procurement programs and competitive procurement events necessary to meet the goals set forth in this subsection (c). The initial long-term renewable resources procurement plan shall be released for comment no later than 160 days after June 1, 2017 (the effective date of Public Act 99-906). The Agency shall review, and may revise on an expedited basis, the long-term renewable resources procurement plan at least every 2 years, which shall be conducted in conjunction with the procurement plan under Section 16-111.5 of the Public Utilities Act to the extent practicable to minimize administrative expense. No later than 120 days after the effective date of this amendatory Act of the 103rd General Assembly, the Agency shall release for comment a revision to the long-term renewable resources procurement plan, updating elements of the most recently approved plan as needed to comply with this amendatory Act of the 103rd General Assembly, and any long-term renewable resources procurement plan update published by the Agency but not yet approved by the Illinois Commerce Commission shall be withdrawn. The long-term renewable resources procurement plans shall be subject to review and approval by the Commission under Section 16-111.5 of the Public Utilities Act.

(B) Subject to subparagraph (F) of this paragraph (1), the long-term renewable resources procurement plan shall attempt to meet the goals for procurement of renewable energy credits at levels of at least the following overall percentages: 13% by the 2017 delivery year; increasing by at least 1.5% each delivery year thereafter to at least 25% by the 2025 delivery year; increasing by at least 3% each delivery year thereafter to at least 40% by the 2030 delivery year, and continuing at no less than 40% for each delivery year thereafter. The Agency shall attempt to procure 50% by delivery year 2040. The Agency shall determine the annual increase between delivery year 2030 and delivery year 2040, if any, taking into account energy demand, other energy resources, and other public policy goals. In the event of a conflict between these goals and the new wind, new photovoltaic, new geothermal heating and cooling, and hydropower procurement requirements described in items (i) through (iii) of subparagraph (C) of this paragraph (1), the long-term plan shall prioritize compliance with the new wind, new photovoltaic, new geothermal heating and cooling, and hydropower procurement requirements described in items (i) through (iii) of subparagraph (C) of this paragraph (1) over the annual percentage targets described in this subparagraph (B). The Agency shall not comply with the annual percentage targets described in this subparagraph (B) by procuring renewable energy credits that are unlikely to lead to the development of new renewable resources or new, modernized, or retooled hydropower facilities.

For the delivery year beginning June 1, 2017, the procurement plan shall attempt to include, subject to the prioritization outlined in this subparagraph (B), cost-effective renewable energy resources equal to at least 13% of each utility's load for eligible retail customers and 13% of the applicable portion of each utility's load for retail customers who are not eligible retail customers, which applicable portion shall equal 50% of the utility's load for retail customers who are not eligible retail customers on February 28, 2017.

For the delivery year beginning June 1, 2018, the procurement plan shall attempt to include, subject to the prioritization outlined in this subparagraph (B), cost-effective renewable energy resources equal to at least 14.5% of each utility's load for eligible retail customers and 14.5% of the applicable portion of each utility's load for retail customers who are not eligible retail customers, which applicable portion shall equal 75% of the utility's load for retail customers who are not eligible retail customers on February 28, 2017.

For the delivery year beginning June 1, 2019, and for each year thereafter, the procurement plans shall attempt to include, subject to the prioritization outlined in this subparagraph (B), cost-effective renewable energy resources equal to a minimum percentage of each utility's load for all retail customers as follows: 16% by June 1, 2019; increasing by 1.5% each year thereafter to 25% by June 1, 2025; and 25% by June 1, 2026; increasing by at least 3% each delivery year thereafter to at least 40% by the 2030 delivery year, and continuing at no less than 40% for each delivery year thereafter. The Agency shall attempt to procure 50% by delivery year 2040. The Agency shall determine the annual increase between delivery year 2030 and delivery year 2040, if any, taking into account energy demand, other energy resources, and other public policy goals.

For each delivery year, the Agency shall first recognize each utility's obligations for that delivery year under existing contracts. Any renewable energy credits under existing contracts, including renewable energy credits as part of renewable energy resources, shall be used to meet the goals set forth in this subsection (c) for the delivery year.

(C) The long-term renewable resources procurement plan described in subparagraph (A) of this paragraph (1) shall include the procurement of renewable energy credits from new projects pursuant to the following terms:

(i) At least 10,000,000 renewable energy credits delivered annually by the end of the 2021 delivery year, and increasing ratably to reach 45,000,000 renewable energy credits delivered annually from new wind and solar projects, from repowered wind projects, or from retooled hydropower facilities by the end of delivery year 2030 such that the goals in subparagraph (B) of this paragraph (1) are met entirely by procurements of renewable energy credits from new wind and photovoltaic projects. Of that amount, to the extent possible, the Agency shall endeavor to procure 45% from new and repowered wind and hydropower projects and shall procure at least 55% from photovoltaic projects. Of the amount to be procured from photovoltaic projects, the Agency shall procure: at least 50% from solar photovoltaic projects using the program outlined in subparagraph (K) of this paragraph (1) from distributed renewable energy generation devices or community renewable generation projects; at least 47% from utility-scale solar projects; at least 3% from brownfield site photovoltaic projects that are not community renewable generation projects. The Agency may propose adjustments to these percentages, including establishing percentage-based goals for the procurement of renewable energy credits from modernized or retooled hydropower facilities and repowered wind projects, through its long-term renewable resources plan described in subparagraph (A) of this paragraph (1) as necessary based on developer interest, market conditions, budget considerations, resource adequacy needs, or other factors. Notwithstanding the percentage-based goals as described in this Section, the Agency shall develop a Geothermal Homes and Businesses Program for the procurement of renewable energy credits from geothermal heating and cooling systems.

In developing the long-term renewable resources procurement plan, the Agency shall consider other approaches, in addition to competitive procurements, that can be used to procure renewable energy credits from brownfield site photovoltaic projects and thereby help return blighted or contaminated land to productive use while enhancing public health and the well-being of Illinois residents, including those in environmental justice communities, as defined using existing methodologies and findings used by the Agency and its Administrator in its Illinois Solar for All Program. The Agency shall also consider other approaches, in addition to competitive procurements, to procure renewable energy credits from new and existing hydropower facilities to support the development and maintenance of these facilities. The Agency shall explore options to convert existing dams but shall not consider approaches to develop new dams where they do not already exist. To encourage the continued operation of utility-scale wind projects, the Agency shall consider and may propose other approaches in addition to competitive procurements to procure renewable energy credits from repowered wind projects.

(ii) In any given delivery year, if forecasted expenses are less than the maximum budget available under subparagraph (E) of this paragraph (1), the Agency shall continue to procure new renewable energy credits until that budget is exhausted in the manner outlined in item (i) of this subparagraph (C).

(iii) For purposes of this Section:

"New wind projects" means wind renewable energy facilities that are energized after June 1, 2017 for the delivery year commencing June 1, 2017.

"New photovoltaic projects" means photovoltaic renewable energy facilities that are energized after June 1, 2017. Photovoltaic projects developed under Section 1-56 of this Act shall not apply towards the new photovoltaic project requirements in this subparagraph (C).

"Repowered wind projects" means utility-scale wind projects featuring the removal, replacement, or expansion of turbines at an existing project site, as defined in the long-term renewable resources procurement plan, after the effective date of this amendatory Act of the 103rd General Assembly. Renewable energy credit contract awards used to support repowered wind projects shall only cover the incremental increase in facility electricity production resultant from repowering.

"Geothermal heating and cooling system" means a system located in this State that meets all of the following requirements:

(I) the system exchanges thermal energy from groundwater or a shallow ground source to generate thermal energy through an electric geothermal heat pump or a system of electric geothermal heat pumps interconnected with any geothermal extraction facility that is (1) a closed loop or a series of closed loop systems in which fluid is permanently confined within a pipe or tubing and does not come in contact with the outside environment or (2) an open loop system in which ground or surface water is circulated in an environmentally safe manner directly into the facility and returned to the same aquifer or surface water source;

(II) the system meets or exceeds federal Energy Star product specification standards for Geothermal Heat Pumps established on January 1, 2012, as clarified by the Environmental Protection Agency guidance document released on February 28, 2012 entitled "Clarification to the Geothermal Heat Pump Verification Testing Requirements and Basic Model Group Definition", or any successor standards that meet or exceed these standards;

(III) the system replaces or displaces less efficient space or water heating systems, regardless of fuel type;

(IV) the system replaces or displaces less efficient space cooling systems, when applicable;

(V) the system does not feed electricity back to the grid, as defined at the level of the geothermal heat pump; and

(VI) the system became operational on or after the effective date of this amendatory Act of the 104th General Assembly.

For purposes of calculating whether the Agency has procured enough new wind and solar renewable energy credits required by this subparagraph (C), renewable energy facilities that have a multi-year renewable energy credit delivery contract with the utility through at least delivery year 2030 shall be considered new, however no renewable energy credits from contracts entered into before June 1, 2021 shall be used to calculate whether the Agency has procured the correct proportion of new wind and new solar contracts described in this subparagraph (C) for delivery year 2021 and thereafter.

(iv) The Agency may implement additional measures, including eligibility requirements, to ensure that new wind projects and new photovoltaic projects supported through renewable energy credit contract awards are a result of a contract award and are otherwise developed pursuant to the financial certainty provided through a contract award.

(D) Renewable energy credits shall be cost effective. For purposes of this subsection (c), "cost effective" means that the costs of procuring renewable energy resources do not cause the limit stated in subparagraph (E) of this paragraph (1) to be exceeded and, for renewable energy credits procured through a competitive procurement event, do not exceed benchmarks based on market prices for like products in the region. For purposes of this subsection (c), "like products" means contracts for renewable energy credits from the same or substantially similar technology, same or substantially similar vintage (new or existing), the same or substantially similar quantity, and the same or substantially similar contract length and structure. Benchmarks shall reflect development, financing, or related costs resulting from requirements imposed through other provisions of State law, including, but not limited to, requirements in subparagraphs (P) and (Q) of this paragraph (1) and the Renewable Energy Facilities Agricultural Impact Mitigation Act. Confidential benchmarks shall be developed by the procurement administrator, in consultation with the Commission staff, Agency staff, and the procurement monitor and shall be subject to Commission review and approval. If price benchmarks for like products in the region are not available, the procurement administrator shall establish price benchmarks based on publicly available data on regional technology costs and expected current and future regional energy prices. The benchmarks in this Section shall not be used to curtail or otherwise reduce contractual obligations entered into by or through the Agency prior to June 1, 2017 (the effective date of Public Act 99-906).

(E) For purposes of this subsection (c), the required procurement of cost-effective renewable energy resources for a particular year commencing prior to June 1, 2017 shall be measured as a percentage of the actual amount of electricity (megawatt-hours) supplied by the electric utility to eligible retail customers in the delivery year ending immediately prior to the procurement, and, for delivery years commencing on and after June 1, 2017, the required procurement of cost-effective renewable energy resources for a particular year shall be measured as a percentage of the actual amount of electricity (megawatt-hours) delivered by the electric utility in the delivery year ending immediately prior to the procurement, to all retail customers in its service territory. For purposes of this subsection (c), the amount paid per kilowatthour means the total amount paid for electric service expressed on a per kilowatthour basis. For purposes of this subsection (c), the total amount paid for electric service includes without limitation amounts paid for supply, transmission, capacity, distribution, surcharges, and add-on taxes.

Notwithstanding the requirements of this subsection (c), and except as provided in subparagraph (E-5) of paragraph (1) of this subsection (c) or except as otherwise authorized by the Commission in its approval of the integrated resource plan under Section 16-202 of the Public Utilities Act, the total of renewable energy resources procured under the procurement plan for any single year shall be subject to the limitations of this subparagraph (E). Such procurement shall be reduced for all retail customers based on the amount necessary to limit the annual estimated average net increase due to the costs of these resources included in the amounts paid by eligible retail customers in connection with electric service to no more than 4.25% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009, adjusted annually for inflation starting with the first adjustment in the delivery year commencing June 1, 2026. For the purposes of this Section, the inflation adjustment shall not be accrued or applied retroactively prior to the effective date of this amendatory Act of the 104th General Assembly and shall apply prospectively starting in 2025. The limitation shall be increased by an additional 1.65 percentage points of the amount paid per kilowatthour by eligible retail customers during the year ending May 31, 2009 starting with the delivery year commencing June 1, 2027. To arrive at a maximum dollar amount of renewable energy resources to be procured for the particular delivery year, the resulting per kilowatthour amount shall be applied to the actual amount of kilowatthours of electricity delivered, or applicable portion of such amount as specified in paragraph (1) of this subsection (c), as applicable, by the electric utility in the delivery year immediately prior to the procurement to all retail customers in its service territory. The calculations required by this subparagraph (E) shall be made only once for each delivery year at the time that the renewable energy resources are procured. Once the determination as to the amount of renewable energy resources to procure is made based on the calculations set forth in this subparagraph (E) and the contracts procuring those amounts are executed between the seller and applicable electric utility, no subsequent rate impact determinations shall be made and no adjustments to those contract amounts shall be allowed. As provided in subparagraph (E-5) of paragraph (1) of this subsection (c), the seller shall be entitled to full, prompt, and uninterrupted payment under the applicable contract notwithstanding the application of this subparagraph (E), and all costs incurred under such contracts shall be fully recoverable by the electric utility as provided in this Section.

(E-5) If, for a particular delivery year, the limitation on the amount of renewable energy resources to be procured, as calculated pursuant to subparagraph (E) of paragraph (1) of this subsection (c), would result in an insufficient collection of funds to fully pay amounts due to a seller under existing contracts executed under this Section or executed under Section 1-56 of this Act, then the following provisions shall apply to ensure full and uninterrupted payment is made to such seller or sellers:

(i) If the electric utility has retained unspent funds in an interest-bearing account as prescribed in subsection (k) of Section 16-108 of the Public Utilities Act, then the utility shall use those funds to remit full payment to the sellers to ensure prompt and uninterrupted payment of existing contractual obligation.

(ii) If the funds described in item (i) of this subparagraph (E-5) are insufficient to satisfy all existing contractual obligations, then the electric utility shall, nonetheless, remit full payment to the sellers to ensure prompt and uninterrupted payment of existing contractual obligations, provided that the full costs shall be recoverable by the utility in accordance with part (ee) of item (iv) of this subsection (E-5).

(iii) The Agency shall promptly notify the Commission that existing contractual obligations are reasonably expected to exceed the maximum collection authorized under subparagraph (E) of paragraph (1) of this subsection (c) for the applicable delivery year. The Agency shall also explain and confirm how the operation of items (i) and (ii) of this subparagraph (E-5) ensures that the electric utility will continue to make prompt and uninterrupted payment under existing contractual obligations. The Agency shall provide this information to the Commission through a notice filed in the Commission docket approving the Agency's operative Long-Term Renewable Resources Procurement Plan that includes the applicable delivery year.

(iv) The Agency shall suspend or reduce new contract awards for the procurement of renewable energy credits until an Agency determination is made under subparagraph (E) that additional procurements would not cause the rate impact limitation of subparagraph (E) to be exceeded. At least once annually after the notice provided for in item (iii) of this subparagraph (E-5) is made, the Agency shall analyze existing contract obligations, projected prices for indexed renewable energy credit contracts executed under item (v) of subparagraph (G) of paragraph (1) of subsection (c) of Section 1-75 of this Act, and expected collections authorized under subparagraph (E) to determine whether and to what extent the limitations of subparagraph (E) would be exceeded by additional renewable energy credit procurement contract awards.

(aa) If the Agency determines that additional renewable energy credit procurement contract awards could be made without exceeding the limitations of subparagraph (E), then the procurements shall be authorized at a scale determined not to exceed the limitations of subparagraph (E) in a manner consistent with the priorities of this Section.

(bb) If the Agency determines that additional renewable energy credit procurement contract awards cannot be made without exceeding the limitations of subparagraph (E), then the Agency shall suspend any new contract awards for the procurement of renewable energy credits until a new rate impact determination is made under subparagraph (E).

(cc) Agency determinations made under this item (iv) shall be detailed and comprehensive and, if not made through the Agency's Long-Term Renewable Resources Procurement Plan, shall be filed as a compliance filing in the most recent docketed proceeding approving the Agency's Long-Term Renewable Resources Procurement Plan.

(dd) With respect to the procurement of renewable energy credits authorized through programs administered under subsection (b) of Section 1-56 and subparagraphs (K) through (M) of paragraph (1) of subsection (k) of Section 1-75 of this Act, the award of contracts for the procurement of renewable energy credits shall be suspended or reduced only at the conclusion of the program year in which the notice provided for under item (iii) of this subparagraph (E-5) is made.

(ee) The contract shall provide that, so long as at least one of: (i) the cost recovery mechanisms referenced in subsection (k) of Section 16-108 and subsection (l) of Section 16-111.5 of the Public Utilities Act remains in full force without limitation or (ii) the utility is otherwise authorized and or entitled to full, prompt, and uninterrupted recovery of its costs through any other mechanism, then such seller shall be entitled to full, prompt, and uninterrupted payment under the applicable contract notwithstanding the application of this subparagraph (E).

(F) If the limitation on the amount of renewable energy resources procured in subparagraph (E) of this paragraph (1) prevents the Agency from meeting all of the goals in this subsection (c), the Agency's long-term plan shall prioritize compliance with the requirements of this subsection (c) regarding renewable energy credits in the following order:

(i) renewable energy credits under existing contractual obligations as of June 1, 2021;

(i-5) funding for the Illinois Solar for All Program, as described in subparagraph (O) of this paragraph (1);

(ii) renewable energy credits necessary to comply with the new wind and new photovoltaic procurement requirements described in items (i) through (iii) of subparagraph (C) of this paragraph (1); and

(iii) renewable energy credits necessary to meet the remaining requirements of this subsection (c).

(G) The following provisions shall apply to the Agency's procurement of renewable energy credits under this subsection (c):

(i) Notwithstanding whether a long-term renewable resources procurement plan has been approved, the Agency shall conduct an initial forward procurement for renewable energy credits from new utility-scale wind projects within 160 days after June 1, 2017 (the effective date of Public Act 99-906). For the purposes of this initial forward procurement, the Agency shall solicit 15-year contracts for delivery of 1,000,000 renewable energy credits delivered annually from new utility-scale wind projects to begin delivery on June 1, 2019, if available, but not later than June 1, 2021, unless the project has delays in the establishment of an operating interconnection with the applicable transmission or distribution system as a result of the actions or inactions of the transmission or distribution provider, or other causes for force majeure as outlined in the procurement contract, in which case, not later than June 1, 2022. Payments to suppliers of renewable energy credits shall commence upon delivery. Renewable energy credits procured under this initial procurement shall be included in the Agency's long-term plan and shall apply to all renewable energy goals in this subsection (c).

(ii) Notwithstanding whether a long-term renewable resources procurement plan has been approved, the Agency shall conduct an initial forward procurement for renewable energy credits from new utility-scale solar projects and brownfield site photovoltaic projects within one year after June 1, 2017 (the effective date of Public Act 99-906). For the purposes of this initial forward procurement, the Agency shall solicit 15-year contracts for delivery of 1,000,000 renewable energy credits delivered annually from new utility-scale solar projects and brownfield site photovoltaic projects to begin delivery on June 1, 2019, if available, but not later than June 1, 2021, unless the project has delays in the establishment of an operating interconnection with the applicable transmission or distribution system as a result of the actions or inactions of the transmission or distribution provider, or other causes for force majeure as outlined in the procurement contract, in which case, not later than June 1, 2022. The Agency may structure this initial procurement in one or more discrete procurement events. Payments to suppliers of renewable energy credits shall commence upon delivery. Renewable energy credits procured under this initial procurement shall be included in the Agency's long-term plan and shall apply to all renewable energy goals in this subsection (c).

(iii) Notwithstanding whether the Commission has approved the periodic long-term renewable resources procurement plan revision described in Section 16-111.5 of the Public Utilities Act, the Agency shall conduct at least one subsequent forward procurement for renewable energy credits from new utility-scale wind projects, new utility-scale solar projects, and new brownfield site photovoltaic projects within 240 days after the effective date of this amendatory Act of the 102nd General Assembly in quantities necessary to meet the requirements of subparagraph (C) of this paragraph (1) through the delivery year beginning June 1, 2021.

(iv) Notwithstanding whether the Commission has approved the periodic long-term renewable resources procurement plan revision described in Section 16-111.5 of the Public Utilities Act, the Agency shall open capacity for each category in the Adjustable Block program within 90 days after the effective date of this amendatory Act of the 102nd General Assembly manner:

(1) The Agency shall open the first block of annual capacity for the category described in item (i) of subparagraph (K) of this paragraph (1). The first block of annual capacity for item (i) shall be for at least 75 megawatts of total nameplate capacity. The price of the renewable energy credit for this block of capacity shall be 4% less than the price of the last open block in this category. Projects on a waitlist shall be awarded contracts first in the order in which they appear on the waitlist. Notwithstanding anything to the contrary, for those renewable energy credits that qualify and are procured under this subitem (1) of this item (iv), the renewable energy credit delivery contract value shall be paid in full, based on the estimated generation during the first 15 years of operation, by the contracting utilities at the time that the facility producing the renewable energy credits is interconnected at the distribution system level of the utility and verified as energized and in compliance by the Program Administrator. The electric utility shall receive and retire all renewable energy credits generated by the project for the first 15 years of operation. Renewable energy credits generated by the project thereafter shall not be transferred under the renewable energy credit delivery contract with the counterparty electric utility.

(2) The Agency shall open the first block of annual capacity for the category described in item (ii) of subparagraph (K) of this paragraph (1). The first block of annual capacity for item (ii) shall be for at least 75 megawatts of total nameplate capacity.

(A) The price of the renewable energy credit for any project on a waitlist for this category before the opening of this block shall be 4% less than the price of the last open block in this category. Projects on the waitlist shall be awarded contracts first in the order in which they appear on the waitlist. Any projects that are less than or equal to 25 kilowatts in size on the waitlist for this capacity shall be moved to the waitlist for paragraph (1) of this item (iv). Notwithstanding anything to the contrary, projects that were on the waitlist prior to opening of this block shall not be required to be in compliance with the requirements of subparagraph (Q) of this paragraph (1) of this subsection (c). Notwithstanding anything to the contrary, for those renewable energy credits procured from projects that were on the waitlist for this category before the opening of this block 20% of the renewable energy credit delivery contract value, based on the estimated generation during the first 15 years of operation, shall be paid by the contracting utilities at the time that the facility producing the renewable energy credits is interconnected at the distribution system level of the utility and verified as energized by the Program Administrator. The remaining portion shall be paid ratably over the subsequent 4-year period. The electric utility shall receive and retire all renewable energy credits generated by the project during the first 15 years of operation. Renewable energy credits generated by the project thereafter shall not be transferred under the renewable energy credit delivery contract with the counterparty electric utility.

(B) The price of renewable energy credits for any project not on the waitlist for this category before the opening of the block shall be determined and published by the Agency. Projects not on a waitlist as of the opening of this block shall be subject to the requirements of subparagraph (Q) of this paragraph (1), as applicable. Projects not on a waitlist as of the opening of this block shall be subject to the contract provisions outlined in item (iii) of subparagraph (L) of this paragraph (1). The Agency shall strive to publish updated prices and an updated renewable energy credit delivery contract as quickly as possible.

(3) For opening the first 2 blocks of annual capacity for projects participating in item (iii) of subparagraph (K) of paragraph (1) of subsection (c), projects shall be selected exclusively from those projects on the ordinal waitlists of community renewable generation projects established by the Agency based on the status of those ordinal waitlists as of December 31, 2020, and only those projects previously determined to be eligible for the Agency's April 2019 community solar project selection process.

The first 2 blocks of annual capacity for item (iii) shall be for 250 megawatts of total nameplate capacity, with both blocks opening simultaneously under the schedule outlined in the paragraphs below. Projects shall be selected as follows:

(A) The geographic balance of selected projects shall follow the Group classification found in the Agency's Revised Long-Term Renewable Resources Procurement Plan, with 70% of capacity allocated to projects on the Group B waitlist and 30% of capacity allocated to projects on the Group A waitlist.

(B) Contract awards for waitlisted projects shall be allocated proportionate to the total nameplate capacity amount across both ordinal waitlists associated with that applicant firm or its affiliates, subject to the following conditions.

(i) Each applicant firm having a waitlisted project eligible for selection shall receive no less than 500 kilowatts in awarded capacity across all groups, and no approved vendor may receive more than 20% of each Group's waitlist allocation.

(ii) Each applicant firm, upon receiving an award of program capacity proportionate to its waitlisted capacity, may then determine which waitlisted projects it chooses to be selected for a contract award up to that capacity amount.

(iii) Assuming all other program requirements are met, applicant firms may adjust the nameplate capacity of applicant projects without losing waitlist eligibility, so long as no project is greater than 2,000 kilowatts in size.

(iv) Assuming all other program requirements are met, applicant firms may adjust the expected production associated with applicant projects, subject to verification by the Program Administrator.

(C) After a review of affiliate information and the current ordinal waitlists, the Agency shall announce the nameplate capacity award amounts associated with applicant firms no later than 90 days after the effective date of this amendatory Act of the 102nd General Assembly.

(D) Applicant firms shall submit their portfolio of projects used to satisfy those contract awards no less than 90 days after the Agency's announcement. The total nameplate capacity of all projects used to satisfy that portfolio shall be no greater than the Agency's nameplate capacity award amount associated with that applicant firm. An applicant firm may decline, in whole or in part, its nameplate capacity award without penalty, with such unmet capacity rolled over to the next block opening for project selection under item (iii) of subparagraph (K) of this subsection (c). Any projects not included in an applicant firm's portfolio may reapply without prejudice upon the next block reopening for project selection under item (iii) of subparagraph (K) of this subsection (c).

(E) The renewable energy credit delivery contract shall be subject to the contract and payment terms outlined in item (iv) of subparagraph (L) of this subsection (c). Contract instruments used for this subparagraph shall contain the following terms:

(i) Renewable energy credit prices shall be fixed, without further adjustment under any other provision of this Act or for any other reason, at 10% lower than prices applicable to the last open block for this category, inclusive of any adders available for achieving a minimum of 50% of subscribers to the project's nameplate capacity being residential or small commercial customers with subscriptions of below 25 kilowatts in size;

(ii) A requirement that a minimum of 50% of subscribers to the project's nameplate capacity be residential or small commercial customers with subscriptions of below 25 kilowatts in size;

(iii) Permission for the ability of a contract holder to substitute projects with other waitlisted projects without penalty should a project receive a non-binding estimate of costs to construct the interconnection facilities and any required distribution upgrades associated with that project of greater than 30 cents per watt AC of that project's nameplate capacity. In developing the applicable contract instrument, the Agency may consider whether other circumstances outside of the control of the applicant firm should also warrant project substitution rights.

The Agency shall publish a finalized updated renewable energy credit delivery contract developed consistent with these terms and conditions no less than 30 days before applicant firms must submit their portfolio of projects pursuant to item (D).

(F) To be eligible for an award, the applicant firm shall certify that not less than prevailing wage, as determined pursuant to the Illinois Prevailing Wage Act, was or will be paid to employees who are engaged in construction activities associated with a selected project.

(4) The Agency shall open the first block of annual capacity for the category described in item (iv) of subparagraph (K) of this paragraph (1). The first block of annual capacity for item (iv) shall be for at least 50 megawatts of total nameplate capacity. Renewable energy credit prices shall be fixed, without further adjustment under any other provision of this Act or for any other reason, at the price in the last open block in the category described in item (ii) of subparagraph (K) of this paragraph (1). Pricing for future blocks of annual capacity for this category may be adjusted in the Agency's second revision to its Long-Term Renewable Resources Procurement Plan. Projects in this category shall be subject to the contract terms outlined in item (iv) of subparagraph (L) of this paragraph (1).

(5) The Agency shall open the equivalent of 2 years of annual capacity for the category described in item (v) of subparagraph (K) of this paragraph (1). The first block of annual capacity for item (v) shall be for at least 10 megawatts of total nameplate capacity. Notwithstanding the provisions of item (v) of subparagraph (K) of this paragraph (1), for the purpose of this initial block, the agency shall accept new project applications intended to increase the diversity of areas hosting community solar projects, the business models of projects, and the size of projects, as described by the Agency in its long-term renewable resources procurement plan that is approved as of the effective date of this amendatory Act of the 102nd General Assembly. Projects in this category shall be subject to the contract terms outlined in item (iii) of subsection (L) of this paragraph (1).

(6) The Agency shall open the first blocks of annual capacity for the category described in item (vi) of subparagraph (K) of this paragraph (1), with allocations of capacity within the block generally matching the historical share of block capacity allocated between the category described in items (i) and (ii) of subparagraph (K) of this paragraph (1). The first two blocks of annual capacity for item (vi) shall be for at least 75 megawatts of total nameplate capacity. The price of renewable energy credits for the blocks of capacity shall be 4% less than the price of the last open blocks in the categories described in items (i) and (ii) of subparagraph (K) of this paragraph (1). Pricing for future blocks of annual capacity for this category may be adjusted in the Agency's second revision to its Long-Term Renewable Resources Procurement Plan. Projects in this category shall be subject to the applicable contract terms outlined in items (ii) and (iii) of subparagraph (L) of this paragraph (1).

