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General Questions

Why is my ABP project application on the waitlist?

As of December 2020, Program capacity for project applications has been filled. Both Distributed Generation (“DG”) and Community Solar project applications submitted to the Adjustable Block Program are now being added to waitlists for the applicable project category.

Project applications are selected from the waitlist as projects ahead of them in the relevant Group (A or B) and category (Large DG, Small DG, or Community Solar) that have been allocated to a capacity block are withdrawn. A project’s selection from the waitlist is based on sufficient capacity being vacated by withdrawn projects, not on a one-to-one project relationship. Part I of a project application will be reviewed only after it has been selected from the waitlist. Because the rate of withdrawals is unknown, it is not possible to determine if or when a new project application may be selected from the waitlist and thus be considered for an incentive through the Program.

At this time there is not a schedule for the opening of future blocks of capacity. As outlined extensively in Chapter 3 of the IPA’s Revised Long-Term Renewable Resources Procurement Plan, obtaining RPS funding necessary for opening additional blocks in 2021 would require passing new legislation.

At this time, due to funding being unavailable, there is not a schedule for the opening of future blocks of capacity. As outlined extensively in Chapter 3 of the IPA’s Revised Long-Term Renewable Resources Procurement Plan, obtaining RPS funding necessary for opening additional blocks in 2021 would require passing new legislation. It is unclear by when legislation providing funding will be passed by the Illinois General Assembly. More information on RPS funding and how it impacts the Program can be found here.

In order for project applications to be approved off of the waitlist or to be considered upon the opening of new blocks when funding becomes available, the projects must be compliant with all Program requirements.  This includes requirements surrounding the distribution of the Illinois Shines brochure and the execution of the Disclosure Form prior to the installation contract.  Project applications that do not conform with Program requirements risk the ability to receive REC contract awards.

Waitlists can be viewed on the ABP dashboard for Small DGLarge DG, and Community Solar.

Are system nameplate sizes AC or DC?

The system sizes listed in the Plan are all AC system sizes based on the size of the inverter.

Can I co-locate multiple distributed generation projects on one parcel of land or adjacent parcels if the aggregate size is over 2,000 kW?

Each unique utility customer may have one distributed generation project of up to 2,000 kW AC in the Adjustable Block Program.  Two or more utility customers that are affiliated and physically adjacent could each have a distributed generation project of up to 2,000 kW AC.

How long do I have to energize my system after acceptance to the Adjustable Block Program?

Distributed generation projects are given 12 months to be developed and energized. Community solar projects are given 18 months to be developed, energized, and demonstrate that they have sufficient subscribers. Extensions may be granted under certain circumstances, as described in more detail in Section 6.15.2 of the Revised Long-Term Plan. To learn more about making extension requests, read the Extension Request Checklist for Approved Vendors announcement.

I live in a rural electric cooperative, municipal electric utility, or the Mt. Carmel Public Utility Company territory. Am I eligible to participate in the Adjustable Block Program?

The Illinois Power Agency’s Revised Long-Term Renewable Resources Procurement Plan proposed allowing participation in the Adjustable Block Program (for REC incentive payments) by community solar and photovoltaic distributed generation projects located in the service territories of rural electric cooperatives, municipal electric utilities, and Mt. Carmel Public Utility Company. That proposal (along with the Long-Term Plan itself) was affirmed by the Illinois Commerce Commission in its Administrative Order issued on April 3, 2018 in ICC Docket No. 17-0838.

In June 2018, Commonwealth Edison Company (ComEd) filed a petition seeking review of that determination (i.e., an appeal) with the state’s Second District Appellate Court, case number 2-18-0504. On May 2, 2019, the Appellate Court affirmed the ICC’s decision in this regard.  On July 11, 2019, ComEd filed a Petition for Leave to Appeal with the Illinois Supreme Court, which denied the Petition (no. 124898) on September 25, 2019.  It thus appears that all avenues for appellate relief have been exhausted, and the Commission’s decision allowing such projects to participate will continue to govern program implementation. As a consequence, barring unanticipated future legislative action, projects in the service territories of rural electric cooperatives, municipal electric utilities, and Mt. Carmel Public Utility Company, will continue to be allowed to receive REC delivery contracts under the Adjustable Block Program, as they have since the outset of the Program.  Please see Sections 6.15.3 and 7.4 of the Revised Long-Term Plan for more information on requirements applicable to projects in the service territories of rural electric cooperatives or municipal electric utilities.

Will my information be kept confidential?

Except where otherwise provided (such as with certain project-specific information being made publicly available through publishing lottery results), Approved Vendor submittals including quarterly reports, annual reports, Approved Vendor applications, and project applications will not be publicly posted or made publicly available as a matter of course – provide that nothing included herein shall a) prohibit the IPA from reporting information taken from Approved Vendor submittals to appropriate authorities should the IPA have reasonable suspicion of any fraudulent or otherwise illegal behavior, b) prevent the IPA from making aggregated information taken from across Approved Vendor submittals publicly available, or c) prevent the IPA from sharing information received with the Illinois Commerce Commission or public utilities to support the Program’s operation.

Additionally, the IPA and the Program Administrator will provide confidential treatment to any commercially sensitive information submitted by Approved Vendors in connection with participation in the Adjustable Block Program. Under Section 1-120 of the IPA Act (20 ILCS 3855), the Illinois Power Agency has a statutory obligation to “provide adequate protection for confidential and proprietary information furnished, delivered, or filed” by any third party. As Section 7(1)(g) of the Illinois Freedom of Information Act (“FOIA”) (5 ILCS 140/7) exempts from disclosure “[t]rade secrets and commercial or financial information obtained from a person or business where the trade secrets or commercial or financial information are furnished under a claim that they are proprietary, privileged or confidential, and that disclosure of the trade secrets or commercial or financial information would cause competitive harm to the person or business,” the IPA believes that its responsibility under Section 1-120 necessitates the assertion of this FOIA exemption when applicable in response to a FOIA request, and to otherwise protect the confidentiality of commercially sensitive information in response to any discovery request or other request made in connection with formal investigation or litigation. While the IPA will presume that submittals including quarterly reports, annual reports, Approved Vendor applications, and project applications are commercially sensitive (to the extent not reflecting public information, or otherwise obviously not commercially sensitive) and thus should be actively protected from disclosure, Approved Vendors should designate any particularly sensitive information as “confidential or proprietary” to maximize the likelihood that such information would be protected from disclosure by a reviewing body (such as a reviewing court or the state’s Public Access Counselor) in response to an appeal of the Agency’s determination that such information should not be disclosed in response to a FOIA request.

Is the value of net metering changing in Illinois?

Retail rate net metering – described in more detail below – is still being offered to residential and small commercial customers of Ameren Illinois (“Ameren”), Commonwealth Edison (“ComEd”), and MidAmerican Energy Company (“MEC”) that install a distributed generation system.  It is anticipated that the replacement of retail rate net metering with a distributed generation rebate will be triggered under current Illinois law in the Ameren territory in late 2022 or early 2023, and likely later in the ComEd and MidAmerican territories.  The mechanism which will trigger the switch from retail rate net metering to a distributed generation rebate, and the process for calculation of that rebate value, is described further below.   Customers of rural electric cooperatives and municipal electric utilities should check with those entities to determine whether net metering is offered in the service area.

Background

Under current Illinois law, net metering is available to any retail customer that “owns or operates solar, wind, or other eligible renewable energy generating facility with a rated capacity of not more than 2,000 kilowatts that is located on the customer’s premises and is intended primarily to offset the customer’s own electrical requirements.”  220 ILCS 5/16-107.5.  Small customers, such as homeowners and small business owners, may receive a one-for-one kWh credit for the net electricity supplied to their utility at the retail rate – that is, for both distribution and supply charges. This is known as “retail rate net metering.”  Non-residential customers, as well as owners and developers of community renewable generation projects, have the option to apply for a rebate equal to $250 per kilowatt of the nameplate capacity of the solar project; these customers are not eligible to receive retail rate net metering and instead only receive net metering credits for the energy supplied from their system to the utility.  The net metering landscape in a utility’s territory will change and retail rate net metering will no longer be available to new net metering customers once the installed net metering capacity in that utility’s territory reaches 5% of the total peak demand supplied by that utility provider in the previous year.  Instead, those customers who install a distributed generation system after that point in time would be eligible for net metering of energy supplied to the utility and to apply for the distributed generation rebate, the value for which is to be set by the Illinois Commerce Commission (“Commission”) (the State agency charged with approving utility rates) through “an investigation into an annual process and formula for calculating the value of rebates.”  220 ILCS 5/16/107.6(e).  The investigations are conducted separately by utility.

Ameren Illinois

In April 2020, upon notification from Ameren that it had reached a 3% net metering penetration, the Commission opened an investigation into the value of successor rebates for distributed generation systems in the Ameren service territory, which remains open and is ongoing.  Additional information related to that proceeding may be found at:   https://www.icc.illinois.gov/docket/P2020-0738.

Ameren Illinois notified the Illinois Commerce Commission that it reached the 5% net metering threshold on October 2, 2020.  The Commission, which has exclusive jurisdiction over the matter of utility net metering, opened an investigation into Ameren’s net metering tariff (Rider NM) to determine whether Ameren had indeed met the 5% threshold as defined under Illinois law.  The Commission found that Ameren’s Rider NM incorrectly calculated the threshold and that the volume of installed net metering capacity in the Ameren service territory has not yet met the 5% threshold.  The effect of that ruling was to restore the availability of retail rate net metering for otherwise-eligible new Ameren Illinois net metering customers.  Pursuant to the Commission’s order, Ameren filed updated tariff language reflecting changes to how Ameren calculates the 5% net metering threshold on December 23, 2020, with an effective date of seven business days later.  Furthermore, the Commission ordered that Ameren compensate any customers who became net metering customers between October 2, 2020, and the effective date of the revisions to Rider NM for the delivery netting credits those customers should have received during that time.  Ameren estimates that it will reach the 5% net metering penetration under the Commission’s interpretation of the Public Utilities Act in late 2022 or early 2023.

Commonwealth Edison

In March 2021, upon notification from ComEd that it had reached a 3% net metering penetration, the Commission opened an investigation into ComEd’s net metering tariff (Rider POGNM) and its community solar tariff (Rider POGCS) to determine whether the tariffs correctly implement section 16-107.5(j) of the Public Utilities Act, which outlines the calculation of the 5% net metering threshold.  In response to an inquiry from the Commission, ComEd confirmed that under the Commission’s interpretation of the Public Utilities Act as applied in the investigation into Ameren’s net metering tariff, the net metering penetration in its service territory as of March 1, 2021, was only 1.48%.  The Commission’s investigation of ComEd’s tariffs is ongoing; related documents may be found at:   https://www.icc.illinois.gov/docket/P2021-0196/documents.

According to the IPA’s December 28, 2020 RPS Funding and Budget Update, RPS-related expenses for the 2021-22 delivery year are projected to be greater than available funding. If I hold an Adjustable Block Program REC delivery contract that is due to receive payments in the 2021-22 delivery year, what risks do I face? How are the IPA and other parties working to address these risks?

As described in the IPA’s RPS Budget and Funding Update, projected 2021-22 delivery year expenses are indeed estimated to exceed available funds.  The IPA’s latest analysis, included in its filing with the Illinois Commerce Commission on March 3, 2021, demonstrated a projected ~$52 million statewide gap between RPS expenses and available funds for the 2021-22 delivery year ($372.4M in expenses versus $325.7M in funds).  As a consequence of this funding differential, holders of REC delivery contracts may indeed face payment reductions for the 2021-22 delivery year to ensure that RPS expenditures do not exceed a statutorily-mandated RPS budget cap.

This challenge is currently being addressed in two ways.

  • First, the IPA is optimistic that this problem can be solved legislatively through an act of the General Assembly extending the deadline by which prior years’ collections can no longer be used. Two bills (HB 3822 and SB 2433) have been introduced in the 102nd General Assembly providing a narrow, targeted fix to RPS funding sufficiency for the 2021-22 delivery year.  In addition, omnibus energy legislation—such as the Clean Energy Jobs Act or the Path to 100 bill—would provide larger, more structural changes to RPS budgeting that would also effectively address near-term RPS funding risks.
  • Second, the IPA has petitioned the Illinois Commerce Commission to reopen ICC Docket No. 19-0995 (the ICC’s approval of the IPA’s Revised Long-Term Renewable Resources Procurement Plan) for authorizing a process to govern by when and how REC delivery contract expenses would be reduced. In that filing, the IPA has proposed that payments be made as scheduled for the first six months of the 2021-22 delivery year before a payment reduction process is implemented.  While relief from the Commission would not solve the problem of funding insufficiency, it would provide clarity and certainty to parties as to by when and how much any payments would be reduced if legislation addressing this issue does not pass.

The IPA is hopeful that a targeted legislative fix can be passed as soon as possible; please note that the Illinois General Assembly’s Spring 2021 legislative session is set to conclude on May 31, 2021.  Additionally, the IPA has proposed a schedule on reopening to the Illinois Commerce Commission resulting in an administrative order by May 27, 2021.  Should you have any additional questions, please contact IPA Chief Legal Counsel Brian Granahan (Brian.Granahan@Illinois.gov).

What is prevailing wage and how does it apply to my ABP application?

