Frequently Asked Questions

Program Application

Are non-ministerial permits required to apply for Block 1?

Systems over 25 kW must obtain all non-ministerial permits prior to applying for Block 1. On the project application Approved Vendors must attest that they have obtained all non-ministerial permits that, according to the commercially reasonable investigation of the Approved Vendor, are necessary to the project at the time of application to the Adjustable Block program. The Approved Vendor must list all such permits, along with the name, phone, and email of a contact person at the issuing authority. The Program Administrator will verify a random selection of permits and reserves the right to verify any permits that it deems require further investigation.

While there is no master list of ministerial and non-ministerial permits, for the avoidance of doubt, the NPDES permit is considered ministerial and not required for submission to the Adjustable Block Program.


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 Any ABP application that wishes to remain eligible for ILSFA must be withdrawn prior to this milestone.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 May 31, 2019 edition 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 and separate utility billing.

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(D) of the May 31, 2019 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 who will then forward it to the Agency for consideration.

*From Section 7.3.1 of the August 6, 2018 edition of the 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. Please see Section 5(e) of the Final REC Contract for additional details.
Does my project have to stay in the utility interconnection queue to remain on the ABP waitlist?

The Program Guidebook notes that a project must remain in the interconnection queue in order to maintain its place on the ABP waitlist, and that exceptions will be made for projects that are forced from the utility interconnection queue due to the utility’s queue management process. Upon selection from the waitlist, these projects need only demonstrate that they exited the interconnection queue involuntarily and have subsequently reapplied for interconnection.

As a clarification to the above, 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 off of 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 for Block 1?

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 if 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 distributed generation 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 distributed generation 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 distributed generation application after 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 distributed generation 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 in the initial application and Part II is for accepted projects when they completed and energized.

What is required in a shading study?
A shading study shall be completed for all projects. Suitable shading studies can include but are not limited to, using tools such as the Solar Pathfinder, Steprobotics, Helioscope, and HORIcatcher as well as or in conjunction with software designed to perform shading analysis. The shading study should include a list of obstructions with measurements to illustrate that the project meets the minimal shading criteria of no obstruction is closer than a distance (“D”) of twice the height (“H”) it extends above the PV array.
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.

To find the most up-to-date information regarding the Illinois Adjustable Block Program Blocks, please visit the Block Capacity Dashboard page.

General Questions

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

In the event of a Block 1 lottery for a Group/category, given the drop-off in REC prices between Block 1 and Block 3, some Approved Vendors may not wish to proceed with a project if that project would receive Block 3 pricing. As the Adjustable Block Program is predicated on price transparency and Approved Vendors may have submitted projects into Block 1 on the expectation of Block 1 pricing (possibly even without any expectation of a lottery), the Agency believes Approved Vendors should be allowed to decline a Block 3 award within a short timeframe after selection without additional process or penalty. The Agency thus will allow any project notified that it has received a REC contract with Block 3 pricing as the result of a previous Block’s lottery to have 5 business days to decline its selection prior to the underlying contract being forwarded for approval to the Illinois Commerce Commission. The Approved Vendor will be able to exercise this option without any further penalty, process, or the posting of collateral. If a project selected to be in Block 3 declines its selection by this option, then the next ordinally ranked project(s) on the waitlist will be selected for REC contract(s) at Block 3 pricing until Block 3 is filled, along with the same terms (5 business days to accept or decline). Projects declining a Block 3 contract award will be removed from the lottery order and will be ineligible to receive a contract with Block 4 pricing through the allocation of discretionary capacity. A project may exercise this option to decline a REC contract with Block 3 pricing by communicating as such in writing to the Program Administrator. The application fee is non-refundable.

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 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.

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

Distributed generation projects will be given one year to be developed and energized. Community solar projects will be 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 Approved Plan.

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 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 Long-Term Plan for more information on requirements applicable to projects in the service territories of rural electric cooperatives or municipal electric utilities.

Is the value of net metering changing in Illinois?

Under 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.  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.  Under Illinois law, upon the date that installed net metering capacity reaches a certain threshold – 5% of the total peak demand supplied by that utility provider in the previous year – the net metering landscape in the utility’s territory will change and retail rate net metering will no longer be available for new net metering customers who would otherwise qualify.