(v) Upon the effective date of this amendatory Act of the 102nd General Assembly, for all competitive procurements and any procurements of renewable energy credit from new utility-scale wind and new utility-scale photovoltaic projects, the Agency shall procure indexed renewable energy credits and direct respondents to offer a strike price.

(1) The purchase price of the indexed renewable energy credit payment shall be calculated for each settlement period. That payment, for any settlement period, shall be equal to the difference resulting from subtracting the strike price from the index price for that settlement period. If this difference results in a negative number, the indexed REC counterparty shall owe the seller the absolute value multiplied by the quantity of energy produced in the relevant settlement period. If this difference results in a positive number, the seller shall owe the indexed REC counterparty this amount multiplied by the quantity of energy produced in the relevant settlement period.

(2) Parties shall cash settle every month, summing up all settlements (both positive and negative, if applicable) for the prior month.

(3) To ensure funding in the annual budget established under subparagraph (E) for indexed renewable energy credit procurements for each year of the term of such contracts, which must have a minimum tenure of 20 calendar years, the procurement administrator, Agency, Commission staff, and procurement monitor shall quantify the annual cost of the contract by utilizing one or more industry-standard, third-party forward price curves for energy at the appropriate hub or load zone, including the estimated magnitude and timing of the price effects related to federal carbon controls. Each forward price curve shall contain a specific value of the forecasted market price of electricity for each annual delivery year of the contract. For procurement planning purposes, the impact on the annual budget for the cost of indexed renewable energy credits for each delivery year shall be determined as the expected annual contract expenditure for that year, equaling the difference between (i) the sum across all relevant contracts of the applicable strike price multiplied by contract quantity and (ii) the sum across all relevant contracts of the forward price curve for the applicable load zone for that year multiplied by contract quantity. The contracting utility shall not assume an obligation in excess of the estimated annual cost of the contracts for indexed renewable energy credits. Forward curves shall be revised on an annual basis as updated forward price curves are released and filed with the Commission in the proceeding approving the Agency's most recent long-term renewable resources procurement plan. If the expected contract spend is higher or lower than the total quantity of contracts multiplied by the forward price curve value for that year, the forward price curve shall be updated by the procurement administrator, in consultation with the Agency, Commission staff, and procurement monitors, using then-currently available price forecast data and additional budget dollars shall be obligated or reobligated as appropriate.

(4) To ensure that indexed renewable energy credit prices remain predictable and affordable, the Agency may consider the institution of a price collar on REC prices paid under indexed renewable energy credit procurements establishing floor and ceiling REC prices applicable to indexed REC contract prices. Any price collars applicable to indexed REC procurements shall be proposed by the Agency through its long-term renewable resources procurement plan.

(vi) All procurements under this subparagraph (G), including the procurement of renewable energy credits from hydropower facilities, shall comply with the geographic requirements in subparagraph (I) of this paragraph (1) and shall follow the procurement processes and procedures described in this Section and Section 16-111.5 of the Public Utilities Act to the extent practicable, and these processes and procedures may be expedited to accommodate the schedule established by this subparagraph (G). To ensure the successful development of new renewable energy projects supported through competitive procurements, for any procurements conducted under items (i), (ii), (iii), and (v) of this subparagraph (G) and any other procurement of new utility-scale wind or utility-scale solar projects that were entered into prior to January 1, 2025, the Agency shall allow, upon a demonstration of need to ensure the commercial viability of a project, for a one-time, post-award renegotiation of select contract terms prior to the project's commercial operation date through bilateral negotiation between the Agency, the buyer, and a winning bidder. Contract terms subject to renegotiation may include the project map, as defined under the applicable competitive solicitation, the real estate footprint or any limitations thereof, the location of the generators, or a potential reduction in the quantity of renewable energy credits to be delivered. Provisions related to a renewable energy credit delivery shortfall and the event of default may be replaced with similar provisions approved by the Agency in subsequent years or subsequent to a successful bid. Post-award renegotiation of competitively bid renewable energy credit contracts entered into prior to January 1, 2025 shall not be permitted to the extent such renegotiation would result in (1) the point of interconnection being within the service area of a different state, a different regional transmission organization zone, or a different regional transmission organization, (2) the generator no longer meeting the definition of the resource category for which the winning bidder was originally awarded a contract, (3) the generator no longer meeting the Agency's public interest criteria as established in the long-term renewable resources plan in effect at the time of the contract award, or (4) a change to material terms of the renewable energy credit contract unrelated to project land or footprint or the number of renewable energy credits to be delivered, including the applicable bid price or strike price. If the Agency, the buyer, and the winning bidder reach an agreement on amended terms, then, upon petition by the winning bidder or current seller, the Commission shall issue an order directing the utility counterparty to execute an amendment drafted by the Agency with the revised terms to the renewable energy credit contract, the product order, or both. The Agency shall provide the amendment to the utility within 15 business days after the Commission's order, and the utility shall execute the amendment no more than 7 calendar days after delivery by the Agency.

(vii) On and after the effective date of this amendatory Act of the 103rd General Assembly, for all procurements of renewable energy credits from hydropower facilities, the Agency shall establish contract terms designed to optimize existing hydropower facilities through modernization or retooling and establish new hydropower facilities at existing dams. Procurements made under this item (vii) shall prioritize projects located in designated environmental justice communities, as defined in subsection (b) of Section 1-56 of this Act, or in projects located in units of local government with median incomes that do not exceed 82% of the median income of the State.

(H) The procurement of renewable energy resources for a given delivery year shall be reduced as described in this subparagraph (H) if an alternative retail electric supplier meets the requirements described in this subparagraph (H).

(i) Within 45 days after June 1, 2017 (the effective date of Public Act 99-906), an alternative retail electric supplier or its successor shall submit an informational filing to the Illinois Commerce Commission certifying that, as of December 31, 2015, the alternative retail electric supplier owned one or more electric generating facilities that generates renewable energy resources as defined in Section 1-10 of this Act, provided that such facilities are not powered by wind or photovoltaics, and the facilities generate one renewable energy credit for each megawatthour of energy produced from the facility.

The informational filing shall identify each facility that was eligible to satisfy the alternative retail electric supplier's obligations under Section 16-115D of the Public Utilities Act as described in this item (i).

(ii) For a given delivery year, the alternative retail electric supplier may elect to supply its retail customers with renewable energy credits from the facility or facilities described in item (i) of this subparagraph (H) that continue to be owned by the alternative retail electric supplier.

(iii) The alternative retail electric supplier shall notify the Agency and the applicable utility, no later than February 28 of the year preceding the applicable delivery year or 15 days after June 1, 2017 (the effective date of Public Act 99-906), whichever is later, of its election under item (ii) of this subparagraph (H) to supply renewable energy credits to retail customers of the utility. Such election shall identify the amount of renewable energy credits to be supplied by the alternative retail electric supplier to the utility's retail customers and the source of the renewable energy credits identified in the informational filing as described in item (i) of this subparagraph (H), subject to the following limitations:

For the delivery year beginning June 1, 2018, the maximum amount of renewable energy credits to be supplied by an alternative retail electric supplier under this subparagraph (H) shall be 68% multiplied by 25% multiplied by 14.5% multiplied by the amount of metered electricity (megawatt-hours) delivered by the alternative retail electric supplier to Illinois retail customers during the delivery year ending May 31, 2016.

For delivery years beginning June 1, 2019 and each year thereafter, the maximum amount of renewable energy credits to be supplied by an alternative retail electric supplier under this subparagraph (H) shall be 68% multiplied by 50% multiplied by 16% multiplied by the amount of metered electricity (megawatt-hours) delivered by the alternative retail electric supplier to Illinois retail customers during the delivery year ending May 31, 2016, provided that the 16% value shall increase by 1.5% each delivery year thereafter to 25% by the delivery year beginning June 1, 2025, and thereafter the 25% value shall apply to each delivery year.

For each delivery year, the total amount of renewable energy credits supplied by all alternative retail electric suppliers under this subparagraph (H) shall not exceed 9% of the Illinois target renewable energy credit quantity. The Illinois target renewable energy credit quantity for the delivery year beginning June 1, 2018 is 14.5% multiplied by the total amount of metered electricity (megawatt-hours) delivered in the delivery year immediately preceding that delivery year, provided that the 14.5% shall increase by 1.5% each delivery year thereafter to 25% by the delivery year beginning June 1, 2025, and thereafter the 25% value shall apply to each delivery year.

If the requirements set forth in items (i) through (iii) of this subparagraph (H) are met, the charges that would otherwise be applicable to the retail customers of the alternative retail electric supplier under paragraph (6) of this subsection (c) for the applicable delivery year shall be reduced by the ratio of the quantity of renewable energy credits supplied by the alternative retail electric supplier compared to that supplier's target renewable energy credit quantity. The supplier's target renewable energy credit quantity for the delivery year beginning June 1, 2018 is 14.5% multiplied by the total amount of metered electricity (megawatt-hours) delivered by the alternative retail supplier in that delivery year, provided that the 14.5% shall increase by 1.5% each delivery year thereafter to 25% by the delivery year beginning June 1, 2025, and thereafter the 25% value shall apply to each delivery year.

On or before April 1 of each year, the Agency shall annually publish a report on its website that identifies the aggregate amount of renewable energy credits supplied by alternative retail electric suppliers under this subparagraph (H).

(I) The Agency shall design its long-term renewable energy procurement plan to maximize the State's interest in the health, safety, and welfare of its residents, including but not limited to minimizing sulfur dioxide, nitrogen oxide, particulate matter and other pollution that adversely affects public health in this State, increasing fuel and resource diversity in this State, enhancing the reliability and resiliency of the electricity distribution system in this State, meeting goals to limit carbon dioxide emissions under federal or State law, and contributing to a cleaner and healthier environment for the citizens of this State. In order to further these legislative purposes, renewable energy credits shall be eligible to be counted toward the renewable energy requirements of this subsection (c) if they are generated from facilities located in this State. The Agency may qualify renewable energy credits from facilities located in states adjacent to Illinois or renewable energy credits associated with the electricity generated by a utility-scale wind energy facility or utility-scale photovoltaic facility and transmitted by a qualifying direct current project described in subsection (b-5) of Section 8-406 of the Public Utilities Act to a delivery point on the electric transmission grid located in this State or a state adjacent to Illinois, if the generator demonstrates and the Agency determines that the operation of such facility or facilities will help promote the State's interest in the health, safety, and welfare of its residents based on the public interest criteria described above. For the purposes of this Section, renewable resources that are delivered via a high voltage direct current converter station located in Illinois shall be deemed generated in Illinois at the time and location the energy is converted to alternating current by the high voltage direct current converter station if the high voltage direct current transmission line: (i) after the effective date of this amendatory Act of the 102nd General Assembly, was constructed with a project labor agreement; (ii) is capable of transmitting electricity at 525kv; (iii) has an Illinois converter station located and interconnected in the region of the PJM Interconnection, LLC; (iv) does not operate as a public utility; and (v) if the high voltage direct current transmission line was energized after June 1, 2023. To ensure that the public interest criteria are applied to the procurement and given full effect, the Agency's long-term procurement plan shall describe in detail how each public interest factor shall be considered and weighted for facilities located in states adjacent to Illinois.

(J) In order to promote the competitive development of renewable energy resources in furtherance of the State's interest in the health, safety, and welfare of its residents, renewable energy credits shall not be eligible to be counted toward the renewable energy requirements of this subsection (c) if they are sourced from a generating unit whose costs were being recovered through rates regulated by this State or any other state or states on or after January 1, 2017. Each contract executed to purchase renewable energy credits under this subsection (c) shall provide for the contract's termination if the costs of the generating unit supplying the renewable energy credits subsequently begin to be recovered through rates regulated by this State or any other state or states; and each contract shall further provide that, in that event, the supplier of the credits must return 110% of all payments received under the contract. Amounts returned under the requirements of this subparagraph (J) shall be retained by the utility and all of these amounts shall be used for the procurement of additional renewable energy credits from new wind or new photovoltaic resources as defined in this subsection (c). The long-term plan shall provide that these renewable energy credits shall be procured in the next procurement event.

Notwithstanding the limitations of this subparagraph (J), renewable energy credits sourced from generating units that are constructed, purchased, owned, or leased by an electric utility as part of an approved project, program, or pilot under Section 1-56 of this Act shall be eligible to be counted toward the renewable energy requirements of this subsection (c), regardless of how the costs of these units are recovered. As long as a generating unit or an identifiable portion of a generating unit has not had and does not have its costs recovered through rates regulated by this State or any other state, HVDC renewable energy credits associated with that generating unit or identifiable portion thereof shall be eligible to be counted toward the renewable energy requirements of this subsection (c).

(K) The long-term renewable resources procurement plan developed by the Agency in accordance with subparagraph (A) of this paragraph (1) shall include an Adjustable Block program for the procurement of renewable energy credits from new photovoltaic projects that are distributed renewable energy generation devices or new photovoltaic community renewable generation projects. The Adjustable Block program shall be generally designed to provide for the steady, predictable, and sustainable growth of new solar photovoltaic development in Illinois. To this end, the Adjustable Block program shall provide a transparent annual schedule of prices and quantities to enable the photovoltaic market to scale up and for renewable energy credit prices to adjust at a predictable rate over time. The prices set by the Adjustable Block program can be reflected as a set value or as the product of a formula.

The Adjustable Block program shall include for each category of eligible projects for each delivery year: a single block of nameplate capacity, a price for renewable energy credits within that block, and the terms and conditions for securing a spot on a waitlist once the block is fully committed or reserved. Except as outlined below, the waitlist of projects in a given year will carry over to apply to the subsequent year when another block is opened. Only projects energized on or after June 1, 2017 shall be eligible for the Adjustable Block program. For each category for each delivery year the Agency shall determine the amount of generation capacity in each block, and the purchase price for each block, provided that the purchase price provided and the total amount of generation in all blocks for all categories shall be sufficient to meet the goals in this subsection (c). The Agency shall strive to issue a single block sized to provide for stability and market growth. The Agency shall establish program eligibility requirements that ensure that projects that enter the program are sufficiently mature to indicate a demonstrable path to completion. The Agency may periodically review its prior decisions establishing the amount of generation capacity in each block, and the purchase price for each block, and may propose, on an expedited basis, changes to these previously set values, including but not limited to redistributing these amounts and the available funds as necessary and appropriate, subject to Commission approval as part of the periodic plan revision process described in Section 16-111.5 of the Public Utilities Act. The Agency may define different block sizes, purchase prices, or other distinct terms and conditions for projects located in different utility service territories if the Agency deems it necessary to meet the goals in this subsection (c).

The Adjustable Block program shall include the following categories in at least the following amounts:

(i) At least 20% from distributed renewable energy generation devices with a nameplate capacity of no more than 25 kilowatts.

(ii) At least 20% from distributed renewable energy generation devices with a nameplate capacity of more than 25 kilowatts and no more than 5,000 kilowatts. The Agency may create sub-categories within this category to account for the differences between projects for small commercial customers, large commercial customers, and public or non-profit customers. A project shall not be colocated with one or more other distributed renewable energy generation projects if the aggregate nameplate capacity of the projects exceeds 5,000 kilowatts AC. Notwithstanding any other provision of this Section, if 2 or more projects are developed, owned, or controlled by or originate from the same developer or an affiliated developer and the projects serve affiliated loads, the projects shall be colocated if the projects are located on adjacent parcels. If 2 or more projects are developed, owned, or controlled by or originate from the same developer and the projects serve unaffiliated loads, the projects may be colocated if documentation indicates affiliated management and ownership in the pre-development, development, construction, and management of the projects and the projects are located on a single or adjacent parcels. Notwithstanding any subsequent transfer, assignment, or conveyance of ownership or development rights to separate legal entities, the Agency shall consider, in its determination of whether projects are affiliated, evidence that the projects were pre-developed by the same legal entity or an affiliated entity. If the Agency determines the projects are affiliated, the projects shall be treated as colocated for purposes of aggregate nameplate capacity limitations and renewable energy credit pricing adjustments. The Agency shall make exceptions on a case-by-case basis if it is demonstrated that projects on one parcel or projects on adjacent parcels are unaffiliated. For purposes of determining colocation, an approved vendor who submits an application for a distributed renewable energy generation project shall be required to submit an affidavit attesting that the project is not affiliated with any other distributed renewable energy generation project such that, if the 2 projects were deemed colocated, the projects would exceed the 5,000 kilowatts nameplate capacity limitation. The receipt of an affidavit shall not restrict the Agency's ability to investigate and determine whether the project is, in fact, colocated.

For purposes of this item (ii):

"Affiliate" has the meaning given to that term in subitem (3) of item (iii) of this subparagraph (K).

"Colocated" means 2 or more distributed renewable energy generation projects that are located on a single parcel, except for projects where the owner of the applicable retail electric account is confirmed to be unaffiliated and the projects serve distinct electrical loads.

"Control" has the meaning given to that term in subitem (3) of item (iii) of this subparagraph (K).

(iii) At least 30% from photovoltaic community renewable generation projects. Capacity for this category for the first 2 delivery years after the effective date of this amendatory Act of the 102nd General Assembly shall be allocated to waitlist projects as provided in paragraph (3) of item (iv) of subparagraph (G). Starting in the third delivery year after the effective date of this amendatory Act of the 102nd General Assembly or earlier if the Agency determines there is additional capacity needed for to meet previous delivery year requirements, the following shall apply:

(1) the Agency shall select projects on a first-come, first-serve basis, however the Agency may suggest additional methods to prioritize projects that are submitted at the same time;

(2) projects shall have subscriptions of 25 kW or less for at least 50% of the facility's nameplate capacity and the Agency shall price the renewable energy credits with that as a factor;

(3) projects shall not be colocated with one or more other photovoltaic community renewable generation projects such that the aggregate nameplate capacity exceeds 10,000 kilowatts. The total nameplate capacity of colocated projects shall be the sum of the nameplate capacities of the individual projects. For purposes of this subitem (3), separate legal formation of approved vendors, owners, or developers shall not preclude a finding of affiliation by the Agency. Evidence of affiliation may include, but is not limited to, shared personnel, common contractual or financing arrangements, a shared interconnection agreement, distinct interconnection agreements obtained by the same pre-development entity that are subsequently sold to distinct legal entities, familial relationships, or any demonstrable pattern of coordinated action in the pre-development, development, construction, or management of photovoltaic community renewable generation projects.

The Agency shall determine affiliation based on evidence that projects either (i) share a common origin on a parcel that has been subdivided in the 5 years before the date of application or (ii) were pre-developed before the beginning of construction by the same legal entity or an affiliated legal entity. The determination shall be made notwithstanding any subsequent transfer, assignment, or conveyance of ownership or development rights to separate legal entities. If the Agency determines the projects are affiliated, the projects shall be treated as colocated for the purposes of aggregate nameplate capacity limitations and renewable energy credit pricing adjustments. The Agency shall make exceptions to this subitem (3) on a case-by-case basis if it is demonstrated that projects on one parcel or projects on adjacent parcels are unaffiliated.

A parcel shall not be divided into multiple parcels within the 5 years before the submission of a project application. If a parcel is divided within the preceding 5 years, a colocation determination shall be made based on the boundaries of the previous undivided parcel.

For purposes of determining colocation, an approved vendor who submits an application for a community renewable generation project shall be required to submit an affidavit attesting that (i) the parcel on which the project is sited has not been subdivided within the 5 years preceding the project application and (ii) the project is not affiliated with any other community renewable energy project in a manner that would cause the 2 projects, if deemed colocated, to exceed the 10,000 kilowatt nameplate capacity limitation. The receipt of an affidavit shall not restrict the Agency's ability to investigate and determine whether the project is colocated.

Multiple community solar projects sited on distinct structures located on a single parcel shall be considered colocated and must demonstrate that the projects are unaffiliated in order to not be considered colocated. Each colocated project shall receive the renewable energy credit price corresponding to the total, aggregated nameplate capacity of the colocated systems, as determined at the time the second project's application is submitted to the Agency. If the second colocated project has been constructed and placed in service prior to application, and was placed in service more than 2 years after Commission approval of the original project, the colocation pricing adjustment shall not apply, and each project shall receive the standalone renewable energy credit price for its individual capacity.

For purposes of this subitem (3):

"Affiliate" means any other entity that, directly or indirectly through one or more intermediaries, is controlled by or is under common control of the primary entity or a third entity. "Affiliate" includes family members for the purposes of colocation between projects. "Affiliate" does not include entities that have shared sales or revenue-sharing arrangements or common debt and equity financing arrangements.

"Colocated" means 2 or more photovoltaic community renewable generation projects located on a single parcel or adjacent parcels, unless it is demonstrated that the projects are developed by unaffiliated entities.

"Control" means the possession, directly or indirectly, of the power to direct the management and policies of an entity; and

(4) projects greater than 2 MW may not apply until after the approval of the Agency's revised Long-Term Renewable Resources Procurement Plan after the effective date of this amendatory Act of the 102nd General Assembly.

(iv) At least 15% from distributed renewable generation devices or photovoltaic community renewable generation projects installed on public school land. The Agency may create subcategories within this category to account for the differences between project size or location. Projects located within environmental justice communities or within Organizational Units that fall within Tier 1 or Tier 2 shall be given priority. Each of the Agency's periodic updates to its long-term renewable resources procurement plan to incorporate the procurement described in this subparagraph (iv) shall also include the proposed quantities or blocks, pricing, and contract terms applicable to the procurement as indicated herein. In each such update and procurement, the Agency shall set the renewable energy credit price and establish payment terms for the renewable energy credits procured pursuant to this subparagraph (iv) that make it feasible and affordable for public schools to install photovoltaic distributed renewable energy devices on their premises, including, but not limited to, those public schools subject to the prioritization provisions of this subparagraph. For the purposes of this item (iv):

"Environmental Justice Community" shall have the same meaning set forth in the Agency's long-term renewable resources procurement plan;

"Organization Unit", "Tier 1" and "Tier 2" shall have the meanings set for in Section 18-8.15 of the School Code;

"Public schools" shall have the meaning set forth in Section 1-3 of the School Code and includes public institutions of higher education, as defined in the Board of Higher Education Act.

(v) At least 5% from community-driven community solar projects intended to provide more direct and tangible connection and benefits to the communities which they serve or in which they operate and, additionally, to increase the variety of community solar locations, models, and options in Illinois. As part of its long-term renewable resources procurement plan, the Agency shall develop selection criteria for projects participating in this category. Nothing in this Section shall preclude the Agency from creating a selection process that maximizes community ownership and community benefits in selecting projects to receive renewable energy credits. Selection criteria shall include:

(1) community ownership or community wealth-building;

(2) additional direct and indirect community benefit, beyond project participation as a subscriber, including, but not limited to, economic, environmental, social, cultural, and physical benefits;

(3) meaningful involvement in project organization and development by community members or nonprofit organizations or public entities located in or serving the community;

(4) engagement in project operations and management by nonprofit organizations, public entities, or community members; and

(5) whether a project is developed in response to a site-specific RFP developed by community members or a nonprofit organization or public entity located in or serving the community.

Selection criteria may also prioritize projects that:

(1) are developed in collaboration with or to provide complementary opportunities for the Clean Jobs Workforce Network Program, the Illinois Climate Works Preapprenticeship Program, the Returning Residents Clean Jobs Training Program, the Clean Energy Contractor Incubator Program, or the Clean Energy Primes Contractor Accelerator Program;

(2) increase the diversity of locations of community solar projects in Illinois, including by locating in urban areas and population centers;

(3) are located in Equity Investment Eligible Communities;

(4) are not greenfield projects;

(5) serve only local subscribers;

(6) have a nameplate capacity that does not exceed 500 kW;

(7) are developed by an equity eligible contractor; or

(8) otherwise meaningfully advance the goals of providing more direct and tangible connection and benefits to the communities which they serve or in which they operate and increasing the variety of community solar locations, models, and options in Illinois.

For the purposes of this item (v):

"Community" means a social unit in which people come together regularly to effect change; a social unit in which participants are marked by a cooperative spirit, a common purpose, or shared interests or characteristics; or a space understood by its residents to be delineated through geographic boundaries or landmarks.

"Community benefit" means a range of services and activities that provide affirmative, economic, environmental, social, cultural, or physical value to a community; or a mechanism that enables economic development, high-quality employment, and education opportunities for local workers and residents, or formal monitoring and oversight structures such that community members may ensure that those services and activities respond to local knowledge and needs.

"Community ownership" means an arrangement in which an electric generating facility is, or over time will be, in significant part, owned collectively by members of the community to which an electric generating facility provides benefits; members of that community participate in decisions regarding the governance, operation, maintenance, and upgrades of and to that facility; and members of that community benefit from regular use of that facility.

Terms and guidance within these criteria that are not defined in this item (v) shall be defined by the Agency, with stakeholder input, during the development of the Agency's long-term renewable resources procurement plan. The Agency shall develop regular opportunities for projects to submit applications for projects under this category, and develop selection criteria that gives preference to projects that better meet individual criteria as well as projects that address a higher number of criteria.

(vi) At least 10% from distributed renewable energy generation devices, which includes distributed renewable energy devices with a nameplate capacity under 5,000 kilowatts or photovoltaic community renewable generation projects, from applicants that are equity eligible contractors. The Agency may create subcategories within this category to account for the differences between project size and type. The Agency shall propose to increase the percentage in this item (vi) over time to 40% based on factors, including, but not limited to, the number of equity eligible contractors and capacity used in this item (vi) in previous delivery years.

The Agency shall propose a payment structure for contracts executed pursuant to this paragraph under which, upon a demonstration of qualification or need under criteria established by the Agency that is focused on supporting small and emerging businesses and businesses that most acutely face barriers to the access of capital, applicant firms are advanced capital disbursed after contract execution but before the contracted project's energization. The amount or percentage of capital advanced prior to project energization shall be sufficient to both cover any increase in development costs resulting from prevailing wage requirements or project-labor agreements, and designed to overcome barriers in access to capital faced by equity eligible contractors. The amount or percentage of advanced capital may vary by subcategory within this category and by an applicant's demonstration of need, with such levels to be established through the Long-Term Renewable Resources Procurement Plan authorized under subparagraph (A) of paragraph (1) of subsection (c) of this Section and any application requirements or evaluation criteria developed pursuant to the Plan.

Contracts developed featuring capital advanced prior to a project's energization shall feature provisions to ensure both the successful development of applicant projects and the delivery of the renewable energy credits for the full term of the contract, including ongoing collateral requirements and other provisions deemed necessary by the Agency, and may include energization timelines longer than for comparable project types. The percentage or amount of capital advanced prior to project energization shall not operate to increase the overall contract value, however contracts executed under this subparagraph may feature renewable energy credit prices higher than those offered to similar projects participating in other categories. Capital advanced prior to energization shall serve to reduce the ratable payments made after energization under items (ii) and (iii) of subparagraph (L) or payments made for each renewable energy credit delivery under item (iv) of subparagraph (L).

For projects developed under this item (vi), the Agency shall take steps to encourage higher portions of contract value to be provided to equity eligible contractors and to support equity eligible persons who participate in this Program and who exercise control and actively manage their businesses and their businesses' contractual projects. These steps may include, but are not limited to, differentiated REC prices, exceptions or exemptions, and other mechanisms and requirements for nonnominal contract value to be provided to equity eligible contractors and equity eligible persons as a prerequisite to Program participation. Any steps taken shall aim to encourage and grow the meaningful participation of equity eligible contractors in this State's clean energy economy. All entities participating under this item (vi) shall comply with the minimum equity standard set forth under Section 1-75.

(vii) The remaining capacity shall be allocated by the Agency in order to respond to market demand. The Agency shall allocate any discretionary capacity prior to the beginning of each delivery year.

(viii) The Agency, through its long-term renewable resources procurement plan, may implement solutions to maintain stable and consistent REC offerings allocated to systems described in item (i) of this subparagraph (K) to avoid gaps in availability during a delivery year, including, but not limited to, creating a floating block of REC capacity in a given delivery year.

To the extent there is uncontracted capacity from any block in any of categories (i) through (vi) at the end of a delivery year, the Agency shall redistribute that capacity to one or more other categories giving priority to categories with projects on a waitlist. The redistributed capacity shall be added to the annual capacity in the subsequent delivery year, and the price for renewable energy credits shall be the price for the new delivery year. Redistributed capacity shall not be considered redistributed when determining whether the goals in this subsection (K) have been met.

Notwithstanding anything to the contrary, as the Agency increases the capacity in item (vi) to 40% over time, the Agency may reduce the capacity of items (i) through (v) proportionate to the capacity of the categories of projects in item (vi), to achieve a balance of project types.

The Adjustable Block program shall be designed to ensure that renewable energy credits are procured from projects in diverse locations and are not concentrated in a few regional areas.

(L) Notwithstanding provisions for advancing capital prior to project energization found in item (vi) of subparagraph (K), the procurement of photovoltaic renewable energy credits under items (i) through (vi) of subparagraph (K) of this paragraph (1) shall otherwise be subject to the following contract and payment terms:

(i) (Blank).