Prevailing wage is a minimum compensation level set by the Illinois Department of Labor by county for construction activities related to public works. Section 1-75(c)(1)(Q) of the IPA Act (20 ILCS 3855) as modified by Climate and Equitable Jobs Act (Public Act 102-0662) now requires that individuals engaged in the construction of applicable projects submitted to the Adjustable Block Program (“ABP”) are paid the relevant prevailing wage. Additionally, Illinois Public Act 102-0673 (effective as of November 30, 2021) clarifies that such projects are “public works” subject to the Prevailing Wage Act—which includes notice requirements and related provisions as well.

For Adjustable Block Program administration, Illinois law allows for only the following types of projects to be considered exempt from prevailing wage requirements:

  • Large Distributed Generation projects (greater than 25 kW AC) that were on a waitlist as of the program’s December 14, 2021 (with applications thus needing to have been received prior to the ABP’s November 1, 2021 closure)
  • Distributed generation projects (Large or Small) that either:
    • serve a single-family or multi-family residential facility, or
    • serve a house of worship and are not greater than 100 kW AC (aggregated with any co-located projects)
  • Distributed generation projects (Large or Small) for which construction can be demonstrated to have been completed before September 15, 2021, the effective date of Public Act 102-0662.

A project application sized between 10-25 kW for which an application was originally received in the Large Distributed Generation category (i.e., before block closure) will be considered a waitlisted Large Distributed Generation project for prevailing wage purposes, although that project will otherwise be reclassified as a Small Distributed Generation project for processing the project application.

Part I of the project application will include a required certification that the applicant understands that prevailing wage requirements may apply to that project, and the Part I verification will include the Program Administrator’s determination regarding applicability of prevailing wage requirements.  In Part II of the project application, the Approved Vendor will be required to certify to and document compliance with prevailing wage requirements, if applicable.

As of the release of this FAQ, the exact processes for verifying that (a) a facility is residential or is a house of worship, (b) construction on a project was completed before September 15, 2021, and (c) prevailing wage was in fact paid to individuals working on an individual photovoltaic project construction, are still being finalized.

How do I properly generate Disclosure Forms and comply with Disclosure Form requirements?

Q: When does the customer need to sign a Disclosure Form?

A: For both Distributed Generation (DG) and Community Solar, the customer must receive, review, and sign the Disclosure Form before signing an installation contract or subscription agreement. Failure to secure customer signature on a Disclosure Form before securing customer signature on an installation contract or subscription agreement could result in rejection of the Disclosure Form or disciplinary action against the Approved Vendor and/or Designee.

The Disclosure Form includes important information about the customer’s proposed solar photovoltaic (PV) system or community solar subscription. For DG, the Disclosure From must be generated for the customer after the customer’s PV system is designed. For Community Solar, the Disclosure Form must be generated after the customer’s community solar subscription is sized.

 

Q: How can Approved Vendors or Designees generate Disclosure Forms?

A: There are three options for Disclosure Form generation:

  • Directly through the Portal: The Approved Vendor/Designee enters all the information for the Disclosure Form in the Portal and generates the form there.
  • Via CSV Upload: The Approved Vendor/Designee enters all information for one or multiple Disclosure Forms into a CSV document available in the ABP Portal. After the information is entered into the CSV, the Approved Vendor/Designee can upload the CSV, and generate multiple Disclosure Forms at once.
  • Via API: With the Program Administrator’s approval, Approved Vendors or Designees (with Approved Vendor approval) may generate Disclosure Forms outside of the ABP Portal via API. Please reach out to the Program Administrator to learn more about this option.

 

Q: How can Approved Vendors or Designees secure a customer’s signature on Disclosure Forms?

A: There are three options available for securing customer signatures:

  • Wet signature: The Approved Vendor/Designee can print a hard copy for the customer to review and sign with a wet signature. After the customer has signed the Disclosure Form, the Approved Vendor/Designee can upload a scan of the signed Disclosure Form to the Portal.
  • E-signature through the ABP Portal: The Approved Vendor/Designee can send the Disclosure Form for e-signature through the ABP Portal. The customer will receive an email from the Program Administrator requesting their e-signature on the Disclosure Form, and the customer can follow the link in that email to e-sign the Disclosure Form. The Portal will automatically record the date, time, and IP address of that e-signature.
  • E-signature through a commercially available, third-party platform: The Approved Vendor/Designee can download the Disclosure Form and send it to the customer for e-signature through a commercially available, third-party e-signature platform. After the customer electronically signs the Disclosure Form, the Approved Vendor/Designee uploads the e-signed document to the Portal. This upload must also include the tracking page generated by the e-signature platform. We suggest that program participants reach out to the Program Administrator if any question exists about whether a signature platform falls within the definition of a commercially available, third-party platform to prevent the rejection of Disclosure Forms at verification check points. In-house developed e-signature platforms will not be accepted.

 

Q: Can an Approved Vendor or Designee edit a Disclosure Form after a customer has executed the Disclosure Form?

A: It is never permissible to edit the static text on Disclosure Forms, whether before or after customer signature. If an Approved Vendor/Designee needs to update the information entered in a Disclosure Form field after the customer signs the Disclosure Form, there are three ways to accomplish that:

  • Generate a new Disclosure Form for the customer: In this instance the Approved Vendor/Designee would start at the beginning of the process, and the new Disclosure Form would have a different Disclosure Form ID than the previous Disclosure Form. With this option, all information on the Disclosure Form would need to be reentered. If the new Disclosure Form needs to be linked to an existing application, please email the Program Administrator with the new Form ID to request it be linked to the existing application. This option is available at any point during the application process.
  • Duplicate an existing Disclosure Form: Approved Vendors/Designees can submit requests to the Program Administrator to duplicate an existing Disclosure Form. This will create a new Disclosure Form (with a new Disclosure Form ID), that is in the “In Progress” stage. This new Disclosure Form will be populated with all the information from the first Disclosure Form, and the Approved Vendor/Designee can update the field(s) as needed. This option is available at any point during the application process.
  • Return the existing, signed Disclosure Form to the “In Progress” status within the ABP Portal: Within the Disclosure Form section of the Portal, click on the system name, scroll to the bottom, and click the “Edit Disclosure Form” button. This will allow you to revisit any sections of the Disclosure Form, update the field(s) that need to be updated, and then resend the Disclosure Form to the customer for e-signature. This generates a new version of the existing Disclosure Form, and the new version will maintain the same Disclosure Form ID. This option is only available until the application associated with that Disclosure Form is Part I submitted. The ABP Portal will maintain a record of any previous e-signatures and uploads of the Disclosure Form. Approved Vendors/Designees cannot currently view this information but can email the Program Administrator to request the full history of a Disclosure Form.

 

Q: How can an Approved Vendor or Designee upload an executed Disclosure Form:

A: If a customer has executed a Disclosure Form outside of the ABP Portal (either via wet signature or through a commercially available, third-party platform) an Approved Vendor/Designee can either manually upload the Disclosure Form or upload the Disclosure Form via API.

 

Q: Can the sales representative send the Disclosure Form to themselves for e-signature, so that the customer can sign the Disclosure Form on the sales representative’s device?

A: No, the Approved Vendor/Designee cannot send the Disclosure Form for e-signature to an email address associated with the sales representative or with the company conducting the sale. If the customer is e-signing the Disclosure Form, it must be sent to an email address belonging to the customer for e-signature. This requirement applies both to Disclosure Forms signed directly through the Portal and to Disclosure Forms signed through third-party commercially available e-signature platforms.

 

Q: What if the customer does not have an email address?

A: All Disclosure Forms submitted to the Program require a customer e-mail address. If the customer does not have an email address, the Program offers a waiver that the customer can sign confirming that they do not have an e-mail address. The Approved Vendor must submit this waiver along with the customer’s Disclosure Form.

Additionally, if the customer does not have an email address, the Approved Vendor/Designee must secure the customer’s wet signature on a hard copy of the Disclosure Form.

 

Q: How do you fill out the Community Solar Disclosure Form field for the method or formula for calculating subscription payments?

A: The Program Administrator has posted guidance on how to fill out the payment calculation field on the Community Solar Disclosure Form in a manner that complies with the Program’s marketing guidelines. Please review this guidance for more information. Failure to comply with this guidance and provide clear disclosure to the customer regarding their payments could result in disciplinary action.

 

Q: When does the Program require the customer to sign a new Disclosure Form?

A: There are different occurrences when a new Disclosure Form may be required.

Change in project size (DG) or subscription size (CS): For Distributed Generation, the Program requires a new Disclosure Form if the AC size of the system has changed more than the greater of 5% or 1 kW from the size noted on the original Disclosure Form. For Community Solar, the Program requires a new Disclosure Form if the AC size of a community solar subscription submitted to the Program Administrator differs by more than the greater of 2 kW or 10% from the subscription size noted in that subscriber’s corresponding Disclosure Form.

Change in terms/conditions that were disclosed on original Disclosure Form: If there is a change in the terms or conditions that were disclosed to a customer on their original form, including changes in fees, expected payments, cancellation terms, etc., these must be disclosed to the customers via a new Disclosure Form.

Net Meter Waiver

Why does the Consumer Protection Handbook require net metering availability for distributed generation ABP projects?

Net metering allows customers to receive credits on their electric utility bill for excess energy that their solar project produces and sends back to the grid. This energy offsets energy that the customer purchases from the grid during other times in the billing cycle. Without net metering, customers do not receive credits for their excess energy production.

Can a project be eligible for ABP if net metering is not offered by the customer’s service utility?

The Consumer Protection Handbook, see Section VI, prohibits Approved Vendors and Designees from making offers to customers if the customer cannot utilize net metering.

Some customers may, with full understanding of the unavailability of net metering and how that impacts overall project financials, still wish to move forward with installing solar.

There is a waiver available for AVs and Designees to make offers to install projects for which net metering is unavailable.

The following waiver procedure is available:

  1. The AV/Designee that discusses the solar project offer with the customer must ensure that the customer understands what net metering is, that net metering credits will not be available for the solar project, and how this will impact the overall financial benefits that the customer will receive from the solar project.
  2. The customer must sign the Net Metering Unavailability Customer Acknowledgement Form (downloadable as standard PDF or fillable PDF) before signing the installation contract.
  3. The AV/Designee must submit the completed customer acknowledgment form to admin@illinoisabp.com prior to submission of the project’s Part I application.

Is there a waiver or exception for AVs and Designees to make offers to install projects for which net metering is unavailable?

Yes. The following waiver procedure is available:

  1. The AV/Designee that discusses the solar project offer with the customer must ensure that the customer understands what net metering is, that net metering credits will not be available for the solar project, and how this will impact the overall financial benefits that the customer will receive from the solar project.
  2. The customer must sign the Net Metering Unavailability Customer Acknowledgement Form (downloadable as standard PDF or fillable PDF) before signing the installation contract.
  3. The AV/Designee must submit the completed customer acknowledgment form to admin@illinoisabp.com prior to submission of the project’s Part I application.

The customer acknowledgement form can be found at the Program website (downloadable as standard PDF or fillable PDF) before signing the installation contract.

Project Application

Can I self-install my system?

A system applying for the Adjustable Block Program can only be self-installed if the individual installing the system is a Qualified Person which is defined under 83 Ill. Adm. Code § 468.20 as:

“Qualified person” means a person who performs installations on behalf of the certificate holder and who has either satisfactorily completed at least five installations of a specific distributed generation technology or has completed at least one of the following programs requiring lab or field work and received a certification of satisfactory completion: an apprenticeship as a journeyman electrician from a DOL registered electrical apprenticeship and training program; a North American Board of Certified Energy Practitioners (NABCEP) distributed generation technology certification program; an Underwriters Laboratories (UL) distributed generation technology certification program; an Electronics Technicians Association (ETA) distributed generation technology certification program; or an Associate in Applied Science degree from an Illinois Community College Board approved community college program in solar generation technology.

Please see Section 4(D) of the Program Guidebook for the full requirements to install a Distributed Generation System.

Can an ABP applicant withdraw their application once they find out which Block pricing their project will receive?

As the Adjustable Block Program is predicated on price transparency, Approved Vendors may have submitted projects with the expectation of receiving certain pricing. The Agency thus will allow any project selected from the waitlist 10 business days to accept its block allocation. The Approved Vendor will be able to exercise this option without any further penalty, process, or the posting of collateral. If a project selected from the waitlist declines its selection by this option, then the next ordinally ranked project(s) on the waitlist will be selected along with the same terms (10 business days to accept or decline). Projects declining a block allocation will be removed from the ABP. The Approved Vendor may exercise this option to decline a block allocation by communicating as such in writing to the Program Administrator. The application fee is non-refundable.

Are non-ministerial permits required to apply to the ABP?

Initially, systems over 25 kW were required to obtain all non-ministerial permits prior to submitting a project application. With the ICC’s approval of the Revised Long-Term Plan, other than a land-use permit for systems above 250kW AV, non-ministerial permits are no longer required.

Can a project be eligible for both ABP and Illinois Solar For All?

While proposed projects may be submitted to both the Adjustable Block Program (ABP) and Illinois Solar for All (ILSFA) (when eligible) for approval and funding, contracts will be awarded from only one program or the other. Because the potential exists that a single proposed project could be found eligible or approved by both programs concurrently, a milestone must be identified that indicates acceptance of contracting from one program and ineligibility from the other. Therefore, once a batch containing a Part I Verified ABP application has been submitted to the Illinois Commerce Commission for approval, the underlying projects in that batch will no longer be eligible for ILSFA. Any ABP application that wishes to remain eligible for ILSFA must be withdrawn prior to this milestone.

