Garden State Energy Storage Program FAQs
Access to these questions and answers by PDF are available here.
1. We have an existing community solar project and would like to add an ESS to that existing system. These are grid connected projects, given that they are community solar projects. Would the addition of the battery fall under Phase 1 of the GSESP, or would that be a Phase 2 project the way it is currently being envisioned?
If the community solar project is directly interconnected to the bulk transmission system, a storage addition to the community solar project would be eligible for both Tranches 1 and 2 of Phase 1 of the GSESP. If it is directly interconnected to a distribution system, any storage addition to the community solar project would be eligible for Phase 2 (Distributed Segment) GSESP incentives. However, such a project would be ineligible for Phase 1 incentives in both Tranche 1 and Tranche 2.
2. Is it possible to collect TREC income from the PV Solar component of a combined PV / BESS / Microgrid System and also get the incentive for the Battery Component under this program?
As there is no TREC bonus specifically for storage, any further storage addition to such a microgrid system would be eligible for GSESP incentives. However, as Staff presumes such a microgrid system is likely interconnecting at the distribution level, it would most likely fall under the Distributed Segment in Phase 2, and would not be eligible for Phase 1 incentives, either in Tranche 1 or any subsequent Tranche. Furthermore, Staff anticipates that only new storage additions to such a microgrid system would be eligible, while any storage added to the microgrid system prior to the opening of Phase 2would be ineligible for incentives.
3. Can you confirm whether a large behind the meter energy storage device associated with a load which is connected to the transmission system through a high-tension service tariff would be eligible to participate in the Tranche 1 transmission scale procurement.
No, a behind-the-meter project would not be eligible for Tranche 1, which is specifically intended for front-of-the-meter systems. Tranche 1 will select projects based on lowest cost per unit of expected accredited capacity, subject to consideration of community benefits. Since behind-the-meter systems typically do not have Capacity Interconnection Rights, they would have zero accredited capacity. As a result, such a system cannot be selected in the Tranche 1 solicitation.
4. Would projects still be eligible to participate in the GSESP if they used NJEDA’s clean energy financing tools (i.e., NJCELs, NJ Green Bank, and Garden State C-PACE)?
Yes, projects that make use of NJEDA’s low-cost financing programs are still eligible to participate in the GSESP. Staff interprets the requirement GSESP supported storage capacity "not participate in any other energy storage program” to mean that GSESP supported storage cannot receive another direct monetary incentive, such as a grant or rebate, from another BPU or other New Jersey program specifically designed to support storage. Thus, GSESP projects can leverage low-cost financing from other New Jersey state agencies, as well as federal and state tax credits or other tax benefits.
5. Do I read the Bid Application/Solicitation Fee Form correctly that if we were, for example, to submit a bid for 500MW then we would have to write you a non-refundable check for $100,000? May I ask what the reason for this steep fee is?
The fee is $200 per MW, so the calculation of what the fee would be for a hypothetical 500 MW system is correct. However, based on PJM queue data, Staff does not anticipate that any system approaching that size would be eligible for Tranche 1. The purpose of the fee is to help offset the administrative costs of designing and running the GSESP, ensure bidder commitment, and encourage follow-through on project obligations.
6. As a developer, can we qualify to apply for GSESP? Do we need EPC contractor to apply GSESP?
To qualify for incentives, transmission-scale storage applicants must be government or private entities (not Electric Distribution Companies (EDCs). Retaining an EPC contractor is not a requirement.
7. What are the specifics incentives for PHASE 1 and PHASE 2? 2. Additionally, what are the specifics for Tranche 1 and Tranche 2 for both phases? 3. Lastly, is there a specific dollar amount per kW or kWh?
For Phase 1, the incentive is competitive; that is, the incentive level will be determined by individual bids. Incentives will be paid in dollars per MW over a 15-year period.
The final design for Phase 2, which will launch the distributed storage segment of the GSESP, has yet to be determined. Per the November 7, 2024, Straw Proposal, Staff proposed that Phase 2 will consist of administratively determined fixed incentives and performance incentives. That is the latest public information and is subject to change. Staff also anticipates that the Board will set the size of fixed incentives and the amount of project capacity to award on an annual basis, offering fixed incentive through administratively determined capacity blocks.
More specific proposed program rules for Phase 2 and the distributed storage segment of the GSESP are in the GSESP Notice of Proposal, which is expected to be published in the August 4, 2025, edition of the New Jersey Register.