(ii) Unless otherwise provided for in the Agency's approved long-term plan, for those renewable energy credits that qualify and are procured under item (i) of subparagraph (K) of this paragraph (1), and any similar category projects that are procured under item (vi) of subparagraph (K) of this paragraph (1) that qualify and are procured under item (vi), the contract length shall be 15 years. Beginning on the effective date of this amendatory Act of the 104th General Assembly, and including the remainder of program year 2026-2027, 50% of the renewable energy credit delivery contract value, based on the estimated generation during the first 15 years of operation, shall be paid by the contracting utilities at the time that the facility producing the renewable energy credits is interconnected at the distribution system level of the utility and verified as energized and compliant by the Program Administrator. The remaining portion of the renewable energy credit delivery contract value shall be paid ratably over the subsequent 6-year period. Relative to a contract structure under which the full renewable energy credit delivery contract value shall be paid in full at the time of interconnection and verification of energization, the Agency shall consider the impact of deferred payments across the subsequent payment period when establishing renewable energy credit prices. The electric utility shall receive and retire all renewable energy credits generated by the project for the first 15 years of operation. Renewable energy credits generated by the project thereafter shall not be transferred under the renewable energy credit delivery contract with the counterparty electric utility.

(iii) Unless otherwise provided for in the Agency's approved long-term plan, for those renewable energy credits that qualify and are procured under item (ii) and (v) of subparagraph (K) of this paragraph (1) and any like projects that qualify and are procured under items (iv) and (vi), the contract length shall be 15 years. 15% of the renewable energy credit delivery contract value, based on the estimated generation during the first 15 years of operation, shall be paid by the contracting utilities at the time that the facility producing the renewable energy credits is interconnected at the distribution system level of the utility and verified as energized and compliant by the Program Administrator. The remaining portion shall be paid ratably over the subsequent 6-year period. The electric utility shall receive and retire all renewable energy credits generated by the project for the first 15 years of operation. Renewable energy credits generated by the project thereafter shall not be transferred under the renewable energy credit delivery contract with the counterparty electric utility.

(iv) Unless otherwise provided for in the Agency's approved long-term plan, for those renewable energy credits that qualify and are procured under item (iii) of subparagraph (K) of this paragraph (1), and any like projects that qualify and are procured under items (iv) and (vi), the renewable energy credit delivery contract length shall be 20 years and shall be paid over the delivery term, not to exceed during each delivery year the contract price multiplied by the estimated annual renewable energy credit generation amount. If generation of renewable energy credits during a delivery year exceeds the estimated annual generation amount, the excess renewable energy credits shall be carried forward to future delivery years and shall not expire during the delivery term. If generation of renewable energy credits during a delivery year, including carried forward excess renewable energy credits, if any, is less than the estimated annual generation amount, payments during such delivery year will not exceed the quantity generated plus the quantity carried forward multiplied by the contract price. The electric utility shall receive all renewable energy credits generated by the project during the first 20 years of operation and retire all renewable energy credits paid for under this item (iv) and return at the end of the delivery term all renewable energy credits that were not paid for. Renewable energy credits generated by the project thereafter shall not be transferred under the renewable energy credit delivery contract with the counterparty electric utility. Notwithstanding the preceding, for those projects participating under item (iii) of subparagraph (K), the contract price for a delivery year shall be based on subscription levels as measured on the higher of the first business day of the delivery year or the first business day 6 months after the first business day of the delivery year. Subscription of 90% of nameplate capacity or greater shall be deemed to be fully subscribed for the purposes of this item (iv). For projects receiving a 20-year delivery contract, REC prices shall be adjusted downward for consistency with the incentive levels previously determined to be necessary to support projects under 15-year delivery contracts, taking into consideration any additional new requirements placed on the projects, including, but not limited to, labor standards.

(v) Each contract shall include provisions to ensure the delivery of the estimated quantity of renewable energy credits and ongoing collateral requirements and other provisions deemed appropriate by the Agency.

(vi) The utility shall be the counterparty to the contracts executed under this subparagraph (L) that are approved by the Commission under the process described in Section 16-111.5 of the Public Utilities Act. No contract shall be executed for an amount that is less than one renewable energy credit per year.

(vii) If, at any time, approved applications for the Adjustable Block program exceed funds collected by the electric utility or would cause the Agency to exceed the limitation described in subparagraph (E) of this paragraph (1) on the amount of renewable energy resources that may be procured, then the Agency may consider future uncommitted funds to be reserved for these contracts on a first-come, first-served basis.

(viii) Nothing in this Section shall require the utility to advance any payment or pay any amounts that exceed the actual amount of revenues anticipated to be collected by the utility under paragraph (6) of this subsection (c) and subsection (k) of Section 16-108 of the Public Utilities Act inclusive of eligible funds collected in prior years and alternative compliance payments for use by the utility.

(ix) Notwithstanding other requirements of this subparagraph (L), no modification shall be required to Adjustable Block program contracts if they were already executed prior to the establishment, approval, and implementation of new contract forms as a result of this amendatory Act of the 102nd General Assembly.

(x) Contracts may be assignable, but only to entities first deemed by the Agency to have met program terms and requirements applicable to direct program participation. In developing contracts for the delivery of renewable energy credits, the Agency shall be permitted to establish fees applicable to each contract assignment.

(M) The Agency shall be authorized to retain one or more experts or expert consulting firms to develop, administer, implement, operate, and evaluate the Adjustable Block program described in subparagraph (K) of this paragraph (1), as well as the Geothermal Homes and Businesses Program described in subparagraph (S) of this paragraph (1), and the Agency shall retain the consultant or consultants in the same manner, to the extent practicable, as the Agency retains others to administer provisions of this Act, including, but not limited to, the procurement administrator. The selection of experts and expert consulting firms and the procurement process described in this subparagraph (M) are exempt from the requirements of Section 20-10 of the Illinois Procurement Code, under Section 20-10 of that Code. The Agency shall strive to minimize administrative expenses in the implementation of the Adjustable Block program.

The Program Administrator may charge application fees to participating firms to cover the cost of program administration. Any application fee amounts shall initially be determined through the long-term renewable resources procurement plan, and modifications to any application fee that deviate more than 25% from the Commission's approved value must be approved by the Commission as a long-term plan revision under Section 16-111.5 of the Public Utilities Act. The Agency shall consider stakeholder feedback when making adjustments to application fees and shall notify stakeholders in advance of any planned changes.

In addition to covering the costs of program administration, the Agency, in conjunction with its Program Administrator, may also use the proceeds of such fees charged to participating firms to support public education and ongoing regional and national coordination with nonprofit organizations, public bodies, and others engaged in the implementation of renewable energy incentive programs or similar initiatives. This work may include developing papers and reports, hosting regional and national conferences, and other work deemed necessary by the Agency to position the State of Illinois as a national leader in renewable energy incentive program development and administration.

The Agency and its consultant or consultants shall monitor block activity, share program activity with stakeholders and conduct quarterly meetings to discuss program activity and market conditions. If necessary, the Agency may make prospective administrative adjustments to the Adjustable Block program and the Geothermal Homes and Businesses Program design, such as making adjustments to purchase prices as necessary to achieve the goals of this subsection (c). Program modifications to any block price that do not deviate from the Commission's approved value by more than 10% shall take effect immediately and are not subject to Commission review and approval. Program modifications to any block price that deviate more than 10% from the Commission's approved value must be approved by the Commission as a long-term plan amendment under Section 16-111.5 of the Public Utilities Act. The Agency shall consider stakeholder feedback when making adjustments to the Adjustable Block and the Geothermal Homes and Businesses Program design and shall notify stakeholders in advance of any planned changes.

The Agency and its program administrators for the Adjustable Block program, the Illinois Solar for All Program, and the Geothermal Homes and Businesses Program consistent with the requirements of this subsection (c) and subsection (b) of Section 1-56 of this Act, shall propose the Adjustable Block program terms, conditions, and requirements, including the prices to be paid for renewable energy credits, where applicable, and requirements applicable to participating entities and project applications, through the development, review, and approval of the Agency's long-term renewable resources procurement plan described in this subsection (c) and paragraph (5) of subsection (b) of Section 16-111.5 of the Public Utilities Act. Terms, conditions, and requirements for program participation shall include the following:

(i) The Agency shall establish a registration process for entities seeking to qualify for program-administered incentive funding and establish baseline qualifications for vendor approval. The Agency shall also establish program requirements and minimum contract terms for vendors and others involved in the marketing, sale, installation, and financing of distributed generation systems and community solar subscriptions to prevent misleading marketing and abusive practices and to otherwise protect customers. The Agency must maintain a list of approved entities on each program's website, and may revoke a vendor's ability to receive program-administered incentive funding status upon a determination that the vendor failed to comply with contract terms, the law, or other program requirements.

(ii) The Agency shall establish program requirements and minimum contract terms to ensure projects are properly installed and produce their expected amounts of energy. Program requirements may include on-site inspections and photo documentation of projects under construction. The Agency may require repairs, alterations, or additions to remedy any material deficiencies discovered. Vendors who have a disproportionately high number of deficient systems may lose their eligibility to continue to receive State-administered incentive funding through Agency programs and procurements.

(iii) To discourage deceptive marketing or other bad faith business practices, the Agency may require direct program participants, including agents operating on their behalf, to provide standardized disclosures to a customer prior to that customer's execution of a contract for the development of a distributed generation system, a subscription to a community solar project, or the development of a geothermal heating and cooling system.

(iv) The Agency shall establish one or multiple Consumer Complaints Centers to accept complaints regarding businesses that participate in, or otherwise benefit from, State-administered incentive funding through Agency-administered programs. The Agency shall maintain a public database of complaints with any confidential or particularly sensitive information redacted from public entries.

(v) Through a filing in the proceeding for the approval of its long-term renewable energy resources procurement plan, the Agency shall provide an annual written report to the Illinois Commerce Commission documenting the frequency and nature of complaints and any enforcement actions taken in response to those complaints.

(vi) The Agency shall schedule regular meetings with representatives of the Office of the Attorney General, the Illinois Commerce Commission, consumer protection groups, and other interested stakeholders to share relevant information about consumer protection, project compliance, and complaints received.

(vii) To the extent that complaints received implicate the jurisdiction of the Office of the Attorney General, the Illinois Commerce Commission, or local, State, or federal law enforcement, the Agency shall also refer complaints to those entities as appropriate.

(viii) The Agency may, at its discretion, establish a registration process for entities, or a subset of entities, that provide financing for consumers for the purchase of distributed renewable generation devices. The Agency may establish baseline qualifications for financing entity approval, including defining the circumstances under which financing entities may be subject to registration. The Agency may also establish program requirements for entities that provide financing for the purchase of distributed renewable generation devices, which may include marketing and disclosure requirements, other requirements as further defined by the Agency through its long-term plan, and any consumer protection requirements developed or modified thereto. If the Agency establishes a registration process for financing entities, the Agency may revoke a financing entity's approval in a program upon a determination that the financing entity failed to comply with contract terms, the law, or other program requirements. The Agency may also establish program requirements that prohibit distributed renewable generation devices intending to apply for program-administered incentive funding from receiving program funding if the consumer's purchase of the device was financed by an entity whose approval status in the program has been revoked. These registration requirements may apply to entities that finance projects intended to apply for program-administered incentive funding even if those entities do not receive any portion of the program-administered incentive funding.

(ix) The Agency, at its discretion, may require that vendors, as part of the application and annual recertification process, present the Agency or its designee with a security bond equal to an amount determined to be reasonable by the Agency. The bond shall be for the benefit of customers harmed by the vendor's violation of Agency requirements or other applicable laws or regulations. The Agency may determine that it is reasonable to have no bond requirement for some categories of vendors or enhanced bond requirements for vendors that the Agency has deemed to pose more acute risks.

(x) For distributed renewable generation devices, the Agency may, in its discretion, establish provisions that restrict, prohibit, or create additional requirements for distributed renewable generation device sales or financing offers through which the customer is promised the pass-through of a portion or all of the payments received by the approved vendor for the delivery of renewable energy credits only after the receipt of such payment by the approved vendor. The requirements may include the use of an escrow process developed by the Agency through which renewable energy credit payments are made to an escrow agent who then disburses the promised amount to the customer and the remainder to the vendor. The requirements in this item (x) shall in no way prohibit the upfront discounting of the purchase price, lease payment, or power purchase agreement rate based on the anticipated receipt of renewable energy credit contract payments by the approved vendor.

(xi) To the extent that distributed renewable generation device sales or financing offers through which the customer is promised the pass-through of a portion or all of the payments received by the vendor for the delivery of renewable energy credits after the receipt of such payment by the vendor are permitted, the following requirements may be implemented, at the Agency's discretion, in a time and manner determined by the Agency:

(I) the vendor shall submit proof of customer payments to the Agency as the Agency deems necessary; and

(II) the vendor shall represent and warrant on a form developed by the Agency that the vendor is not insolvent, has not voluntarily filed for bankruptcy, and has not been subject to or threatened with involuntary insolvency.

(xii) To ensure that customers receive full and uninterrupted benefits and services promised by vendors, the Agency may propose additional solutions through its long-term renewable resources procurement plan described in this subsection (c) and paragraph (5) of subsection (b) of Section 16-111.5 of the Public Utilities Act. The solutions may allow for collections made pursuant to subsection (k) of Section 16-108 of the Public Utilities Act to support the programs and procurements outlined in paragraph (1) of subsection (c) of this Section to be leveraged to (1) ensure that a vendor's promised payments are received by customers, (2) incentivize vendors to establish service agreements with customers whose original vendor has become nonresponsive, (3) ensure that customers receive restitution for financial harm proven to be caused by a program vendor or its designee, or (4) otherwise ensure that customers do not suffer loss or harm through activities supported by the Adjustable Block program and the Illinois Solar for All Program.

(N) The Agency shall establish the terms, conditions, and program requirements for photovoltaic community renewable generation projects with a goal to expand access to a broader group of energy consumers, to ensure robust participation opportunities for residential and small commercial customers and those who cannot install renewable energy on their own properties. Subject to reasonable limitations, any plan approved by the Commission shall allow subscriptions to community renewable generation projects to be portable and transferable. For purposes of this subparagraph (N), "portable" means that subscriptions may be retained by the subscriber even if the subscriber relocates or changes its address within the same utility service territory; and "transferable" means that a subscriber may assign or sell subscriptions to another person within the same utility service territory.

Through the development of its long-term renewable resources procurement plan, the Agency may consider whether community renewable generation projects utilizing technologies other than photovoltaics should be supported through State-administered incentive funding, and may issue requests for information to gauge market demand.

Electric utilities shall provide a monetary credit to a subscriber's subsequent bill for service for the proportional output of a community renewable generation project attributable to that subscriber as specified in Section 16-107.5 of the Public Utilities Act.

The Agency shall purchase renewable energy credits from subscribed shares of photovoltaic community renewable generation projects through the Adjustable Block program described in subparagraph (K) of this paragraph (1) or through the Illinois Solar for All Program described in Section 1-56 of this Act. The electric utility shall purchase any unsubscribed energy from community renewable generation projects that are Qualifying Facilities ("QF") under the electric utility's tariff for purchasing the output from QFs under Public Utilities Regulatory Policies Act of 1978.

The owners of and any subscribers to a community renewable generation project shall not be considered public utilities or alternative retail electricity suppliers under the Public Utilities Act solely as a result of their interest in or subscription to a community renewable generation project and shall not be required to become an alternative retail electric supplier by participating in a community renewable generation project with a public utility.

(O) For the delivery year beginning June 1, 2018, the long-term renewable resources procurement plan required by this subsection (c) shall provide for the Agency to procure contracts to continue offering the Illinois Solar for All Program described in subsection (b) of Section 1-56 of this Act, and the contracts approved by the Commission shall be executed by the utilities that are subject to this subsection (c). The long-term renewable resources procurement plan shall allocate up to $50,000,000 per delivery year to fund the programs, and the plan shall determine the amount of funding to be apportioned to the programs identified in subsection (b) of Section 1-56 of this Act; provided that for the delivery years beginning June 1, 2021, June 1, 2022, and June 1, 2023, the long-term renewable resources procurement plan may average the annual budgets over a 3-year period to account for program ramp-up. For the delivery years beginning June 1, 2021, June 1, 2024, June 1, 2027, and June 1, 2030 and additional $10,000,000 shall be provided to the Department of Commerce and Economic Opportunity to implement the workforce development programs and reporting as outlined in Section 16-108.12 of the Public Utilities Act. In making the determinations required under this subparagraph (O), the Commission shall consider the experience and performance under the programs and any evaluation reports. The Commission shall also provide for an independent evaluation of those programs on a periodic basis that are funded under this subparagraph (O).

(P) All programs and procurements under this subsection (c) shall be designed to encourage participating projects to use a diverse and equitable workforce and a diverse set of contractors, including minority-owned businesses, disadvantaged businesses, trade unions, graduates of any workforce training programs administered under this Act, and small businesses.

The Agency shall develop a method to optimize procurement of renewable energy credits from proposed utility-scale projects that are located in communities eligible to receive Energy Transition Community Grants pursuant to Section 10-20 of the Energy Community Reinvestment Act. If this requirement conflicts with other provisions of law or the Agency determines that full compliance with the requirements of this subparagraph (P) would be unreasonably costly or administratively impractical, the Agency is to propose alternative approaches to achieve development of renewable energy resources in communities eligible to receive Energy Transition Community Grants pursuant to Section 10-20 of the Energy Community Reinvestment Act or seek an exemption from this requirement from the Commission.

(Q) Each facility listed in subitems (i) through (ix) of item (1) of this subparagraph (Q) for which a renewable energy credit delivery contract is signed after the effective date of this amendatory Act of the 102nd General Assembly is subject to the following requirements through the Agency's long-term renewable resources procurement plan:

(1) Each facility shall be subject to the prevailing wage requirements included in the Prevailing Wage Act. The Agency shall require verification that all construction performed on the facility by the renewable energy credit delivery contract holder, its contractors, or its subcontractors relating to construction of the facility is performed by construction employees receiving an amount for that work equal to or greater than the general prevailing rate, as that term is defined in Section 2 of the Prevailing Wage Act. For purposes of this item (1), "house of worship" means property that is both (1) used exclusively by a religious society or body of persons as a place for religious exercise or religious worship and (2) recognized as exempt from taxation pursuant to Section 15-40 of the Property Tax Code. This item (1) shall apply to any of the following:

(i) all new utility-scale wind projects;

(ii) all new utility-scale photovoltaic projects and repowered wind projects;

(iii) all new brownfield photovoltaic projects;

(iv) all new photovoltaic community renewable energy facilities that qualify for item (iii) of subparagraph (K) of this paragraph (1);

(v) all new community driven community photovoltaic projects that qualify for item (v) of subparagraph (K) of this paragraph (1);

(vi) all new photovoltaic projects on public school land that qualify for item (iv) of subparagraph (K) of this paragraph (1);

(vii) all new photovoltaic distributed renewable energy generation devices that (1) qualify for item (i) of subparagraph (K) of this paragraph (1); (2) are not projects that serve single-family or multi-family residential buildings; and (3) are not houses of worship where the aggregate capacity including colocated projects would not exceed 100 kilowatts;

(viii) all new photovoltaic distributed renewable energy generation devices that (1) qualify for item (ii) of subparagraph (K) of this paragraph (1); (2) are not projects that serve single-family or multi-family residential buildings; and (3) are not houses of worship where the aggregate capacity including colocated projects would not exceed 100 kilowatts;

(ix) all new, modernized, or retooled hydropower facilities;

(x) all new geothermal heating and cooling systems awarded through the Geothermal Homes and Businesses Program under subparagraph (S) of this paragraph (1) that do not serve (1) single-family residential buildings, (2) multi-family residential buildings with aggregate geothermal system tonnage, including colocated projects, of no more than 29 tons, or (3) houses of worship with aggregate geothermal system tonnage, including colocated projects, of no more than 29 tons.

(2) Renewable energy credits procured from new utility-scale wind projects, new utility-scale solar projects, new brownfield solar projects, repowered wind projects, and retooled hydropower facilities pursuant to Agency procurement events occurring after the effective date of this amendatory Act of the 102nd General Assembly and photovoltaic community renewable generation projects where the aggregate capacity, including colocated projects, exceeds 3,000 kilowatts pursuant to a renewable energy credit delivery contract approved by the Illinois Commerce Commission under the Adjustable Block Program after the effective date of this amendatory Act of the 104th General Assembly must be from facilities built by general contractors that must enter into a project labor agreement, as defined by this Act, prior to construction. Photovoltaic community renewable generation projects on a program waitlist as of the effective date of this amendatory Act of the 104th General Assembly awarded capacity for the program year commencing June 1, 2026 or any program year thereafter shall not be exempt from the project labor agreement requirements of this item (2). The project labor agreement shall be filed with the Director in accordance with procedures established by the Agency through its long-term renewable resources procurement plan. Any information submitted to the Agency in this item (2) shall be considered commercially sensitive information. At a minimum, the project labor agreement must provide the names, addresses, and occupations of the owner of the plant and the individuals representing the labor organization employees participating in the project labor agreement consistent with the Project Labor Agreements Act. The agreement must also specify the terms and conditions as defined by this Act.

(2.5) Energy storage credits procured from battery storage projects pursuant to Agency procurement events and additional energy storage resources procured in accordance with subparagraph (B) of paragraph (3) of subsection (d-20) of this Section pursuant to Agency procurement events occurring after the effective date of this amendatory Act of the 104th General Assembly must be from facilities built by general contractors that must enter into a project labor agreement prior to construction. The project labor agreement shall be filed with the Director in accordance with procedures established by the Agency through its long-term renewable resources procurement plan. Any information submitted to the Agency pursuant to this item (2.5) shall be considered commercially sensitive information. At a minimum, the project labor agreement must provide the names, addresses, and occupations of the owner of the plant and the individuals representing the labor organization employees participating in the project labor agreement consistent with the Project Labor Agreements Act. The agreement must also specify the terms and conditions, as defined by this Act.

(3) It is the intent of this Section to ensure that economic development occurs across Illinois communities, that emerging businesses may grow, and that there is improved access to the clean energy economy by persons who have greater economic burdens to success. The Agency shall take into consideration the unique cost of compliance of this subparagraph (Q) that might be borne by equity eligible contractors, shall include such costs when determining the price of renewable energy credits in the Adjustable Block program and the Geothermal Homes and Businesses Program, and shall take such costs into consideration in a nondiscriminatory manner when comparing bids for competitive procurements. The Agency shall consider costs associated with compliance whether in the development, financing, or construction of projects. The Agency shall periodically review the assumptions in these costs and may adjust prices, in compliance with subparagraph (M) of this paragraph (1).

(R) In its long-term renewable resources procurement plan, the Agency shall establish a self-direct renewable portfolio standard compliance program for eligible self-direct customers that purchase renewable energy credits from utility-scale wind and solar projects through long-term agreements for purchase of renewable energy credits as described in this Section. Such long-term agreements may include the purchase of energy or other products on a physical or financial basis and may involve an alternative retail electric supplier as defined in Section 16-102 of the Public Utilities Act. This program shall take effect in the delivery year commencing June 1, 2023.

(1) For the purposes of this subparagraph:

"Eligible self-direct customer" means any retail customers of an electric utility that serves 3,000,000 or more retail customers in the State and whose total highest 30-minute demand was more than 10,000 kilowatts, or any retail customers of an electric utility that serves less than 3,000,000 retail customers but more than 500,000 retail customers in the State and whose total highest 15-minute demand was more than 10,000 kilowatts.

"Retail customer" has the meaning set forth in Section 16-102 of the Public Utilities Act and multiple retail customer accounts under the same corporate parent may aggregate their account demands to meet the 10,000 kilowatt threshold. The criteria for determining whether this subparagraph is applicable to a retail customer shall be based on the 12 consecutive billing periods prior to the start of the year in which the application is filed.

(2) For renewable energy credits to count toward the self-direct renewable portfolio standard compliance program, they must:

(i) qualify as renewable energy credits as defined in Section 1-10 of this Act;

(ii) be sourced from one or more renewable energy generating facilities that comply with the geographic requirements as set forth in subparagraph (I) of paragraph (1) of subsection (c) as interpreted through the Agency's long-term renewable resources procurement plan, or, where applicable, the geographic requirements that governed utility-scale renewable energy credits at the time the eligible self-direct customer entered into the applicable renewable energy credit purchase agreement;

(iii) be procured through long-term contracts with term lengths of at least 10 years either directly with the renewable energy generating facility or through a bundled power purchase agreement, a virtual power purchase agreement, an agreement between the renewable generating facility, an alternative retail electric supplier, and the customer, or such other structure as is permissible under this subparagraph (R);

(iv) be equivalent in volume to at least 40% of the eligible self-direct customer's usage, determined annually by the eligible self-direct customer's usage during the previous delivery year, measured to the nearest megawatt-hour;

(v) be retired by or on behalf of the large energy customer;

(vi) be sourced from new utility-scale wind projects or new utility-scale solar projects; and

(vii) if the contracts for renewable energy credits are entered into after the effective date of this amendatory Act of the 102nd General Assembly, the new utility-scale wind projects or new utility-scale solar projects must comply with the requirements established in subparagraphs (P) and (Q) of paragraph (1) of this subsection (c) and subsection (c-10).

(3) The self-direct renewable portfolio standard compliance program shall be designed to allow eligible self-direct customers to procure new renewable energy credits from new utility-scale wind projects or new utility-scale photovoltaic projects. The Agency shall annually determine the amount of utility-scale renewable energy credits it will include each year from the self-direct renewable portfolio standard compliance program, subject to receiving qualifying applications. In making this determination, the Agency shall evaluate publicly available analyses and studies of the potential market size for utility-scale renewable energy long-term purchase agreements by commercial and industrial energy customers and make that report publicly available. If demand for participation in the self-direct renewable portfolio standard compliance program exceeds availability, the Agency shall ensure participation is evenly split between commercial and industrial users to the extent there is sufficient demand from both customer classes. Each renewable energy credit procured pursuant to this subparagraph (R) by a self-direct customer shall reduce the total volume of renewable energy credits the Agency is otherwise required to procure from new utility-scale projects pursuant to subparagraph (C) of paragraph (1) of this subsection (c) on behalf of contracting utilities where the eligible self-direct customer is located. The self-direct customer shall file an annual compliance report with the Agency pursuant to terms established by the Agency through its long-term renewable resources procurement plan to be eligible for participation in this program. Customers must provide the Agency with their most recent electricity billing statements or other information deemed necessary by the Agency to demonstrate they are an eligible self-direct customer.

(4) The Commission shall approve a reduction in the volumetric charges collected pursuant to Section 16-108 of the Public Utilities Act for approved eligible self-direct customers equivalent to the anticipated cost of renewable energy credit deliveries under contracts for new utility-scale wind and new utility-scale solar entered for each delivery year after the large energy customer begins retiring eligible new utility-scale renewable energy credits for self-compliance. The self-direct credit amount shall be determined annually and is equal to the estimated portion of the cost authorized by subparagraph (E) of paragraph (1) of this subsection (c) that supported the annual procurement of utility-scale renewable energy credits in the prior delivery year using a methodology described in the long-term renewable resources procurement plan, expressed on a per kilowatthour basis, and does not include (i) costs associated with any contracts entered into before the delivery year in which the customer files the initial compliance report to be eligible for participation in the self-direct program, and (ii) costs associated with procuring renewable energy credits through existing and future contracts through the Adjustable Block Program, subsection (c-5) of this Section 1-75, and the Solar for All Program. The Agency shall assist the Commission in determining the current and future costs. The Agency must determine the self-direct credit amount for new and existing eligible self-direct customers and submit this to the Commission in an annual compliance filing. The Commission must approve the self-direct credit amount by June 1, 2023 and June 1 of each delivery year thereafter.

(5) Customers described in this subparagraph (R) shall apply, on a form developed by the Agency, to the Agency to be designated as a self-direct eligible customer. Once the Agency determines that a self-direct customer is eligible for participation in the program, the self-direct customer will remain eligible until the end of the term of the contract. Thereafter, application may be made not less than 12 months before the filing date of the long-term renewable resources procurement plan described in this Act. At a minimum, such application shall contain the following:

(i) the customer's certification that, at the time of the customer's application, the customer qualifies to be a self-direct eligible customer, including documents demonstrating that qualification;

(ii) the customer's certification that the customer has entered into or will enter into by the beginning of the applicable procurement year, one or more bilateral contracts for new wind projects or new photovoltaic projects, including supporting documentation;

(iii) certification that the contract or contracts for new renewable energy resources are long-term contracts with term lengths of at least 10 years, including supporting documentation;

(iv) certification of the quantities of renewable energy credits that the customer will purchase each year under such contract or contracts, including supporting documentation;

(v) proof that the contract is sufficient to produce renewable energy credits to be equivalent in volume to at least 40% of the large energy customer's usage from the previous delivery year, measured to the nearest megawatt-hour; and

(vi) certification that the customer intends to maintain the contract for the duration of the length of the contract.