Can Distributed Generation systems on one parcel be submitted into the Illinois Adjustable Block Program as separate applications?

Pursuant to Section 4.E of the Program Guidebook, all solar projects at a customer’s location that are owned by that customer or affiliates of that customer must be submitted under a single ABP application regardless of the number of utility accounts associated with the projects. An ABP application represents all of the systems on a customer’s parcel, regardless of the location of the utility meter(s). The location of the modules and arrays, not the location of the utility meter(s) determines the location of a project.

In cases in which two or more projects on one parcel are separately owned and serve to offset the load of separate entities, they may be submitted as separate applications. The Approved Vendor must provide documentation that those customers are not affiliated* entities and that each project has a separate utility meter.

If an Approved Vendor submits an application for a project owned by a customer and a co-located project owned by the same customer already is under an ABP REC contract, the new application will be subject to the expansion rules and pricing in Section 4(E) of the February 26, 2021 edition of the Program Guidebook.

The intent of these requirements is to prevent gaming, such as a situation in which an Approved Vendor or customer intentionally divides up a project in order to receive higher REC pricing that might be available to a smaller system. The IPA appreciates that there may be special circumstances that apply to specific projects, particularly in rural areas and those served by rural electric cooperatives, and those situations could warrant different consideration. Therefore, the Agency will consider requests for exemptions to this requirement on a case-by-case basis. A request should be submitted via a letter (not just an email) on the Approved Vendor’s company letterhead and emailed to the Program Administrator at admin@illinoisabpstg.wpengine.com who will then forward it to the Agency for consideration.

*From Section 7.3.1 of the Revised Long-Term Renewable Resources Procurement Plan: “’Affiliate’ means, with respect to any entity, any other entity that, directly, or indirectly through one or more intermediaries, controls, is controlled by, or is under common control with each other or a third entity. ‘Control’ means the possession, directly or indirectly, of the power to direct the management and policies of an entity, whether through the ownership of voting securities, by contract, or otherwise. Affiliates may not have shared sales or revenue-sharing arrangements, or common debt and equity financing arrangements.”

Can I register less than the total planned capacity to qualify for a different Block award?

No, the ABP Guidebook requires that DG systems entered into the ABP must include the entire output of the system. If there are multiple installations with separate interconnections, you can opt to not register the separately interconnected capacity.   Any capacity of a system which is not part of the ABP must be separately metered with a separate inverter.

A system can be built to be smaller than proposed in Part I while still staying within the greater of 5kW or 25%, but it would keep the lower REC price commensurate with the proposed larger system and the quantity of RECs used for purposes of payment shall be the lesser of the REC quantities calculated based on: (1) the Proposed Nameplate Capacity and Capacity Factor and (2) the Actual Nameplate Capacity and Capacity Factor. For additional details please see Section 5(e) of the REC Contract.

Does my project have to stay in the utility interconnection queue to remain on the ABP waitlist?

Projects may, but are not required to, remain in the interconnection queue (i.e., maintain a valid interconnection agreement with the applicable utility) to maintain their place on the waitlist. Exceptions will be made for projects that are forced from the utility interconnection queue due to the utility’s queue management process, including, but not limited to, being forced to pay a potentially nonrefundable deposit to remain in the queue, or incurring other costs to remain on the waitlist. Any project that has exited the interconnection queue must provide proof that it has reapplied for interconnection as a condition of its selection off of the waitlist. Any project that declines a utility interconnection restudy, declines to pay a potentially nonrefundable deposit to remain in the queue, or otherwise takes an action that pre-emptively removes itself from the utility interconnection queue rather than wait for involuntary removal will be deemed to have been removed from the queue involuntarily. Such projects will remain eligible for selection from the waitlist.

How can a project demonstrate site control?

Site control must be evidenced through a binding contract for system purchase, lease, PPA, option, or other form. Non-binding documents such as a Letter of Intent do not meet this requirement. It’s acceptable for the binding contract to be contingent on the underlying project securing a REC contract in the Adjustable Block Program, however securing such a REC contract must satisfy that contingency, rendering the contract otherwise binding. In cases where the system owner and host are the same entity, site control can be demonstrated by a statement from the system owner and host that this is the case.

Is a signed interconnection agreement required to apply to the ABP?

A signed interconnection agreement is required to apply for the Program for all systems over 25 kW.

Section 4.3(a) of the REC contract contemplates that if a Designated System is energized as of the Trade Date, the Seller may request that the contracting utility withhold the Collateral Requirement associated with that system from the first REC payment—thus obviating the Approved Vendor’s need to post Performance Assurance for that system. Given the Program Guidebook defines “Energized” in part as requiring completion and approval of Part II of the project application, is there a deadline applicable to an Approval Vendor’s Part II project application submittal such that Part II review and approval can occur prior to the project’s collateral due date?

For an energized project seeking to have its associated collateral withheld from its first REC payment, the Approved Vendor should submit its Part II project application at least 4 calendar weeks prior to the collateral due date (per the REC contract, collateral is due within 30 business days after the Trade Date).  This period will offer the Program Administrator sufficient time to review and verify the Part II project application in time for the Approved Vendor to formally request that collateral be withheld from the first REC payment.

If the Program Administrator determines that a timely-submitted Part II application requires more than 4 calendar weeks for review, the Program Administrator will recommend that the contracting utility extend the collateral payment deadline.  Please be aware, however, that the final decision about whether to offer an extension in time for collateral payment rests with the contracting utility.

Should an Approved Vendor submit its Part II application less than 4 calendar weeks prior to the collateral due date, then it is highly unlikely that the Program Administrator will be able to review the Part II application in time for collateral to be authorized to be withheld from the first REC payment.  In such cases, given the untimely submission, the Program Administrator will not recommend that the contracting utility extend the collateral payment deadline.  Similarly, if additional information is required from the Approved Vendor to complete review of a timely-submitted Part II application, then the Program Administrator may not be able to verify the Part II project application in time for collateral withholding.  In such a case, the Program Administrator will exercise reasonable discretion in recommending an extension to the collateral payment deadline, with the final decision resting with the contracting utility as outlined above.

What is required for a project to apply for the Adjustable Block Program?

Please see the Program Guidebook for the specific application requirements for the Part I and Part II application. Part I is the initial application and Part II is for projects in an ICC approved batch when they are completed and energized.

What is required in a shading study?

Initially, a shading study was required for all projects. With the ICC’s approval of the Revised Long-Term Plan, a shading study is no longer required for project applications as covered in this announcement.

What is the application fee for the Adjustable Block Program?

The application fee for the Adjustable Block Program is $10/kW, not to exceed $5,000, per project. This application fee will be paid to the Program Administrator at the time the batch is submitted. The application fee for each project will be part of the batch submission process and the fee per project will be automatically calculated by the application portal.  Fees may be paid by wire or ACH direct deposit initiated by the applicant using a unique tracking code generated by the application portal in the wire or direct deposit notes section to allow matching of deposits to batch submissions by the Administrator. If the Approved Vendor opts for this payment method, the batch will not be deemed submitted until the application fee is received by the Program Administrator. Approved Vendors will also be offered the ability to request that the Program Administrator withdraw funds from their account via ACH or pay by credit card. The batch will be deemed submitted at the time of submission if either of these methods are used. Credit card payments will be subject to an additional fee of 2.9% of the total payment to account for credit card processing fees and will be limited to no more than $10,000 per month per Approved Vendor.

When can I apply for the program?

The Program is currently open for applications from Approved Vendors.

Program capacity for project applications has been filled. Distributed Generation and Community Solar project applications submitted to the Adjustable Block Program are now being added to waitlists for the applicable project category. Subscriptions to Community Solar projects remain open.

Please find the current status of each Group/category on the Adjustable Block Program Block Capacity Dashboard page.

What happens if an Energized (Part II verified) system has a production meter failure?

In order to provide reliable and accurate information on REC production, the meter must be capable of recording the cumulative or incremental kWh that the system produces. When an Approved Vendor learns that one of its Part II verified systems has had a production meter failure, it must notify both the Program Administrator and that system’s contracting utility as soon it becomes aware of the failure. When alerting the Program Administrator, the Approved Vendor should provide an estimate of when the meter failed, when it became aware of the failure, its expected plan and timeline for fixing or replacing the meter, and any proposed temporary alternatives for reporting production if there is a significant time before the meter can be fixed or replaced.

Approved Vendors

Can a Part I application project that’s been waitlisted or otherwise not yet selected for a REC contract change Approved Vendors?

Yes. A project that has been waitlisted or otherwise not yet selected for a REC contract may change its Approved Vendor.  To be clear, this switch of Approved Vendor could be for an individual project that is a subset of a larger batch (although minimum batch size requirements would still apply).

While it is not necessary to seek Program Administrator approval in advance of commencing this transaction, the Approved Vendor transferring the project and the Approved Vendor receiving the project (“Transferee”) must provide the Program Administrator with a binding document wherein both agree that the Transferee shall have rights to the RECs produced by the project and the authorization to represent the project for an ABP application. The documentation also must show that the project host and the project owner, if different, consent to the change of Approved Vendor.

Please note that if a project was submitted co-located with another project, it will continue to be deemed co-located after any change of Approved Vendor. As a result, any co-located pricing or array layout requirements will still apply after a potential change of Approved Vendor.  The transferred project, if community solar, could, if applicable, be newly considered co-located after being received by the Transferee. The co-located pricing provision will only be applicable if the Illinois Commerce Commission’s approval of the second project is within one year or less of the Commission’s approval of the first project. If the first project has not yet received Commission approval at the time of the second project’s approval, then the co-located pricing provision will apply.

Can I switch Approved Vendors after my distributed generation project on my home or building is accepted to the Adjustable Block Program?

Another Approved Vendor could obtain the rights to your project’s Adjustable Block Program REC contract, but only with the consent of your original Approved Vendor.  See Section 6.7 of the Revised Long-Term Plan.

Can I tell customers that solar will eliminate their utility bill?

No. A utility bill includes both fixed and volumetric ($/kWh) charges. Electricity from solar can offset and reduce volumetric charges, but not fixed charges (e.g., the “customer charge” and “meter charge”). Thus, even if electricity from solar were to offset 100% of the volumetric charges of a given utility bill, fixed charges would still be levied by the utility. Therefore, it is incorrect and is a misrepresentation to claim that solar can eliminate, or reduce to zero, a customer’s utility bill. Claims through an Approved Vendor’s (or its agent’s) marketing materials that participation in the ABP will eliminate a customer’s utility bill are not permitted and will be flagged by the Program Administrator. For more information see Section 1.B.1.e of the Guidelines for Distributed Generation Marketing Materials and Marketing Behavior.

Do Approved Vendors need an account in PJM-GATS and/or M-RETS?

Proof of an account in PJM-GATS or M-RETS is required to become an Approved Vendor. This requirement is outlined in Section 6.9 of the Approved Plan.

In PJM-GATS an Approved Vendor can have a generator account (if they have a generator to register) or an aggregator/broker account (does not require a generator). Click here to view the various account types offered by PJM-GATS and the fees associated with those account types.

In M-RETS an Approved Vendor can have a General Subscription, a Project Subscription, a Small Generator Project Subscription, or a Micro Gen Project Subscription (only eligible for one 100 kW batch of generators). Click here to view the various account types offered by M-RETS and the fees associated with those account types.

Do Approved Vendors need to be Distributed Generation Installer certified?

No. The Distributed Generation Installer certification is required by all firms performing actual distributed generation installations, and as such an Approved Vendor may also be a Distributed Generation Installer. However, any entity that meets the Approved Vendor requirements can become an Approved Vendor and doesn’t necessarily need to be involved in the installation process at all, in which case they would not need to be certified as a Distributed Generation Installer.

Do solar installers need to be certified in Illinois?

Yes, there are two requirements for distributed generation installation in Illinois. The first is a company level requirement that Distributed Generation Installers be certified by the Illinois Commerce Commission (ICC). Details of this requirement can be found at the ICC’s Distributed Installers page. A list of Certified Distributed Generation Installers can be found here. Any questions about this requirement should be directed to the ICC which oversees this program.

Additionally, installation of a photovoltaic system, if it will seek a REC contract under the Adjustable Block Program, must be done by a Qualified Person as defined under 83 Ill. Adm. Code § 468.20, which covers the qualifications required of the individuals who are actually installing the system.

What if applications are submitted by two different Approved Vendors for the same project?

In a case where one Approved Vendor submits a Part I application for a project, and then (before the first application is reviewed and approved by the Program Administrator and its batch submitted to the ICC for approval) a second Approved Vendor submits a new Part I application for a project at the same location, the Program Administrator will proceed as follows to resolve the potential conflict:

  • The Program Administrator will first investigate (including potentially contacting the site host) whether there is an intent that the multiple project applications are for separate, co-located projects (and if so, whether the co-location would be allowed under Program terms and conditions).
  • If co-location is intended and feasible, then the Program Administrator will allow for co-location.
  • If co-location is not both intended and feasible (i.e., if the two applications appear to represent the same project), the Agency will review the documents submitted with the Part I applications to determine which Approved Vendor is premising its control of RECs on an earlier-executed site control agreement (or, if both Approved Vendors rely on the same site control agreement, then which Approved Vendor has an earlier-executed REC control agreement); this Approved Vendor will be presumed to be the proper representative of the project.
  • An Approved Vendor with a later-executed site control or REC control agreement (as applicable) will be given an opportunity to furnish documentation showing that the earlier-executed instrument was properly terminated prior to that Approved Vendor’s Part I ABP application. If acceptable documentation is provided (subject to confirmation with the other Approved Vendor), then the application from the Approved Vendor with the later-executed agreement would proceed (subject to any other review and approvals of the application).