Ameren Illinois has somewhat unexpectedly notified the Illinois Commerce Commission (the State agency charged with approving Ameren’s tariffs) that is has reached this 5% threshold and, as a result, otherwise-qualified new customers who apply for net metering service will not receive retail rate net metering, but rather, supply-only net metering.  Eligible customers who apply for the $250/kW rebate will continue to receive that rebate until a new rebate value is determined in a Commission-approved proceeding.  This notification has spurred a flurry of legal filings, including by the solar energy industry and environmental advocates seeking for retail rate net metering to continue until the matter is fully investigated.

The Commission, which has exclusive jurisdiction over the matter of utility net metering, has opened investigations (1) into Ameren’s net metering rider (Rider NM), to determine whether Ameren has met the 5% threshold and is appropriately ending retail rate net metering, and (2) into the process and formula for calculating the value of distributed generation rebates on a going-forward basis.  The Commission has ordered the investigation into Rider NM to be completed by early November; until that time, the IPA understands that retail rate net metering is not available for new, otherwise-qualifying Ameren net metering customers.  The investigation to determine successor distributed generation rebate values is expected to be completed in the spring of 2021.

At this time, these ongoing investigations have no immediate impact on net metering in the Commonwealth Edison territory.  Additionally, the IPA understands that customers who already receive retail rate net metering from Ameren Illinois will continue to receive credits at that amount.  As the IPA has no jurisdiction over Ameren Illinois or its tariffs, any questions regarding the availability of new or continuing net metering credits should be directed to Ameren.  The IPA will update this FAQ as additional information becomes available with respect to the status of net metering rebates.

Update (December 9, 2020): 

On December 2, the Illinois Commerce Commission completed its investigation into Ameren Illinois’ Rider NM.  The Commission found that Ameren’s Rider requires revisions to the calculation of the 5% threshold discussed above.  Furthermore, the Commission found that the volume of installed net metering capacity in the Ameren service territory has not yet met the 5% threshold.  The effect of this ruling is 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 is required to file updated tariff language reflecting changes to how Ameren calculates this 5% threshold on or by December 23, 2020, with an effective date of seven business days later.  Furthermore, the Commission has 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 has the right to seek rehearing or appeal the Commission’s order.  The IPA will update this FAQ as necessary with additional information.

The Commission’s investigation into the value of successor rebates in the Ameren service territory remains open and is ongoing.  Additional information related to that proceeding may be found at:

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 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.

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.

Approved Vendors

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 to 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 or call (877) 783-1820.

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 (“AV”).  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 AV. 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 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 of the  Program Guidebook for the full requirements to install a Distributed Generation System.

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 Approved Plan.

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

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.

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 Corporation Commission (ICC). Details of this requirement can be found at the ICC’s Distributed Generation Installer 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.

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

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

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. A change in ownership of the Approved Vendor (e.g., the sale of the entire LLC to a new entity) with no change of the AV/project pairings would not have to adhere to an additional process of submitting documentation as in the case of a change in Approved Vendors. Rather, the Approved Vendor should provide an update to its Approved Vendor profile within the ABP Approved Vendor portal with its new ownership information.

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.

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.

Existing Solar Generator (systems built & energized after 2017-06-01)

Can I enter my home/small business system into the program myself?

All applications will have to be entered 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 once the program opens for project applications.  Each Approved Vendor may offer you different terms and you should 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 on the Illinois Shines website here. 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 community solar marketing material standard disclosures and requirements which can be found here. 

Program Block Capacity

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 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 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?

A: 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. 16.5 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 has been reduced in size from 22 MW to 5.5 MW to conform to the ICC’s ruling. This approach applies 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, will be held back for later discretionary allocation. The Agency released the remaining 25% of program allocation in April 2019 in their discretionary capacity allocation decision. Please see the Section 6.3 of the Revised Long-Term Renewable Resources Procurement Plan for additional details.

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 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).

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.