(6) If a customer receives the self-direct credit but fails to properly procure and retire renewable energy credits as required under this subparagraph (R), the Commission, on petition from the Agency and after notice and hearing, may direct such customer's utility to recover the cost of the wrongfully received self-direct credits plus interest through an adder to charges assessed pursuant to Section 16-108 of the Public Utilities Act. Self-direct customers who knowingly fail to properly procure and retire renewable energy credits and do not notify the Agency are ineligible for continued participation in the self-direct renewable portfolio standard compliance program.

(R-5) In recognition of the market and electricity system impacts, including rising capacity and electricity prices, and potential reliability and resource adequacy concerns inherent in interconnecting new large load retail customers without developing corresponding new clean energy supply, beginning on the effective date of this amendatory Act of the 104th General Assembly, all customers taking service under the hyperscale data center tariff described in Section 16-105.8 of the Public Utilities Act shall be eligible for the hyperscale data center self-direct program described in this subparagraph (R-5). The hyperscale data center self-direct program shall allow for hyperscale data centers to receive a reduction in the charges collected for the procurement of renewable energy resources pursuant to Section 16-108 of the Public Utilities Act in recognition of that customer's contribution to the successful facilitation of the development of new, additive, clean energy generation. The reduction in charges available to the customer shall increase based on the energy or capacity value of the new, additive clean energy generation's contribution using the following formula:

(1) For a generating facility to qualify to contribute to the self-direct crediting rate, the generating facility must meet the following criteria:

(i) The facility must meet the definition of clean energy under Section 1-10, and the facility must sequester or avoid at least 90% of the total carbon dioxide emissions that a similar generating facility would otherwise emit or qualify as an energy storage system as defined in Section 1-10.

(ii) The facility must constitute new, deliverable clean energy generation facilitated by the applicant customer with the following requirements:

(1) New, deliverable generation successfully facilitated at an existing generating facility may qualify under this item (ii), but only for the incremental increase in generation that directly resulted from the investment in facility expansion or repowering facilitated by the applicant customer.

(2) Generating facilities having received a contract for the sale of renewable energy credits under this Section or Section 1-56, having been used as part of an application for the self-direct program described in subparagraph (R), or having received support through the energy storage resources procurements conducted pursuant to subsection (d-20) of this Section shall be ineligible. For the purposes of this item (ii), "new" means a generating facility energized after the effective date of this amendatory Act of the 104th General Assembly; "facilitated by the applicant customer" means the customer must have a relationship with the facility that satisfies the contract or colocation requirements outlined in this item (ii).

(iii) The facility must be located within the same regional transmission organization for which the hyperscale data center is interconnected and the facility must meet the geographic requirements as set forth in subparagraph (I) of paragraph (1) of subsection (c) as interpreted through the Agency's long-term renewable resources procurement plan or constitute renewable energy generation featuring electricity delivered via high voltage direct current transmission facilities if the high voltage direct current transmission line meets the following criteria:

(1) was constructed with a project labor agreement;

(2) is capable of transmitting electricity at 525kv or above;

(3) has a converter station located in Illinois or in a state adjacent to Illinois that is located or interconnected within the region of the PJM Interconnection, LLC, or Midcontinent Independent System Operator, Inc.; and

(4) does not operate as a public utility, as defined in Section 3-105 of the Public Utilities Act, serving more than 100,000 customers as of January 1, 2021.

(iv) The facility must qualify as an accredited capacity resource within the same service areas as the customer within the PJM Interconnection, LLC, or Midcontinent Independent System Operator, Inc.

(v) The facility's development and construction must meet all labor and equity requirements that would otherwise apply to a similarly sized and similarly located project under this Section, including prevailing wage, project labor agreement, and minimum equity standard requirements.

(3) Participating customers shall be eligible to offset a portion or all of the assessed charges by securing supply through colocating or entering into power purchase agreements with eligible generating facilities. Eligible contracts may involve an alternative retail electric supplier as defined in Section 16-102 of the Public Utilities Act. Eligible contracts must be at least 10 years in length and shall be deemed sufficiently additive if the facility is colocated with the customer such that the facility is located on the customer's side of the electric meter and primarily used to offset the customer's electricity load. Bundled power purchase agreements for some combination of energy, capacity, and environmental attributes shall also be considered sufficiently additive. Contracts only for the purchase of environmental attributes shall only be considered sufficiently additive upon a successful demonstration to the Agency that the contract instrument facilitated the facility's development. Environmental attributes, including renewable energy credits, purchased under any qualifying contract or generated from colocated generation shall be retired on that customer's behalf.

(4) To determine the self-direct crediting rate, the following 3 steps must be completed:

(i) A comparison between the amount of energy produced from customer contracted eligible resources to the customer's expected usage to establish a self-supplied energy percentage.

(ii) A comparison of the calculated capacity of the contracted eligible resources by multiplying the resource's nameplate capacity by the applicable regional transmission organization effective load carrying capacity for the applicable facility and comparing the resulting value against the customer's non-coincident peak demand to develop a self-supplied capacity percentage.

(iii) The simple average of the self-supplied energy percentage and the self-supplied capacity percentage shall constitute the offset value that serves to reduce the applicant customer's renewable portfolio standard-related charges by the resulting percentage. The process for establishing a large load customer's usage shall be based upon a predefined calculation, accounting for a customer's demand based upon the best available information for that customer. Eligible resource effective load carrying capacity shall be established using the most recent publicly available RTO-established values. Once established, the applicable effective load carrying capacity shall not change unless an error in the RTO process is identified and corrected or an adjustment in the eligible resource's operation impacts its ability to operate according to reasonable operational parameters for its type. A significant change in either the large load customer's operation or that of the eligible resource may result in a reassessment and change in self-supplied energy or capacity percentage. The maximum crediting rate shall not allow for crediting that customer's proportionate share of support for the costs associated with procuring renewable energy credits through the Solar for All Program described in subsection (b) of Section 1-56 of this Act. If the resulting crediting rate reaches 90%, a customer shall be charged the minimum possible RPS-related charges due to the scale and qualitative benefits of that customer's investment in facilitating new clean energy generation. The resulting crediting rate shall not exceed 100%.

(5) Customers described in this subparagraph (R-5) shall apply, on a form developed by the Agency, to the Agency to be designated as a hyperscale data center. The Agency shall open the hyperscale data center program for applications quarterly, with an application window of no less than 2 weeks each quarter. Once the Agency determines that a self-direct customer is eligible for participation in the program, the self-direct customer shall remain eligible until the end of the term of the contract. At a minimum, such application shall contain the following:

(i) the customer's certification that, at the time of the customer's application, the customer takes service or would qualify to take service under the tariff described in paragraph (3) of subsection (c) of Section 16-105.5 of the Public Utilities Act, including documents demonstrating that qualification and proof of qualification once achieved;

(ii) the customer's certification that the customer has entered into one or more bilateral contracts with eligible generating facilities or is colocated with eligible generating facilities, including supporting documentation that provides information about those facilities necessary for facility qualification and that determines applicable crediting rates;

(iii) certification that the contract or contracts with new clean energy generating facilities are long-term contracts with term lengths of at least 10 years, including supporting documentation;

(iv) certification of the quantities of energy, capacity, or renewable energy credits that the customer will purchase each year under such contract or contracts, including supporting documentation;

(v) historical information and projections related to the customer's electricity consumption, including a demonstration of the share of the customer's electricity consumption and peak load contribution, that the facility or facilities is intended to meet as demonstrated through supporting documentation; and

(vi) a certification that the customer intends to maintain the contract for the duration of the length of the contract. The Agency may request, and applicant customers shall provide, any additional information necessary for determining customer program eligibility, facility eligibility, and applicable crediting rate.

(6) The Agency shall provide biannual filings outlining customer qualification and applicable crediting rates as compliance filings in the most recent Commission docketed proceeding for approval of the Agency's Long-Term Renewable Resources Procurement Plan.

(7) The Agency may require that participating customers provide annual reports related to facility operation and performance, customer electricity consumption and load profiles, and other information as necessary. Upon a material change in any information underpinning the customer's qualification for the program or establishment of the customer's crediting rate, the participating customer shall provide notice to the Agency outlining the nature and impact of such changes.

(8) The Agency shall include additional terms, conditions, details, and requirements applicable to the hyperscale data center self-direct RPS program within its long-term renewable resources procurement plan. Notwithstanding whether an updated long-term renewable resources procurement plan, including this program, has been approved by the Commission, the hyperscale data center self-direct RPS program shall begin taking applications no later than 90 days after Commission approval of the tariff outlined in paragraph (3) of subsection (c) of Section 16-105.5 of the Public Utilities Act.

(S) Beginning with the long-term renewable resources procurement plan covering program and procurement activity for the delivery year beginning on June 1, 2028, any long-term renewable resources procurement plan developed by the Agency in accordance with subparagraph (A) of this paragraph (1) shall include a Geothermal Homes and Businesses Program for the procurement of geothermal renewable energy credits from new geothermal heating and cooling systems. The long-term renewable resources procurement plan shall allocate up to $10,000,000 per delivery year to fund the Program as described in this subparagraph (S). The Program shall be designed to stimulate the steady, predictable, and sustainable growth of new geothermal heating and cooling system deployment in this State and meet gaps in the marketplace. To this end, the Geothermal Homes and Businesses Program shall provide a transparent annual schedule of prices and quantities to enable the geothermal heating and cooling market to scale up and renewable energy credit prices to adjust at a predictable rate over time. The prices set by the Geothermal Homes and Businesses Program may be reflected as a set value or as the product of a formula.

(i) The Geothermal Homes and Businesses Program shall allocate blocks of renewable energy credits as follows:

(1) The Agency may create categories for the Program based on structure features and use cases, including categories based on the nature and size of the Program's projects, customers, communities in which a project is located, and other attributes, defined at the discretion of the Agency through its long-term plan.

(2) The Agency shall propose an initial single annual block for each Program delivery year for each category it creates through the delivery year beginning on June 1, 2035. The Program shall include the following for eligible projects for each delivery year: (I) a block of geothermal renewable energy credit volumes; (II) a price for renewable energy credits from geothermal heating and cooling systems within the identified block; and (III) the terms and conditions for securing a spot on a waitlist once the block is fully committed or reserved. The Agency may periodically review its prior decisions establishing the amount of geothermal renewable energy credit volumes in each annual block and the purchase price for each block and may propose, on an expedited basis, changes to the previously set values, including, but not limited to, redistributing the amounts and the available funds as necessary and appropriate, subject to Commission approval. The Agency may define different block sizes, purchase prices, or other distinct terms and conditions for projects located in different utility service territories if the Agency deems it necessary.

(3) The Agency may develop an intra-year and year-to-year waitlist and block reservation policy that balances market certainty, program availability, and expedient project deployment.

(4) For the program year beginning on June 1, 2028, at least 33% of each annual block shall be available to be reserved for systems that are residential, as defined by the Agency. The Agency shall endeavor to ensure at least 40% of each annual block is available to be reserved by systems located in Equity Investment Eligible Communities. At least 10% of all annual blocks shall be available to be reserved by systems from applicants that are equity eligible contractors, and the Agency shall propose to increase the percentage of systems from applicants that are equity eligible contractors over time to 40% based on factors that include, but are not limited to, the number of equity eligible contractors and the volume used under this clause (4) in previous delivery years. For long-term renewable resources procurement plans developed thereafter, the Agency may propose adjustments to the minimum percentages based on developer interest, market interest and availability, and other factors.

(5) The Agency shall establish Program eligibility requirements that ensure that systems that enter the Program are sufficiently mature enough to indicate a demonstrable path to completion and other terms, conditions, and requirements for the program, including vendor registration and approval, sales and marketing requirements, and other consumer protection requirements as the Agency deems necessary.

(6) The Program shall be designed to ensure that geothermal renewable energy credits are procured from projects in diverse locations and are not procured from projects that are concentrated in a few regional areas.

(7) The Agency, through its long-term renewable resources procurement plan, may implement solutions to maintain stable and consistent REC offerings to avoid gaps in availability during a delivery year, including, but not limited to, creating a floating block of REC capacity in a given delivery year.

(ii) Energy derived from a geothermal heating and cooling system shall be eligible for inclusion in meeting the requirements of the Program. Geothermal renewable energy credits shall be expressed in megawatt-hour units. To make this calculation, the Agency (1) shall identify an appropriate formula supported by a geothermal industry trade organization, a national laboratory, or another data-backed and verifiable methodology, (2) may propose adjustments to any formulas for its proposed renewable energy credit calculation methodology, and (3) may reflect calculation methodologies already in use for other State renewable portfolio standards, if applicable and appropriate. The Agency shall determine the form and manner in which the renewable energy credits are verified and retired, in accordance with national best practices.

Geothermal renewable energy credits retired by obligated utilities for compliance with the Program are only valid for compliance if those geothermal renewable energy credits have not been previously retired by another entity that is not the obligated utility on any tracking system, carbon registry, or other accounting mechanism at any time. Additionally, geothermal renewable energy credits retired by obligated utilities for compliance with the Program shall only be valid for compliance if those geothermal renewable energy credits have not been used to substantiate a public emissions or energy usage claim by any other another entity that is not the obligated utility, of any type and at any time, whether or not the geothermal renewable energy credits were actually retired on a tracking system, registry, or other accounting mechanism at the time of the public emissions-based claim. Geothermal renewable energy credits generated for compliance with the Program shall be valid only if retired once, and claimed once, by the obligated utility.

In order to promote the competitive development of geothermal heating and cooling systems in furtherance of this State's interest in the health, safety, and welfare of its residents, renewable energy credits from geothermal heating and cooling systems shall not be eligible for purchase and retirement under this Act if the credits are sourced from a geothermal heating and cooling system for which costs are being recovered on or after the effective date of this amendatory Act of the 104th General Assembly through rates regulated by this State or any other state.

(iii) The Agency shall establish Program requirements and minimum contract terms to ensure that projects are properly installed and that projects operate to the level of expected benefits. The contract terms shall include, but are not limited to, the following:

(1) The capital that is not advanced shall be disbursed upon a schedule determined by the Agency, based on the total contracted fulfillment over the delivery term, not to exceed, during each delivery year, the contract price multiplied by the estimated annual renewable energy credit generation amount. Payment structures shall include provisions that provide portions of the renewable energy credit delivery contract value upon energization, including no less than 40% of the contract value for residential projects, based on the estimated renewable energy credit production during the contract term.

(2) For renewable energy credits that qualify and are procured under the Program, the delivery contract length shall be 15 years.

(3) For contracts that are paid upon the delivery of renewable energy credits, if generation of renewable energy credits from geothermal heating and cooling systems during a delivery year exceeds the estimated annual generation amount, the excess of such renewable energy credits shall be carried forward to future delivery years and shall not expire during the delivery term. If the renewable energy credit generation during a delivery year, including any carried forward excess renewable energy credits, is less than the estimated annual generation amount, payments during the delivery year shall not exceed the quantity generated plus the quantity carried forward multiplied by the contract price. The electric utility shall receive all renewable energy credits generated by the project during the first 15 years of operation, and retire all renewable energy credits paid for under this clause (3) and return at the end of the delivery term all geothermal renewable energy credits that were not paid for. Renewable energy credits generated by the project thereafter shall not be transferred under the renewable energy credit delivery contract with the counterparty electric utility.

(4) For renewable energy contracts for any type of community, shared, or similar geothermal heating and cooling system that operates using a subscription model and for which subscriptions are a basis for contractual payments, subscription of 90% of total renewable energy credit volumes or greater shall be deemed to be fully subscribed.

(5) Beginning with the long-term renewable resources procurement plan covering the delivery year beginning on June 1, 2030, the Agency may propose a payment structure for Program contracts upon a demonstration of qualification or need under criteria established by the Agency that is focused on supporting the small and emerging businesses and the businesses that most acutely face barriers to capital access. Successful applicant firms shall have advanced capital disbursed before renewable energy credits are first generated. The maximum amount or percentage of capital advanced shall be included in the long-term renewable resources procurement plan, and any amount actually advanced shall be designed to overcome the barriers in access to capital that are faced by an applicant through that applicant's demonstration of need. The amount or percentage of advanced capital may vary by year, or inter-year, by structure category, block, and other factors as deemed applicable by the Agency and by an applicant's demonstration of need. Contracts featuring capital advanced prior to system operation shall feature provisions to ensure both the successful development of applicant projects and the delivery of renewable energy credits for the full term of the contract, including ongoing collateral requirements and other provisions deemed necessary by the Agency. The percentage or amount of capital advanced prior to system operation shall not increase the overall contract value.

(6) Each contract shall include provisions to ensure the delivery of the estimated quantity of geothermal renewable energy credits, including a requirement of performance assurance in an amount deemed appropriate by the Agency.

(7) An obligated utility shall be the counterparty to the contracts executed under this subparagraph (S) that are approved by the Commission. No contract shall be executed for an amount that is less than one geothermal renewable energy credit per year.

(8) Nothing in this subparagraph (S) shall require the utility to advance any payment or pay any amounts that exceed the actual amount of revenues anticipated to be collected by the utility inclusive of eligible funds collected in prior years and alternative compliance payments for use by the utility.

(9) Contracts may be assignable, but only to entities first deemed by the Agency to have met Program terms and requirements applicable to direct Program participation. In developing contracts for the delivery of renewable energy credits from geothermal heating and cooling systems, the Agency may establish fees applicable to each contract assignment.

(10) If, at any time, approved applications for the Program exceed funds collected by the electric utility or would cause the Agency to exceed the limitation on the amount of renewable energy resources that may be procured, then the Agency may consider future uncommitted funds to be reserved for these contracts on a first-come, first-served basis.

(iv) In order to advance priority access to the clean energy economy for businesses and workers from communities that have been excluded from economic opportunities in the energy sector, been subject to disproportionate levels of pollution, and disproportionately experienced negative public health outcomes, the Agency shall apply its equity accountability system and minimum equity standards established under subsections (c-10), (c-15), (c-20), (c-25), and (c-30) to geothermal heating and cooling system renewable energy credit procurement and programs and may include any proposed modifications to the equity accountability system and minimum equity standards that may be warranted with respect to geothermal heating and cooling systems in its plan submission to the Commission under Section 16-111.5 of the Public Utilities Act.

(v) Projects shall be developed in compliance with the prevailing wage and project labor agreement requirements, as applicable, for renewable energy projects in subparagraph (Q) of paragraph (1) of subsection (c). Projects approved under this Program are subject to the prevailing wage requirements outlined in subitem (x) of item (1) of subparagraph (Q) of paragraph (1) of this subsection (c). Renewable energy credits for any single geothermal heating and cooling project that is 142 tons or larger and is procured under this Program after the effective date of this amendatory Act of the 104th General Assembly shall only be eligible if the associated project was built by general contractors who entered into a project labor agreement prior to construction. The project labor agreement shall be filed with the Director in accordance with procedures established by the Agency through its long-term renewable resources procurement plan. The project labor agreement shall provide the names, addresses, and occupations of the owner of the plant and the individuals representing the labor organization employees that participate in the project labor agreement. The project labor agreement shall also specify terms and conditions as provided in this Act.

(vi) The Agency shall strive to minimize administrative expenses in the implementation of the Program. The Agency may use any existing program administrator and any applicable subcontractors to develop, administer, implement, operate, and evaluate the Program.

(T) Renewable energy credits procured under Agency procurements or programs for community solar projects with more than 3 megawatts in nameplate capacity must be procured from facilities built by general contractors that, prior to construction, enter into a project labor agreement, as defined by this Act, subject to the following requirements and limitations:

(i) The project labor agreement shall be filed with the Director in accordance with procedures established by the Agency through its long-term renewable resources procurement plan. Any information submitted to the Agency under this item (i) shall be considered commercially sensitive information.

(ii) At a minimum, the project labor agreement must provide the names, addresses, and occupations of the owner of the project and any individuals representing the labor organization of the employees participating in the project labor agreement consistent with the Project Labor Agreements Act. The project labor agreement must also meet the terms and conditions, as set forth in this Act.

(iii) It is the intent of this Section to ensure that economic development occurs across communities in this State, that emerging businesses may grow, and that there is improved access to the clean energy economy by persons who have greater economic burdens to success. The Agency shall take into consideration the unique cost of compliance of this subparagraph (T) that may be borne by equity eligible contractors and shall include those costs when determining the price of renewable energy credits in the Adjustable Block program. The Agency shall consider costs associated with compliance, including in the development, financing, or construction of projects. The Agency shall periodically review the assumptions in these costs and may adjust prices in compliance with subparagraph (M) of this paragraph (1).

(2) (Blank).

(3) (Blank).

(4) The electric utility shall retire all renewable energy credits used to comply with the standard.

(5) Beginning with the 2010 delivery year and ending June 1, 2017, an electric utility subject to this subsection (c) shall apply the lesser of the maximum alternative compliance payment rate or the most recent estimated alternative compliance payment rate for its service territory for the corresponding compliance period, established pursuant to subsection (d) of Section 16-115D of the Public Utilities Act to its retail customers that take service pursuant to the electric utility's hourly pricing tariff or tariffs. The electric utility shall retain all amounts collected as a result of the application of the alternative compliance payment rate or rates to such customers, and, beginning in 2011, the utility shall include in the information provided under item (1) of subsection (d) of Section 16-111.5 of the Public Utilities Act the amounts collected under the alternative compliance payment rate or rates for the prior year ending May 31. Notwithstanding any limitation on the procurement of renewable energy resources imposed by item (2) of this subsection (c), the Agency shall increase its spending on the purchase of renewable energy resources to be procured by the electric utility for the next plan year by an amount equal to the amounts collected by the utility under the alternative compliance payment rate or rates in the prior year ending May 31.

(6) The electric utility shall be entitled to recover all of its costs associated with the procurement of renewable energy credits under plans approved under this Section and Section 16-111.5 of the Public Utilities Act. These costs shall include associated reasonable expenses for implementing the procurement programs, including, but not limited to, the costs of administering and evaluating the Adjustable Block program and the Geothermal Homes and Businesses Program, through an automatic adjustment clause tariff in accordance with subsection (k) of Section 16-108 of the Public Utilities Act.

(7) Renewable energy credits procured from new photovoltaic projects or new distributed renewable energy generation devices under this Section after June 1, 2017 (the effective date of Public Act 99-906) must be procured from devices installed by a qualified person in compliance with the requirements of Section 16-128A of the Public Utilities Act and any rules or regulations adopted thereunder.

In meeting the renewable energy requirements of this subsection (c), to the extent feasible and consistent with State and federal law, the renewable energy credit procurements, Adjustable Block solar program, and community renewable generation program shall provide employment opportunities for all segments of the population and workforce, including minority-owned and female-owned business enterprises, and shall not, consistent with State and federal law, discriminate based on race or socioeconomic status.

(c-5) Procurement of renewable energy credits from new renewable energy facilities installed at or adjacent to the sites of electric generating facilities that burn or burned coal as their primary fuel source.

(1) In addition to the procurement of renewable energy credits pursuant to long-term renewable resources procurement plans in accordance with subsection (c) of this Section and Section 16-111.5 of the Public Utilities Act, the Agency shall conduct procurement events in accordance with this subsection (c-5) for the procurement by electric utilities that served more than 300,000 retail customers in this State as of January 1, 2019 of renewable energy credits from new renewable energy facilities to be installed at or adjacent to the sites of electric generating facilities that, as of January 1, 2016, burned coal as their primary fuel source and meet the other criteria specified in this subsection (c-5). For purposes of this subsection (c-5), "new renewable energy facility" means a new utility-scale solar project as defined in this Section 1-75. The renewable energy credits procured pursuant to this subsection (c-5) may be included or counted for purposes of compliance with the amounts of renewable energy credits required to be procured pursuant to subsection (c) of this Section to the extent that there are otherwise shortfalls in compliance with such requirements. The procurement of renewable energy credits by electric utilities pursuant to this subsection (c-5) shall be funded solely by revenues collected from the Coal to Solar and Energy Storage Initiative Charge provided for in this subsection (c-5) and subsection (i-5) of Section 16-108 of the Public Utilities Act, shall not be funded by revenues collected through any of the other funding mechanisms provided for in subsection (c) of this Section, and shall not be subject to the limitation imposed by subsection (c) on charges to retail customers for costs to procure renewable energy resources pursuant to subsection (c), and shall not be subject to any other requirements or limitations of subsection (c).

(2) The Agency shall conduct 2 procurement events to select owners of electric generating facilities meeting the eligibility criteria specified in this subsection (c-5) to enter into long-term contracts to sell renewable energy credits to electric utilities serving more than 300,000 retail customers in this State as of January 1, 2019. The first procurement event shall be conducted no later than March 31, 2022, unless the Agency elects to delay it, until no later than May 1, 2022, due to its overall volume of work, and shall be to select owners of electric generating facilities located in this State and south of federal Interstate Highway 80 that meet the eligibility criteria specified in this subsection (c-5). The second procurement event shall be conducted no sooner than September 30, 2022 and no later than October 31, 2022 and shall be to select owners of electric generating facilities located anywhere in this State that meet the eligibility criteria specified in this subsection (c-5). The Agency shall establish and announce a time period, which shall begin no later than 30 days prior to the scheduled date for the procurement event, during which applicants may submit applications to be selected as suppliers of renewable energy credits pursuant to this subsection (c-5). The eligibility criteria for selection as a supplier of renewable energy credits pursuant to this subsection (c-5) shall be as follows:

(A) The applicant owns an electric generating facility located in this State that: (i) as of January 1, 2016, burned coal as its primary fuel to generate electricity; and (ii) has, or had prior to retirement, an electric generating capacity of at least 150 megawatts. The electric generating facility can be either: (i) retired as of the date of the procurement event; or (ii) still operating as of the date of the procurement event.

(B) The applicant is not (i) an electric cooperative as defined in Section 3-119 of the Public Utilities Act, or (ii) an entity described in subsection (b)(1) of Section 3-105 of the Public Utilities Act, or an association or consortium of or an entity owned by entities described in (i) or (ii); and the coal-fueled electric generating facility was at one time owned, in whole or in part, by a public utility as defined in Section 3-105 of the Public Utilities Act.

(C) If participating in the first procurement event, the applicant proposes and commits to construct and operate, at the site, and if necessary for sufficient space on property adjacent to the existing property, at which the electric generating facility identified in paragraph (A) is located: (i) a new renewable energy facility of at least 20 megawatts but no more than 100 megawatts of electric generating capacity, and (ii) an energy storage facility having a storage capacity equal to at least 2 megawatts and at most 10 megawatts. If participating in the second procurement event, the applicant proposes and commits to construct and operate, at the site, and if necessary for sufficient space on property adjacent to the existing property, at which the electric generating facility identified in paragraph (A) is located: (i) a new renewable energy facility of at least 5 megawatts but no more than 20 megawatts of electric generating capacity, and (ii) an energy storage facility having a storage capacity equal to at least 0.5 megawatts and at most one megawatt.

(D) The applicant agrees that the new renewable energy facility and the energy storage facility will be constructed or installed by a qualified entity or entities in compliance with the requirements of subsection (g) of Section 16-128A of the Public Utilities Act and any rules adopted thereunder.

(E) The applicant agrees that personnel operating the new renewable energy facility and the energy storage facility will have the requisite skills, knowledge, training, experience, and competence, which may be demonstrated by completion or current participation and ultimate completion by employees of an accredited or otherwise recognized apprenticeship program for the employee's particular craft, trade, or skill, including through training and education courses and opportunities offered by the owner to employees of the coal-fueled electric generating facility or by previous employment experience performing the employee's particular work skill or function.

(F) The applicant commits that not less than the prevailing wage, as determined pursuant to the Prevailing Wage Act, will be paid to the applicant's employees engaged in construction activities associated with the new renewable energy facility and the new energy storage facility and to the employees of applicant's contractors engaged in construction activities associated with the new renewable energy facility and the new energy storage facility, and that, on or before the commercial operation date of the new renewable energy facility, the applicant shall file a report with the Agency certifying that the requirements of this subparagraph (F) have been met.

(G) The applicant commits that if selected, it will negotiate a project labor agreement for the construction of the new renewable energy facility and associated energy storage facility that includes provisions requiring the parties to the agreement to work together to establish diversity threshold requirements and to ensure best efforts to meet diversity targets, improve diversity at the applicable job site, create diverse apprenticeship opportunities, and create opportunities to employ former coal-fired power plant workers.

(H) The applicant commits to enter into a contract or contracts for the applicable duration to provide specified numbers of renewable energy credits each year from the new renewable energy facility to electric utilities that served more than 300,000 retail customers in this State as of January 1, 2019, at a price of $30 per renewable energy credit. The price per renewable energy credit shall be fixed at $30 for the applicable duration and the renewable energy credits shall not be indexed renewable energy credits as provided for in item (v) of subparagraph (G) of paragraph (1) of subsection (c) of Section 1-75 of this Act. The applicable duration of each contract shall be 20 years, unless the applicant is physically interconnected to the PJM Interconnection, LLC transmission grid and had a generating capacity of at least 1,200 megawatts as of January 1, 2021, in which case the applicable duration of the contract shall be 15 years.

(I) The applicant's application is certified by an officer of the applicant and by an officer of the applicant's ultimate parent company, if any.