What if the project is sold, but the Approved Vendor does not change – is that permissible, and what requirements or conditions apply?

A sale of the project itself (or a majority equity share in the project) that results in a new system owner but not a new Approved Vendor is allowed while the project remains unselected for a REC contract. In such a case, the Approved Vendor is expected to contact the Program Administrator in order to update the ownership data for the project in the ABP portal. This project ownership change would not change any previous determination that the project was co-located, and it could, if applicable, cause the project to be newly considered co-located. The co-located pricing provision will only be applicable if the Illinois Commerce Commission’s approval of the second project is within one year or less of the Commission’s approval of the first project. If the first project has not yet received Commission approval at the time of the second project’s approval, then the co-located pricing provision will apply.

What if the Approved Vendor itself is sold to a new entity – is that permissible, and what requirements or conditions apply?

The sale of an Approved Vendor is permissible. Both the previous and new owner of the Approved Vendor should notify the Program Administrator in the event of a sale of an entity operating as an Approved Vendor. The new owner will be required to enter its information into the registration record for that Approved Vendor entity.

What is required to become an Approved Vendor?

The Program Administrator has published a set of Approved Vendor requirements and marketing material standard disclosure requirements.

How do I request to update my banking information for invoice payments in advance of an invoicing window?

A change in an Approved Vendor’s banking information represents a change to Section 13(a) of the REC contract. As such, in order for the contracting utility to process the change, the Approved Vendor must provide a letter to ComEd at WB&CStaff@comed.com or to Ameren at dlpowersupplyacquisition@ameren.com and AICsettlements@ameren.com, requesting the change in banking information. The letter must be on company letterhead, contain the new banking information as well as a contact from the Approved Vendor’s Treasury group that the utility can contact directly to confirm this change request, and be signed by an authorized signatory of the company. If the contracting utility is MidAmerican, the Approved Vendor must contact the utility’s accounts payable department at AccountsPayable@midamerican.com to request a banking change form.

To provide for processing time, a request to update banking information (including a completed banking change form to MidAmerican) must be provided to the contracting utility at least 15 calendar days in advance of an invoicing window (e.g., no later than February 14, 2021 in time for the opening of the invoicing window on March 1, 2021). The updated banking information may be entered into the “Enter Contract Notices Contact Information” section of the Approved Vendor’s dashboard in the ABP portal at any time prior to generation of an invoice.

How should a request for the extension of a project’s Scheduled Energized Date be submitted?

Each Scheduled Energized Date extension request under Section 5(b) of the ABP REC contract should reference the specific contract clause under which an extension is sought (i.e., which subparagraph of Section 5(b) is being relied upon) and should avoid referencing multiple clauses in a single request (as multiple clauses may implicate multiple distinct processes and decision-makers for the request). For COVID-19-related extensions, the most straightforward path may be a request for a “good cause” extension granted at the IPA’s discretion under Section 5(b)(v) of the REC contract rather than the declaration of a force majeure event or reliance on a separate subparagraph of Section 5(b).

Each extension request should include, at minimum, a brief narrative outlining the justification for the request. This narrative should clearly explain the situation under which the Approved Vendor believes an extension is warranted for the referenced systems. If extensions are being requested for multiple systems and the narrative is similar, a single extension request may be made for multiple systems (although please provide separate requests for each contracting utility).

The IPA also strongly encourages that each of the following be included in an extension request.

  1. Approved Vendor Name (as listed in your ABP Approved Vendor portal)
  2. Approved Vendor ID #
  3. Designated System ID #
  4. Project Name
  5. Project Type (distributed generation or community solar)
  6. Contract ID #
  7. Batch ID #
  8. Trade Date
  9. Contracting Utility
  10. REC Contract Clause Referenced (e.g., Section 5.b.v)
  11. Length of Extension Requested
  12. Original Scheduled Energization Date
  13. Requested New Scheduled Energization Date (Rounded to the last business day of the month for Section 5(b)(v) requests)

For requests covering multiple systems, please include this information in a spreadsheet attached to the request.

Note that any extension requests under Section 5(b)(v) should be rounded to the last business day of the month. For example, if a system’s Scheduled Energized Date is August 19, 2020, and the Approved Vendor requests a 12-month extension under Section 5(b)(v), the new Scheduled Energized Date will be August 31, 2021, instead of August 19, 2021. Please ensure this is captured in all extension requests sought under Section 5(b)(v).

Lastly, please double-check the accuracy of all extension request information, including whether a given system is still under contract, prior to submitting an extension request. And remember that under Section 5(b), requests must be “made in writing by Seller to Buyer and the IPA prior to the Scheduled Energized Date.” Buyer contact information is contained in Section 13 of the ABP Contract and requests to the IPA should be sent to IPA.solar@illinois.gov.

Should you have any questions prior to submitting a request, please contact IPA Chief Legal Counsel Brian Granahan at Brian.Granahan@Illinois.gov.

What information about a customer can I collect when performing online customer acquisition for Distributed Generation systems?

Section 2(I)(1) of the Revised DG Marketing Guidelines related to “Online Marketing” states the following:

“Each Approved Vendor offering PV system sale or financing online shall clearly and conspicuously make available the Illinois Shines Informational Brochure prior to collecting any personal information other than a zip code or electric service territory.”

As a clarification, this provision only applies to online marketing (e.g., social media) or solicitation (e.g., email) activities actively conducted by Approved Vendors. It would not be applicable to the passive collection of basic information, such as a website form where a prospective customer could request more information and/or receive follow-up contact from an Approved Vendor or Designee. The Approved Vendor or Designee would be expected to provide the Illinois Shines Informational Brochure as part of any response to such a form submittal.

Additional Guidance on Completing Disclosure Forms

Q: How should the Disclosure Form field for “the method or formula for calculating payments throughout the term of the subscription” be completed for community solar offers where the subscription payment is a percentage of the bill credit received by the customer?

A:  The Illinois Power Agency’s Long-Term Renewable Resources Procurement Plan provides that the Program’s Disclosure Form requirements “are fundamental to subscribers receiving standardized information,” serving as “the backbone of the Agency’s efforts to deliver uniform content about the rights and obligations under a ratepayer-funded program to everyday citizens.”  (Emphasis added.)  To this end, the Program’s Community Solar Marketing Guidelines require that customers receive “a populated community solar form” prior to subscription contract execution, with the intent that the populated form “gives consumers who are considering subscribing to a community solar project clear information about their subscription offer.”

It is important that Approved Vendors and Designees provide complete and accurate information that is responsive to each Disclosure Form field prompt. Just as providing an incomplete Disclosure Form would violate Program requirements, providing a Disclosure Form that does not provide the information required by the field prompt or description also violates Program requirements.

To date, the Agency has observed that select community solar Disclosure Forms have failed to provide “clear information” about subscription offers to customers.  To ensure Disclosure Form content meets the Program’s intent of uniform, standardized content, the Agency provides the following clarification of Program requirements.

Many community solar offers set the subscription payment as a specific percentage of the bill credits received by the customer. For example, the customer’s monthly payment may be set at 80% of the bill credit amount on their utility bill, such that the customer retains 20% of the value of the bill credit.

Companies that use this model must disclose the specific percentage of the bill credit that will be charged to the customer as their community solar subscription fee. In general, in assessing whether a Disclosure Form’s payment calculation explanation is judged to meet Program standards, the Program Administrator will employ a standard of whether the average customer could be reasonably expected to calculate their monthly subscription fee based on the explanation provided within the Disclosure Form.  That calculation must match actual charges back to the customer.  Going forward, the Agency and Program Administrator may modify the community solar Disclosure Form to include a specific option for offers where the payment is a percentage of the bill credit, such that the Approved Vendor or Designee can simply fill in the specific percentage and the Disclosure Form will generate standardized language describing this payment structure.  Until those modifications are made, Approved Vendors and Designees utilizing percentage-of-bill-credit offers must disclose the percentage of bill credits being charged, rather than communicating an estimated monthly price (which may be inaccurate) or an estimated rate (which may change as the customer’s supply rate or the utility price to compare changes).

The following statements are acceptable for describing this type of offer:

  • “Your payment will be [xx]% of the community solar credit on your utility bill.”
  • “The subscriber will be charged for [xx]% of the value of the solar credits allocated to them.”

Generalized narrative descriptions that do not allow the customer to calculate or understand their payment amount are not adequate. The following descriptions are not acceptable, as they do not provide adequate information to the customer about how their payment will be calculated:

  • “A utility bill credit will be determined using the Community Solar Rider POGCS which is the Purchased Electricity Charge plus the Purchase Electricity Adjustment.”
  • “The Bill Credits will be calculated using the Rider Net Meter.”
  • “A per-kilowatt-hour fixed rate (as defined within your Subscription Agreement) multiplied by the production associated with your Subscription.”
  • “Based on a percentage of received amount on a utility bill.”
  • “Calculated based on monthly usage.”
  • “Number of kWhs generated by the Project in a given Bill Period x the Percentage Allocation x the Subscription Rate.”

Approved Vendors and Designees are required to comply with this clarification of the Program requirements. The Program Administrator will monitor Disclosure Forms for compliance and may pursue disciplinary action for violations, although prior acceptance of problematic forms shall not be considered a determination that explanations contained therein are compliant. Should an Approved Vendor or Designee have any questions about whether a specific subscription offer explanation is acceptable, the Approved Vendor or Designee should ask the Program Administrator before utilizing any potentially questionable language.

Q: What is the effect of incomplete information or errors in a Disclosure Form?

A: The Illinois Power Agency’s Long-Term Renewable Resources Procurement Plan provides that the Program’s Disclosure Form requirements “are fundamental to subscribers receiving standardized information,” serving as “the backbone of the Agency’s efforts to deliver uniform content about the rights and obligations under a ratepayer-funded program to everyday citizens.”  (Emphasis added.) Both the Community Solar and Distributed Generation Marketing Guidelines require that customers receive a completed Disclosure Form prior to contract execution, so that the customer has “clear information” about the offer.

Therefore, providing a customer with a Disclosure Form that has incomplete or erroneous information is a violation of program requirements and may lead to disciplinary action. In addition, noncompliant Disclosure Forms may be rejected by the Program Administrator.

Q: Can the Disclosure Form reference and include attachments with additional information?

A: The Illinois Power Agency’s Long-Term Renewable Resources Procurement Plan provides that the Program’s Disclosure Form requirements “are fundamental to subscribers receiving standardized information,” serving as “the backbone of the Agency’s efforts to deliver uniform content about the rights and obligations under a ratepayer-funded program to everyday citizens.”  (Emphasis added.)  Both the Community Solar and Distributed Generation Marketing Guidelines require that customers receive a completed Disclosure Form prior to contract execution, so that the customer has “clear information” about the offer.

The Agency has observed that select Disclosure Forms have included references to attachments. To ensure Disclosure Form content meets the Program’s intent of uniform, standardized content, the Agency provides the following clarification of Program requirements.

Each Disclosure Form field must be completed such that it provides the information required by the field prompt or description. A Disclosure Form field may not simply refer the customer to an attachment or other document. An attachment may be used to provide additional information beyond what is required in the Disclosure Form. For example, the community solar Disclosure Form requires, for offers with a variable rate, an explanation of the method or formula for calculating payments throughout the term of the subscription.  An Approved Vendor or Designee must complete that field with information from which an average customer could fairly be expected to calculate their monthly subscription fee. An Approved Vendor or Designee could then also provide a full rate schedule in an attachment.

Q: What counts as an early termination fee or penalty, such that a Disclosure Form must disclose that there is an early termination fee or penalty?

A: Both the Community Solar and Distributed Generation Marketing Guidelines require that customers receive a completed Disclosure Form prior to contract execution, so that the customer has “clear information” about the offer. One Disclosure Form requirement for community solar and distributed generation leases and PPAs is disclosure of whether there are any fees or penalties for early termination of the contract.

Any requirement (triggered by early termination) that a customer make additional payments that they would not otherwise be required to make at that time counts as an early termination fee or penalty. For example, a requirement that a customer pay part or all of the future payments under the remaining duration of the contract counts as an early termination fee or penalty and must be disclosed as such.

Project Eligibility

Can I submit an application for a solar PV system on my home/small business system into the Program myself?

All applications will have to be submitted to the Program by an Approved Vendor. Larger (non-residential) systems of at least 100 kW can apply as a Single Project Approved Vendor.

For small systems that have already been built (and energized after June 1, 2017), if your installer does not become an Approved Vendor, or work with an Approved Vendor, you will need to choose an Approved Vendor from the Approved Vendor list to apply on your behalf.  Each Approved Vendor may offer you different terms and you should review multiple offers and choose carefully.

Systems will have to comply with all Program terms and conditions, which may require retroactive adjustments to the system or agreements with the installer.  Systems in the Adjustable Block Program must have been installed by an individual who is a “Qualified Person” as defined in Section 16-128A of the Illinois Public Utilities Act and Title 83, Part 468 of the Illinois Administrative Code.

Community Solar

How do I find a community solar project to participate in?

A list of community solar projects that have opted to be listed publicly is posted here and on the Illinois Shines website. Please keep in mind that projects that are in development and have not yet applied to and been approved by the Adjustable Block Program will not appear on the list. Also keep in mind that some of the projects here may already be fully subscribed. This list will be updated as projects opt to be added.