The specifics for Tranche 1 and Tranche 2 are that the board will award Transmission Fixed Incentives to eligible transmission-scale energy storage systems via a competitive solicitation process that will determine both which projects are selected, and the size of the incentive awards each project receives. These incentives will be paid out at a constant annual rate denoted in dollars per megawatt per year for a 15-year award period.
8. Can you confirm if the BPU will consider battery storage projects under 5 MW for the RFP and whether a waiver is required for participation?
The Order does not explicitly require Tranche 1 projects to be greater than 5 MW, but the recently passed bill A5267 does. Assuming the Governor signs the bill, projects will have to have a capacity of at least 5 MW AC in order to be eligible for the Tranche 1 solicitation. Even if the A5267 does not become law, projects must be connect at transmission-scale voltages, which makes projects less than 5 MW unlikely.
9. Will BPU consider granting a waiver for storage facilities that aren't entirely new?
The Board will not waive the requirement that energy storage capacity has to be new to qualify for GSESP incentives. That said, incremental additions of energy storage capacity to existing storage facilities are eligible for GSESP incentives. The key question is whether the energy storage capacity and related equipment for which incentives are requested existed before the launch of the GSESP, not whether the entire facility itself is new.
10. How does the BPU define small, medium, and large battery storage sizes?The order doesn't specify this.
The "small," "medium," and "large" definitions refer to distributed energy storage systems and are only relevant to the Distributed Phase 2 program segment.
"Large" means a distributed system that is greater than 500 kW, "medium" means 100 kW to 500 kW, and "small" means less than 100 kW, as shown in Table 3 of the November 2024, Straw Proposal. Phase 2 of the GSESP is subject to revision in a future Board order.
11. Will the rule proposal mentioned at the Board meeting be published in the July 17 NJ Register?
The estimated New Jersey Register publication date is August 4, 2025.
12. Will the Board issue a form contract for bidders use?
No. However, the June 18, 2025, Board order states on page 25: “Staff recommends that registration packages (post notice of award) submitted to the GSESP follow the same general review process as the CSI Program”. The CSI Registration Package contains a number of important terms and conditions. Staff plans on adapting/modifying as appropriate the CSI terms and conditions for the GSESP. Staff will upload the registration materials to the GSESP website once they become available.
13. If an asset has an executed PJM Generation Interconnection Agreement (GIA) but is not a PJM capacity resource can it participate in the GSESP?
It is highly unlikely that a storage project that is not a PJM capacity resource would be selected in the Tranche 1 solicitation. This is because the Board will primarily rank and select projects based on their cost per unit of accredited capacity. A project that is not a capacity resource would by definition have no capacity interconnection rights (CIRs) and therefore zero accredited capacity. Consequently, such a project would only be selected in Tranche 1 if there are insufficient projects with CIRs to meet the Tranche 1 procurement target.
(a) Can awarded energy storage projects be placed into service prior to EY27? Yes
(b) Are there required interconnection voltages to be considered transmission scale under Tranche 1? In New Jersey, transmission-level voltages are generally understood to be any voltages above the sub transmission/distribution threshold, which state law effectively sets at above 69 kV. That said, the A5267 bill passed by both house of the Legislature on June 30, 2025 would define transmission-scale storage for the purposes of the Tranche 1 and 2 solicitations as “an energy storage system, with an installed capacity of at least 5 MW AC, that is interconnected with the PJM Transmission Network and situated inside a Transmission Zone in New Jersey or is otherwise located in New Jersey and qualified to provide energy, capacity, or ancillary services in the wholesale markets established by PJM.” Staff reads the italicized part of this definition as rendering any storage system of 5 MW AC or greater a “transmission-scale storage system” regardless of its interconnection voltage provided it is qualified to provide energy, capacity, and/or ancillary services in PJM wholesale markets. Such systems could therefore bid into the Tranche 1 solicitation if the Governor signs A5267 into law.
14. Regarding dispatch availability metrics, how does the BPU intend to define compliance with the 7,900-hour annual availability requirement?
The Board will define compliance with the 7,900-hour annual availability requirement in the manner described in the Board Order at pages 27-28. The energy storage system will be considered available during hours when it is capable of charging or discharging energy to the grid. The unit must submit an offer into the PJM Day-ahead Market. A unit will be considered unavailable when it is incapable of responding to PJM dispatch signals for reasons of forced, planned or maintenance outages.