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

As the Program Guidebook states at page 35, “[T]he Program Administrator [will] submit contract information to the Commission for approval, [] includ[ing] the Program Administrator’s recommendation for approval of the batch[.]  Once a batch is approved by the Commission, the applicable utility will execute the [REC] contract. The Approved Vendor will then be required to sign the contract within seven business days of receiving it.”  This requirement covers a batch that is approved for a REC contract in a Block through the ordinary non-lottery procedures (see paragraphs C.2 through C.4 on pages 9-10 of the Program Guidebook), as well as a batch that is approved for a REC contract at Block 1 pricing as a result of a Block 1 lottery. Approved Vendors that do not accept the contract will face disciplinary measures that will impact their status as an Approved Vendor in the Program moving forward. It is expected that if a project batch is submitted to the ABP while Block 1 is open, the Approved Vendor is prepared to enter into a contract for Block 1 prices with the applicable utility, although there is an option for a project to withdraw its application within a reasonable time before a lottery occurs for its Group/category.  Through requirements in the Long-Term Renewable Resources Procurement Plan and the Lottery Procedure, the Agency has generally sought to ensure that projects applying to the ABP are ready, willing, and able to advance to development and energization.

There are two exceptions to the general requirement that a project selected for a REC contract must have its Approved Vendor accept the selection. These exceptions, described in paragraphs B.6 and B.7 on pages 8-9 of the Program Guidebook, cover a project selected for Block 3 as the result of a Block 1 lottery, and a project selected for Block 4 from the lottery waitlist.

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

A: 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

After my distributed generation project has an approved contract under the Adjustable Block Program, can I move the panels to a different building?

No.  The project approval is location-specific.

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

Approved Vendors will not be permitted to make a tracker change between ICC contract approval and the final build. A change such as this would be significant and have a material effect on the project.

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 meter that is accurate to +/-5% or an inverter specified by the manufacturer to be accurate to +/‐5% that is UL-certified and includes a digital or web-based output display.

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

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

All systems registered in M-RETS must utilize an ANSI C.12 certified revenue quality meter.

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.



How is the REC obligation calculated for a specific project?

This topic is fully addressed in section 6.14.5 of the Approved 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 standard capacity factor or an alternative capacity factor (based on an estimated production analysis from PV Watts or an equivalent tool) to determine the REC obligation for a project. Information on approved capacity factor calculations for use under the program can be found in the Program Guidebook, Section 4: System Eligibility, REC Quantity Calculation

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 renewable 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 shall be paid ratably 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.

What are the REC prices being offered through the Adjustable Block Program?

The final REC prices can be found in section 6.4 of the Approved Plan.

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, please be aware that the Adjustable Block Program Guidebook (p. 42 in the May 31, 2019 edition) provides as follows:

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.

As a consequence, you may face discipline – including a possible suspension or termination of your Approved Vendor status under the Adjustable Block Program – for failing to execute a contract or product order after submitting a project application and receiving a contract award. Suspension or termination will not impact your rights or obligations under other executed contracts or product orders, but rather it will impact your 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 so it would be helpful to receive a detailed, comprehensive explanation for why you 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 your explanation may want to emphasize and explain any such circumstances outside of your control resulting in non-execution. 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. 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.
  9. Buyer notifies Program Administrator that the assignment is complete.
  10. 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 in collateral withholding provisions. Implementing those changes will require the development of a new REC contract, which is expected to occur over the course of Spring 2020. Until that process is completed and a new contract 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;
    • 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.


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 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).

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 will the new definition of subscriber enrollment address enrollments that are rejected by the utility (for instance, because a customer would be over the utility’s sizing threshold, or because a customer had an account finaled, utility error, enrolled on Rate RTOUPP if that rate is approved and the Illinois Commerce Commission adopts ComEd’s proposal to make Rider POGCS customers ineligible, customers 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.

Invoices are generated quarterly by the Program Administrator and will be provided to the Approved Vendor to send to its contracting utility. Per the REC contract, invoices are generated on or around the first day 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. Invoices are generated by the Program Administrator on or around the first business day of each of the months noted above as a one-time event for each quarter, rather than on a rolling basis during the invoicing window.

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.