(3) An applicant may submit applications to contract to supply renewable energy credits from more than one new renewable energy facility to be constructed at or adjacent to one or more qualifying electric generating facilities owned by the applicant. The Agency may select new renewable energy facilities to be located at or adjacent to the sites of more than one qualifying electric generation facility owned by an applicant to contract with electric utilities to supply renewable energy credits from such facilities.

(4) The Agency shall assess fees to each applicant to recover the Agency's costs incurred in receiving and evaluating applications, conducting the procurement event, developing contracts for sale, delivery and purchase of renewable energy credits, and monitoring the administration of such contracts, as provided for in this subsection (c-5), including fees paid to a procurement administrator retained by the Agency for one or more of these purposes.

(5) The Agency shall select the applicants and the new renewable energy facilities to contract with electric utilities to supply renewable energy credits in accordance with this subsection (c-5). In the first procurement event, the Agency shall select applicants and new renewable energy facilities to supply renewable energy credits, at a price of $30 per renewable energy credit, aggregating to no less than 400,000 renewable energy credits per year for the applicable duration, assuming sufficient qualifying applications to supply, in the aggregate, at least that amount of renewable energy credits per year; and not more than 580,000 renewable energy credits per year for the applicable duration. In the second procurement event, the Agency shall select applicants and new renewable energy facilities to supply renewable energy credits, at a price of $30 per renewable energy credit, aggregating to no more than 625,000 renewable energy credits per year less the amount of renewable energy credits each year contracted for as a result of the first procurement event, for the applicable durations. The number of renewable energy credits to be procured as specified in this paragraph (5) shall not be reduced based on renewable energy credits procured in the self-direct renewable energy credit compliance program established pursuant to subparagraph (R) of paragraph (1) of subsection (c) of Section 1-75.

(6) The obligation to purchase renewable energy credits from the applicants and their new renewable energy facilities selected by the Agency shall be allocated to the electric utilities based on their respective percentages of kilowatthours delivered to delivery services customers to the aggregate kilowatthour deliveries by the electric utilities to delivery services customers for the year ended December 31, 2021. In order to achieve these allocation percentages between or among the electric utilities, the Agency shall require each applicant that is selected in the procurement event to enter into a contract with each electric utility for the sale and purchase of renewable energy credits from each new renewable energy facility to be constructed and operated by the applicant, with the sale and purchase obligations under the contracts to aggregate to the total number of renewable energy credits per year to be supplied by the applicant from the new renewable energy facility.

(7) The Agency shall submit its proposed selection of applicants, new renewable energy facilities to be constructed, and renewable energy credit amounts for each procurement event to the Commission for approval. The Commission shall, within 2 business days after receipt of the Agency's proposed selections, approve the proposed selections if it determines that the applicants and the new renewable energy facilities to be constructed meet the selection criteria set forth in this subsection (c-5) and that the Agency seeks approval for contracts of applicable durations aggregating to no more than the maximum amount of renewable energy credits per year authorized by this subsection (c-5) for the procurement event, at a price of $30 per renewable energy credit.

(8) The Agency, in conjunction with its procurement administrator if one is retained, the electric utilities, and potential applicants for contracts to produce and supply renewable energy credits pursuant to this subsection (c-5), shall develop a standard form contract for the sale, delivery and purchase of renewable energy credits pursuant to this subsection (c-5). Each contract resulting from the first procurement event shall allow for a commercial operation date for the new renewable energy facility of either June 1, 2023 or June 1, 2024, with such dates subject to adjustment as provided in this paragraph. Each contract resulting from the second procurement event shall provide for a commercial operation date on June 1 next occurring up to 48 months after execution of the contract. Each contract shall provide that the owner shall receive payments for renewable energy credits for the applicable durations beginning with the commercial operation date of the new renewable energy facility. The form contract shall provide for adjustments to the commercial operation and payment start dates as needed due to any delays in completing the procurement and contracting processes, in finalizing interconnection agreements and installing interconnection facilities, and in obtaining other necessary governmental permits and approvals. The form contract shall be, to the maximum extent possible, consistent with standard electric industry contracts for sale, delivery, and purchase of renewable energy credits while taking into account the specific requirements of this subsection (c-5). The form contract shall provide for over-delivery and under-delivery of renewable energy credits within reasonable ranges during each 12-month period and penalty, default, and enforcement provisions for failure of the selling party to deliver renewable energy credits as specified in the contract and to comply with the requirements of this subsection (c-5). The standard form contract shall specify that all renewable energy credits delivered to the electric utility pursuant to the contract shall be retired. The Agency shall make the proposed contracts available for a reasonable period for comment by potential applicants, and shall publish the final form contract at least 30 days before the date of the first procurement event.

(9) Coal to Solar and Energy Storage Initiative Charge.

(A) By no later than July 1, 2022, each electric utility that served more than 300,000 retail customers in this State as of January 1, 2019 shall file a tariff with the Commission for the billing and collection of a Coal to Solar and Energy Storage Initiative Charge in accordance with subsection (i-5) of Section 16-108 of the Public Utilities Act, with such tariff to be effective, following review and approval or modification by the Commission, beginning January 1, 2023. The tariff shall provide for the calculation and setting of the electric utility's Coal to Solar and Energy Storage Initiative Charge to collect revenues estimated to be sufficient, in the aggregate, (i) to enable the electric utility to pay for the renewable energy credits it has contracted to purchase in the delivery year beginning June 1, 2023 and each delivery year thereafter from new renewable energy facilities located at the sites of qualifying electric generating facilities, and (ii) to fund the grant payments to be made in each delivery year by the Department of Commerce and Economic Opportunity, or any successor department or agency, which shall be referred to in this subsection (c-5) as the Department, pursuant to paragraph (10) of this subsection (c-5). The electric utility's tariff shall provide for the billing and collection of the Coal to Solar and Energy Storage Initiative Charge on each kilowatthour of electricity delivered to its delivery services customers within its service territory and shall provide for an annual reconciliation of revenues collected with actual costs, in accordance with subsection (i-5) of Section 16-108 of the Public Utilities Act.

(B) Each electric utility shall remit on a monthly basis to the State Treasurer, for deposit in the Coal to Solar and Energy Storage Initiative Fund provided for in this subsection (c-5), the electric utility's collections of the Coal to Solar and Energy Storage Initiative Charge in the amount estimated to be needed by the Department for grant payments pursuant to grant contracts entered into by the Department pursuant to paragraph (10) of this subsection (c-5).

(10) Coal to Solar and Energy Storage Initiative Fund.

(A) The Coal to Solar and Energy Storage Initiative Fund is established as a special fund in the State treasury. The Coal to Solar and Energy Storage Initiative Fund is authorized to receive, by statutory deposit, that portion specified in item (B) of paragraph (9) of this subsection (c-5) of moneys collected by electric utilities through imposition of the Coal to Solar and Energy Storage Initiative Charge required by this subsection (c-5). The Coal to Solar and Energy Storage Initiative Fund shall be administered by the Department to provide grants to support the installation and operation of energy storage facilities at the sites of qualifying electric generating facilities meeting the criteria specified in this paragraph (10).

(B) The Coal to Solar and Energy Storage Initiative Fund shall not be subject to sweeps, administrative charges, or chargebacks, including, but not limited to, those authorized under Section 8h of the State Finance Act, that would in any way result in the transfer of those funds from the Coal to Solar and Energy Storage Initiative Fund to any other fund of this State or in having any such funds utilized for any purpose other than the express purposes set forth in this paragraph (10).

(C) The Department shall utilize up to $280,500,000 in the Coal to Solar and Energy Storage Initiative Fund for grants, assuming sufficient qualifying applicants, to support installation of energy storage facilities at the sites of up to 3 qualifying electric generating facilities located in the Midcontinent Independent System Operator, Inc., region in Illinois and the sites of up to 2 qualifying electric generating facilities located in the PJM Interconnection, LLC region in Illinois that meet the criteria set forth in this subparagraph (C). The criteria for receipt of a grant pursuant to this subparagraph (C) are as follows:

(1) the electric generating facility at the site has, or had prior to retirement, an electric generating capacity of at least 150 megawatts;

(2) the electric generating facility burns (or burned prior to retirement) coal as its primary source of fuel;

(3) if the electric generating facility is retired, it was retired subsequent to January 1, 2016;

(4) the owner of the electric generating facility has not been selected by the Agency pursuant to this subsection (c-5) of this Section to enter into a contract to sell renewable energy credits to one or more electric utilities from a new renewable energy facility located or to be located at or adjacent to the site at which the electric generating facility is located;

(5) the electric generating facility located at the site was at one time owned, in whole or in part, by a public utility as defined in Section 3-105 of the Public Utilities Act;

(6) the electric generating facility at the site is not owned by (i) an electric cooperative as defined in Section 3-119 of the Public Utilities Act, or (ii) an entity described in subsection (b)(1) of Section 3-105 of the Public Utilities Act, or an association or consortium of or an entity owned by entities described in items (i) or (ii);

(7) the proposed energy storage facility at the site will have energy storage capacity of at least 37 megawatts;

(8) the owner commits to place the energy storage facility into commercial operation on either June 1, 2023, June 1, 2024, or June 1, 2025, with such date subject to adjustment as needed due to any delays in completing the grant contracting process, in finalizing interconnection agreements and in installing interconnection facilities, and in obtaining necessary governmental permits and approvals;

(9) the owner agrees that the new energy storage facility will be constructed or installed by a qualified entity or entities consistent with the requirements of subsection (g) of Section 16-128A of the Public Utilities Act and any rules adopted under that Section;

(10) the owner agrees that personnel operating the energy storage facility will have the requisite skills, knowledge, training, experience, and competence, which may be demonstrated by completion or current participation and ultimate completion by employees of an accredited or otherwise recognized apprenticeship program for the employee's particular craft, trade, or skill, including through training and education courses and opportunities offered by the owner to employees of the coal-fueled electric generating facility or by previous employment experience performing the employee's particular work skill or function;

(11) the owner commits that not less than the prevailing wage, as determined pursuant to the Prevailing Wage Act, will be paid to the owner's employees engaged in construction activities associated with the new energy storage facility and to the employees of the owner's contractors engaged in construction activities associated with the new energy storage facility, and that, on or before the commercial operation date of the new energy storage facility, the owner shall file a report with the Department certifying that the requirements of this subparagraph (11) have been met; and

(12) the owner commits that if selected to receive a grant, it will negotiate a project labor agreement for the construction of the new energy storage facility that includes provisions requiring the parties to the agreement to work together to establish diversity threshold requirements and to ensure best efforts to meet diversity targets, improve diversity at the applicable job site, create diverse apprenticeship opportunities, and create opportunities to employ former coal-fired power plant workers.

The Department shall accept applications for this grant program until March 31, 2022 and shall announce the award of grants no later than June 1, 2022. The Department shall make the grant payments to a recipient in equal annual amounts for 10 years following the date the energy storage facility is placed into commercial operation. The annual grant payments to a qualifying energy storage facility shall be $110,000 per megawatt of energy storage capacity, with total annual grant payments pursuant to this subparagraph (C) for qualifying energy storage facilities not to exceed $28,050,000 in any year.

(D) Grants of funding for energy storage facilities pursuant to subparagraph (C) of this paragraph (10), from the Coal to Solar and Energy Storage Initiative Fund, shall be memorialized in grant contracts between the Department and the recipient. The grant contracts shall specify the date or dates in each year on which the annual grant payments shall be paid.

(E) All disbursements from the Coal to Solar and Energy Storage Initiative Fund shall be made only upon warrants of the Comptroller drawn upon the Treasurer as custodian of the Fund upon vouchers signed by the Director of the Department or by the person or persons designated by the Director of the Department for that purpose. The Comptroller is authorized to draw the warrants upon vouchers so signed. The Treasurer shall accept all written warrants so signed and shall be released from liability for all payments made on those warrants.

(11) Diversity, equity, and inclusion plans.

(A) Each applicant selected in a procurement event to contract to supply renewable energy credits in accordance with this subsection (c-5) and each owner selected by the Department to receive a grant or grants to support the construction and operation of a new energy storage facility or facilities in accordance with this subsection (c-5) shall, within 60 days following the Commission's approval of the applicant to contract to supply renewable energy credits or within 60 days following execution of a grant contract with the Department, as applicable, submit to the Commission a diversity, equity, and inclusion plan setting forth the applicant's or owner's numeric goals for the diversity composition of its supplier entities for the new renewable energy facility or new energy storage facility, as applicable, which shall be referred to for purposes of this paragraph (11) as the project, and the applicant's or owner's action plan and schedule for achieving those goals.

(B) For purposes of this paragraph (11), diversity composition shall be based on the percentage, which shall be a minimum of 25%, of eligible expenditures for contract awards for materials and services (which shall be defined in the plan) to business enterprises owned by minority persons, women, or persons with disabilities as defined in Section 2 of the Business Enterprise for Minorities, Women, and Persons with Disabilities Act, to LGBTQ business enterprises, to veteran-owned business enterprises, and to business enterprises located in environmental justice communities. The diversity composition goals of the plan may include eligible expenditures in areas for vendor or supplier opportunities in addition to development and construction of the project, and may exclude from eligible expenditures materials and services with limited market availability, limited production and availability from suppliers in the United States, such as solar panels and storage batteries, and material and services that are subject to critical energy infrastructure or cybersecurity requirements or restrictions. The plan may provide that the diversity composition goals may be met through Tier 1 Direct or Tier 2 subcontracting expenditures or a combination thereof for the project.

(C) The plan shall provide for, but not be limited to: (i) internal initiatives, including multi-tier initiatives, by the applicant or owner, or by its engineering, procurement and construction contractor if one is used for the project, which for purposes of this paragraph (11) shall be referred to as the EPC contractor, to enable diverse businesses to be considered fairly for selection to provide materials and services; (ii) requirements for the applicant or owner or its EPC contractor to proactively solicit and utilize diverse businesses to provide materials and services; and (iii) requirements for the applicant or owner or its EPC contractor to hire a diverse workforce for the project. The plan shall include a description of the applicant's or owner's diversity recruiting efforts both for the project and for other areas of the applicant's or owner's business operations. The plan shall provide for the imposition of financial penalties on the applicant's or owner's EPC contractor for failure to exercise best efforts to comply with and execute the EPC contractor's diversity obligations under the plan. The plan may provide for the applicant or owner to set aside a portion of the work on the project to serve as an incubation program for qualified businesses, as specified in the plan, owned by minority persons, women, persons with disabilities, LGBTQ persons, and veterans, and businesses located in environmental justice communities, seeking to enter the renewable energy industry.

(D) The applicant or owner may submit a revised or updated plan to the Commission from time to time as circumstances warrant. The applicant or owner shall file annual reports with the Commission detailing the applicant's or owner's progress in implementing its plan and achieving its goals and any modifications the applicant or owner has made to its plan to better achieve its diversity, equity and inclusion goals. The applicant or owner shall file a final report on the fifth June 1 following the commercial operation date of the new renewable energy resource or new energy storage facility, but the applicant or owner shall thereafter continue to be subject to applicable reporting requirements of Section 5-117 of the Public Utilities Act.

(c-10) Equity accountability system. It is the purpose of this subsection (c-10) to create an equity accountability system, which includes the minimum equity standards for all renewable energy procurements, the equity category of the Adjustable Block Program, and the equity prioritization for noncompetitive procurements, that is successful in advancing priority access to the clean energy economy for businesses and workers from communities that have been excluded from economic opportunities in the energy sector, have been subject to disproportionate levels of pollution, and have disproportionately experienced negative public health outcomes. Further, it is the purpose of this subsection to ensure that this equity accountability system is successful in advancing equity across Illinois by providing access to the clean energy economy for businesses and workers from communities that have been historically excluded from economic opportunities in the energy sector, have been subject to disproportionate levels of pollution, and have disproportionately experienced negative public health outcomes.

(1) Minimum equity standards. The Agency shall create programs with the purpose of increasing access to and development of equity eligible contractors, who are prime contractors and subcontractors, across all of the programs it manages. All applications for renewable energy credit procurements shall comply with specific minimum equity commitments. Starting in the delivery year immediately following the next long-term renewable resources procurement plan, at least 10% of the project workforce for each entity participating in a procurement program outlined in this subsection (c-10) must be done by equity eligible persons or equity eligible contractors. The Agency shall increase the minimum percentage each delivery year thereafter by increments that ensure a statewide average of 30% of the project workforce for each entity participating in a procurement program is done by equity eligible persons or equity eligible contractors by 2030. The Agency shall propose a schedule of percentage increases to the minimum equity standards in its draft revised renewable energy resources procurement plan submitted to the Commission for approval pursuant to paragraph (5) of subsection (b) of Section 16-111.5 of the Public Utilities Act. In determining these annual increases, the Agency shall have the discretion to establish different minimum equity standards for different types of procurements and different regions of the State if the Agency finds that doing so will further the purposes of this subsection (c-10). The proposed schedule of annual increases shall be revisited and updated on an annual basis. Revisions shall be developed with stakeholder input, including from equity eligible persons, equity eligible contractors, clean energy industry representatives, and community-based organizations that work with such persons and contractors.

(A) At the start of each delivery year, the Agency shall require a compliance plan from each entity participating in a procurement program of subsection (c) of this Section, and entities opting to comply with the minimum equity standard through the Illinois Solar for All Program under Section 1-56 of this Act, that demonstrates how they will achieve compliance with the minimum equity standard percentage for work completed in that delivery year. If an entity applies for its approved vendor or designee status between delivery years, the Agency shall require a compliance plan at the time of application.

(B) Halfway through each delivery year, the Agency shall require each entity participating in a procurement program to confirm that it will achieve compliance in that delivery year, when applicable. The Agency may offer corrective action plans to entities that are not on track to achieve compliance.

(C) At the end of each delivery year, each entity participating and completing work in that delivery year in a procurement program of subsection (c) shall submit a report to the Agency that demonstrates how it achieved compliance with the minimum equity standards percentage for that delivery year.

(D) The Agency shall prohibit participation in procurement programs by an approved vendor or designee, as applicable, or entities with which an approved vendor or designee, as applicable, shares a common parent company if an approved vendor or designee, as applicable, failed to meet the minimum equity standards for the prior delivery year. Waivers approved for lack of equity eligible persons or equity eligible contractors in a geographic area of a project shall not count against the approved vendor or designee. The Agency shall offer a corrective action plan for any such entities to assist them in obtaining compliance and shall allow continued access to procurement programs upon an approved vendor or designee demonstrating compliance.

(E) The Agency shall pursue efficiencies achieved by combining with other approved vendor or designee reporting.

(2) Equity accountability system within the Adjustable Block program. The equity category described in item (vi) of subparagraph (K) of subsection (c) is only available to applicants that are equity eligible contractors.

(3) Equity accountability system within competitive procurements. Through its long-term renewable resources procurement plan, the Agency shall develop requirements for ensuring that competitive procurement processes, including utility-scale solar, utility-scale wind, and brownfield site photovoltaic projects, advance the equity goals of this subsection (c-10). Subject to Commission approval, the Agency shall develop bid application requirements and a bid evaluation methodology for ensuring that utilization of equity eligible contractors, whether as bidders or as participants on project development, is optimized, including requiring that winning or successful applicants for utility-scale projects are or will partner with equity eligible contractors and giving preference to bids through which a higher portion of contract value flows to equity eligible contractors. To the extent practicable, entities participating in competitive procurements shall also be required to meet all the equity accountability requirements for approved vendors and their designees under this subsection (c-10). In developing these requirements, the Agency shall also consider whether equity goals can be further advanced through additional measures.

(4) In the first revision to the long-term renewable energy resources procurement plan and each revision thereafter, the Agency shall include the following:

(A) The current status and number of equity eligible contractors listed in the Energy Workforce Equity Database designed in subsection (c-25), including the number of equity eligible contractors with current certifications as issued by the Agency.

(B) A mechanism for measuring, tracking, and reporting project workforce at the approved vendor or designee level, as applicable, which shall include a measurement methodology and records to be made available for audit by the Agency or the Program Administrator.

(C) A program for approved vendors, designees, eligible persons, and equity eligible contractors to receive trainings, guidance, and other support from the Agency or its designee regarding the equity category outlined in item (vi) of subparagraph (K) of paragraph (1) of subsection (c) and in meeting the minimum equity standards of this subsection (c-10).

(D) A process for certifying equity eligible contractors and equity eligible persons. The certification process shall coordinate with the Energy Workforce Equity Database set forth in subsection (c-25).

(E) An application for waiver of the minimum equity standards of this subsection, which the Agency shall have the discretion to grant in rare circumstances. The Agency may grant such a waiver where the applicant provides evidence of significant efforts toward meeting the minimum equity commitment, including: use of the Energy Workforce Equity Database; efforts to hire or contract with entities that hire eligible persons; and efforts to establish contracting relationships with eligible contractors. The Agency shall support applicants in understanding the Energy Workforce Equity Database and other resources for pursuing compliance of the minimum equity standards. Waivers shall be project-specific, unless the Agency deems it necessary to grant a waiver across a portfolio of projects, and in effect for no longer than one year. Any waiver extension or subsequent waiver request from an applicant shall be subject to the requirements of this Section and shall specify efforts made to reach compliance. When considering whether to grant a waiver, and to what extent, the Agency shall consider the degree to which similarly situated applicants have been able to meet these minimum equity commitments. For repeated waiver requests for specific lack of eligible persons or eligible contractors available, the Agency shall make recommendations to target recruitment to add such eligible persons or eligible contractors to the database.

(5) The Agency shall collect information about work on projects or portfolios of projects subject to these minimum equity standards to ensure compliance with this subsection (c-10). Reporting in furtherance of this requirement may be combined with other annual reporting requirements. Such reporting shall include proof of certification of each equity eligible contractor or equity eligible person during the applicable time period.

As part of the reporting requirement under this subparagraph (5), the Agency shall collect and report information about the use of equity eligible contractors and equity eligible persons, as well as Minimum Equity Standard compliance and waiver usage on the Adjustable Block program and utility-scale projects subject to project labor agreements. The Agency shall note any instances of the projects being unable to meet or requiring a waiver to meet Minimum Equity Standard requirements and the location of those projects.

On an annual basis, the Agency shall submit a written summary of its findings on an annual basis to the General Assembly and the Governor and shall make the report and summary available on the Agency's website.

(6) The Agency shall keep confidential all information and communication that provides private or personal information.

(7) Modifications to the equity accountability system. As part of the update of the long-term renewable resources procurement plan to be initiated in 2023, or sooner if the Agency deems necessary, the Agency shall determine the extent to which the equity accountability system described in this subsection (c-10) has advanced the goals of this amendatory Act of the 102nd General Assembly, including through the inclusion of equity eligible persons and equity eligible contractors in renewable energy credit projects. If the Agency finds that the equity accountability system has failed to meet those goals to its fullest potential, the Agency may revise the following criteria for future Agency procurements: (A) the percentage of project workforce, or other appropriate workforce measure, certified as equity eligible persons or equity eligible contractors; (B) definitions for equity investment eligible persons and equity investment eligible community; and (C) such other modifications necessary to advance the goals of this amendatory Act of the 102nd General Assembly effectively. Such revised criteria may also establish distinct equity accountability systems for different types of procurements or different regions of the State if the Agency finds that doing so will further the purposes of such programs. Revisions shall be developed with stakeholder input, including from equity eligible persons, equity eligible contractors, and community-based organizations that work with such persons and contractors.

(c-15) Racial discrimination elimination powers and process.

(1) Purpose. It is the purpose of this subsection to empower the Agency and other State actors to remedy racial discrimination in Illinois' clean energy economy as effectively and expediently as possible, including through the use of race-conscious remedies, such as race-conscious contracting and hiring goals, as consistent with State and federal law.

(2) Racial disparity and discrimination review process.

(A) Within one year after awarding contracts using the equity actions processes established in this Section, the Agency shall publish a report evaluating the effectiveness of the equity actions point criteria of this Section in increasing participation of equity eligible persons and equity eligible contractors. The report shall disaggregate participating workers and contractors by race and ethnicity. The report shall be forwarded to the Governor, the General Assembly, and the Illinois Commerce Commission and be made available to the public.

(B) As soon as is practicable thereafter, the Agency, in consultation with the Department of Commerce and Economic Opportunity, Department of Labor, and other agencies that may be relevant, shall commission and publish a disparity and availability study that measures the presence and impact of discrimination on minority businesses and workers in Illinois' clean energy economy. The Agency may hire consultants and experts to conduct the disparity and availability study, with the retention of those consultants and experts exempt from the requirements of Section 20-10 of the Illinois Procurement Code. The Illinois Power Agency shall forward a copy of its findings and recommendations to the Governor, the General Assembly, and the Illinois Commerce Commission. If the disparity and availability study establishes a strong basis in evidence that there is discrimination in Illinois' clean energy economy, the Agency, Department of Commerce and Economic Opportunity, Department of Labor, Department of Corrections, and other appropriate agencies shall take appropriate remedial actions, including race-conscious remedial actions as consistent with State and federal law, to effectively remedy this discrimination. Such remedies may include modification of the equity accountability system as described in subsection (c-10).

(c-20) Program data collection.

(1) Purpose. Data collection, data analysis, and reporting are critical to ensure that the benefits of the clean energy economy provided to Illinois residents and businesses are equitably distributed across the State. The Agency shall collect data from program applicants in order to track and improve equitable distribution of benefits across Illinois communities for all procurements the Agency conducts. The Agency shall use this data to, among other things, measure any potential impact of racial discrimination on the distribution of benefits and provide information necessary to correct any discrimination through methods consistent with State and federal law.

(2) Agency collection of program data. The Agency shall collect demographic and geographic data for each entity awarded contracts under any Agency-administered program.

(3) Required information to be collected. The Agency shall collect the following information from applicants and program participants where applicable:

(A) demographic information, including racial or ethnic identity for real persons employed, contracted, or subcontracted through the program and owners of businesses or entities that apply to receive renewable energy credits from the Agency;

(B) geographic location of the residency of real persons employed, contracted, or subcontracted through the program and geographic location of the headquarters of the business or entity that applies to receive renewable energy credits from the Agency; and

(C) any other information the Agency determines is necessary for the purpose of achieving the purpose of this subsection.

(4) Publication of collected information. The Agency shall publish, at least annually, information on the demographics of program participants on an aggregate basis.

(5) Nothing in this subsection shall be interpreted to limit the authority of the Agency, or other agency or department of the State, to require or collect demographic information from applicants of other State programs.

(c-25) Energy Workforce Equity Database.

(1) The Agency, in consultation with the Department of Commerce and Economic Opportunity, shall create an Energy Workforce Equity Database, and may contract with a third party to do so ("database program administrator"). If the Department decides to contract with a third party, that third party shall be exempt from the requirements of Section 20-10 of the Illinois Procurement Code. The Energy Workforce Equity Database shall be a searchable database of suppliers, vendors, and subcontractors for clean energy industries that is:

(A) publicly accessible;

(B) easy for people to find and use;

(C) organized by company specialty or field;

(D) region-specific; and

(E) populated with information including, but not limited to, contacts for suppliers, vendors, or subcontractors who are minority and women-owned business enterprise certified or who participate or have participated in any of the programs described in this Act.

(2) The Agency shall create an easily accessible, public facing online tool using the database information that includes, at a minimum, the following:

(A) a map of environmental justice and equity investment eligible communities;

(B) job postings and recruiting opportunities;

(C) a means by which recruiting clean energy companies can find and interact with current or former participants of clean energy workforce training programs;

(D) information on workforce training service providers and training opportunities available to prospective workers;

(E) renewable energy company diversity reporting;

(F) a list of equity eligible contractors with their contact information, types of work performed, and locations worked in;

(G) reporting on outcomes of the programs described in the workforce programs of the Energy Transition Act, including information such as, but not limited to, retention rate, graduation rate, and placement rates of trainees; and

(H) information about the Jobs and Environmental Justice Grant Program, the Clean Energy Jobs and Justice Fund, and other sources of capital.

(3) The Agency shall ensure the database is regularly updated to ensure information is current and shall coordinate with the Department of Commerce and Economic Opportunity to ensure that it includes information on individuals and entities that are or have participated in the Clean Jobs Workforce Network Program, Clean Energy Contractor Incubator Program, Returning Residents Clean Jobs Training Program, or Clean Energy Primes Contractor Accelerator Program.

(c-30) Enforcement of minimum equity standards. All entities seeking renewable energy credits must submit an annual report to demonstrate compliance with each of the equity commitments required under subsection (c-10). If the Agency concludes the entity has not met or maintained its minimum equity standards required under the applicable subparagraphs under subsection (c-10), the Agency shall deny the entity's ability to participate in procurement programs in subsection (c), including by withholding approved vendor or designee status. The Agency may require the entity to enter into a corrective action plan. An entity that is not recertified for failing to meet required equity actions in subparagraph (c-10) may reapply once they have a corrective action plan and achieve compliance with the minimum equity standards.

(d) Clean coal portfolio standard.