If I subscribe to a community solar project participating in the Adjustable Block Program, can I keep my subscription when I move? Can I transfer my subscription to someone else?

Under state law and the Long-Term Renewable Resources Procurement Plan, subscriptions to community solar projects must be portable (i.e., the subscriber may retain the subscription while changing locations within the same utility service territory) and transferable (i.e., a subscriber may assign or sell the subscription to another person within the same utility service territory).  The Adjustable Block Program requires that the community solar provider may not charge a fee for transferring your subscription to someone else.  These rights of transferability and portability may still be subject to other restrictions, including the community solar provider’s right to check a new subscriber’s credit score, and the utility’s right to ensure that a subscription is appropriately sized relative to the subscriber’s usage.

What is required to sell subscriptions in a community solar project?

The Program Administrator has published a set of marketing materials, standard disclosures, designee registration and requirements for community solar projects which can be found here.

What is the process for updating the standing order percentage of a Community Solar project?

Sections 5(e)(iv)(B) and 5(e)(iv)(C) of the REC contract describe the requirement for any changes in the standing order percentage of a Community Solar project, based on any changes to that project’s total percentage subscribed, to be updated in the relevant registry after both Part II verification and Program Administrator review of each of a project’s four Community Solar Quarterly Reports. This process is as follows:

If the project is registered in GATS:

  1. The Program Administrator sends email to the contracting utility and Approved Vendor with a link to the revised Schedule B, highlighting any change in the standing order percentage.
  1. If there is a change to the standing order percentage, the Program Administrator sends email to the GATS admin, copying the utility and Approved Vendor, requesting removal of the irrevocable flag on the Community Solar project’s standing order. The email will include at a minimum, the project’s ABP application ID, registry Unit ID, and new standing order percentage.
  2. The utility replies to all confirming its consent to remove the irrevocable flag.
  1. GATS removes the irrevocable flag and replies to all confirming that the irrevocable flag has been removed.
  2. The Approved Vendor cancels the existing standing order and initiates a new irrevocable standing order with the new specified percentage.
  3. The Approved Vendor replies to all confirming the new standing order has been initiated.
  4. The utility confirms the new standing order is accurate.

If the project is registered in M-RETS:

  1. The Program Administrator sends email to the contracting utility and Approved Vendor with a link to the revised Schedule B, highlighting any change in the standing order percentage.
  1. If there is a change to the standing order percentage, the Program Administrator sends email to the M-RETS admin,copying the utility and Approved Vendor, requesting a change to the Community Solar project’s standing order percentage. The email will include at a minimum, the project’s ABP application ID, registry Unit ID, current standing order percentage, and new standing order percentage.
  2. The utility and Approved Vendor reply to all confirming their consent to updating the standing order percentage.
  3. M-RETS updates the standing order with the new percentage and replies to all confirming that the change is complete.
  4. Both the utility and Approved Vendor confirm that the standing order accurately reflects the new percentage in the registry.

The above process should be completed in no less than 30 calendar days from the Program Administrator’s initial email to the registry. Failure to update the standing order in a timely fashion may have an impact upon obligations under the REC Contract.

Under what circumstances can a traditional community solar project be substituted for another waitlisted project?

Under Section 1-75(c)(1)(G)(iv)(3)(iii) of the IPA Act, Approved Vendors that are awarded a 2021 20-Year REC Delivery Contract for a community solar project that was previously waitlisted have the right under the contract to substitute the contracted community solar project(s) with other waitlisted community solar projects without penalty in the event that the project receives 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.  The 2021 REC Delivery Contract does not provide for substitution of a project for other circumstances outside of the control of the applicant; therefore, once a project has received a REC Contract, it may only be substituted due to interconnection costs in excess of 30 cents/W AC.

In accordance with Section 7.2 of the REC Delivery Contract, an Approved Vendor wishing to make a substitution may make a written request to the Buyer and IPA within 30 days of receipt of the cost estimate to substitute a project or projects from the waitlist of equal or lesser nameplate capacity.  The request must be accompanied by the cost estimate from the interconnecting utility which demonstrates the costs exceeds 30 cents/W AC.  The written request and accompanying documentation should be submitted to the IPA via email to IPA.Solar@Illinois.gov.  As soon as practicable after this request, the Program Administrator will provide to Buyer and Seller a revised Schedule A, Schedule C and Schedule D.

The Agency understands that other circumstances beyond the control of the Approved Vendor may adversely impact the viability of a project such that the AV wishes to substitute the project.  Therefore, after the submission of an Approved Vendor’s portfolio of community solar projects to the Program Administrator on March 14, 2021, but prior to the Program Administrator submitting a batch that contains such a project to the Commission for approval of a 2021 REC Delivery Contract for a project submitted under Section 1-75(c)(1)(G)(iv)(3) of the IPA Act, an Approved Vendor may request to substitute a submitted project with other waitlisted project(s) up to the submitted project’s nameplate capacity.  Substitution will be granted without penalty in all cases where the project receives a cost estimate for interconnection facilities and any required distribution upgrades of greater than 30 cents/W AC of that project’s nameplate capacity.  The Agency will allow substitution of projects due to other circumstances outside of the control of the applicant firm upon demonstration that project substitution is warranted, including but not limited to unforeseeable development hurdles, permitting issues, and/or restrictions resulting from the COVID-19 global health pandemic.  Approved Vendors that wish to substitute a waitlisted project for a submitted project prior to the batch containing that project having been submitted to the Commission for approval of a REC Delivery Contract should send a written request to the Program Administrator and include a copy of any supporting documentation.  As soon as practicable after a review of the circumstances supporting the request, the Program Administrator will notify the Approved Vendor of its determination.  If granted, the Program Administrator will notify the Approved Vendor that the substitution has been completed and will submit the project to the Commission for approval.  If denied, the Approved Vendor may appeal that decision to the IPA, and the original project application will continue to be held pending determination of that appeal.

Approved Vendors wishing to hold a traditional community solar project from submission to the Commission in order to determine whether a substitution of the project is necessary must make that request in writing to the Program Administrator once the relevant project(s) are Part I verified.  The Program Administrator will hold each such project for 60 days or until a substitution has been completed and will consider requests for additional time on a case-by-case basis.  The Program Administrator will work with Approved Vendors to submit projects/batches to the Commission for approval after the expiration of the 60-day window or subsequent extension.

Please note that substitution is limited to community solar projects awarded contracts upon reopening pursuant to Section 1-75(c)(1)(G)(3) of the IPA Act.  Whether substitution will be permitted under future blocks of Traditional Community Solar will be determined through the Agency’s Long-Term Renewable Resources Procurement Plan or requirements published thereafter.

How does the Community Solar waitlist capacity allocation process operate?

Under Section 1-75(c)(1)(G)(iv)(3) of the Illinois Power Agency Act (20 ILCS 3855), as modified through the Climate and Equitable Jobs Act (Public Act 102-0662), the first two blocks of annual capacity for traditional community solar projects participating in the Adjustable Block Program will open simultaneously for a total waitlist capacity allocation of 250 MW (30% or 75 MW to Group A; and 70% or 175 MW to Group B) within 90 days after the effective date of the Act.  The IPA Act specifies that this capacity shall be filled will projects selected exclusively from waitlisted ABP community solar applications, with waitlist shares allocated to Approved Vendors and their affiliates proportionate to those entities’ shares of capacity of waitlisted applications.  Eligible projects (for both the determination of allocations and that meet the following requirements) are required to have been eligible for the April 2019 lottery, on the ABP community solar waitlist as of December 31, 2020, and currently active applications (i.e., Part I status remains verified). On December 14, 2021, the Program Administrator announced the proportional allocation of the 250 MW of new capacity to Approved Vendors (and affiliates).

Allocation Minimum and Maximum

By law, the allocation includes a statutory 500 kW minimum for each Approved Vendor having a valid project application.  That minimum will be applied across both Groups (A and B) in aggregate, and then allocation will be provided on a pro rata basis if an Approved Vendor has capacity on the waitlist of both Groups (please note that, per below, those fractional allocations may be transferred to other Approved Vendors).  For example, an Approved Vendor with projects across both groups could receive a pro rata allocation of 300 kW in one group and a 200 kW allocation in another group, for a 500 kW total minimum allocation across both groups.

Additionally, by law, each Approved Vendor (inclusive of its affiliates) is subject to an allocation maximum of 20% of capacity for each Group.  Capacity in excess of that 20% maximum allocation will serve to increase the proportionate allocation for each other Approved Vendor within that Group (e.g., if one Approved Vendor has 25% of waitlisted project capacity within a given Group, then the remaining 5% is added proportionately to the capacity allocated to those other Approved Vendors).

Allocation Determinations and Transfer of Allocation

Approved Vendors still must notify the Program Administrator of any transfers of waitlisted projects or sales of Approved Vendors under Program requirements.  However, a snapshot of the waitlist at some particular time must be used to determine an Approved Vendor’s proportionate share of capacity, prior to the communication of that waitlist share.  The IPA has determined that the statutory effective date of September 15, 2021, which established the proportionate allocation regime and memorialized each party’s pending rights, is the appropriate date for determining proportionate shares of the community solar waitlist for capacity awards.  This allows the Program Administrator to use the same known and understood waitlist for waitlist capacity allocation as it used across the fall in verifying affiliate information for Approved Vendors and their affiliates.

Consequently, transfers or sales of projects that occurred after September 15, 2021 will not impact the proportional allocation of total nameplate capacity across the waitlist.  However, as outlined below, entities may transfer allocations once provided with those allocations after December 14, 2021.  If entities have acquired projects since September 15, 2021 and the underlying legal instruments did not expressly provide for a transfer of the pending waitlist allocation rights, the IPA hopes and strongly encourages that all parties operate in good faith in ensuring that the rights intended to be transferred through the sale of a project are ultimately reflected in the terms of that transfer.  Assuming that parties operate in good faith and consistent with shared intentions, the transfer of waitlisted capacity may then attach to the prior-executed transfer of a project, thus allowing waitlist allocation to reflect changes in project ownership where so intended.

The Program Administrator confirmed affiliations directly with the Approved Vendors through a process completed on November 23, 2021.  Allocations to Approved Vendors were announced on December 14, 2021.  By law, Approved Vendors have 90 additional days to offer a portfolio of projects back to the IPA, providing for a statutory deadline of March 14, 2022. Waitlisted projects may be resized up to 2 MW in size, but must be sized at a level commensurate with that Approved Vendor’s allocated capacity.

However, no Approved Vendor (or its affiliates) may have more than 20% of a Group’s capacity (e.g., no more than 15 MW for Group A or 35 MW for Group B) in those project application portfolios submitted back to the Program Administrator on March 14, 2022. Approved Vendors (or their affiliates) may exceed that limit between December 14, 2021 and the deadline for transfers of allocation, but must be at or below the limits by February 28, 2022.

Process of Transferring of Allocation

As indicated above, to maximize both economic efficiency and the extent to which the full 250 MW of capacity allocated results in successful projects, Approved Vendors may transfer some or all of their allocated capacity within a Group to other Approved Vendors after the allocation is finalized by the Program Administrator (i.e., after that allocation has been made to those Approved Vendors on December 14, 2021). Transfers must be completed and memorialized by no later than February 28, 2022 to ensure that the Program Administrator has sufficient time to confirm transfers and final portfolios prior to the March 14, 2022 deadline.  Approved Vendors are encouraged to submit transfer memorialization forms as soon as allocation transfers have been agreed to and completed.

However, to maintain consistency with the law’s guidance that awards to any given Approved Vendor constitute no more than 20% of a Group’s allocation (which the IPA understands as intending to support a sufficiently diverse and non-concentrated pool of Approved Vendors receiving contract awards through this process), no Approved Vendor (or its affiliates) may have more than 20% of a Group’s capacity (e.g., no more than 15 MW for Group A or 35 MW for Group B) in those project application portfolios submitted back to the Program Administrator on March 14, 2022.

Approved Vendors transferring capacity must provide the Program Administrator a fully executed copy of this Community Solar Waitlist Capacity Transfer Confirmation form for the Program Administrator’s review and verification by no later than February 28, 2022, as noted previously.

By March 14, 2022, Approved Vendors must submit to the Program Administrator the application IDs of the projects that they select for their portfolio and the total AC capacity of those projects. Subsequently, Approved Vendors must submit to the Program Administrator the associated specifications for any projects in their portfolio that have changed from what was previously Part I verified, including but not limited to project size. While there is not a deadline for submitting updated specifications, Approved Vendors are encouraged to submit this information as soon as possible so that the Program Administrator may re-review these projects and move them through the application review process to ICC submission.

As Approved Vendors update project specifications, the size of each project may change from the size submitted to the Program Administrator by March 14, 2022 so long as the total portfolio size does not increase. For example, if an Approved Vendor has a 3.25 MW allocation and submits to the Program Administrator a portfolio of two projects, one project at 1.5 MW and one project at 1.75 MW, and subsequently updates the specification for the 1.5 MW project to make it a 1.6 MW project, then the Approved Vendor would also have to submit updated specifications to decrease the 1.75 MW project to 1.65 MW in size. If a change is only for a project size to decrease, the Approved Vendor is not required increase the size of other projects in their portfolio. A project’s capacity may not be reallocated to other projects in an Approved Vendor’s portfolio of selected projects such that the first project’s size decreases to 0 MW. Any such size changes requested by an Approved Vendor will serve as the Part I verified size used for determining expected REC delivery quantities for contracts submitted to the ICC for approval.