(a) Will energy storage assets be required to always maintain a minimum state of charge? No, the GSESP does not contain such a requirement.
(b) If an energy storage asset is charging from the grid, will the resource be considered available? Yes.
(c) Will there be additional regulations/guidance released as it relates to availability metrics? If so, should we expect further guidance before the final bid submission deadline of August 20th, 2025? The Board has no current plans to publish further guidance relating to availability metrics, except to the extent these Q&A responses address the issue. We welcome further comments as to what such guidance may consist of for consideration in future tranches of the program.
(d) How should developers account for degradation when forecasting meeting dispatch availability metrics throughout the life of the energy storage asset? Developers must make their own judgments in planning for degradation and any impacts on availability. Degradation does not directly impact the availability metric used for determining if a storage project is to receive the full value of its annual fixed incentive award payment, except to the extent it may lead to forced, planned or maintenance outages. Energy storage project owners are required to fulfill all obligations required by PJM to maintain CIRs.
15. Where is the link to the proposed Rule?
The Order launching the Garden State Energy Storage Program, as part of Docket No. QO22080540, is available here. The order was issued on June 18, 2025. The proposed rule, N.J.A.C. 14:8-14, was published in the New Jersey Register on August 4, 2025.
16. I am hoping you can help clarify the requirements surrounding interconnection for the GSESP – there is reference in certain sections of the program/application process materials that indicates projects seeking to add storage to an existing system are eligible for the GSESP, however other materials note that those projects must be connecting to deactivated or deactivating generation facilities – Can you confirm which is the case?
If we have existing PJM projects with WMPAs, are we able to submit a bid under the premise that we will connect that storage project to the same transmission network using the excess CIRs common among PV only assets?
The GSESP does not mandate that projects connect to deactivated or deactivating generation facilities, and storage additions to existing facilities are eligible for GSESP incentives. If a project is connecting to a deactivating generation facility, providing documentation demonstrating that the proposed project will be able to use the CIRs of that facility is required.
17. Are the incentive payments meant to cover the cost of the project revenue requirements by making the producer whole? Or do they act as capacity payments for being available 90% of the time?
If participating in this program, is a producer able to collect the incentive and participate in other market activities (i.e. energy arb) or are they only able to receive payments through this program?
Is pricing that is submitted for the August 20th bid firm or indicative?
Incentive payments are intended to help address prospective project revenue gaps, and are therefore intended to be additional to revenues from other market activities such as energy arbitrage and participation in PJM’s capacity market. The incentive payments are not intended to act as capacity payments.
Pricing submitted for the August 20th bid is firm.
18. Section 4.4 (p. 9) of the Pre-qualification Request & Final Application Instructions states that Final Application submissions must include the proposed project’s PJM interconnection queue ID number. Does this requirement apply for projects proposing using CIRs of a deactivating generation facility?
If a project does not have a PJM interconnection queue ID number for the reason cited above, this item may be omitted in the Final Application submission. The application submission may include the Generator ID for the deactivating generation facility.
19. I have a question on how BPU specifically plans to assess the ratepayer benefit in comparison to the Tranche 1 fixed incentive. Understanding the Appendix B in the 8E order document shows an example analysis, can you confirm and provide assumptions and detailed methodologies with respect to:
- VRR curve (shown in Appendix B is the Curve 2 MRI VRR, proposed in the 6th Quad Review)
- ELCC class rating projections for all storage classes (4/6/8/10)
- Reliability requirement (shown in Appendix B is based on 2025 load forecast)
- Total Transmission-Scale Incentive Costs (TIC) as omitted in Appendix B
- Assumptions on price separation on LDA capacity constraints
The BPU does not have specific plans at this time to update the partial ratepayer benefit analysis summarized in Appendix B of the 8E Order. The document provides an explanation of assumptions relevant to the VRR curve, ELCC class rating, reliability requirement, and LDA price separation. The ratepayer benefit evaluated in Appendix B is based upon the potential capacity market savings in upcoming Base Residual Auctions.
20. We respectfully request an extension of the Garden State Energy Storage Program Tranche 1 bid application deadline from August 20, 2025, to August 27, 2025. Since the BPU’s proposed rule was published only a week ago on August 4, 2025, there are some differences between the proposed rule and the BPU’s June 18, 2025, order launching this program, and today is the deadline for bidders to submit questions to BPU Staff, more time is needed for the bidders to review the proposed rule and submit questions and for the BPU Staff to evaluate and respond to the questions from bidders who reasonably wish to fully understand the program before submitting their bids to the Tranche 1 solicitation.