(1) The procurement plans shall include electricity generated using clean coal. Each utility shall enter into one or more sourcing agreements with the initial clean coal facility, as provided in paragraph (3) of this subsection (d), covering electricity generated by the initial clean coal facility representing at least 5% of each utility's total supply to serve the load of eligible retail customers in 2015 and each year thereafter, as described in paragraph (3) of this subsection (d), subject to the limits specified in paragraph (2) of this subsection (d). It is the goal of the State that by January 1, 2025, 25% of the electricity used in the State shall be generated by cost-effective clean coal facilities. For purposes of this subsection (d), "cost-effective" means that the expenditures pursuant to such sourcing agreements do not cause the limit stated in paragraph (2) of this subsection (d) to be exceeded and do not exceed cost-based benchmarks, which shall be developed to assess all expenditures pursuant to such sourcing agreements covering electricity generated by clean coal facilities, other than the initial clean coal facility, by the procurement administrator, in consultation with the Commission staff, Agency staff, and the procurement monitor and shall be subject to Commission review and approval.

A utility party to a sourcing agreement shall immediately retire any emission credits that it receives in connection with the electricity covered by such agreement.

Utilities shall maintain adequate records documenting the purchases under the sourcing agreement to comply with this subsection (d) and shall file an accounting with the load forecast that must be filed with the Agency by July 15 of each year, in accordance with subsection (d) of Section 16-111.5 of the Public Utilities Act.

A utility shall be deemed to have complied with the clean coal portfolio standard specified in this subsection (d) if the utility enters into a sourcing agreement as required by this subsection (d).

(2) For purposes of this subsection (d), the required execution of sourcing agreements with the initial clean coal facility for a particular year shall be measured as a percentage of the actual amount of electricity (megawatt-hours) supplied by the electric utility to eligible retail customers in the planning year ending immediately prior to the agreement's execution. For purposes of this subsection (d), the amount paid per kilowatthour means the total amount paid for electric service expressed on a per kilowatthour basis. For purposes of this subsection (d), the total amount paid for electric service includes without limitation amounts paid for supply, transmission, distribution, surcharges and add-on taxes.

Notwithstanding the requirements of this subsection (d), the total amount paid under sourcing agreements with clean coal facilities pursuant to the procurement plan for any given year shall be reduced by an amount necessary to limit the annual estimated average net increase due to the costs of these resources included in the amounts paid by eligible retail customers in connection with electric service to:

(A) in 2010, no more than 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009;

(B) in 2011, the greater of an additional 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2010 or 1% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009;

(C) in 2012, the greater of an additional 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2011 or 1.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009;

(D) in 2013, the greater of an additional 0.5% of the amount paid per kilowatthour by those customers during the year ending May 31, 2012 or 2% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009; and

(E) thereafter, the total amount paid under sourcing agreements with clean coal facilities pursuant to the procurement plan for any single year shall be reduced by an amount necessary to limit the estimated average net increase due to the cost of these resources included in the amounts paid by eligible retail customers in connection with electric service to no more than the greater of (i) 2.015% of the amount paid per kilowatthour by those customers during the year ending May 31, 2009 or (ii) the incremental amount per kilowatthour paid for these resources in 2013. These requirements may be altered only as provided by statute.

No later than June 30, 2015, the Commission shall review the limitation on the total amount paid under sourcing agreements, if any, with clean coal facilities pursuant to this subsection (d) and report to the General Assembly its findings as to whether that limitation unduly constrains the amount of electricity generated by cost-effective clean coal facilities that is covered by sourcing agreements.

(3) Initial clean coal facility. In order to promote development of clean coal facilities in Illinois, each electric utility subject to this Section shall execute a sourcing agreement to source electricity from a proposed clean coal facility in Illinois (the "initial clean coal facility") that will have a nameplate capacity of at least 500 MW when commercial operation commences, that has a final Clean Air Act permit on June 1, 2009 (the effective date of Public Act 95-1027), and that will meet the definition of clean coal facility in Section 1-10 of this Act when commercial operation commences. The sourcing agreements with this initial clean coal facility shall be subject to both approval of the initial clean coal facility by the General Assembly and satisfaction of the requirements of paragraph (4) of this subsection (d) and shall be executed within 90 days after any such approval by the General Assembly. The Agency and the Commission shall have authority to inspect all books and records associated with the initial clean coal facility during the term of such a sourcing agreement. A utility's sourcing agreement for electricity produced by the initial clean coal facility shall include:

(A) a formula contractual price (the "contract price") approved pursuant to paragraph (4) of this subsection (d), which shall:

(i) be determined using a cost of service methodology employing either a level or deferred capital recovery component, based on a capital structure consisting of 45% equity and 55% debt, and a return on equity as may be approved by the Federal Energy Regulatory Commission, which in any case may not exceed the lower of 11.5% or the rate of return approved by the General Assembly pursuant to paragraph (4) of this subsection (d); and

(ii) provide that all miscellaneous net revenue, including but not limited to net revenue from the sale of emission allowances, if any, substitute natural gas, if any, grants or other support provided by the State of Illinois or the United States Government, firm transmission rights, if any, by-products produced by the facility, energy or capacity derived from the facility and not covered by a sourcing agreement pursuant to paragraph (3) of this subsection (d) or item (5) of subsection (d) of Section 16-115 of the Public Utilities Act, whether generated from the synthesis gas derived from coal, from SNG, or from natural gas, shall be credited against the revenue requirement for this initial clean coal facility;

(B) power purchase provisions, which shall:

(i) provide that the utility party to such sourcing agreement shall pay the contract price for electricity delivered under such sourcing agreement;

(ii) require delivery of electricity to the regional transmission organization market of the utility that is party to such sourcing agreement;

(iii) require the utility party to such sourcing agreement to buy from the initial clean coal facility in each hour an amount of energy equal to all clean coal energy made available from the initial clean coal facility during such hour times a fraction, the numerator of which is such utility's retail market sales of electricity (expressed in kilowatthours sold) in the State during the prior calendar month and the denominator of which is the total retail market sales of electricity (expressed in kilowatthours sold) in the State by utilities during such prior month and the sales of electricity (expressed in kilowatthours sold) in the State by alternative retail electric suppliers during such prior month that are subject to the requirements of this subsection (d) and paragraph (5) of subsection (d) of Section 16-115 of the Public Utilities Act, provided that the amount purchased by the utility in any year will be limited by paragraph (2) of this subsection (d); and

(iv) be considered pre-existing contracts in such utility's procurement plans for eligible retail customers;

(C) contract for differences provisions, which shall:

(i) require the utility party to such sourcing agreement to contract with the initial clean coal facility in each hour with respect to an amount of energy equal to all clean coal energy made available from the initial clean coal facility during such hour times a fraction, the numerator of which is such utility's retail market sales of electricity (expressed in kilowatthours sold) in the utility's service territory in the State during the prior calendar month and the denominator of which is the total retail market sales of electricity (expressed in kilowatthours sold) in the State by utilities during such prior month and the sales of electricity (expressed in kilowatthours sold) in the State by alternative retail electric suppliers during such prior month that are subject to the requirements of this subsection (d) and paragraph (5) of subsection (d) of Section 16-115 of the Public Utilities Act, provided that the amount paid by the utility in any year will be limited by paragraph (2) of this subsection (d);

(ii) provide that the utility's payment obligation in respect of the quantity of electricity determined pursuant to the preceding clause (i) shall be limited to an amount equal to (1) the difference between the contract price determined pursuant to subparagraph (A) of paragraph (3) of this subsection (d) and the day-ahead price for electricity delivered to the regional transmission organization market of the utility that is party to such sourcing agreement (or any successor delivery point at which such utility's supply obligations are financially settled on an hourly basis) (the "reference price") on the day preceding the day on which the electricity is delivered to the initial clean coal facility busbar, multiplied by (2) the quantity of electricity determined pursuant to the preceding clause (i); and

(iii) not require the utility to take physical delivery of the electricity produced by the facility;

(D) general provisions, which shall:

(i) specify a term of no more than 30 years, commencing on the commercial operation date of the facility;

(ii) provide that utilities shall maintain adequate records documenting purchases under the sourcing agreements entered into to comply with this subsection (d) and shall file an accounting with the load forecast that must be filed with the Agency by July 15 of each year, in accordance with subsection (d) of Section 16-111.5 of the Public Utilities Act;

(iii) provide that all costs associated with the initial clean coal facility will be periodically reported to the Federal Energy Regulatory Commission and to purchasers in accordance with applicable laws governing cost-based wholesale power contracts;

(iv) permit the Illinois Power Agency to assume ownership of the initial clean coal facility, without monetary consideration and otherwise on reasonable terms acceptable to the Agency, if the Agency so requests no less than 3 years prior to the end of the stated contract term;

(v) require the owner of the initial clean coal facility to provide documentation to the Commission each year, starting in the facility's first year of commercial operation, accurately reporting the quantity of carbon emissions from the facility that have been captured and sequestered and report any quantities of carbon released from the site or sites at which carbon emissions were sequestered in prior years, based on continuous monitoring of such sites. If, in any year after the first year of commercial operation, the owner of the facility fails to demonstrate that the initial clean coal facility captured and sequestered at least 50% of the total carbon emissions that the facility would otherwise emit or that sequestration of emissions from prior years has failed, resulting in the release of carbon dioxide into the atmosphere, the owner of the facility must offset excess emissions. Any such carbon offsets must be permanent, additional, verifiable, real, located within the State of Illinois, and legally and practicably enforceable. The cost of such offsets for the facility that are not recoverable shall not exceed $15 million in any given year. No costs of any such purchases of carbon offsets may be recovered from a utility or its customers. All carbon offsets purchased for this purpose and any carbon emission credits associated with sequestration of carbon from the facility must be permanently retired. The initial clean coal facility shall not forfeit its designation as a clean coal facility if the facility fails to fully comply with the applicable carbon sequestration requirements in any given year, provided the requisite offsets are purchased. However, the Attorney General, on behalf of the People of the State of Illinois, may specifically enforce the facility's sequestration requirement and the other terms of this contract provision. Compliance with the sequestration requirements and offset purchase requirements specified in paragraph (3) of this subsection (d) shall be reviewed annually by an independent expert retained by the owner of the initial clean coal facility, with the advance written approval of the Attorney General. The Commission may, in the course of the review specified in item (vii), reduce the allowable return on equity for the facility if the facility willfully fails to comply with the carbon capture and sequestration requirements set forth in this item (v);

(vi) include limits on, and accordingly provide for modification of, the amount the utility is required to source under the sourcing agreement consistent with paragraph (2) of this subsection (d);

(vii) require Commission review: (1) to determine the justness, reasonableness, and prudence of the inputs to the formula referenced in subparagraphs (A)(i) through (A)(iii) of paragraph (3) of this subsection (d), prior to an adjustment in those inputs including, without limitation, the capital structure and return on equity, fuel costs, and other operations and maintenance costs and (2) to approve the costs to be passed through to customers under the sourcing agreement by which the utility satisfies its statutory obligations. Commission review shall occur no less than every 3 years, regardless of whether any adjustments have been proposed, and shall be completed within 9 months;

(viii) limit the utility's obligation to such amount as the utility is allowed to recover through tariffs filed with the Commission, provided that neither the clean coal facility nor the utility waives any right to assert federal pre-emption or any other argument in response to a purported disallowance of recovery costs;

(ix) limit the utility's or alternative retail electric supplier's obligation to incur any liability until such time as the facility is in commercial operation and generating power and energy and such power and energy is being delivered to the facility busbar;

(x) provide that the owner or owners of the initial clean coal facility, which is the counterparty to such sourcing agreement, shall have the right from time to time to elect whether the obligations of the utility party thereto shall be governed by the power purchase provisions or the contract for differences provisions;

(xi) append documentation showing that the formula rate and contract, insofar as they relate to the power purchase provisions, have been approved by the Federal Energy Regulatory Commission pursuant to Section 205 of the Federal Power Act;

(xii) provide that any changes to the terms of the contract, insofar as such changes relate to the power purchase provisions, are subject to review under the public interest standard applied by the Federal Energy Regulatory Commission pursuant to Sections 205 and 206 of the Federal Power Act; and

(xiii) conform with customary lender requirements in power purchase agreements used as the basis for financing non-utility generators.

(4) Effective date of sourcing agreements with the initial clean coal facility. Any proposed sourcing agreement with the initial clean coal facility shall not become effective unless the following reports are prepared and submitted and authorizations and approvals obtained:

(i) Facility cost report. The owner of the initial clean coal facility shall submit to the Commission, the Agency, and the General Assembly a front-end engineering and design study, a facility cost report, method of financing (including but not limited to structure and associated costs), and an operating and maintenance cost quote for the facility (collectively "facility cost report"), which shall be prepared in accordance with the requirements of this paragraph (4) of subsection (d) of this Section, and shall provide the Commission and the Agency access to the work papers, relied upon documents, and any other backup documentation related to the facility cost report.

(ii) Commission report. Within 6 months following receipt of the facility cost report, the Commission, in consultation with the Agency, shall submit a report to the General Assembly setting forth its analysis of the facility cost report. Such report shall include, but not be limited to, a comparison of the costs associated with electricity generated by the initial clean coal facility to the costs associated with electricity generated by other types of generation facilities, an analysis of the rate impacts on residential and small business customers over the life of the sourcing agreements, and an analysis of the likelihood that the initial clean coal facility will commence commercial operation by and be delivering power to the facility's busbar by 2016. To assist in the preparation of its report, the Commission, in consultation with the Agency, may hire one or more experts or consultants, the costs of which shall be paid for by the owner of the initial clean coal facility. The Commission and Agency may begin the process of selecting such experts or consultants prior to receipt of the facility cost report.

(iii) General Assembly approval. The proposed sourcing agreements shall not take effect unless, based on the facility cost report and the Commission's report, the General Assembly enacts authorizing legislation approving (A) the projected price, stated in cents per kilowatthour, to be charged for electricity generated by the initial clean coal facility, (B) the projected impact on residential and small business customers' bills over the life of the sourcing agreements, and (C) the maximum allowable return on equity for the project; and

(iv) Commission review. If the General Assembly enacts authorizing legislation pursuant to subparagraph (iii) approving a sourcing agreement, the Commission shall, within 90 days of such enactment, complete a review of such sourcing agreement. During such time period, the Commission shall implement any directive of the General Assembly, resolve any disputes between the parties to the sourcing agreement concerning the terms of such agreement, approve the form of such agreement, and issue an order finding that the sourcing agreement is prudent and reasonable.

The facility cost report shall be prepared as follows:

(A) The facility cost report shall be prepared by duly licensed engineering and construction firms detailing the estimated capital costs payable to one or more contractors or suppliers for the engineering, procurement and construction of the components comprising the initial clean coal facility and the estimated costs of operation and maintenance of the facility. The facility cost report shall include:

(i) an estimate of the capital cost of the core plant based on one or more front end engineering and design studies for the gasification island and related facilities. The core plant shall include all civil, structural, mechanical, electrical, control, and safety systems.

(ii) an estimate of the capital cost of the balance of the plant, including any capital costs associated with sequestration of carbon dioxide emissions and all interconnects and interfaces required to operate the facility, such as transmission of electricity, construction or backfeed power supply, pipelines to transport substitute natural gas or carbon dioxide, potable water supply, natural gas supply, water supply, water discharge, landfill, access roads, and coal delivery.

The quoted construction costs shall be expressed in nominal dollars as of the date that the quote is prepared and shall include capitalized financing costs during construction, taxes, insurance, and other owner's costs, and an assumed escalation in materials and labor beyond the date as of which the construction cost quote is expressed.

(B) The front end engineering and design study for the gasification island and the cost study for the balance of plant shall include sufficient design work to permit quantification of major categories of materials, commodities and labor hours, and receipt of quotes from vendors of major equipment required to construct and operate the clean coal facility.

(C) The facility cost report shall also include an operating and maintenance cost quote that will provide the estimated cost of delivered fuel, personnel, maintenance contracts, chemicals, catalysts, consumables, spares, and other fixed and variable operations and maintenance costs. The delivered fuel cost estimate will be provided by a recognized third party expert or experts in the fuel and transportation industries. The balance of the operating and maintenance cost quote, excluding delivered fuel costs, will be developed based on the inputs provided by duly licensed engineering and construction firms performing the construction cost quote, potential vendors under long-term service agreements and plant operating agreements, or recognized third party plant operator or operators.

The operating and maintenance cost quote (including the cost of the front end engineering and design study) shall be expressed in nominal dollars as of the date that the quote is prepared and shall include taxes, insurance, and other owner's costs, and an assumed escalation in materials and labor beyond the date as of which the operating and maintenance cost quote is expressed.

(D) The facility cost report shall also include an analysis of the initial clean coal facility's ability to deliver power and energy into the applicable regional transmission organization markets and an analysis of the expected capacity factor for the initial clean coal facility.

(E) Amounts paid to third parties unrelated to the owner or owners of the initial clean coal facility to prepare the core plant construction cost quote, including the front end engineering and design study, and the operating and maintenance cost quote will be reimbursed through Coal Development Bonds.

(5) Re-powering and retrofitting coal-fired power plants previously owned by Illinois utilities to qualify as clean coal facilities. During the 2009 procurement planning process and thereafter, the Agency and the Commission shall consider sourcing agreements covering electricity generated by power plants that were previously owned by Illinois utilities and that have been or will be converted into clean coal facilities, as defined by Section 1-10 of this Act. Pursuant to such procurement planning process, the owners of such facilities may propose to the Agency sourcing agreements with utilities and alternative retail electric suppliers required to comply with subsection (d) of this Section and item (5) of subsection (d) of Section 16-115 of the Public Utilities Act, covering electricity generated by such facilities. In the case of sourcing agreements that are power purchase agreements, the contract price for electricity sales shall be established on a cost of service basis. In the case of sourcing agreements that are contracts for differences, the contract price from which the reference price is subtracted shall be established on a cost of service basis. The Agency and the Commission may approve any such utility sourcing agreements that do not exceed cost-based benchmarks developed by the procurement administrator, in consultation with the Commission staff, Agency staff and the procurement monitor, subject to Commission review and approval. The Commission shall have authority to inspect all books and records associated with these clean coal facilities during the term of any such contract.

(6) Costs incurred under this subsection (d) or pursuant to a contract entered into under this subsection (d) shall be deemed prudently incurred and reasonable in amount and the electric utility shall be entitled to full cost recovery pursuant to the tariffs filed with the Commission.

(d-5) Zero emission standard.

(1) Beginning with the delivery year commencing on June 1, 2017, the Agency shall, for electric utilities that serve at least 100,000 retail customers in this State, procure contracts with zero emission facilities that are reasonably capable of generating cost-effective zero emission credits in an amount approximately equal to 16% of the actual amount of electricity delivered by each electric utility to retail customers in the State during calendar year 2014. For an electric utility serving fewer than 100,000 retail customers in this State that requested, under Section 16-111.5 of the Public Utilities Act, that the Agency procure power and energy for all or a portion of the utility's Illinois load for the delivery year commencing June 1, 2016, the Agency shall procure contracts with zero emission facilities that are reasonably capable of generating cost-effective zero emission credits in an amount approximately equal to 16% of the portion of power and energy to be procured by the Agency for the utility. The duration of the contracts procured under this subsection (d-5) shall be for a term of 10 years ending May 31, 2027. The quantity of zero emission credits to be procured under the contracts shall be all of the zero emission credits generated by the zero emission facility in each delivery year; however, if the zero emission facility is owned by more than one entity, then the quantity of zero emission credits to be procured under the contracts shall be the amount of zero emission credits that are generated from the portion of the zero emission facility that is owned by the winning supplier.

The 16% value identified in this paragraph (1) is the average of the percentage targets in subparagraph (B) of paragraph (1) of subsection (c) of this Section for the 5 delivery years beginning June 1, 2017.

The procurement process shall be subject to the following provisions:

(A) Those zero emission facilities that intend to participate in the procurement shall submit to the Agency the following eligibility information for each zero emission facility on or before the date established by the Agency:

(i) the in-service date and remaining useful life of the zero emission facility;

(ii) the amount of power generated annually for each of the years 2005 through 2015, and the projected zero emission credits to be generated over the remaining useful life of the zero emission facility, which shall be used to determine the capability of each facility;

(iii) the annual zero emission facility cost projections, expressed on a per megawatthour basis, over the next 6 delivery years, which shall include the following: operation and maintenance expenses; fully allocated overhead costs, which shall be allocated using the methodology developed by the Institute for Nuclear Power Operations; fuel expenditures; non-fuel capital expenditures; spent fuel expenditures; a return on working capital; the cost of operational and market risks that could be avoided by ceasing operation; and any other costs necessary for continued operations, provided that "necessary" means, for purposes of this item (iii), that the costs could reasonably be avoided only by ceasing operations of the zero emission facility; and

(iv) a commitment to continue operating, for the duration of the contract or contracts executed under the procurement held under this subsection (d-5), the zero emission facility that produces the zero emission credits to be procured in the procurement.

The information described in item (iii) of this subparagraph (A) may be submitted on a confidential basis and shall be treated and maintained by the Agency, the procurement administrator, and the Commission as confidential and proprietary and exempt from disclosure under subparagraphs (a) and (g) of paragraph (1) of Section 7 of the Freedom of Information Act. The Office of Attorney General shall have access to, and maintain the confidentiality of, such information pursuant to Section 6.5 of the Attorney General Act.

(B) The price for each zero emission credit procured under this subsection (d-5) for each delivery year shall be in an amount that equals the Social Cost of Carbon, expressed on a price per megawatthour basis. However, to ensure that the procurement remains affordable to retail customers in this State if electricity prices increase, the price in an applicable delivery year shall be reduced below the Social Cost of Carbon by the amount ("Price Adjustment") by which the market price index for the applicable delivery year exceeds the baseline market price index for the consecutive 12-month period ending May 31, 2016. If the Price Adjustment is greater than or equal to the Social Cost of Carbon in an applicable delivery year, then no payments shall be due in that delivery year. The components of this calculation are defined as follows:

(i) Social Cost of Carbon: The Social Cost of Carbon is $16.50 per megawatthour, which is based on the U.S. Interagency Working Group on Social Cost of Carbon's price in the August 2016 Technical Update using a 3% discount rate, adjusted for inflation for each year of the program. Beginning with the delivery year commencing June 1, 2023, the price per megawatthour shall increase by $1 per megawatthour, and continue to increase by an additional $1 per megawatthour each delivery year thereafter.

(ii) Baseline market price index: The baseline market price index for the consecutive 12-month period ending May 31, 2016 is $31.40 per megawatthour, which is based on the sum of (aa) the average day-ahead energy price across all hours of such 12-month period at the PJM Interconnection LLC Northern Illinois Hub, (bb) 50% multiplied by the Base Residual Auction, or its successor, capacity price for the rest of the RTO zone group determined by PJM Interconnection LLC, divided by 24 hours per day, and (cc) 50% multiplied by the Planning Resource Auction, or its successor, capacity price for Zone 4 determined by the Midcontinent Independent System Operator, Inc., divided by 24 hours per day.

(iii) Market price index: The market price index for a delivery year shall be the sum of projected energy prices and projected capacity prices determined as follows:

(aa) Projected energy prices: the projected energy prices for the applicable delivery year shall be calculated once for the year using the forward market price for the PJM Interconnection, LLC Northern Illinois Hub. The forward market price shall be calculated as follows: the energy forward prices for each month of the applicable delivery year averaged for each trade date during the calendar year immediately preceding that delivery year to produce a single energy forward price for the delivery year. The forward market price calculation shall use data published by the Intercontinental Exchange, or its successor.

(bb) Projected capacity prices:

(I) For the delivery years commencing June 1, 2017, June 1, 2018, and June 1, 2019, the projected capacity price shall be equal to the sum of (1) 50% multiplied by the Base Residual Auction, or its successor, price for the rest of the RTO zone group as determined by PJM Interconnection LLC, divided by 24 hours per day and, (2) 50% multiplied by the resource auction price determined in the resource auction administered by the Midcontinent Independent System Operator, Inc., in which the largest percentage of load cleared for Local Resource Zone 4, divided by 24 hours per day, and where such price is determined by the Midcontinent Independent System Operator, Inc.

(II) For the delivery year commencing June 1, 2020, and each year thereafter, the projected capacity price shall be equal to the sum of (1) 50% multiplied by the Base Residual Auction, or its successor, price for the ComEd zone as determined by PJM Interconnection LLC, divided by 24 hours per day, and (2) 50% multiplied by the resource auction price determined in the resource auction administered by the Midcontinent Independent System Operator, Inc., in which the largest percentage of load cleared for Local Resource Zone 4, divided by 24 hours per day, and where such price is determined by the Midcontinent Independent System Operator, Inc.

For purposes of this subsection (d-5):

"Rest of the RTO" and "ComEd Zone" shall have the meaning ascribed to them by PJM Interconnection, LLC.

"RTO" means regional transmission organization.

(C) No later than 45 days after June 1, 2017 (the effective date of Public Act 99-906), the Agency shall publish its proposed zero emission standard procurement plan. The plan shall be consistent with the provisions of this paragraph (1) and shall provide that winning bids shall be selected based on public interest criteria that include, but are not limited to, minimizing carbon dioxide emissions that result from electricity consumed in Illinois and minimizing sulfur dioxide, nitrogen oxide, and particulate matter emissions that adversely affect the citizens of this State. In particular, the selection of winning bids shall take into account the incremental environmental benefits resulting from the procurement, such as any existing environmental benefits that are preserved by the procurements held under Public Act 99-906 and would cease to exist if the procurements were not held, including the preservation of zero emission facilities. The plan shall also describe in detail how each public interest factor shall be considered and weighted in the bid selection process to ensure that the public interest criteria are applied to the procurement and given full effect.

For purposes of developing the plan, the Agency shall consider any reports issued by a State agency, board, or commission under House Resolution 1146 of the 98th General Assembly and paragraph (4) of subsection (d) of this Section, as well as publicly available analyses and studies performed by or for regional transmission organizations that serve the State and their independent market monitors.

Upon publishing of the zero emission standard procurement plan, copies of the plan shall be posted and made publicly available on the Agency's website. All interested parties shall have 10 days following the date of posting to provide comment to the Agency on the plan. All comments shall be posted to the Agency's website. Following the end of the comment period, but no more than 60 days later than June 1, 2017 (the effective date of Public Act 99-906), the Agency shall revise the plan as necessary based on the comments received and file its zero emission standard procurement plan with the Commission.

If the Commission determines that the plan will result in the procurement of cost-effective zero emission credits, then the Commission shall, after notice and hearing, but no later than 45 days after the Agency filed the plan, approve the plan or approve with modification. For purposes of this subsection (d-5), "cost effective" means the projected costs of procuring zero emission credits from zero emission facilities do not cause the limit stated in paragraph (2) of this subsection to be exceeded.

(C-5) As part of the Commission's review and acceptance or rejection of the procurement results, the Commission shall, in its public notice of successful bidders:

(i) identify how the winning bids satisfy the public interest criteria described in subparagraph (C) of this paragraph (1) of minimizing carbon dioxide emissions that result from electricity consumed in Illinois and minimizing sulfur dioxide, nitrogen oxide, and particulate matter emissions that adversely affect the citizens of this State;

(ii) specifically address how the selection of winning bids takes into account the incremental environmental benefits resulting from the procurement, including any existing environmental benefits that are preserved by the procurements held under Public Act 99-906 and would have ceased to exist if the procurements had not been held, such as the preservation of zero emission facilities;

(iii) quantify the environmental benefit of preserving the resources identified in item (ii) of this subparagraph (C-5), including the following:

(aa) the value of avoided greenhouse gas emissions measured as the product of the zero emission facilities' output over the contract term multiplied by the U.S. Environmental Protection Agency eGrid subregion carbon dioxide emission rate and the U.S. Interagency Working Group on Social Cost of Carbon's price in the August 2016 Technical Update using a 3% discount rate, adjusted for inflation for each delivery year; and

(bb) the costs of replacement with other zero carbon dioxide resources, including wind and photovoltaic, based upon the simple average of the following:

(I) the price, or if there is more than one price, the average of the prices, paid for renewable energy credits from new utility-scale wind projects in the procurement events specified in item (i) of subparagraph (G) of paragraph (1) of subsection (c) of this Section; and

(II) the price, or if there is more than one price, the average of the prices, paid for renewable energy credits from new utility-scale solar projects and brownfield site photovoltaic projects in the procurement events specified in item (ii) of subparagraph (G) of paragraph (1) of subsection (c) of this Section and, after January 1, 2015, renewable energy credits from photovoltaic distributed generation projects in procurement events held under subsection (c) of this Section.

Each utility shall enter into binding contractual arrangements with the winning suppliers.

The procurement described in this subsection (d-5), including, but not limited to, the execution of all contracts procured, shall be completed no later than May 10, 2017. Based on the effective date of Public Act 99-906, the Agency and Commission may, as appropriate, modify the various dates and timelines under this subparagraph and subparagraphs (C) and (D) of this paragraph (1). The procurement and plan approval processes required by this subsection (d-5) shall be conducted in conjunction with the procurement and plan approval processes required by subsection (c) of this Section and Section 16-111.5 of the Public Utilities Act, to the extent practicable. Notwithstanding whether a procurement event is conducted under Section 16-111.5 of the Public Utilities Act, the Agency shall immediately initiate a procurement process on June 1, 2017 (the effective date of Public Act 99-906).

(D) Following the procurement event described in this paragraph (1) and consistent with subparagraph (B) of this paragraph (1), the Agency shall calculate the payments to be made under each contract for the next delivery year based on the market price index for that delivery year. The Agency shall publish the payment calculations no later than May 25, 2017 and every May 25 thereafter.

