2024-STM 00002 Published On: 06/14/2024
Question: Could you please advise where can I register to attend the 2024 RFP Technical Conference on June 17, 2024?
Answer: The materials for the Technical Conference are filed in the following NCUC dockets E-2, Sub 1340 and E-7, Sub 1310. The conference will also be broadcast on the NCUC You Tube channel a link is available here NCUC: Public Hearings
2024-STM 00001 Published On: 06/07/2024
Question: When will the 3rd Stakeholder Meeting for the 2024 RFP be held and will a registration link be sent out?
Answer: The 3rd Stakeholder Meeting is planned for June 14, 2024. An email annoucenement was sent out to registered users on the RFP Website on June 7, 2024. To become a registered user on the website, follow the steps on https://www.dukeenergyrfpcarolinas.com/Registration.
A link to register to attend the meeting is posted on the 2024 RFP Process Timeline section of the Home page: Duke Energy RFP Carolinas > Home.
2024-GEN 00049 Published On: 11/19/2024
Question: For UOT projects, is the developer required to file a CPCN sometime before project ownership is transferred to Duke Energy? Or will Duke Energy file the CPCN after it takes ownership of the project?
Answer: No, a CPCN application does not need to be filed before transferring ownership. For selected Asset Transfer or Build Own Transfer proposals, if the MP has an approved or pending CPCN, then post definitive contract execution the parties will seek a transfer of the approved CPCN from the MP to DEC/DEP. If the MP does not have an approved or pending CPCN, then DEC/DEP will prepare and submit a CPCN application after the definitive contract execution. Similar approach applies for applicable SC projects that require a CECPCN. CPCN/CECPCN approvals/transfer will be a requirement / closing condition pursuant to the applicable definitive agreement.
2024-GEN 00048 Published On: 10/25/2024
Question: Do you need a docket number from NCUC to apply for a Duke RFP?
Answer: The NCUC docket number field is an optional field to complete on the North Carolina Interconnection Application; it can be left blank.
2024-GEN 00047 Published On: 10/10/2024
Question: In reference to question 2024-DOC 00003, can a project bid SPS PPA for a project and a solar-only UOT to meet the solar only requirement or will we be required to bid a solar only PPA? Another way to ask this, is the solar-only offer requirement per project or per project per track?
Answer: The solar-only bid requirement applies per project per track, so no, a Market Participant cannot submit a project as an SPS PPA if no solar-only PPA proposal was offered for the same project.
2024-GEN 00046 (revised 10/03/2024) Published On: 10/03/2024
Question: I wish to clarify the response to a 2024-GEN-2012 regarding coop service territory properties and Duke Transmission lines. The response restated the general point that projects must be in Duke service territory AND connect to a Duke transmission line. The response did not simply state, "No", which implies that there may be ambiguity or overlap in service territories. To clarify:
1) Is there some ambiguity for projects? In other words, if DEP is the service provider in a county which is shown as within DEP service territory, but the detailed site information for the location of the property providing generation shows a coop service territory, but there is direct access to a DEP transmission line, can the project bid and be eligible? Please reply, YES or NO.
2) If the project submits and CRA or Duke determine the project is ineligible due to the service territory, will the project lose the $10,000 deposit?
Answer:
2024-GEN 00045 Published On: 10/01/2024
Question: Are Transmission Provider Interconnection Facilities and Network Upgrades both not reimbursable for the PPA track?
Answer: Cost to directly connect to the existing DEC/DEP transmission system (“Interconnection Facilities”) should be included in the Part A / Part C Price. System Upgrade Costs should be included in the Part B / Part D price. See seciton VI.A of the RFP.
2024-GEN 00044 (revised 09/30/2024) Published On: 09/27/2024
Question: We hope this message finds you safe. As many areas, including those with market participants in the 2024 Solar RFP, are currently experiencing significant power outages due to the recent hurricane, we are writing to inquire whether Duke Energy is considering an extension to the RFP submission deadline. Given that many bidders, who are also Duke Energy customers, are being directly impacted by the storm, we believe it would be prudent to allow additional time to ensure fair participation for all involved.