Thank you for your request. We regret that we are unable to extend the bid application deadline of August 20, 2025.
Please note, however, that requirements for Tranche 1 remain as they are indicated in the Board’s June 18, 2025, Order. All determinations will be made in accordance with the requirements as indicated in the June 18, 2025, Order. Until adopted, the rules as proposed on August 4, 2025 have no legal effect and remain subject to further changes upon adoption. Any such rule adoption would not be filed and effective until after the completion of the Tranche 1 solicitation and would not retroactively impact the solicitation. As such, in the event of any conflict between the language and requirements in proposed rules and the June 18, 2025, Order, the requirements set forth in the June 18, 2025, Order shall prevail.
21. Section 9 (p.16) of the Pre-qualification Request & Final Application Instructions refers to a pre-development security, but this amount is not specified. Is there a pre-development security amount required of projects and if so, what is it?
Pre-development security is waived for this Tranche 1 solicitation. The pre-development security amount will be specified in the solicitation application for future tranches.
22. What is the payment cadence for awarded projects (monthly/quarterly/annual)?
Incentives for awarded projects will be distributed on annual basis.
23. Page 8 of the GSESP Final Application document mentions that bidders that wish to claim confidentiality should “upload a public copy created by printing out a copy of the completed application, conforming to the requirements of N.J.A.C. 14:1-12.3, that redacts the information deemed confidential”. Would a redacted PDF file of the application be sufficient, or is a physical redacted copy required? How should physical documents be delivered to the BPU?
Applicants claiming confidentiality must submit both a redacted version and a confidential version of their application. An electronic submission, either via the BPU’s E-File system or by email to (mailto:board.secretary@bpu.nj.gov), is sufficient. Hard copies are not required. If an applicant chooses to provide physical documents, they should be mailed to the attention of the Board Secretary. Physical submissions will be received through the Office Services mailroom.
24. Could the BPU please provide more detail on the criteria and standards used by Staff and the Division Director when evaluating requests for extensions to the Planned COD deadline—such as how good-faith efforts are assessed, what constitutes sufficient evidence of efforts to avoid delays and how a force majeure event is defined?
Extension requests and good-faith efforts will be considered on a case-by-case basis. Force majeure is defined in the May 18, 2025, Board Order, footnote 34.
25. The RFP documents outline a pre-development security. Can you please confirm the required quantum? What is the required timeline to post this pre-development security? What form of security will be accepted: cash, Letter of Credit, Bond?
Pre-development security is waived for this Tranche 1 solicitation. The required amount, timeline, and accepted forms of pre-development security will be specified in the solicitation application for future tranches.
26. If a project is awarded under Tranche 1 and subsequently achieves Commercial Operation, is the applicant required to post an operating security? If so, please clarify the required quantum of the security and the timing of when it must be posted. What form of security will be accepted: cash, Letter of Credit, Bond?
No. Pre-development security is waived for this Tranche 1 solicitation. For future tranches, the pre-development security timing, form and quantity will be specified in the pre-qualification instructions.
27. The Final Application requests certain financing details under Section 15, “Cost Structure.” Could the BPU please clarify whether this information will be used when making award decisions? Because the figures are still subject to change at the current project stage, would it be acceptable to provide value ranges instead of fixed amounts?
The Cost Structure data requirements will not be used directly in making award decisions. The data will be used to inform future program development. Value ranges are acceptable.
28. Will the BPU provide a draft/form contract prior to the application deadline for applicants to review? If not or if the BPU does not envision utilizing a contract between the state and developers (who receive a GSESP award), will there be an alternative binding document between parties?
Board Staff does not anticipate utilizing a form contract between the State and developers who receive a GSESP award. Instead, the anticipated October 2025 Board Order providing the actual award will the legal instrument that sets forth the binding terms and conditions of the award. In addition, the applicant will be bound by the information contained in the registration materials, which will be uploaded to the GSESP website when they become available.
29. What loan programs are available to provide low-cost financing for storage projects?
As mentioned in response to Question 4 above, the New Jersey Economic Development Authority (NJEDA) offers various clean energy financing programs including NJCELs, NJ Green Bank, and Garden State C-PACE. Each project owner must make their own investigation of available low-cost financing options.