(E) Notwithstanding the requirements of this subsection (d-5), the contracts executed under this subsection (d-5) shall provide that the zero emission facility may, as applicable, suspend or terminate performance under the contracts in the following instances:

(i) A zero emission facility shall be excused from its performance under the contract for any cause beyond the control of the resource, including, but not restricted to, acts of God, flood, drought, earthquake, storm, fire, lightning, epidemic, war, riot, civil disturbance or disobedience, labor dispute, labor or material shortage, sabotage, acts of public enemy, explosions, orders, regulations or restrictions imposed by governmental, military, or lawfully established civilian authorities, which, in any of the foregoing cases, by exercise of commercially reasonable efforts the zero emission facility could not reasonably have been expected to avoid, and which, by the exercise of commercially reasonable efforts, it has been unable to overcome. In such event, the zero emission facility shall be excused from performance for the duration of the event, including, but not limited to, delivery of zero emission credits, and no payment shall be due to the zero emission facility during the duration of the event.

(ii) A zero emission facility shall be permitted to terminate the contract if legislation is enacted into law by the General Assembly that imposes or authorizes a new tax, special assessment, or fee on the generation of electricity, the ownership or leasehold of a generating unit, or the privilege or occupation of such generation, ownership, or leasehold of generation units by a zero emission facility. However, the provisions of this item (ii) do not apply to any generally applicable tax, special assessment or fee, or requirements imposed by federal law.

(iii) A zero emission facility shall be permitted to terminate the contract in the event that the resource requires capital expenditures in excess of $40,000,000 that were neither known nor reasonably foreseeable at the time it executed the contract and that a prudent owner or operator of such resource would not undertake.

(iv) A zero emission facility shall be permitted to terminate the contract in the event the Nuclear Regulatory Commission terminates the resource's license.

(F) If the zero emission facility elects to terminate a contract under subparagraph (E) of this paragraph (1), then the Commission shall reopen the docket in which the Commission approved the zero emission standard procurement plan under subparagraph (C) of this paragraph (1) and, after notice and hearing, enter an order acknowledging the contract termination election if such termination is consistent with the provisions of this subsection (d-5).

(2) For purposes of this subsection (d-5), the amount paid per kilowatthour means the total amount paid for electric service expressed on a per kilowatthour basis. For purposes of this subsection (d-5), the total amount paid for electric service includes, without limitation, amounts paid for supply, transmission, distribution, surcharges, and add-on taxes.

Notwithstanding the requirements of this subsection (d-5), the contracts executed under this subsection (d-5) shall provide that the total of zero emission credits procured under a procurement plan shall be subject to the limitations of this paragraph (2). For each delivery year, the contractual volume receiving payments in such year shall be reduced for all retail customers based on the amount necessary to limit the net increase that delivery year to the costs of those credits included in the amounts paid by eligible retail customers in connection with electric service to no more than 1.65% of the amount paid per kilowatthour by eligible retail customers during the year ending May 31, 2009. The result of this computation shall apply to and reduce the procurement for all retail customers, and all those customers shall pay the same single, uniform cents per kilowatthour charge under subsection (k) of Section 16-108 of the Public Utilities Act. To arrive at a maximum dollar amount of zero emission credits to be paid for the particular delivery year, the resulting per kilowatthour amount shall be applied to the actual amount of kilowatthours of electricity delivered by the electric utility in the delivery year immediately prior to the procurement, to all retail customers in its service territory. Unpaid contractual volume for any delivery year shall be paid in any subsequent delivery year in which such payments can be made without exceeding the amount specified in this paragraph (2). The calculations required by this paragraph (2) shall be made only once for each procurement plan year. Once the determination as to the amount of zero emission credits to be paid is made based on the calculations set forth in this paragraph (2), no subsequent rate impact determinations shall be made and no adjustments to those contract amounts shall be allowed. All costs incurred under those contracts and in implementing this subsection (d-5) shall be recovered by the electric utility as provided in this Section.

No later than June 30, 2019, the Commission shall review the limitation on the amount of zero emission credits procured under this subsection (d-5) and report to the General Assembly its findings as to whether that limitation unduly constrains the procurement of cost-effective zero emission credits.

(3) Six years after the execution of a contract under this subsection (d-5), the Agency shall determine whether the actual zero emission credit payments received by the supplier over the 6-year period exceed the Average ZEC Payment. In addition, at the end of the term of a contract executed under this subsection (d-5), or at the time, if any, a zero emission facility's contract is terminated under subparagraph (E) of paragraph (1) of this subsection (d-5), then the Agency shall determine whether the actual zero emission credit payments received by the supplier over the term of the contract exceed the Average ZEC Payment, after taking into account any amounts previously credited back to the utility under this paragraph (3). If the Agency determines that the actual zero emission credit payments received by the supplier over the relevant period exceed the Average ZEC Payment, then the supplier shall credit the difference back to the utility. The amount of the credit shall be remitted to the applicable electric utility no later than 120 days after the Agency's determination, which the utility shall reflect as a credit on its retail customer bills as soon as practicable; however, the credit remitted to the utility shall not exceed the total amount of payments received by the facility under its contract.

For purposes of this Section, the Average ZEC Payment shall be calculated by multiplying the quantity of zero emission credits delivered under the contract times the average contract price. The average contract price shall be determined by subtracting the amount calculated under subparagraph (B) of this paragraph (3) from the amount calculated under subparagraph (A) of this paragraph (3), as follows:

(A) The average of the Social Cost of Carbon, as defined in subparagraph (B) of paragraph (1) of this subsection (d-5), during the term of the contract.

(B) The average of the market price indices, as defined in subparagraph (B) of paragraph (1) of this subsection (d-5), during the term of the contract, minus the baseline market price index, as defined in subparagraph (B) of paragraph (1) of this subsection (d-5).

If the subtraction yields a negative number, then the Average ZEC Payment shall be zero.

(4) Cost-effective zero emission credits procured from zero emission facilities shall satisfy the applicable definitions set forth in Section 1-10 of this Act.

(5) The electric utility shall retire all zero emission credits used to comply with the requirements of this subsection (d-5).

(6) Electric utilities shall be entitled to recover all of the costs associated with the procurement of zero emission credits through an automatic adjustment clause tariff in accordance with subsection (k) and (m) of Section 16-108 of the Public Utilities Act, and the contracts executed under this subsection (d-5) shall provide that the utilities' payment obligations under such contracts shall be reduced if an adjustment is required under subsection (m) of Section 16-108 of the Public Utilities Act.

(7) This subsection (d-5) shall become inoperative on January 1, 2028.

(d-10) Nuclear Plant Assistance; carbon mitigation credits.

(1) The General Assembly finds:

(A) The health, welfare, and prosperity of all Illinois citizens require that the State of Illinois act to avoid and not increase carbon emissions from electric generation sources while continuing to ensure affordable, stable, and reliable electricity to all citizens.

(B) Absent immediate action by the State to preserve existing carbon-free energy resources, those resources may retire, and the electric generation needs of Illinois' retail customers may be met instead by facilities that emit significant amounts of carbon pollution and other harmful air pollutants at a high social and economic cost until Illinois is able to develop other forms of clean energy.

(C) The General Assembly finds that nuclear power generation is necessary for the State's transition to 100% clean energy, and ensuring continued operation of nuclear plants advances environmental and public health interests through providing carbon-free electricity while reducing the air pollution profile of the Illinois energy generation fleet.

(D) The clean energy attributes of nuclear generation facilities support the State in its efforts to achieve 100% clean energy.

(E) The State currently invests in various forms of clean energy, including, but not limited to, renewable energy, energy efficiency, and low-emission vehicles, among others.

(F) The Environmental Protection Agency commissioned an independent audit which provided a detailed assessment of the financial condition of the Illinois nuclear fleet to evaluate its financial viability and whether the environmental benefits of such resources were at risk. The report identified the risk of losing the environmental benefits of several specific nuclear units. The report also identified that the LaSalle County Generating Station will continue to operate through 2026 and therefore is not eligible to participate in the carbon mitigation credit program.

(G) Nuclear plants provide carbon-free energy, which helps to avoid many health-related negative impacts for Illinois residents.

(H) The procurement of carbon mitigation credits representing the environmental benefits of carbon-free generation will further the State's efforts at achieving 100% clean energy and decarbonizing the electricity sector in a safe, reliable, and affordable manner. Further, the procurement of carbon emission credits will enhance the health and welfare of Illinois residents through decreased reliance on more highly polluting generation.

(I) The General Assembly therefore finds it necessary to establish carbon mitigation credits to ensure decreased reliance on more carbon-intensive energy resources, for transitioning to a fully decarbonized electricity sector, and to help ensure health and welfare of the State's residents.

(2) As used in this subsection:

"Baseline costs" means costs used to establish a customer protection cap that have been evaluated through an independent audit of a carbon-free energy resource conducted by the Environmental Protection Agency that evaluated projected annual costs for operation and maintenance expenses; fully allocated overhead costs, which shall be allocated using the methodology developed by the Institute for Nuclear Power Operations; fuel expenditures; nonfuel capital expenditures; spent fuel expenditures; a return on working capital; the cost of operational and market risks that could be avoided by ceasing operation; and any other costs necessary for continued operations, provided that "necessary" means, for purposes of this definition, that the costs could reasonably be avoided only by ceasing operations of the carbon-free energy resource.

"Carbon mitigation credit" means a tradable credit that represents the carbon emission reduction attributes of one megawatt-hour of energy produced from a carbon-free energy resource.

"Carbon-free energy resource" means a generation facility that: (1) is fueled by nuclear power; and (2) is interconnected to PJM Interconnection, LLC.

(3) Procurement.

(A) Beginning with the delivery year commencing on June 1, 2022, the Agency shall, for electric utilities serving at least 3,000,000 retail customers in the State, seek to procure contracts for no more than approximately 54,500,000 cost-effective carbon mitigation credits from carbon-free energy resources because such credits are necessary to support current levels of carbon-free energy generation and ensure the State meets its carbon dioxide emissions reduction goals. The Agency shall not make a partial award of a contract for carbon mitigation credits covering a fractional amount of a carbon-free energy resource's projected output.

(B) Each carbon-free energy resource that intends to participate in a procurement shall be required to submit to the Agency the following information for the resource on or before the date established by the Agency:

(i) the in-service date and remaining useful life of the carbon-free energy resource;

(ii) the amount of power generated annually for each of the past 10 years, which shall be used to determine the capability of each facility;

(iii) a commitment to be reflected in any contract entered into pursuant to this subsection (d-10) to continue operating the carbon-free energy resource at a capacity factor of at least 88% annually on average for the duration of the contract or contracts executed under the procurement held under this subsection (d-10), except in an instance described in subparagraph (E) of paragraph (1) of subsection (d-5) of this Section or made impracticable as a result of compliance with law or regulation;

(iv) financial need and the risk of loss of the environmental benefits of such resource, which shall include the following information:

(I) the carbon-free energy resource's cost projections, expressed on a per megawatt-hour basis, over the next 5 delivery years, which shall include the following: operation and maintenance expenses; fully allocated overhead costs, which shall be allocated using the methodology developed by the Institute for Nuclear Power Operations; fuel expenditures; nonfuel capital expenditures; spent fuel expenditures; a return on working capital; the cost of operational and market risks that could be avoided by ceasing operation; and any other costs necessary for continued operations, provided that "necessary" means, for purposes of this subitem (I), that the costs could reasonably be avoided only by ceasing operations of the carbon-free energy resource; and

(II) the carbon-free energy resource's revenue projections, including energy, capacity, ancillary services, any other direct State support, known or anticipated federal attribute credits, known or anticipated tax credits, and any other direct federal support.

The information described in this subparagraph (B) may be submitted on a confidential basis and shall be treated and maintained by the Agency, the procurement administrator, and the Commission as confidential and proprietary and exempt from disclosure under subparagraphs (a) and (g) of paragraph (1) of Section 7 of the Freedom of Information Act. The Office of the Attorney General shall have access to, and maintain the confidentiality of, such information pursuant to Section 6.5 of the Attorney General Act.

(C) The Agency shall solicit bids for the contracts described in this subsection (d-10) from carbon-free energy resources that have satisfied the requirements of subparagraph (B) of this paragraph (3). The contracts procured pursuant to a procurement event shall reflect, and be subject to, the following terms, requirements, and limitations:

(i) Contracts are for delivery of carbon mitigation credits, and are not energy or capacity sales contracts requiring physical delivery. Pursuant to item (iii), contract payments shall fully deduct the value of any monetized federal production tax credits, credits issued pursuant to a federal clean energy standard, and other federal credits if applicable.

(ii) Contracts for carbon mitigation credits shall commence with the delivery year beginning on June 1, 2022 and shall be for a term of 5 delivery years concluding on May 31, 2027.

(iii) The price per carbon mitigation credit to be paid under a contract for a given delivery year shall be equal to an accepted bid price less the sum of:

(I) one of the following energy price indices, selected by the bidder at the time of the bid for the term of the contract:

(aa) the weighted-average hourly day-ahead price for the applicable delivery year at the busbar of all resources procured pursuant to this subsection (d-10), weighted by actual production from the resources; or

(bb) the projected energy price for the PJM Interconnection, LLC Northern Illinois Hub for the applicable delivery year determined according to subitem (aa) of item (iii) of subparagraph (B) of paragraph (1) of subsection (d-5).

(II) the Base Residual Auction Capacity Price for the ComEd zone as determined by PJM Interconnection, LLC, divided by 24 hours per day, for the applicable delivery year for the first 3 delivery years, and then any subsequent delivery years unless the PJM Interconnection, LLC applies the Minimum Offer Price Rule to participating carbon-free energy resources because they supply carbon mitigation credits pursuant to this Section at which time, upon notice by the carbon-free energy resource to the Commission and subject to the Commission's confirmation, the value under this subitem shall be zero, as further described in the carbon mitigation credit procurement plan; and

(III) any value of monetized federal tax credits, direct payments, or similar subsidy provided to the carbon-free energy resource from any unit of government that is not already reflected in energy prices.

If the price-per-megawatt-hour calculation performed under item (iii) of this subparagraph (C) for a given delivery year results in a net positive value, then the electric utility counterparty to the contract shall multiply such net value by the applicable contract quantity and remit the amount to the supplier.

To protect retail customers from retail rate impacts that may arise upon the initiation of carbon policy changes, if the price-per-megawatt-hour calculation performed under item (iii) of this subparagraph (C) for a given delivery year results in a net negative value, then the supplier counterparty to the contract shall multiply such net value by the applicable contract quantity and remit such amount to the electric utility counterparty. The electric utility shall reflect such amounts remitted by suppliers as a credit on its retail customer bills as soon as practicable.

(iv) To ensure that retail customers in Northern Illinois do not pay more for carbon mitigation credits than the value such credits provide, and notwithstanding the provisions of this subsection (d-10), the Agency shall not accept bids for contracts that exceed a customer protection cap equal to the baseline costs of carbon-free energy resources.

The baseline costs for the applicable year shall be the following:

(I) For the delivery year beginning June 1, 2022, the baseline costs shall be an amount equal to $30.30 per megawatt-hour.

(II) For the delivery year beginning June 1, 2023, the baseline costs shall be an amount equal to $32.50 per megawatt-hour.

(III) For the delivery year beginning June 1, 2024, the baseline costs shall be an amount equal to $33.43 per megawatt-hour.

(IV) For the delivery year beginning June 1, 2025, the baseline costs shall be an amount equal to $33.50 per megawatt-hour.

(V) For the delivery year beginning June 1, 2026, the baseline costs shall be an amount equal to $34.50 per megawatt-hour.

An Environmental Protection Agency consultant forecast, included in a report issued April 14, 2021, projects that a carbon-free energy resource has the opportunity to earn on average approximately $30.28 per megawatt-hour, for the sale of energy and capacity during the time period between 2022 and 2027. Therefore, the sale of carbon mitigation credits provides the opportunity to receive an additional amount per megawatt-hour in addition to the projected prices for energy and capacity.

Although actual energy and capacity prices may vary from year-to-year, the General Assembly finds that this customer protection cap will help ensure that the cost of carbon mitigation credits will be less than its value, based upon the social cost of carbon identified in the Technical Support Document issued in February 2021 by the U.S. Interagency Working Group on Social Cost of Greenhouse Gases and the PJM Interconnection, LLC carbon dioxide marginal emission rate for 2020, and that a carbon-free energy resource receiving payment for carbon mitigation credits receives no more than necessary to keep those units in operation.

(D) No later than 7 days after the effective date of this amendatory Act of the 102nd General Assembly, the Agency shall publish its proposed carbon mitigation credit procurement plan. The Plan shall provide that winning bids shall be selected by taking into consideration which resources best match public interest criteria that include, but are not limited to, minimizing carbon dioxide emissions that result from electricity consumed in Illinois and minimizing sulfur dioxide, nitrogen oxide, and particulate matter emissions that adversely affect the citizens of this State. The selection of winning bids shall also take into account the incremental environmental benefits resulting from the procurement or procurements, such as any existing environmental benefits that are preserved by a procurement held under this subsection (d-10) and would cease to exist if the procurement were not held, including the preservation of carbon-free energy resources. For those bidders having the same public interest criteria score, the relative ranking of such bidders shall be determined by price. The Plan shall describe in detail how each public interest factor shall be considered and weighted in the bid selection process to ensure that the public interest criteria are applied to the procurement. The Plan shall, to the extent practical and permissible by federal law, ensure that successful bidders make commercially reasonable efforts to apply for federal tax credits, direct payments, or similar subsidy programs that support carbon-free generation and for which the successful bidder is eligible. Upon publishing of the carbon mitigation credit procurement plan, copies of the plan shall be posted and made publicly available on the Agency's website. All interested parties shall have 7 days following the date of posting to provide comment to the Agency on the plan. All comments shall be posted to the Agency's website. Following the end of the comment period, but no more than 19 days later than the effective date of this amendatory Act of the 102nd General Assembly, the Agency shall revise the plan as necessary based on the comments received and file its carbon mitigation credit procurement plan with the Commission.

(E) If the Commission determines that the plan is likely to result in the procurement of cost-effective carbon mitigation credits, then the Commission shall, after notice and hearing and opportunity for comment, but no later than 42 days after the Agency filed the plan, approve the plan or approve it with modification. For purposes of this subsection (d-10), "cost-effective" means carbon mitigation credits that are procured from carbon-free energy resources at prices that are within the limits specified in this paragraph (3). As part of the Commission's review and acceptance or rejection of the procurement results, the Commission shall, in its public notice of successful bidders:

(i) identify how the selected carbon-free energy resources satisfy the public interest criteria described in this paragraph (3) of minimizing carbon dioxide emissions that result from electricity consumed in Illinois and minimizing sulfur dioxide, nitrogen oxide, and particulate matter emissions that adversely affect the citizens of this State;

(ii) specifically address how the selection of carbon-free energy resources takes into account the incremental environmental benefits resulting from the procurement, including any existing environmental benefits that are preserved by the procurements held under this amendatory Act of the 102nd General Assembly and would have ceased to exist if the procurements had not been held, such as the preservation of carbon-free energy resources;

(iii) quantify the environmental benefit of preserving the carbon-free energy resources procured pursuant to this subsection (d-10), including the following:

(I) an assessment value of avoided greenhouse gas emissions measured as the product of the carbon-free energy resources' output over the contract term, using generally accepted methodologies for the valuation of avoided emissions; and

(II) an assessment of costs of replacement with other carbon-free energy resources and renewable energy resources, including wind and photovoltaic generation, based upon an assessment of the prices paid for renewable energy credits through programs and procurements conducted pursuant to subsection (c) of Section 1-75 of this Act, and the additional storage necessary to produce the same or similar capability of matching customer usage patterns.

(F) The procurements described in this paragraph (3), including, but not limited to, the execution of all contracts procured, shall be completed no later than December 3, 2021. The procurement and plan approval processes required by this paragraph (3) shall be conducted in conjunction with the procurement and plan approval processes required by Section 16-111.5 of the Public Utilities Act, to the extent practicable. However, the Agency and Commission may, as appropriate, modify the various dates and timelines under this subparagraph and subparagraphs (D) and (E) of this paragraph (3) to meet the December 3, 2021 contract execution deadline. Following the completion of such procurements, and consistent with this paragraph (3), the Agency shall calculate the payments to be made under each contract in a timely fashion.

(F-1) Costs incurred by the electric utility pursuant to a contract authorized by this subsection (d-10) shall be deemed prudently incurred and reasonable in amount, and the electric utility shall be entitled to full cost recovery pursuant to a tariff or tariffs filed with the Commission.

(G) The counterparty electric utility shall retire all carbon mitigation credits used to comply with the requirements of this subsection (d-10).

(H) If a carbon-free energy resource is sold to another owner, the rights, obligations, and commitments under this subsection (d-10) shall continue to the subsequent owner.

(I) This subsection (d-10) shall become inoperative on January 1, 2028.

(d-20) Energy storage system portfolio standard.

(1) The General Assembly finds that the deployment of energy storage systems is necessary to successfully integrate high levels of renewable energy, to avoid the creation and increase of carbon emissions from electric generation sources, and to ensure affordable, stable, clean, reliable, and resilient electricity.

(2) The Agency shall develop an energy storage system resources procurement plan that includes the competitive procurement events, procurement programs, or both, as necessary (i) to meet the goals set forth in this subsection (d-20), (ii) to meet the planning requirements established under Sections 16-201 and 16-202 of the Public Utilities Act, (iii) to meet the clean energy policy established by Public Act 102-662, and (iv) to cause electric utilities serving more than 300,000 customers in the State as of January 1, 2019 to contract for energy storage resources. The energy storage system resources procurement plan approval processes shall be conducted consistent with the processes outlined in paragraph (6) of subsection (b) of Section 16-111.5 of the Public Utilities Act, with the initial energy storage system resources procurement plan released for comment in calendar year 2027. The Agency shall review and may revise the energy storage system resources procurement plan at least every 2 years. The Agency shall establish, and the Commission shall approve or approve as modified, an energy storage system resources procurement plan that includes:

(A) storage targets in addition to the initial procurements specified in paragraph (3) of this subsection (d-20) at levels identified through the integrated resource planning process outlined in Section 16-202 of the Public Utilities Act;

(B) a bid selection process that is based on the bid price, when compared with an equal energy storage duration and interconnected to the same independent system operator (ISO) or regional transmission organization (RTO), and that may provide for consideration of the following:

(i) the project's viability and ability to meet or exceed operational date targets;

(ii) the developer's experience;

(iii) requirements for demonstration of binding site control that are sufficient for proposed energy storage facilities;

(iv) the availability or dependence on any transmission expansion or upgrades needed; and

(v) other resource adequacy and reliability considerations;

(C) consideration of the need to ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time;

(D) proposals for the financial support of energy storage systems using contract models, which may include, but are not limited to, the following:

(i) an indexed storage credit procurement, including payments to energy storage system owners or operators with any offsets and refunds for potential energy and capacity revenues;

(ii) support for energy storage system resources through contract structures that do not create contractual obligations on utilities that are not contingent on full and timely cost recovery, that avoid negative financial impacts on the utilities, and that are agreed upon by the utilities; and

(iii) other approaches as deemed suitable by the Agency and the Commission; and

(E) consideration that the Agency may include a methodology that could prioritize procurement of energy storage resources that are located in communities eligible to receive Energy Transition Community Grants pursuant to Section 10-20 of the Energy Community Reinvestment Act.

In developing its procurement plan and conducting the storage procurements outlined in this paragraph (2) and in paragraph (3), the Agency may use the services of expert consulting firms identified in paragraphs (1) and (2) of subsection (a) of this Section.

(3) Notwithstanding whether an energy storage system resources procurement plan has been approved, the following provisions shall apply to the Agency's initial procurement of energy storage system resources under this subsection (d-20):

(A) The Agency shall conduct an initial energy storage procurement on or before August 26, 2026 or 90 days after the effective date of this amendatory Act of the 104th General Assembly, whichever is earlier. For the purposes of this initial energy storage procurement, the Agency shall conduct a procurement that results in electric utilities that served more than 300,000 customers in the State as of January 1, 2019 contracting for at least 1,038 megawatts of cost-effective stand-alone energy storage systems that can achieve commercial operation on or before December 31, 2029 or an alternative date proposed by the Agency that is no later than December 31, 2030. The procurement target shall be separated for projects interconnected within Midcontinent Independent System Operator Local Resource Zone 4 (MISO Zone 4) and for projects interconnected within the PJM Interconnection, LLC ComEd Locational Deliverability Area (PJM ComEd Area) as follows:

(i) 450 megawatts in MISO Zone 4; and

(ii) 588 megawatts in the PJM ComEd Area.

For purposes of this subsection (d-20), "stand-alone" means systems that are (i) separately metered by a revenue-quality meter that satisfies the requirements of the RTO; (ii) operate independently without constraints or hindrances from other generation units; and (iii) demonstrate the ability to charge and discharge independent of any generation unit output.

(B) The Agency shall conduct a series of additional energy storage procurements that result in electric utilities contracting for energy storage resources in an amount of 3,000 megawatts of cumulative energy storage capacity for projects committed to reaching commercial operation on or before December 31, 2030, or an alternative date proposed by the Agency, subject to extension for a delay due to interconnection of the energy storage system, a delay in obtaining permits necessary to build or operate the energy storage system, or other circumstances at the discretion of the Agency.

The additional energy storage resources procurements shall be conducted in calendar years 2027 and 2028 in a manner that ensures the quantities listed in this subparagraph (B), and as updated in the integrated resource plan approved by the Commission pursuant to Section 16-201 of the Public Utilities Act, are met in the specified timeframe. To the extent the integrated resource planning process outlined in Section 16-202 of the Public Utilities Act authorizes energy storage system procurement amounts above the amount identified in this subparagraph (B), the Agency shall conduct additional energy storage procurements in 2028, 2029, 2030, and thereafter that result in electric utilities contracting for energy storage resources at those additional identified levels. The procurements shall be conducted in a manner that maximizes projects available in the MISO and PJM queues, ensures the likelihood of project development through the development of project maturity requirements, enables sufficient competition for price competitiveness, and aligns to the extent practicable with regional transmission organization study phases. The procurements shall select projects interconnected to MISO Zone 4 and the PJM ComEd Area and shall follow either (i) a similar geographic split to the ratio of quantities established in subparagraph (A) of this paragraph (3), (ii) an alternative geographic split proposed by the Agency based on project availability in advanced stages of the MISO and PJM queues, or (iii) that is informed by MISO and PJM planning activities, auctions, or reports that indicate capacity resource shortages or impending shortages and that reflect the assessments made through the processes outlined in subparagraph (A) of paragraph (2). The additional energy storage capacity procurements may be adjusted upward if determined necessary through the planning process outlined in Section 16-201 of the Public Utilities Act at times determined by the Commission.

(C) The initial energy storage resources procurement under subparagraph (A) of this paragraph (3) shall adopt a standard indexed storage credit contract modeled after the contract and follow a process modeled after the process included in the staff report submitted to the Governor, General Assembly, and Commission pursuant to subsection (g) of Section 16-135 of the Public Utilities Act on May 1, 2025. In developing the procurement rules and procurement process for the initial procurement, the Agency shall provide an opportunity for comment on the indexed storage credit contract included in the May 1, 2025 staff report and shall adopt modifications to the contract consistent with the process outlined in paragraph (2) of subsection (e) of Section 16-111.5 of the Public Utilities Act.

(D) For the additional energy storage resources procurements conducted in accordance with subparagraph (B) of this paragraph (3), the Agency may, among other considerations, consider other contract structures if such contract structures and agreements do not create contractual obligations on utilities that are not contingent on full and timely cost recovery, avoid negative financial impacts on the utilities, and are agreed upon by the participating utility.

(E) The initial and additional energy storage resources procurements under this paragraph (3) shall solicit 20-year contracts.

(F) The Agency shall submit its proposed selection of successful bids for each procurement event pursuant to paragraphs (2) and (3) to the Commission for approval consistent with the processes outlined in Section 16-111.5 of the Public Utilities Act to the extent practicable.

(4) The energy storage system resources procurement plans developed by the Agency may consider alternatives to the initial and additional procurement terms described in paragraph (3) of this subsection (d-20), including, but not limited to:

(A) alternatives to the standard indexed storage credit contract used in the initial terms described in subparagraph (C) of paragraph (3) of this subsection (d-20);

(B) energy storage systems that are not stand-alone;

(C) proportionate allocations between MISO Zone 4 and the PJM ComEd Area that are not based upon load share, including allocations reflecting the assessments made through the processes outlined in subparagraph (A) of paragraph (2);

(D) contract lengths other than 20 years;

(E) energy storage system durations other than 4 hours; and

(F) energy storage systems connected to the distribution systems of the electric utilities.

The Agency may propose specific timelines for energy storage system resources procurements, which may differ across RTO zones, that are based in part upon a consideration of (i) the timing of the release of interconnection cost information through both MISO and PJM interconnection queue processes, (ii) factors that maximize the likelihood of successful project development, (iii) enabling sufficient competition for price competitiveness, and (iv) aligning to the extent practicable with RTO study phases.