As outlined above, Approved Vendors will have until March 14, 2022 to select waitlisted applications up to their allocated capacity, inclusive of any transfers of allocation from other Approved Vendors.  Associated specifications that may be updated include number and size of panels and inverter, capacity factor, and type (e.g., fixed or tracking). A project must remain on the same parcel(s) as noted in the original Part I application. Approved Vendors do not need to provide documentation of refreshed site control, land-use permits, and the interconnection agreement in order for eligible projects to be included their portfolio of selected projects. (The process by which the Program Administrator confirmed refreshed site control and active land-use permits for waitlisted community solar projects pursuant to the 2020 Revised Long-Term Renewable Resourced Procurement Plan was a one-time event in 2020.) After the selection of projects by Approved Vendors for their final portfolio is completed, the Program Administrator will conduct a final review of project information. Approved and verified applications will then be submitted to the Illinois Commerce Commission for approval.

Capacity allocations inclusive of transfers of allocated capacity that have been received and approved by the Program Administrator will be updated on the Reopening Updates page on a weekly basis through March 14, 2022.

REC Contract for Community Solar Waitlisted Projects

All selected projects will utilize the new form of the REC Delivery Contract (“2021 20-year REC Delivery Contract”) to be finalized by December 14, 2021.  That contract features a number of changes required by Public Act 102-0662, including a 20-year pay-upon-delivery REC payment structure, a 50% small subscriber minimum commitment, and requirements for compliance with the Prevailing Wage Act.

Discretionary Capacity

When are the discretionary funds going to be released?

The IPA released an announcement on April 3, 2019 detailing the allocation of discretionary capacity. All projects selected using discretionary capacity will receive Block 4 pricing.

Community Solar Lottery

If I was awarded a Block 1 REC contract through the ABP lottery, am I obligated to sign that contract?

Through requirements in the Revised Long-Term Renewable Resources Procurement Plan and the Lottery Procedure in Section 1(C) of the Program Guidebook, the Agency has generally sought to ensure that projects applying to the ABP are ready, willing, and able to advance to development and energization. Approved Vendors that do not execute an ABP contract (or Product Order) after project selection, submission to the Commission for approval, the Commission’s approval, or the utility’s execution may face disciplinary measures impacting their status as an Approved Vendor in the Program moving forward. Any such discipline will be based on the Program Administrator and IPA’s review of the circumstances under which the contract (or Product Order) was declined. If circumstances genuinely outside of an Approved Vendor’s control necessitated non-execution, then discipline may have limited deterrent effect and may not be warranted, and thus the Approved Vendor’s explanation may want to emphasize and explain any such circumstances. Neither the IPA nor the Program Administrator is able to provide a disciplinary determination in advance of non-execution to “pre-approve” such an action, nor can they provide a timeframe for the issuance of such determination after non-execution.

As described in Section 1(D)(2) of the Program Guidebook, once a project is selected from the waitlist, the Approved Vendor will be given 10 business days to accept or decline the selection.

If one of my projects is not selected in the lottery, when is the next cycle?

There will not be another lottery selection cycle for Adjustable Block Program community solar projects.  Section 6.3.3 of the IPA’s Revised Long-Term Renewable Resources Procurement Plan details the management of various Program waitlists, including the current community solar waitlist and offers a plan for community solar project selection should a Block 5 be created.

What was the process for the Block 1 lottery?

This flowchart explains the lottery process for any given Block/category.  Three Group/category combinations (Group A, Large DG; Group A, Community Solar; and Group B, Community Solar) held lotteries on April 10, 2019.

Why were certain projects (i.e. previously installed systems or host-owned systems) not given priority in the lottery?

The Adjustable Block Program lottery approach was approved by the Illinois Commerce Commission when it approved the Long-Term Renewable Resources Procurement Plan on April 3, 2018. The lottery approach does not give priority to (for distributed generation systems) host-owned systems as opposed to third-party-owned systems or (for any type of system) previously installed systems as opposed to planned systems. The Plan, as approved by the Illinois Commerce Commission, only had a single prioritization provision for the lottery – for community solar projects with commitments for at least 50% small subscribers.

System Engineering

Can a project be upgraded from a fixed mount panel to a tracker mounted panel after ICC contract approval?

Switching between tracking system types and non-tracked systems is allowed; however, the lower of the Part I capacity factor or Part II capacity factor must be used.

Do I need a revenue grade meter or can I just use my inverter reading?

Systems up to 10kW in size are able to use either a production meter that is accurate to +/-5% (including refurbished and certified meters) or an inverter specified by the manufacturer to be accurate to +/‐5%. The inverter must be UL-certified and must include either a digital or web-based output display. Inverters with integrated ANSI C.12 compliant production meters are allowed with a specification sheet showing this standard has been met.

Systems over 10 kW and less than 25 kW in size must utilize a production meter that meets ANSI C.12 standards. Meters that are refurbished (and certified by the meter supplier) are allowed.

Systems over 25 kW must utilize a new production meter that meets ANSI C.12 standards.

Note: System sizes are AC nameplate capacity. Therefore, a system with a 10kW inverter, for example, is considered a 10kW system regardless of DC nameplate capacity of the system.

RECs

How is the REC obligation calculated for a specific project?

This topic is addressed in section 6.14.5 of the Revised Long-Term Plan. When a project is approved for the Adjustable Block Program, a 15-year REC obligation will be calculated for that project. Approved Vendors will have the option to use either a PVWatts calculated capacity factor automatically computed by the ABP portal or an alternative capacity factor based on an estimated production analysis conducted using an equivalent tool. Information on approved capacity factor calculations for use under the program can be found in Section 4(J) of the Program Guidebook.

How will systems be paid for RECs through the Adjustable Block Program?

For systems up to 10 kW, an upfront payment for the full value of the REC contract will be made to the Approved Vendor at the time the project is fully energized. For distributed generation systems greater than 10 kW and up to 2,000 kW and community solar projects, 20% of the renewable energy credit purchase price will be paid to the Approved Vendor when the project is energized. The remaining portion is paid quarterly over the subsequent 4-year period. Details on the payment schedule can be found in the REC contract between the Utility and the Approved Vendor.

REC Contract

Are price adders, such as the small subscriber adder, factored into a Designated System’s initial REC collateral calculation?

Yes.  The following discussion applies to a Designated System that is a Community Renewable Energy Generation Project. The contractual definition of Collateral Requirement before Energization is based on Proposed Price – which, in turn, is based on the Proposed Nameplate Capacity and the proposed Community Solar Subscription Mix (which may qualify the system for REC price adders under the ABP) presented at the ABP Part 1 application stage.  Within 30 Business Days after the Illinois Commerce Commission approves inclusion of a Designated System within a Product Order for a REC Contract, assuming the Designated System is not energized yet, the Approved Vendor will be required to post Performance Assurance in an amount that includes the initial Collateral Requirement for that Designated System.

The calculation of the Designated System’s Collateral Requirement at subsequent times may differ for the following reasons, however.  The definition of Contract Price indicates that it can change at the time of Energization of the Designated System and then up to four additional times after the first four Quarterly Periods after Energization, each time based upon changes in Community Solar Subscription Mix that may change the small subscriber price adders applicable under the ABP. The Contract Price will be permanently fixed after the fourth Community Solar Quarterly Report.  The Contract Nameplate Capacity, which is based on the share of Actual Nameplate Capacity that is subscribed, also will be evaluated at the time of Energization and after each of the four Community Solar Quarterly Reports, then permanently fixed. For a Designated System that has reached Energization, the Collateral Requirement at any given time will be based both on the Contract Price and the Contract Nameplate Capacity. The Collateral Requirement for each Designated System in the REC Contract (including any Community Renewable Energy Generation Project) would be re-evaluated at any time (but not at other times) when there is a Drawdown Amount for any Designated System(s) in the REC Contract and an ensuing required top-up of the total Performance Assurance Amount.

Can I decline to execute a REC contract or product order?

With respect to declining to execute a contract after receiving a contract award, Section 5(A) of the Program Guidebook notes the following:

When the Program Administrator submits contract information to the Commission for approval, that submittal will include the Program Administrator’s recommendation for approval of the batch, with a summary of factors relevant to Plan compliance and pertinent to the Commission’s standard of review for batch approval. Once a batch is approved by the Commission, the applicable utility will execute the contract. The Approved Vendor will then be required to sign the contract within seven business days of receiving it. Approved Vendors that do not execute an ABP contract after project selection, submission to the Commission for approval, the Commission’s approval, or the utility’s contract execution may face disciplinary measures impacting their status as an Approved Vendor in the Program moving forward; any such discipline will be based on the Program Administrator and IPA’s review of the circumstances under which the contract was declined.

Discipline may include a possible suspension or termination of the Approved Vendor’s status under the Adjustable Block Program. Suspension or termination will not impact an Approved Vendor’s rights or obligations under already-executed contracts or product orders, but rather it will impact its ability to submit new project applications. Generally, the Program Administrator and the IPA will review all of the circumstances informing why a contract award was declined before the issuance of any discipline. Approved Vendors should provide a detailed, comprehensive explanation for why they declined to execute any contract or product order. If circumstances genuinely outside of an Approved Vendor’s control necessitated non-execution, then discipline may have limited deterrent effect and may not be warranted, and thus the Approved Vendor’s explanation may want to emphasize and explain any such circumstances. Neither the IPA nor Program Administrator is able to provide a disciplinary determination in advance of non-execution to “pre-approve” such an action, nor can they provide a timeframe for the issuance of such determination after non-execution.

Can you please clarify the precise extent to which an Approved Vendor must serve as the entity for each payment/transaction type? By rough approximation there are three ‘entities’ here, which overlap: 1) the program Approved Vendor 2) the legal entity (such as an LLC) that is associated with the Approved Vendor 3) the payments/transactions node (i.e. the holder of the account into which payment from REC Contract will be deposited) To what degree can an Approved Vendor utilize other entities (such as another LLC controlled by the same entity that controls the Approved Vendor) to manage payments, both outgoing and incoming (application fee, collateral, REC payments from utility)? The REC Contract contains the following language: “‘Approved Vendor’ means the entity approved by the IPA (or its designee) under the ABP to be eligible for an award of a REC Contract under the ABP.” Must the legal entity associated with the Approved Vendor move money through its accounts?

Although the REC Contract indicates in several places that fees and collateral are payable by the Seller, the IPA is not aware of language in the Final REC Contract prohibiting a Seller from appointing a different entity to make cash payments on its behalf.  The IPA does note that the Letter of Credit forms in Exhibit E of the REC Contract indicate that the “Account Party” under the Letter of Credit must be the same as the Seller under the REC Contract.

Regarding receipt of REC payment funds, the REC Contract indicates in several places that payment is to be made to Seller or received by Seller. The IPA notes that Sections 13(a) and 13(c) of the Cover Sheet give the Seller the power to indicate its account details for receiving a wire transfer or ACH payment.

How do I assign product order(s) or an entire REC contract?

Assignments are governed by Section 9.2 of the Master REC Agreement, as modified by Section 13(j) of the Cover Sheet. As explained in the REC contract, assignments may be subject to fees, and may in certain circumstances require the Buyer’s consent to be effectuated.

An entire REC contract or any product orders/batches under a contract may be assigned in their entirety. It is not possible to assign individual projects within a product order.

Following are the steps for assignment. The Assignor is the Approved Vendor that already holds the product order(s) and wishes to initiate assignment, while the Assignee is the Approved Vendor that will receive the assignment. The Buyer is the contracting utility.

  1. Assignor contacts Buyer and Program Administrator to provide informal notice of intent to assign, including the identity of Assignee.
  2. Assignee applies to be an Approved Vendor (if not already) on the Program website. (In the case that the Assignee is a foreclosing financing party, the requirement that the Assignee is an Approved Vendor shall be waived for up to 180 days following the transfer.)
  3. Program Administrator reviews and approves Approved Vendor application (if the Assignee is not already an Approved Vendor).
  4. Assignee and Assignor execute the appropriate form of Acknowledgement. The Acknowledgement without consent form is used if the Assignee already is a valid Approved Vendor with an existing fully executed REC contract. The Acknowledgement and Consent form is used in all other situations. Thus, one of the two versions of the form is required in all cases.
  5. Program Administrator and Buyer collaborate to confirm that Assignor has met all prerequisites for assignment:
    1. Full collateral has been posted for the subject product order(s).
    2. Thirty business days have passed since ICC approval of the subject product order(s).
    3. Buyer has received any applicable assignment fees.
      1. A fee of $1,500 is required for the first assignment of a contract or product order. If Assignee and Assignor are affiliates, this fee is waived. Any subsequent assignments of prior-assigned product orders, even between affiliates, carry a fee of $5,000. All assignment fees are payable directly to Buyer.
    4. Assignee, Assignor, and Buyer must work out together how collateral will be maintained.
    5. Assignee and Assignor have met any other requests by Buyer for additional information for Buyer to use in determining whether to grant consent (not applicable if consent is not required).
  6. Program Administrator generates shell REC contract (if needed), Exhibit A, Schedule A(s), and Schedule B(s) (if appropriate) for Assignee. Generates Schedule A(s) for Assignor. All documents are provided directly to Buyer.
  7. Buyer signs Acknowledgement, REC contract (if needed), and Exhibit A. Sends all items to Assignee. Sends Acknowledgement to Assignor.
  8. If any irrevocable standing orders have been established from Assignor’s registry account for projects in the batches being assigned, Assignor must transfer those projects to Assignee’s GATS or M-RETS account. Assignor and Assignee must ensure that the irrevocable standing orders remain in place during the transfer or are re-established post-transfer.
  9. Assignee and Assignor effect the legal assignment. Assignee countersigns REC agreement and Exhibit A. Assignee and Assignor provide copies of fully executed documents to Buyer along with proof that any projects with irrevocable standing orders have been transferred to Assignee’s registry account and that those irrevocable standing orders have been maintained or re-established post-transfer.
  10. Upon confirming that all requirements have been completed, Buyer notifies Program Administrator that the assignment is complete.
  11. Program Administrator updates ABP database, moving subject product order(s) from Assignor’s REC contract to Assignee’s REC contract.