30. Can you please confirm how the total incentive payment will be calculated? The RFP mentions the incentive award will be calculated in $/MW-year – Is the MW mentioned the nameplate capacity of the proposed project? Can you please confirm the only adjustments that may occur to the fixed incentive payments are delay penalties and availability shortfall deductions as described in Sections 7.1 and 7.2 respectively?
The incentive payment will be calculated as the product of the “as bid” price in $/MW-year and the project’s nameplate capacity in MW. The incentive will be paid out annually at a constant rate for a 15-year award period. For example, a 100 MW nameplate project that submits a winning bid of $50,000 per MW-year would receive a base annual payment of $5,000,000 for each year of the 15-year award period. The only adjustments to the fixed incentive payments are delay penalties and availability shortfall deductions as described in Sections 7.1 and 7.2 of the Pre-qualification Request & Final Application Instructions.
31. Could you expand on requirement no. 8? Are there specific policies or planning goals that we should reference or specific evidence that you are looking for us to provide?
Upload a written statement explaining how your project fits into the long-term vision for reliable and efficient electricity in your region, and how it is being developed in collaboration with PJM and your local electric public utility. Applicants can meet this requirement in several ways without having to reference specific policies or goals. Examples of what you can provide in your statement include the following (note that you do not need to provide all or necessarily even most of the following items):
- An explanation of how your project will contribute to meeting PJM resource adequacy planning criteria for New Jersey and/or the region as a whole.
- Any state energy plans or laws your project supports, especially if it helps improve the grid or reduce congestion.
- Reliability tests or simulations you’ve conducted.
- Documentation of interconnection studies or approvals.
- Any involvement in PJM planning meetings or discussions.
A description of how you’re working with PJM and your local utility to ensure smooth system operation.
32. I am hoping you can help clarify the requirements surrounding interconnection for the GSESP – there is reference in certain sections of the program/application process materials that indicates projects seeking to add storage to an existing system are eligible for the GSESP, however other materials note that those projects must be connecting to deactivated or deactivating generation facilities – Can you confirm which is the case? If we have existing PJM projects with WMPAs, are we able to submit a bid under the premise that we will connect that storage project to the same transmission network using the excess CIRs common among PV only assets?
Per the Board Order: “Staff recommends allowing both standalone storage as well as storage additions to existing solar, solar-plus-storage resources, and other Class I renewable energy resources to participate in Phase 1 solicitations, provided they are not receiving and will not receive incentives for the same storage capacity from the CSI program.” As long as the existing project has not and will not receive incentives from the CSI program for the same storage capacity, it may be eligible for GSESP. It is not the case that projects seeking to add storage to an existing system must be connecting to deactivated or deactivating generation facilities. Projects may be an addition to an existing resource (including PV) that is interconnected to the PJM transmission network and located within a transmission zone in New Jersey. The project may submit a completed surplus interconnection study demonstrating use of excess CIRs from existing PV facilities.
33. Will awarded projects have to post the $100,000/MW pre-development security mentioned in the 2024 NJ SIP Straw Proposal? If so, can you please confirm the timing for posting and return of any credit support required?
No pre-development security is required for Tranche 1. For Tranche 2 and subsequent solicitations, pre-development security requirements will be defined in a subsequent Board Order.
34. Can you please confirm item 9 (Transmission & Resource Planning Alignment) of the GSESP Final Application Completion Checklist is not required for projects proposing using CIRs of a deactivating generation facility?
That is correct. If a system provides evidence of using CIRs then section 9 is not required.
35. Can you please confirm whether the ELCC forward projections that are going to be used for bid ranking are the “Preliminary ELCC Class Ratings for Period 2027-2028 through 2035-2036” from the document posted on the PJM website on 06/19/2025?
The Board will use what it considers the most appropriate forward projections of ELCC ratings at the time it makes its bid rankings. At this time we anticipate that the document cited will be the primary source. PJM’s forward projections of ELCC is available here.
36. The BPU recently published the Proposed Community Benefits Evaluation Method. Could the BPU clarify the rationale for using a 110 denominator in the scaling factor of step #2 (CBAF formula)? CBAF = (CBS ÷ 100) * (10 ÷ 110). Shouldn’t this 110 instead be a 100, as the recommendation is that the Board award incentives to bids no more than ten percent higher than the lowest rejected bid price in the same solicitation?