(5) The Agency shall procure cost-effective energy storage credits or other contract instruments intended to facilitate the successful development of energy storage projects. The procurement administrator shall establish confidential price benchmarks based on publicly available data on regional technology costs. Confidential price benchmarks shall be developed by the procurement administrator, in consultation with Commission staff, Agency staff, and the procurement monitor, and shall be subject to Commission review and approval. Price benchmarks shall reflect development costs, financing costs, and related costs resulting from requirements imposed through other provisions of State law. As used in this paragraph (5), "cost-effective" means a bidder's bid price that does not exceed confidential price benchmarks.

(6) All procurements under this subsection (d-20) shall comply with the geographic requirements in subparagraph (I) of paragraph (1) of subsection (c) of Section 1-75 and shall follow the procurement processes and procedures described in this Section and Section 16-111.5 of the Public Utilities Act, to the extent practicable. The processes and procedures may be expedited to accommodate the schedule established by this Section. The Agency shall require all bidders to pay to the Agency a nonrefundable deposit determined by the Agency and no less than $10,000 per bid as practical. The Agency may also assess bidder and supplier fees to cover the cost of procurement events and develop collateral requirements to maximize the likelihood of successful project development. Bidders in the initial and additional procurements described in paragraph (3) of this subsection (d-20) shall also demonstrate experience in developing to commercial readiness. As used in this paragraph (6), "developing to commercial readiness" means having notice to proceed in owning or operating energy facilities with a combined nameplate capacity of at least 100 megawatts.

(7) In order to advance priority access to the clean energy economy for businesses and workers from communities that have been excluded from economic opportunities in the energy sector, have been subject to disproportionate levels of pollution, and have disproportionately experienced negative public health outcomes, the Agency shall apply its equity accountability system and minimum equity standards established under subsections (c-10), (c-15), (c-20), (c-25), and (c-30) of this Section to energy storage procurement and programs and may include any proposed modifications to the equity accountability system and minimum equity standards that may be warranted with respect to energy storage resources in its plan submission to the Commission under Section 16-111.5 of the Public Utilities Act.

(8) Projects shall be developed in compliance with the prevailing wage and project labor agreement requirements for renewable energy projects in subparagraph (Q) of paragraph (1) of subsection (c) of Section 1-75.

(9) An entity operating an energy storage facility shall demonstrate that it has entered into a labor peace agreement with a bona fide labor organization that is actively engaged in representing its employees. The labor peace agreement shall apply to the employees necessary for the ongoing maintenance and operation of the energy storage facility. The existence of a labor peace agreement shall be an ongoing material condition of an entity's authorization to maintain and operate the energy storage facility.

(10) In order to promote the competitive development of energy storage systems in furtherance of the State's interest in the health, safety, and welfare of its residents, storage credits shall not be eligible to be selected under this subsection (d-20) if the energy storage resources are sourced from an energy storage system whose costs were being recovered through rates regulated by the State or any other state or states on or after January 1, 2017. No entity shall be permitted to bid unless it certifies to the Agency that it is not an electric utility, as defined in Section 16-102 of the Public Utilities Act, serving more than 10,000 customers in the State.

(11) The Agency shall require, as a prerequisite to payment for any storage credits, that the winning bidder provide the Agency or its designee a copy of the interconnection agreement under which the applicable energy storage system is connected to the transmission or distribution system.

(12) Contracts shall provide that, if the cost recovery mechanism referenced in subsection (k) of Section 16-108 of the Public Utilities Act remains in full force without amendment or the utility is otherwise authorized or entitled to full, prompt, and uninterrupted recovery of its costs through any other mechanism, then such seller shall be entitled to full, prompt, and uninterrupted payment under the applicable contract notwithstanding the application of this paragraph (12).

(13) A hyperscale data center shall have the option to help the Agency meet its future energy storage procurement targets under this subsection (d-20) and thereby reduce its charges collected for the procurement of energy storage resources under this same subsection pursuant to Section 16-108 of the Public Utilities Act. Only hyperscale data centers that develop new energy storage resources that are otherwise eligible for procurements pursued under this subsection (d-20) through the bring your new clean energy option set forth in Section 16-105.9 of the Public Utilities Act and included in their Clean Energy Supply Plan described in that same Section are eligible to help the Agency meet storage procurement targets and thereby offset its energy-storage related charges. The terms and conditions, process, and methodology for establishing a hyperscale data center's contribution to storage procurement targets under this subsection (d-20) and the proportional reduction in charges shall be set by the Agency in its Long Term Energy Storage System Resources Procurement Plan. No hyperscale data center may thereby be credited more than 100% of its energy storage-related charge. New energy storage resources developed by hyperscale data centers do not count toward the Agency's procurement targets required under paragraph (3) of this subsection (d-20).

(e) The draft procurement plans are subject to public comment, as required by Section 16-111.5 of the Public Utilities Act.

(f) The Agency shall submit the final procurement plan to the Commission. The Agency shall revise a procurement plan if the Commission determines that it does not meet the standards set forth in Section 16-111.5 of the Public Utilities Act.

(g) The Agency shall assess fees to each affected utility to recover the costs incurred in preparation of procurement plans and in the operation of programs.

(h) The Agency shall assess fees to each bidder to recover the costs incurred in connection with a competitive procurement process.

(i) A renewable energy credit, carbon emission credit, zero emission credit, or carbon mitigation credit can only be used once to comply with a single portfolio or other standard as set forth in subsection (c), subsection (d), or subsection (d-5) of this Section, respectively. A renewable energy credit, carbon emission credit, zero emission credit, or carbon mitigation credit cannot be used to satisfy the requirements of more than one standard. If more than one type of credit is issued for the same megawatt hour of energy, only one credit can be used to satisfy the requirements of a single standard. After such use, the credit must be retired together with any other credits issued for the same megawatt hour of energy.

(Source: P.A. 103-380, eff. 1-1-24; 103-580, eff. 12-8-23; 103-1066, eff. 2-20-25; 104-458, eff. 6-1-26.)

Section 5-15. The State Finance Act is amended by adding Sections 5.1038 and 5.1039 as follows:

(30 ILCS 105/5.1038 new)

Sec. 5.1038. The Data Center Community Intervenor Compensation Fund.

(30 ILCS 105/5.1039 new)

Sec. 5.1039. The Hyperscale Data Center Public Benefits and Affordability Fund.

Section 5-20. The Public Utilities Act is amended by adding Sections 4-620, 16-105.8, and 16-105.9 as follows:

(220 ILCS 5/4-620 new)

Sec. 4-620. Hyperscale data center energy and water reporting requirements.

(a) The purpose of this Section is to ensure transparency regarding the environmental impacts of new hyperscale data center non-residential facilities operating within the State by requiring the disclosure of energy and water usage data to the Commission.

(b) As used in this Section:

"Energy consumption" means the total amount of electricity or other forms of energy consumed by a hyperscale data center, measured in kilowatt-hours.

"Hyperscale data center" means a facility used primarily or exclusively for electronic information services such as the management, storage, processing, and dissemination of electronic data and information through the use of computer systems, servers, networking equipment, and related components, where the total highest demand established by the facility during the most recent 12 consecutive monthly billing periods or a forecast of its next 12 consecutive monthly billing periods was more than 50,000 kilowatts.

"Hyperscale data center" does not include an entity located within an area approved by the Department of Commerce and Economic Opportunity as a quantum computing campus enterprise zone pursuant to Section 605-1115 of the Department of Commerce and Economic Opportunity Law as of May 1, 2026, or an entity owned and operated by a federally funded research and development center, as defined in 48 CFR 35.017, as of May 1, 2026.

"Water consumption" means the total amount of water consumed by a hyperscale data center, including water used for cooling, measured in gallons.

(c) On and after January 1, 2027, all hyperscale data centers operating within the State shall annually disclose the facility's energy and water consumption data to the Commission for the preceding calendar year. The disclosure shall include:

(1) the total energy consumption for the previous calendar year, broken down by month and specifying the energy source;

(2) total water consumption for the previous calendar year, broken down by month and specifying whether the consumption was for cooling or another application; and

(3) any measures undertaken in the previous calendar year to improve energy efficiency or reduce water usage.

(d) Disclosures shall be submitted to the Commission no later than March 31 of each year.

(e) The information and data required to be disclosed under this Section may be submitted on a confidential basis, shall be treated and maintained by the Commission as confidential and proprietary, and shall be exempt from disclosure under subparagraphs (a) and (g) of paragraph (1) of Section 7 of the Freedom of Information Act. The Office of the Attorney General shall have access to, and maintain the confidentiality of, such information pursuant to Section 6.5 of the Attorney General Act.

(f) The Commission shall make the aggregated and anonymized form of data disclosed to it under this Section available on a publicly accessible webpage.

(g) The Commission shall publish an annual report summarizing statewide energy and water consumption trends in hyperscale data centers, including, but not limited to, legislative recommendations to address identified issues.

(h) Hyperscale data centers that fail to comply with the reporting requirements under this Act may be subject to fines of up to $10,000 per violation. All funds collected under this subsection (h) shall be deposited into the Energy Efficiency Trust Fund.

(i) The Commission shall conduct a comprehensive study on the impact that hyperscale data centers in the State have on rate-paying customers. The study shall include, but is not limited to, the following:

(1) the energy consumption of hyperscale data centers and the facilities' effects on overall electricity demand in the State;

(2) the extent to which hyperscale data centers contribute to electricity rate changes for residential, commercial, and industrial customers;

(3) the environmental impact of hyperscale data centers in the State; and

(4) potential legislation to mitigate any negative impacts of hyperscale data centers on rate-paying customers.

The Commission may hire consultants and experts to conduct the study under this subsection (i) and the retention of the consultants and experts shall be exempt from the requirements of Section 20-10 of the Illinois Procurement Code.

(j) In conducting the study under subsection (i), the Commission shall:

(1) consult with stakeholders, including, but not limited to, public utilities, hyperscale data centers, consumer advocacy groups, and environmental organizations;

(2) analyze data from public utilities and other relevant sources to assess the energy consumption and rate impacts associated with hyperscale data centers; and

(3) consider best practices from other states in managing the energy and rate impacts of hyperscale data centers.

(k) The Commission shall submit a report detailing the findings of the study under subsection (i) to the General Assembly and the Governor no later than March 31, 2028.

(l) The Commission may adopt rules necessary to implement the provisions of this Section.

(220 ILCS 5/16-105.8 new)

Sec. 16-105.8. Hyperscale data center tariffs.

(a) The General Assembly finds and declares:

(1) The State of Illinois is experiencing rapid growth in the construction of hyperscale data centers, which creates both opportunities and risks for the State's economy and environment. It is the policy of this State to facilitate the responsible development of hyperscale data center infrastructure in a manner that ensures reliability of the electric power system, protects other customers from increased costs and risks, and supports the environmental policy goals of this State which include climate, clean air, clean water, and environmental justice.

(2) As a consequence of their unprecedented size, high load factor, need for costly infrastructure, and unique risk profile, hyperscale data centers have characteristics that generally distinguish them from other electricity consumers in the State.

(3) Uncertainty in forecasting future data center load, coupled with the substantial infrastructure costs necessary to develop hyperscale data centers, poses significant risks of stranded costs for other electric utility customers in the State.

(4) Load growth forecasts that include both actual and speculative data center demands raise significant concerns about resource adequacy and affordability for Illinois electricity consumers.

(5) In order to mitigate these costs and risks, the General Assembly finds that the State's electric utilities should develop electric service tariffs for hyperscale data center customers that reasonably balance the State's interest in economic growth with the need to ensure a reliable grid, affordable electricity service, and a clean and healthful environment.

(6) Tariffs that promote demand flexibility and encourage large customers to develop or procure their own (BYO) new clean electricity resources can significantly mitigate the costs and risks described above. Accordingly, the utility tariffs required by this Section should prioritize and expedite hyperscale data center projects that procure their own clean energy (MWh) and capacity (MW) from new wind, solar, energy storage, demand response, energy efficiency, operational flexibility, and other clean energy technologies and facilities to the maximum extent possible.

(b) Within 90 days after the effective date of this amendatory Act of the 104th General Assembly, all electric utilities in the State shall file new rate tariffs designed specifically for hyperscale data center customers. The Commission shall ensure that the tariffs achieve the State policy goals set forth in paragraph (a) and include the following components:

(1) provisions to ensure that utility investments needed to serve hyperscale data center customers, inclusive of any high-voltage (i.e. above 100 kilovolts)infrastructure needed to extend service to such customers, are allocated to those customers and are not socialized to other rate classes;

(2) appropriate contract terms, including but not limited to minimum charges, minimum contract length, minimum monthly billing demand, time-variant rates, collateral requirements, mandatory notice periods for contract reduction or termination, fees for large reductions in contract capacity, premature exit or termination fees, and other similar provisions to mitigate the risk of stranded costs for other customers;

(3) large load interconnection technical requirements to ensure the safety and reliability of electric service in Illinois. Utilities shall design such requirements to address the unique operational characteristics of hyperscale data centers, taking into consideration the recommendations and findings of the North American Electric Reliability Corporation (NERC) and similar entities on topics such as large load ride-through requirements, data and model sharing, disturbance monitoring equipment, power factor limits, power quality requirements, oscillation damping and ramping requirements, and protection coordination settings;

(4) a flexible interconnection approach, as described in Section 16-105.9(b) of this Act, that: (i) requires hyperscale data center applicants to connect to the grid on a nonfirm basis for load that is not backed by new, deliverable, BYO capacity (MW) included in the applicant's Clean Energy Supply Plan, and (ii) allows hyperscale data center applicants to establish firm electric service over time in proportion to the new, deliverable, BYO capacity the applicant develops itself, procures from a third-party, or sources from other customers (such as through a BYO VPP product) as demonstrated in the applicant's Clean Energy Supply Plan filed under this Section;

(5) a Fast-Track load interconnection process for hyperscale data center projects that bring their own (BYO) new clean energy resources such new wind, solar, energy efficiency, and other clean energy technologies and facilities at levels that achieve the clean energy supply standards (MWh) set forth in subsection (d) of Section 16-105.9 of this Act.

(c) The Commission shall suspend the tariffs filed pursuant to subsection (b) and open contested case dockets to review the filed tariffs for compliance with the goals and requirements of this Section. The Commission shall approve, reject, or approve with modifications a tariff within 240 days after the electric utility's filing. If the Commission rejects a tariff, it shall require the utility to refile a corrected tariff within no more than 90 days.

(220 ILCS 5/16-105.9 new)

Sec. 16-105.9. Flexible interconnection and Bring Your Own New Clean Energy requirements for hyperscale data centers.

(a) In this Section:

"BYO" or "bring your own" supply means new, deliverable clean energy (MWh) or capacity (MW) that a hyperscale data center project applicant develops itself, procures from a third-party, or sources from other customers as demonstrated in a Clean Energy Supply Plan filed pursuant to this Section.

"Clean Energy Supply Plan" means a submission from a hyperscale data center project applicant to the electric utility, as part of that applicant's request for service, consistent with the bring your own (BYO) clean energy (MWh) and capacity (MW) requirements described in this Section. The Plan shall include the hyperscale data center applicant's proposed steps to develop, procure, or source their own new, deliverable clean energy and capacity resources, and shall adhere to any rules or guidance established by the Commission for this purpose.

"Fast-track interconnection" means a priority load interconnection process under which qualifying hyperscale data centers facilities are reviewed and interconnected by electric utilities ahead of non-qualifying hyperscale data center facilities.

"Flexible interconnection" means an approach by which a hyperscale data center takes service from the electric utility pursuant to a tariff that requires the hyperscale data center to reduce or defer load when called upon by the utility under certain clearly defined conditions, thereby lowering system peak stress, accelerating the interconnection timeline, and reducing costs borne by all customers.

(b) The hyperscale data center tariffs described in Section 16-105.8 shall incorporate a flexible interconnection approach that requires hyperscale data center projects to contract with the utility to reduce or defer load when called upon by the utility during times of peak grid stress or other clearly defined conditions. The tariff shall allow hyperscale data center applicants to receive electric service on a firm basis for the portion of their requested load that is supported by new, deliverable BYO capacity demonstrated in a Clean Energy Supply Plan filed pursuant to this Section. Any requested load that is not backed by new, deliverable BYO capacity shall be taken on a non-firm basis under the conditions described in paragraph (c)(5) of this Section. For the purposes of this subsection (b), "new" means a generating facility energized or a demand-side load reduction measure created after the effective date of this amendatory Act of the 104th General Assembly.

(c) The hyperscale data center tariffs described in Section 16-105.8 shall include the following to implement the flexible interconnection approach described in this Section:

(1) The tariff shall provide an opportunity for hyperscale data center applicants to file and periodically update a Clean Energy Supply Plan to demonstrate their eligibility for firm, non-curtailable electric service and fast-track interconnection review.

(2) The tariff shall require a hyperscale data center to provide bring your own (BYO) clean capacity, equal to the hyperscale data center's maximum demand or be subject to mandatory load flexibility as described in this amendatory Act for any portion of the hyperscale data center's maximum demand that is not provided on a BYO basis. Clean capacity for these purposes may include a broad range of electric generation, storage, and demand-side resources and technologies in an applicant's Clean Energy Supply Plan, such as new wind, solar, energy storage, demand response, energy efficiency, virtual power plants (VPP), and other clean demand-side technologies and resources. Any load reduction from fuels other than electricity that are converted to megawatt-equivalents shall not be counted.

(3) Eligible demand-side measures shall include: (i) load reduction achieved by the hyperscale data center at their own facility, such as through battery storage or load shifting, that results in system-wide load reduction; (ii) load reduction procured from a third-party through a demand response, VPP, or other similar program that is not otherwise offered by an electric utility; or (iii) load reduction achieved by the utility by virtue of the hyperscale data center customer's payment into a demand response program administered by the utility, including, but not limited to, energy efficiency and battery storage incentive programs. A utility shall not earn a financial return from the use of funds contributed by hyperscale data centers to energy efficiency, demand response, or other utility-administered programs pursuant to the Public Utilities Act.

(4) The tariff shall describe any geographic, operational, and capacity accreditation requirements for new clean capacity resources in an applicant's Clean Energy Supply Plan to ensure deliverability, additionality, and temporal matching of new capacity with load. To the extent possible, the tariff shall align with any related requirements of the corresponding RTO/ISO wholesale markets. The capacity resources in an applicant's Clean Energy Supply Plan must be sourced exclusively from clean energy technologies and demand-side measures equal to the amount of demand for which the utility provides the hyperscale data center firm service.

(5) The tariff and any resulting electric service agreements for hyperscale data center customers shall clearly define the mandatory load flexibility conditions for any load served on a non-firm basis such as curtailment capability, speed, dispatch rules, verified performance, monitoring equipment requirements, and penalty clauses for not performing mandatory load flexibility when required. The tariff and electric service agreements shall also identify specific triggers for mandatory load flexibility, such as (i) reliability emergencies determined by the RTO/ISO; (ii) anticipated peak hours that drive capacity price increases; (iii) wholesale energy prices that exceed a determined threshold; or (iv) other triggers that the Commission determines are necessary to ensure grid reliability and consumer protection. The Commission shall ensure that electric service agreements to implement this flexible interconnection approach provide hyperscale data center applicants with the transparency and certainty needed for project financing and development.

(6) The utility tariff shall include requirements for the operation of any diesel or other fossil-fueled back-up generation to ensure that the deferral or mandatory load flexibility of hyperscale data center load under this flexible interconnection approach does not lead to increased local air pollution impacts.

(d) The tariff shall provide an opportunity for hyperscale data center applicants to qualify for fast-track load interconnection based on the level of new, deliverable clean energy resources they have developed, procured, or sourced as demonstrated in a Clean Energy Supply Plan filed pursuant to this Section. In order to qualify for fast-track interconnection, the applicant's Clean Energy Supply Plan must demonstrate:

(1) by January 1, 2030, that it has procured new, deliverable clean energy from renewable resources and clean demand-side resources in an amount that meets or exceeds 80% of its forecasted annual energy and capacity requirements, and maintained at least 25% of its backup generation needs from renewable clean demand-side resources;

(2) by January 1, 2035, that it has procured new, deliverable clean energy from renewable resources and clean demand-side resources in an amount that meets or exceeds 90% of its forecasted annual energy and capacity requirements, and maintained at least 35% of its backup generation needs from renewable clean demand-side resources; and

(3) by January 1, 2045, that it has procured new, deliverable clean energy from renewable resources and clean demand-side resources in an amount that meets or exceeds 100% of its forecasted annual energy and capacity requirements, and maintained 45% of its backup generation needs from renewable clean demand-side resources.

(e) Prior to providing electric service to a hyperscale data center applicant, the utility shall review the applicant's Clean Energy Supply Plan to determine whether and in what proportion the applicant is eligible for firm electric service and fast-track interconnection. The utility shall provide the applicant with an electric service agreement that includes all of the terms and conditions necessary to implement the requirements of this Section. The electric service agreement shall include reporting requirements for the hyperscale data center applicant to demonstrate compliance with its Clean Energy Supply Plan, including timelines and milestones to synchronize the customer's supply strategy with its planned load ramp. The utility shall make all reports publicly accessible to the maximum extent possible, with limited redactions for information that qualifies for trade secret protection under the Commission's rules.

(f) The utility shall provide an annual report to the Commission that summarizes:

(1) the total amount of verified new, deliverable, clean energy and capacity developed, procured, or sourced by hyperscale data center customers pursuant to a Clean Energy Supply Plan;

(2) a breakdown of clean energy and capacity commitments in the utility's Clean Energy Supply Plans by technology-type, geography, and planned development timeline;

(3) a description of the utility's steps to verify and ensure hyperscale data center compliance with the commitments made in a Clean Energy Supply Plan; and

(4) recommendations for further regulatory or legislative action to improve the utility's hyperscale data center interconnection process, consistent with the legislative goals and objectives of Section 16-105.8.

The Commission shall make all reports publicly accessible to the maximum extent possible, with limited redactions for information that qualifies for trade secret protection under the Commission's rules.

(g) The Commission shall have authority to investigate and audit a utility or hyperscale data center's compliance with this Section, and may take appropriate corrective action, including the assessment of monetary penalties or suspension of electric service for the period of noncompliant operation. The Commission may adopt rules to implement and administer this Section.

Section 5-25. The Municipal and Cooperative Electric Utility Transparent Planning Act is amended by adding Section 1-40 as follows:

(220 ILCS 31/1-40 new)

Sec. 1-40. Hyperscale Data Center Customers.

(a) Before a utility may enter into any contractual agreement to provide energy to a hyperscale data center customer, the utility must conduct an updated integrated resource plan and develop a hyperscale data center tariff, as described in this Section. The utility must prepare an updated integrated resource plan, provide notice to its customers, and hold at least one stakeholder meeting, as described, before entering into any contractual obligation to provide service to a large load customer.

(b) As soon as practicable upon receiving a request to initiate service to any hyperscale data center, a utility shall update its most recent integrated resource plan as follows:

(1) The utility shall issue a request for proposal to identify available renewable generation resources to meet the additional demand associated with the prospective hyperscale data center.

(2) The utility shall prepare a new load forecast, consistent with paragraph (8) of subsection (d) of Section 1-15, incorporating the requested additional delivery and reasonably anticipated future delivery.

(3) The utility shall prepare a new action plan, consistent with paragraph (9) of subsection (d) of Section 1-15, that reflects the prospective hyperscale data center's anticipated demand over the next ten years.

(c) The utility shall post its updated integrated resource plan on the same publicly accessible website and in the same manner it posted its most recent preliminary integrated resource plan. The utility shall conduct at least one stakeholder meeting relating to the updated integrated resource plan no sooner than 30 days after it is publicly posted. The utility shall provide notice of the updated integrated resource plan and of a stakeholder meeting on the utility's website and to customers through the normal billing process not less than 30 days prior to the stakeholder meeting. The utility shall provide means by which customers may provide written feedback on the updated integrated resource plan as well as during the stakeholder meeting.

(d) Utilities must develop a hyperscale data center tariff under which all hyperscale data centers are required to take service. Such hyperscale data center tariff shall include a minimum contractual term equal to or greater than the depreciation term or power purchase agreement of any additional generation resources identified in the action plan of the revised integrated resources plan to meet the large load customer demand; minimum demand charges sufficient to cover the costs of capital expenditures; upfront payment in full of the costs associated with any transmission facilities required to serve the large load customer; and demand charges and energy rates consistent with cost causation principles and, to the extent possible, hold existing customers harmless from any additional costs incurred as a result of the hyperscale data center's demand.

(e) A utility shall procure, as soon as practicable but in no case more than 5 years after initiating service to a hyperscale data center, firm clean capacity equal to or greater than the non-interruptible demand associated with the hyperscale data center, where the interruptible portion of demand shall be that as registered and accredited as a capacity market resource by the relevant regional transmission organization. Clean capacity for these purposes may include a broad range of electric generation, storage, and demand-side resources and technologies in an applicant's Clean Energy Supply Plan, including but not limited to new wind, solar, energy storage, demand response, energy efficiency, virtual power plants (VPP), and other clean energy technologies and facilities. Any load reduction from fuels other than electricity that are converted to megawatt-equivalents shall not be counted.

(f) Firm clean capacity procured under this Section must be:

(1) deliverable, being located on the same site as the large new load customer or connected to the same regional transmission organization to which the large load customer is connected; and

(2) additional, having begun operation no more than 12 months prior to the date the hyperscale data center is expected to begin operation or, for added capacity to an existing renewable energy resource, that the capacity to be procured by the hyperscale data center became available no more than 12 months prior to the date the hyperscale data center is expected to begin operation.

Article 10.

Section 10-1. Short title. This Article may be cited as the Residential Automated Solar Permitting Platform Act.

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

Section 10-5. Definitions. As used in this Act:

"Baseline residential code" means an edition of the International Residential Code for One and Two-Family Dwellings first published by the International Code Council during the current year or preceding calendar years, excluding Parts IV and VII.

"Residential automated solar permitting platform" means software or a combination of software that automates plan review, automatically produces code-compliant approvals, accepts online payments for permitting fees if permitting fees are levied, and instantly issues permits and permit revisions for residential photovoltaic systems upon online submission of permitting fee payments, if permitting fees are levied, and a code-compliant application. The residential automated solar permitting platform shall be available for residential photovoltaic systems up to the maximum capacity allowed with a 200-amp main service disconnect and installed to the requirements of the baseline residential code that may include an energy storage system up to the maximum capacity allowed under the baseline residential code, a main panel upgrade, or a main breaker derate.

Section 10-10. Adoption of platform. On or before July 1, 2027, municipalities and counties shall adopt a residential automated solar permitting platform. The municipality or county shall anticipate that the residential automated solar permitting platform will have the capability to process at least 75% of residential solar applications on existing construction submitted to authorities having jurisdiction in the State.

For a solar photovoltaic system approved by such a platform under this Section, municipalities and counties may not require manual review at any time during the permitting and inspection processes, including, but not limited to, before issuing a permit or before conducting or finalizing the inspection. This does not preclude an inspector from examining construction documents.

Section 10-15. Over-the-counter permitting. A county or municipality that offers in-person permitting for all residential solar applications within 5 business days is exempt from the requirements set out in Section 10-10 of this Act.

Section 10-20. Reporting. On or before July 1, 2027, municipalities with a population of more than 5,000 residents and all counties shall include on their websites the availability of a residential automated solar permitting platform and how to access it.

Section 10-25. Remedies.

(a) A person or entity aggrieved by a violation of this Act or any rule adopted under this Act by a municipality or county may file a civil action in the county in which the alleged offense occurred or where any person who is party to the action resides, without regard to exhaustion of any alternative administrative remedies provided in this Act. Actions may be brought by one or more persons or entities for and on behalf of themselves and other persons similarly situated. A person or entity whose rights have been violated under this Act by a municipality or county is entitled to collect:

(1) a civil penalty of up to $1,000;

(2) all other legal or equitable relief as may be appropriate, including, but not limited to, legal or equitable relief in the case of unlawful retaliation; and

(3) attorney's fees and costs.

(b) The right of an interested party or aggrieved person to bring an action under this Act terminates after 3 years from the date that a person or entity requested a permit for a residential photovoltaic system. This limitation period is tolled if a municipality or county has deterred a person's exercise of rights under this Act.

Section 10-30. Remote inspections. On or before July 1, 2027, municipalities with a population of more than 5,000 residents and all counties shall provide an option for remote inspections via recorded video or photo that can be submitted electronically for projects permitted by the residential automated solar permitting platform. These inspections shall be offered at no greater cost and shall be available with no greater delay than in-person inspections.

(1) A municipality or county shall require no more than one inspection for projects permitted by the automated solar permitting software unless the first inspection failed.

(2) A municipality or county that does not require a permit for residential photovoltaic solar and storage systems is exempt from the requirements in this Section.

Article 15.

Section 15-1. No acceleration or delay. Where this Act makes changes in a statute that is represented in this Act by text that is not yet or no longer in effect (for example, a Section represented by multiple versions), the use of that text does not accelerate or delay the taking effect of (i) the changes made by this Act or (ii) provisions derived from any other Public Act.