Note that an Approved Vendor may, without consent, collaterally assign or pledge the revenue stream of a REC contract or product order(s), or collaterally assign the REC contract itself, in conjunction with financing or other financial arrangements. The Approved Vendor must provide notice to the Program Administrator and Buyer of such a collateral assignment or pledge, including the identity and contact information of the financing party obtaining collateral rights.

How does a project qualify to have collateral withheld from the first REC payment?

The Revised Long-Term Renewable Resources Procurement Plan approved by the Illinois Commerce Commission on February 18, 2020 included changes eliminating the collateral withholding provisions. Implementing those changes requires the development of a new REC contract for use when new blocks of capacity for the Program are opened. Until new blocks are opened and a new contract is in use, the current collateral withholding process will remain in effect. This FAQ clarifies the current process.

In order to have collateral withheld from the first REC payment rather than having to post collateral in the form of cash or a letter of credit, a Designated System must:

  1. Be interconnected and generating electricity as of the date of ICC approval (Trade Date);
  2. Have an irrevocable standing order with no end date initiated with the contracting utility in PJM-GATS or M-RETS within 30 business days of the Trade Date;
  3. Be Part II Verified by the Program Administrator, as evidenced by the issuance of Schedule B to Exhibit A, within 30 business days of the Trade Date;
    1. The Approved Vendor must submit Part II of a Designated System’s project application at least four weeks prior to the collateral due date to allow the Program Administrator sufficient time to review the submission and issue Schedule B to Exhibit A. Please see this FAQ for additional detail.
  4. Have a request made via email by the Approved Vendor to the contracting utility requesting that the utility withhold collateral from the Approved Vendor’s first REC payment. To ensure that the contracting utility has sufficient time to process the request and recalculate the collateral amount due, this request must be made as soon as possible after the Approved Vendor’s receipt of the Schedule B and no later than 25 business days after the Trade Date. The email requesting withholding of collateral must include the application ID, batch ID, contract ID, Trade Date, interconnection date, and Approved Vendor name.

Email requests for collateral withholding should be directed to the following contacts for a project’s contracting utility, which may be different from the interconnecting utility:

Once the contracting utility verifies that a Designated System meets the criteria to have collateral withheld from the first REC payment:

  • The contracting utility will confirm via email to the Approved Vendor that the Designated System qualifies for collateral withholding.
  • Once the Approved Vendor receives the Program Administrator’s invoice during the quarterly invoicing window, the Approved Vendor will append to the Program Administrator’s invoice a line item for each Designated System from which collateral will be withheld, noting the collateral amount from the Schedule B for each Designated System.

Example:

DESCRIPTION AMOUNT
System ID xxx – collateral withholding $xx,xxx.xx
  • The contracting utility will review the Approved Vendor’s invoice and provide any feedback and/or corrections that may be needed.
  • Once the contracting utility verifies that the Approved Vendor’s invoice is correct, it will provide payment in accordance with the terms of the REC contract.

Please note that the invoices and Quarterly Netting Statements originally generated by the Program Administrator at the beginning of each quarterly invoicing window represent the Maximum Allowable Payment for the Quarterly Period. The amount contained on that initial invoice does not reflect any collateral withheld under modified Section 4.3(a) of the Master REC Agreement of the REC Contract. In the case of an individual Designated System’s Collateral Requirement being withheld from its first REC payment, the actual amount due will be lower than that listed on the original invoice.

How will enrollments that are rejected by the utility be addressed (for instance, because a customer would be over the utility’s sizing threshold, a customer had an account finaled, utility error, a customer was enrolled on Rate RTOUPP , or a customer is on Ameren Illinois’s Flexpay program (if approved) if the utility stops service).

Section 6(e) of the Cover Sheet states that, when evaluating a community solar system’s subscription levels for a Delivery Year, a daily average will be computed for each day in the Delivery Year, “based on subscription start and end dates comprised of the day a subscription start or end request was submitted to the utility, as entered in the REC Annual Report.”  The REC Contract does not expressly address what may happen if a request to enroll in net metering is rejected by the utility where the prospective subscriber is located – in other words, whether that prospective subscriber would be contractually treated as a subscriber of the Designated System for any period of time.   The Agency notes that the REC Contract expressly adopts the definition of Community Renewable Energy Generation Project found in the Illinois Power Agency Act, 20 ILCS 3855/1-10, which includes a requirement that such a project “credits the value of electricity generated by the facility to the subscribers of the facility.”  Thus, if the applicable utility declines to provide net metering credits to a prospective subscriber under Section 16-107.5(l) of the Public Utilities Act (potentially, although perhaps not exclusively, because it does not recognize that individual or entity to be eligible to serve as a “subscriber” at the indicated subscription size to that facility), it appears that such customer cannot be a subscriber and would not be counted as part of subscription levels for the calculations under Section 6(e) of the Cover Sheet.

Is there a timeframe for notices of material violations in Section 5(h) of the Cover Sheet?

The IPA anticipates that it could receive information about a Designated System “[being in] material non-conformance with requirements of the ABP or [being] materially non-conforming with the information previously submitted by Seller to the IPA about that Designated System” at any time following the execution of a REC Contract involving that Designated System.  Thus, the IPA would expect to potentially exercise its rights contemplated in Section 5(h) of the Cover Sheet relative to a Designated System’s material deficiency at any time following execution of the REC Contract until the end of the Designated System’s Delivery Term.  Following receipt and confirmation of information about a Designated System’s material deficiency, the IPA would strive to notify the Seller/Approved Vendor at the earliest practicable time, triggering the 20-Business-Day cure period allowed in Section 5(h) of the Cover Sheet.

On page 18 of the REC Contract, Section 1.22.8, and page 19, Section 1.22.9, the contract defines Designated System Contract Maximum REC Quantity and Designated System Expected Maximum REC Quantity as follows: “Designated System Contract Maximum REC Quantity” means, with respect to a Designated System, the number of RECs expected to be Delivered under this Agreement as of the date of Energization, which may be amended or adjusted subsequently thereto, and shall be equal to the multiplicative product of (a) Contract Nameplate Capacity (in MW), (b) Capacity Factor, (c) 8,760 hours and (d) 15 years, which result shall be rounded down to the nearest whole REC.” And ““Designated System Expected Maximum REC Quantity” means, with respect to a Designated System, the number of RECs expected to be Delivered under this Agreement as of the Trade Date and shall be equal to the multiplicative product of (a) Proposed Nameplate Capacity (in MW), (b) Capacity Factor, (c) 8,760 hours and (d) 15 years, which result shall be rounded down to the nearest whole REC.” Is the intention to make this an AC calculation or can developers maintain a DC calculation for capacity factor?

“Nameplate Capacity” is defined in the REC Contract, mirroring the definition in the Illinois Power Agency Act, as based on the nameplate capacity of the system’s inverter in kilowatts AC.  Proposed Nameplate Capacity and Contract Nameplate Capacity are defined in the REC Contract as derivative of Nameplate Capacity.  Although the contractual definition of Capacity Factor does not indicate whether it is based on DC or AC concepts, the contractual calculations referenced in the question above make clear that Capacity Factor must be with reference to Nameplate Capacity in AC.

Separate from the REC Contract, the ABP Program Guidebook and the ABP project application provide an option for an Approved Vendor to indicate a custom capacity factor (which, if approved by the ABP Program Administrator, will ultimately become the contractual Capacity Factor) indirectly, by entering estimated first-year production in kilowatt-hours.  This estimate of first-year production can incorporate DC-based calculations.  This estimate must be made using a custom software tool designed to calculate such capacity factors or calculated by a professional engineer; the Agency’s Program Administrator will reserve the right to audit any proprietary third-party software tool.

When will payment be issued for my RECs?

Small DG systems (≤10kW AC) will be paid the full value of their RECs (minus 5% if collateral is withheld from the REC payment, which is allowed if the system was already Energized as of the ICC approval date) after they have been deemed Energized by the Program Administrator. All other systems will be paid 20% of the value of their RECs (minus 5% if collateral is withheld from the first REC payment) after they have been deemed Energized by the Program Administrator. The remaining 80% will be paid quarterly in 5% increments for the subsequent 4 years.

To be deemed Energized, once a project is interconnected, it must submit Part II of the project application. The Program Administrator will verify this submission, including confirmation that an irrevocable standing order for the RECs has been established within the project’s chosen registry. Note that the project is not able to initiate the standing order until it has received its REC contract, as the contract will indicate which of the three utilities (Ameren, ComEd, or MidAmerican) is the contract counterparty, which may or may not be the same as the interconnecting utility. Once the Program Administrator has verified a project’s Part II submission, it will mark it as Verified, which will make the project eligible for invoicing at the next quarterly invoicing window.

The Approved Vendor may generate an invoice in the ABP portal between the 1st and 10th of March, June, September, and December. Any project that has been deemed Energized by the Program Administrator prior to these invoice generation dates will be included in the invoice. The Approved Vendor must send the invoice to the contracting utility by the 10th day of the same month.

The deadline for the contracting utility to issue the first (or only) payment for a project is the last business day of the following month (April, July, October, and January) for the first invoice from a given contract or the last business day of the same month (March, June, September, and December) for subsequent invoices from a given contract. Thus, there could be a maximum period of up to five months between a project being deemed Energized by the Program Administrator and issuance of the first payment. For example, if a project is deemed Energized on June 2 and the Approved Vendor has not yet sent any invoices under the relevant REC contract, the utility would issue the first (or only) payment by the last business day of October.  The minimum possible period would be one month – if a project is deemed Energized on May 31 and the Approved Vendor has previously received payments under its REC contract, then the first (or only) payment for that project would be received by the last business day of June.

Why does the sum of the annual delivery obligations on page 2 of Schedule B of the ABP REC Contract sum to a number smaller than the total 15-year delivery obligation?

As PJM-GATS and M-RETS create only whole RECs, the delivery obligation for each year must be rounded down to a whole REC. As a result, the sum of the annual delivery obligations almost always is less than the total 15-year delivery obligation. Having lower annual delivery obligations also conveys to Sellers the benefit of reducing the potential for REC under-delivery and commensurate collateral drawdowns.

Annual evaluations of delivery performance as described in Section 6(d) of the Cover Sheet to the REC contract are based on annual delivery obligations, i.e. each delivery year’s Delivery Year Expected REC Quantity. The 15-year delivery obligation, i.e. the Designated System Contract Maximum REC Quantity, is used in calculating payment but is not used in evaluating annual REC deliveries. Thus, a project can deliver fewer RECs by the end of the delivery term than the 15-year delivery obligation indicates and still be fully compliant with its delivery obligations under the REC contract.

How far in advance of an invoicing window should Part II of an application be submitted so that the system is eligible to submit an invoice during that invoicing window?

In order to allow the Program Administrator sufficient time to verify the application, Approved Vendors should submit distributed generation Part II applications no later than four weeks prior to the opening of an invoicing window. For community solar projects, because of the more complex verification process that includes validating subscriber data, Approved Vendors should submit Part II applications no later than six weeks prior to the opening of an invoicing window.

The Program Administrator will endeavor to review and verify Part II applications that follow this guidance prior to the opening of the relevant invoicing window. Should the Program Administrator have questions and request additional information as part of the review process, Part II verification may be delayed beyond the upcoming invoicing window depending on how long it takes to resolve any open issues an application may have after a preliminary review.

How does the REC contract manage rounding of RECs and underdelivered RECs after a drawdown event?

Section 6(d) of the REC Contract governs the requirements surrounding the review of quantities of REC deliveries, including the application of any RECs included in the Delivery Year Surplus Amount under 6(d)(ii) to any Delivery Year Shortfall Amount under 6(d)(iii). Surplus RECs will be applied to any shortfall, and any shortfall that remains after the application of the surplus will result in the drawdown of an Approved Vendor’s posted Performance Assurance.

In the case of a shortfall of RECs after the application of Surplus RECs resulting in a subsequent Drawdown Payment, the RECs Delivered will be adjusted to reflect that the RECs Delivered in each of the three Delivery Years of a Delivery Year REC Performance equals the Expected REC Quantity for those Delivery Years for the purposes of reviewing the quantities of subsequent REC Deliveries. In this way, an Approved Vendor is not penalized for the same shortfall of RECs Delivered in subsequent 3-year rolling averages.

Additionally, a 3-year rolling average that results in the shortfall of a number of RECs that is not a whole number will be rounded down to the nearest whole REC, since it is not possible to create or deliver a fraction of a REC. If a 3-year rolling average results in an over-delivery of RECs, any fractional RECs will be carried forward until such time as the fractions add up to a whole REC.