No. The CBAF is applied as a discount to bids for the purposes of price-ranking. If hypothetical Bid A is 10 percent greater than Bid B, it is not mathematically true that Bid B discounted ten percent is equal to Bid A. In fact, Bid B discounted by (10 ÷ 110) or approximately 9.1% would be equal to Bid A. The value of 110 within the CBAF formula is calibrated to yield the maximum potential CBAF that will not in any circumstances allow for a bid that is more than ten percent higher than another bid to outrank that lower bid.
37. From a nameplate capacity perspective is a project limited to its PJM approved Maximum Facility Output (MFO)?
Yes, the nameplate capacity specified in a project’s application cannot exceed its PJM approved Maximum Facility Output (MFO).
38. The proposed rule notes the fixed incentive payments will be over 10-20 years, though the table on page 1 and Senate Bill 4289 note a term of 15 years. Can the BPU clarify the expected term?
Per Table 1 of the Board Order, the fixed incentive payment for Tranche 1 will be paid over a 15-year period. The 10-20 year period mentioned in the proposed rule proposed rule is intended to set the outer limits on the length of any award period that the Board chooses to use for a particular solicitation. Moreover, the proposed rule will not be adopted until after the Board issues Tranche 1 awards and therefore does not govern the Tranche 1 solicitation.
a. Should an applicant submit a proposed incentive and specify proposed term length?
As part of the Final Application, bidders should submit their requested bid incentive amount in dollars per megawatt per year. A bidder should not submit a proposed term length, as all winning Tranche 1 bidders will have the same award period of 15 years per the Board’s June 18, 2025 Launch Order.
b. Will the BPU evaluate NPV for different terms if different term lengths are submitted?
A NPV calculation will not be carried out for different term lengths, as all Tranche 1 awards will use the same 15-year term length.
39. How and when will the Board determine if a pre-development security is required?
No, pre-development security is required for Tranche 1. For Tranche 2 and subsequent solicitations, pre-development security requirements will be defined in a subsequent Board Order.
40. When does the BPU expect to issue an order that determines the “delay damages rate”?
Details on the Delay Penalties can be found on page 27 of the Board Order. The deduction from the first annual incentive payment will equal the lesser of the entire first annual incentive payment or $1,000 per MW of the project’s installed capacity for each calendar day of delay, beginning on the calendar day after the project’s planned COD if the Division Director does not grant an extension, or the calendar day after the date to which Staff extended the COD deadline if the Division Director granted an extension. An applicant experiencing a delay must submit evidence and demonstrate to Staff’s satisfaction that the applicant sought to avoid said delays and advance the project in good faith to qualify for an extension of up to 180 calendar days.
41. Can the BPU clarify the maturity requirements for Tranche 1? The proposed rule and the recently passed Senate bill 4289 appear to be in conflict when it comes to the maturity requirements for Tranche 1. Senate Bill 4289 requires the applicant to have a fully executed GIA or ISA, have a completed Surplus Interconnection Study, or have notified PJM of the intent to transfer existing Capacity Interconnection Rights (see sections 2.b.(3)(a) and (b)) at the time of submitting an application to the Board for Tranche 1. The proposed rule would also allow an applicant who has only completed a Phase I system impact study, surplus interconnection study, or equivalent study to qualify (see 14:8-14:3 (d)5(i)-(iii)) in Tranche 1 which, according to Senate Bill 4289, were meant for Tranche 2.
The Board Order establishing the requirements for the Tranche 1 Solicitation, not the proposed rules, governs the Tranche 1 solicitation, as the proposed rule has not yet been adopted and its exact language is subject to revision in response to public comments. Staff anticipates that Tranche 2 would be the first solicitation that could be subject to the adopted version of the proposed rules. For Tranche 1, the Board Order states that applicants must provide one of the following as part of their submission:
- A fully executed Generation Interconnection Agreement (GIA);
- A fully executed Interconnection Service Agreement (ISA);
- Fully executed distribution-level interconnection agreement and Wholesale Market Participation Agreement
- A completed Surplus Interconnection Study; or
- Documentation confirming that the proposed project will utilize the Capacity Interconnection Rights (CIRs) of a deactivating generation facility.
42. What is the methodology of measuring the accredited capacity (section (e) on page 10)? Should the applicant submit the designated method of calculation for “lowest bid prices on a per-unit basis”? Can BPU clarify how prices will be evaluated in section (e) on page 10 with an example? The options provided make it unclear how these will be compared on an equivalent basis.
The Board shall determine which transmission-scale energy storage systems requesting fixed incentive awards have the lowest bid prices on a per-unit basis by dividing an applicant’s requested annual incentives by either:
(i) The lesser of the transmission-scale energy storage systems’ installed capacity or energy storage capacity divided by four hours; or
(ii) The expected average accredited capacity of the transmission-scale energy storage systems over the first five years of the system’s life, or another period of time established by Board order.
Per page 23 of the Board Order, Staff will determine the lowest price bid on a per-unit basis by dividing the applicant’s requested annual incentives by the expected average accredited capacity of the transmission-scale energy storage system over the first five years of the system’s commercial operation. This will be the designated method of calculation for the lowest-bid prices on a per-unit basis for the Tranche 1 solicitation For this solicitation, bid prices will NOT be compared on the lesser of the transmission-scale energy storage systems’ installed capacity or energy storage capacity divided by four hours.
43. Would multiple bids for variants of the same project be permitted? I.e., would the BPU accept bids for the same project at the same POI but at different sizes or durations? If so, are separate applications and bid fees required for each project variant?
Yes, multiple bids for variants of the same project are permitted. A separate application and bid fee for each project variant would be required. Additionally, each application proposing a variant of the same project should clearly note that the applicant is proposing multiple variants of the same project, and can ultimately only develop one.
44. Is there any penalty that the applicant could incur if the project is awarded but does not ultimately go through?
In short, for tranche 1, an awarded project that fails to ever reach commercial operation would receive no incentive payments and would likely have its award terminated. However, there would be no financial penalty beyond the loss of the incentive payments.
More specifically, there are delay penalties whereby Staff may reduce the first annual incentive payment if the project does not achieve commercial operation by its planned COD, unless the Division Director grants an extension of the Planned COD deadline of up to 180 calendar days. The deduction from the first annual incentive payment will equal the lesser of the entire first annual incentive payment or $1,000 per MW of the project’s installed capacity for each calendar day of delay, beginning on the calendar day after the project’s planned COD if the Division Director does not grant an extension, or the calendar day after the date to which Staff extended the COD deadline if the Division Director granted an extension. The Board, or the Program Administrator if the Board decides to delegate this authority, will revoke the incentive award if the applicant misses their guaranteed COD by 36 months, or adjusted for any grace period otherwise established by the Board.
45. We are thinking of participating in the upcoming storage program and were hoping to get some clarification on what the program would like to see in an execution plan for permitting. Is there an example that you can point me to?
NJBPU Staff has not developed an example execution plan for permitting. However, applicants are expected to provide a clear roadmap demonstrating how they will secure any outstanding permits prior to project development. Applicants are not required to present an execution plan that follows a particular format; NJBPU Staff is more concerned with substance of the plans than form in which they are presented. A strong execution plan would thus identify the permits required, their current status, anticipated timelines for submission and approval, engagement with the relevant authorities having jurisdiction, and supporting documentation (such as submitted applications, correspondence, or projected schedules). The goal of the execution plan is to demonstrate that permitting is being actively managed and that the project remains on track to meet GSESP deadlines.
46. For ESS projects proposing to utilize leftover CIRs from existing PV projects, what sort of interconnection documentation is required? The existing PV projects’ WMPA or a new SIS or similar from PJM for the PV + newly proposed ESS?
For any project that is interconnecting at the distribution level, as would be the case for an ESS addition to any project that has a WMPA, the applicant must provide a fully executed copy of the distribution-level interconnection agreement with the relevant EDC plus one of the following PJM interconnection documents as part of their submission:
- A Wholesale Market Participation Agreement
- A completed Surplus Interconnection Study; or
- Documentation confirming that the proposed project will utilize the Capacity Interconnection Rights (CIRs) of a deactivating generation facility.
ESS projects that plan to interconnect to the bulk transmission system need only provide one of the following PJM interconnection documents as part of their submission:
- A fully executed Generation Interconnection Agreement (GIA);
- A fully executed Interconnection Service Agreement (ISA);
- A completed Surplus Interconnection Study; or
- Documentation confirming that the proposed project will utilize the Capacity Interconnection Rights (CIRs) of a deactivating generation facility.
47. Could you please assist in providing the Project ID for our project which was submitted for pre-qualification (below)? The Project ID is requested in the attached GSESP Bid Fee form. If it is the same as the Docket number below, could you please advise how best to proceed?
Applicants are requested to provide the MyNewJersey portal ID that was assigned to them when they created their MyNewJersey account.