In the example below, for a project with a delivery obligation of 100 RECs annually, 20 RECs are delivered in the first year, 110 in the second year, and 120 in the third year, resulting in a 3-year rolling average of 83.33 RECs ((20+110+120)/3) at the end of year 3. This number gets rounded down to 83 whole RECs, resulting in a shortfall of 17 RECs (delivery obligation of 100 RECs minus 83 RECs delivered). After a drawdown to cover the 17 RECs that were not delivered, 100 RECs will be deemed to have been delivered in year 1, 100 RECs will be deemed to have been delivered in year 2, and 100 RECs will be deemed to have been delivered in year 3, exactly meeting the delivery obligations for each of the component years of the 3-year rolling average. Subsequently, if 100 RECs are delivered in year 4, this results in a 3-year rolling average of 100 RECs ((100 from year 2 + 100 from year 3 + 100 from year 4)/3).

What happens if an Energized (Part II verified) system goes offline?

If an Approved Vendor learns that one of its Part II verified systems has been offline (no longer electrically connected to the distribution system or no longer delivering power to either an on-site load or to the distribution grid) for one month or longer, it must notify both the Program Administrator and that system’s contracting utility. If appropriate given the specific circumstances for which the system is offline, the Approved Vendor may consider making a force majeure claim under Section 13(g) of the REC contract or request a reduction in REC delivery obligation under Section 6(f) of the REC contract.

If the system remains offline for more than three months, the Approved Vendor must notify the contacting utility, Program Administrator, and IPA. The contracting utility and IPA will then evaluate if the system is in material non-conformance with the requirements of the ABP under Section 5(h) of the REC contract, and if any repercussions may be applicable, including pausing payment on any unpaid amounts under the ABP.

Please direct any questions to the Program Administrator at admin@illinoisabpstg.wpengine.com or (877) 783-1820.

Designee Registration

What prompted the requirement for Designees to register with the Program?

Section 6.9.1 of the Approved Plan published by the IPA on April 20, 2020, describes a new requirement for Approved Vendor Designees (i.e., third-party entities working with Approved Vendors that have direct interaction with end-use customers) to register and be listed on the ABP and Illinois Shines websites along with identifying the Approved Vendors with which they are working. The purpose of this requirement is to increase transparency: potential customers will be able to verify that a company contacting that customer is indeed registered with the Program and be able to review if that company is listed in the Program’s consumer complaint database or the disciplinary actions report. All Designees will be added to the Program’s publicly facing Designee database once registered. This database is housed on both the ABP and Illinois Shines websites for easy access.

Do installers of community solar have to register as designees (since they aren’t consumer-facing)?

No, because community solar installers do not have direct interaction with end-use customers they are not required to register as a Designee with the Program.

Who needs to register as an Approved Vendor Designee?

Every third-party entity that has direct interaction with end-use customers needs to register as a Designee. This includes:

  • DG Installers
  • Marketing firms
  • Lead generators
  • Sales organizations

Do third party companies working with Approved Vendors under Illinois Solar for All need to register as an Approved Vendor Designee?

Illinois Solar for All has a process for registering third-party entities that have direct interaction with end-use customers as ILSFA Aggregator Designees and subcontractors. More information about registering with Illinois Solar for All can be found here. ILSFA Aggregator Designees and subcontractors are not required to register as ABP Approved Vendor Designees.

If our company is an Approved Vendor but also operates as an Approved Vendor Designee for other Approved Vendors, do we need to submit an Approved Vendor Designee Registration?

If your company operates as a Designee but is also an Approved Vendor, you must also register as a Designee and identify those Approved Vendors or Designees with which you work.

Are Approved Vendor Designee registrations required at the company level or user level?

One account from each entity registering as a Designee is required. It is not required for all employees (or, in the case of sales personnel operating as independent contractors, each independent contractor) of the Designee to have their own Designee accounts.  The Program Administrator encourages Designees to only have one Designee account at the company level with an appointed person that is the contact for this Designee account on file with the Program.

What is a nested Designee?

A nested Designee is a Designee’s Designee (Approved Vendor > Approved Vendor Designee > Nested Designee), as opposed to an Approved Vendor Designee. All nested Designees that have direct interaction with end-use customers are required to register as Designees with the Program.

What is the deadline for existing Designees to register with the Program?

New Designees must register with the Program prior to working with any Approved Vendor. Designees that were already working with an Approved Vendor needed to register by Thursday, December 10, 2020 (which is 45 calendar days from the October 26, 2020 release of the Designee Registration functionality) to remain in compliance with Program requirements.

Our company is already linked to an Approved Vendor account as their Designee, do I still need to register as an Approved Vendor Designee?

Yes, all third-party entities that have direct interaction with end-use customers need to submit a registration using the new registration functionality, even if your company has already been operating as a Designee for an Approved Vendor in the Program. If your company is not registered as an Approved Vendor Designee by December 10, 2020, it will not be able to access functionality in the ABP portal.

Are Designees required to use the Illinois Shines Designee logo?

No, use of the Illinois Shines Designee logo is not required. Section 1(C)(1)(b) of the Revised Distributed Generation Marketing Guidelines, published on September 16, 2020, states that “an Approved Vendor and its Designees may state the fact that it is an Approved Vendor under the IPA’s Adjustable Block Program/Illinois Shines either with a text-based statement or by using a uniquely assigned Illinois Shines Approved Vendor logo or Illinois Shines Designee logo.”

 

Use of the Illinois Shines Approved Vendor or Designee logo is optional for all Approved Vendors and Designees. Only Designees who have been authorized by one or more Approved Vendors may use the logo. If a Designee loses authorization from Approved Vendor(s) it must discontinue use of the logo (and may be required halt activities related to participation in the program).

The sample Designee logo shown in the Revised DG Marketing Guidelines contains both the Designee’s identification number as well as the identification number of the Designee’s Approved Vendor. This sample Designee logo is for use if a Designee is working on behalf of a specific Approved Vendor. The Program Administrator appreciates that Designees may work with multiple Approved Vendors. In order to accommodate those situations, a Designee logo that only contains the Designee’s identification number can be issued by the Program Administrator.

Sample Designee logos are below:

Please also note that the Revised DG Marketing Guidelines state that:

  1. The Illinois Shines Approved Vendor logo and the Illinois Shines Designee logo were created by the Program Administrator to help potential customers easily distinguish between Approved Vendors (and their Designees) and those companies that are not approved to submit applications to the ABP. The Program Administrator will provide a unique Illinois Shines Approved Vendor or Designee logo containing identifying information to each Approved Vendor or Designee upon request.
  2. Both the Illinois Shines Approved Vendor logo and the Illinois Shines Designee logo may be used only by an Approved Vendor or (with the Approved Vendor’s authorization) its Designees.
    1. Designees shall only use an Illinois Shines Approved Vendor logo with the express approval of the Approved Vendor.
    2. Neither the Illinois Shines Approved Vendor logo and the Illinois Shines Designee logo may be modified. Approved Vendors shall not use other forms of the Illinois Shines logo.

The Program Administrator encourages Designees to use the appropriate Illinois Shines Designee logo in order to increase transparency and avoid confusion among potential Program participants and customers.

To request an Illinois Shines Designee logo, please email the Program Administrator at admin@illinoisabpstg.wpengine.com or call 877-783-1996.

Why can’t an Approved Vendor’s Designee complete Disclosure Forms?

A Designee can complete Disclosure Forms only if it is registered in the ABP portal as a Disclosure Form Designee. To complete this registration, the Approved Vendor that the Designee is tied to must approve the Designee in that role. If a Designee was able to complete Disclosure Forms prior to the implementation of the new Designee registration functionality which went into effect on December 10, 2020, but is now unable to complete Disclosure Forms on behalf of an Approved Vendor, that Designee likely has not registered as a Disclosure Form Designee and/or an Approved Vendor has not approved the Designee for this role in the portal after the Designee registered as a Disclosure Form Designee.

 

If a Designee is unable to complete Disclosure Forms, please confirm that both steps outlined above have been taken. If questions remain, please contact the Program Administrator at admin@illinoisabpstg.wpengine.com or (877) 783-1820.

Archive

Why was the Program opening delayed at the end of January 2019?

As stated by the IPA in its January 4, 2019 announcement, the opening of the Adjustable Block Program was delayed from January 15, 2019 to January 30, 2019 to allow for additional time to refine the standard REC contract between Approved Vendors and utilities, after extensive concerns were raised by stakeholders during two rounds of comments on the First Draft REC Contract released on December 7, 2018. As the IPA stated in the January 4, 2019 announcement, “The Agency has considered the benefits and drawbacks of a minor delay and believes that an additional round of comments will ensure that any unintended consequences of new provisions and wordings in the second draft contract are identified and addressed prior to finalizing the contract.”

Will the Adjustable Block Program continue in subsequent years? (i.e., 2021 and 2022)

Section 1-75(c)(1)(C) of the Illinois Power Agency Act calls for at least 1,000,000 RECs annually from the Adjustable Block Program by the end of the 2020-2021 delivery year, then a cumulative 1,500,000 RECs annually from ABP by the end of 2025-2026, then a cumulative 2,000,000 RECs annually by end of 2030-2031. The existing ICC-approved Revised Long-Term Renewable Resources Procurement Plan provides for these RECs to be delivered, subject to developer interest and RPS budget constraints, via contracts between the developers and utilities.

Can funds be diverted from Group B (ComEd territory and nearby utility territories within PJM) project categories to Group A (Ameren Illinois territory, MidAmerican Energy territory, and nearby utility territories within MISO) project categories?

No. According to Sections 6.3 and 6.3.1 of the Revised Long-Term Renewable Resources Procurement Plan, the allocations of capacity between Groups in Blocks 1, 2, and 3, for any project category, are made based on load forecasts and Renewable Portfolio Standard budget forecasts for the 2020-2021 delivery year. As a result, for any project category, the allocations are as follows:

  • Block 1: Group A 22 MW, Group B 52 MW
  • Block 2: Group A 22 MW, Group B 52 MW
  • Block 3: Group A 5.5 MW, Group B 13 MW

These allocations are fixed in the Plan and may not be changed. 166.5 MW of discretionary capacity remains, which was allocated to Block 4 across the following allocations:

  • Block 4: Group A 103.5 MW, Group B 63 MW

As mentioned in the Plan, contracts may be with an electric utility other than that utility in whose service territory the project is located; in allocating discretionary capacity, this flexibility could theoretically allow for a different allocation of additional project capacity across Groups, as while allocations for contracts must strictly adhere to budget allocations resultant from load forecasts, that balance between the physical location of systems need not be so strictly observed.

Why is the ComEd Large DG block larger than the Ameren Illinois Large DG block?

The relative capacity of project categories in Group B (ComEd territory and nearby utility territories within PJM) vs. the capacity of project categories in Group A (Ameren Illinois territory, MidAmerican Energy territory, and nearby utility territories within MISO) is based on load forecasts for each utility and the resulting projected Renewable Portfolio Standard budgets for ComEd, Ameren Illinois, and MidAmerican during the 2020-2021 delivery year. Based on this calculation, 70% of Adjustable Block Program capacity within any of the three project categories is allocated to Group B and 30% to Group A. More information on this can be found in Sections 3.1 and 6.3 of the Revised Long-Term Renewable Resources Procurement Plan.

Why is the Large DG category in Group A changed from 3 blocks to 2 and the amount from 66MW to 44MW? Where did the excess funds get reallocated?

The proposed Long-Term Renewable Resources Procurement Plan filed by the IPA on December 4, 2017 included the following Adjustable Block Program block allocation for Large DG projects in Group A: 22 MW in Block 1, 22 MW in Block 2, and 22 MW in Block 3. The Illinois Commerce Commission ultimately ruled on April 3, 2018 that 75% of the initially proposed Block 3 capacity, i.e. 166.5 MW in the Large DG category, be “held back” and allocated later to a Block 4 in some of the Group/category combinations, at the Agency’s discretion. The Group A, Large DG category was not changed from 3 blocks to 2 blocks; it still has 3 blocks, but Block 3 was reduced in size from 22 MW to 5.5 MW to conform to the ICC’s ruling. This approach applied across all six Group/categories, so that 75% of all of the initially proposed Block 3s, totaling 166.5 MW or 25% of Program capacity as a whole, was held back for later discretionary allocation. The Agency announced the allocation of the held-back capacity on April 3, 2019. For more information on this approach, please see the final Long-Term Renewable Resources Procurement Plan at Section 6.3 and the Lottery Procedure at Section F.

Why is the Small DG block only for systems up to 10kW? If the 25kW and under systems were part of the Small DG block, it would have better balanced the categories.

It is mandated by law that 25% of Adjustable Block Program capacity be allocated to distributed generation systems of up to 10 kW (plus 25% to DG systems of over 10 kW up to 2,000 kW, 25% to community solar systems, and the remaining 25% to be allocated in the Revised Long-Term Renewable Resources Procurement Plan). Prior to the revisions to the Illinois Renewable Portfolio Standard contained in Public Act 99-0906 (The “Future Energy Jobs Act”) there was a distinction made for DG at the 25 kW level. That provision was repealed and replaced with a 10 kW distinction. Furthermore, the Plan, which was approved by the Illinois Commerce Commission, maintains the 25%-25%-25% allocation from the law across the three project categories (including the up to 10 kW or “Small DG” category) and determines that the remaining 25% shall be discretionarily allocated by the IPA to the three project categories (or more specifically, to the six Group/category combinations).