Answer: After additional time to assess the impact of Hurricane Helene in the Carolinas, Duke Energy Carolinas and Duke Energy Progress, after consultation with CRA, are further extending the deadlines for bid submittal and Interconnection Requests to enable participation in the 2024 RFP and 2024 Resource Solicitation Cluster (“RSC”). All third-party MP-sponsored proposals and applications must be submitted by 11:59am (noon) on Monday, October 7, 2024. We encourage those MPs who are not impacted by Hurricane Helene to submit their applications promptly. Please email the RFP Manager to notify them once you have uploaded all documents for your Proposal(s).
The Companies and CRA will continue to monitor conditions this week, and will provide information on any additional impacts to the RFP schedule resulting from this extension of the bid window in the coming weeks.
2024-GEN 00043 Published On: 09/26/2024
Question: What is the current assumption for the 2024 RFP Solar Reference Cost?
Answer: As stated in the RFP, the Solar Reference Cost is the assumed priced of solar resources in the Companies’ most recently filed 2023 Resource Plan. Footnote 27 describes that the 2023 Resource Plan's Solar Reference Cost is different in each year modeled, and the 2024 RFP will use the cost from model year 2028. Consistent with the RFP, the Companies will share the final Solar Reference Cost prior to the Step 2 bid refresh phase.
2024-GEN 00042 Published On: 09/25/2024
Question: A couple of questions: 1) Can you confirm that the total solar PV inverter capacity (e.g. Row 17 in the UOT SPS bid form) does not need to match the interconnection rating (2 rows below)? The text notes imply that the two should match but the total inverter capacity should actually equal the maximum AC size before clipping, not the AC limit at the POI. 2) Can you confirm that UOT asset transfer bids do not require an 8760 production model? With Duke determining the dc size of the system, any estimates provided by the bidder would be inaccurate. Slide 35 of the 8/12/24 bidders conference states explicitly that only BOT bids should include 8760s but the bid form is not clear. 3) Can you confirm that the 8760 models for PPA bids do not need to adhere to the standards of Exhibit A4? There is no confirmation required in the bid form as there is in UOT responses to imply that they do.
2024-GEN 00041 Published On: 09/25/2024
Question: Could you confirm what Duke considered "major project milestones"?
Answer: As provided for in Section VII.B.1 of the RFP Document, MPs should disclose all major project development milestones, which includes “permits that will have to be obtained, the status of each permit, a timeline for the completion of all permits that relate to the Proposal, site evaluation and studies conducted to date, and a timeline for completing all outstanding studies.”
Note that for UOT proposals, there are also specific Key Milestone Schedule inputs in the UOT Solar-Only bid form (rows 200-222 at 1. Solar-only tab) and in the UOT SPS bid form (rows 173-198 at 1. UOT SPS tab).
2024-GEN 00040 Published On: 09/24/2024
Question: The RFP document states that the "BESS Capacity rating between 35-40% of the Solar MWac (POI) maximum export capacity, sized to the nearest 1 MW increment; (BESS must be a minimum of 35% of the facility’s maximum export capacity)". When we round up our battery capacity to the nearest 1 MW increment, the BESS capacity rating becomes 40.005% of the solar MWac POI maximum export capacity. Is this acceptable for the RFP application for the PPA proposal track?
Answer: Yes, this is acceptable.
2024-GEN 00039 Published On: 09/23/2024
Question: Upon completion of the upload of the whole application package (the Input Bid + Relevant appendices + NDA + RSC Payments), is there anything to do to confirm that the submission upload is completed?
Answer: Please email the RFP Manager to inform them that you have uploaded all documents. The RFP Manager will then send a confirmation of receipt. The RFP Manager contact information is included in the Bid Input Forms.
2024-GEN 00038 Published On: 09/23/2024
Question: Regarding the closing deliverables for the APA, does a desktop summary count for the cultural resource study requirement?
Answer: A desktop cultural resource assessment would only be satisfactory if its results concluded in “no field studies being required” and agency concurrence is provided confirming the same. If the desktop assessment identifies and recommends further field assessments, the additional studies will be required to be completed to satisfy the developer’s scope of selling a fully developed project pursuant to an Asset Transfer proposal and the APA.
2024-GEN 00037 Published On: 09/23/2024
Question: Can a UOT project submit the same project as both a Build Own Transfer AND Utility Self-Developed project? If so, must two forms be filed and two 10,000 deposits be submitted?
Answer: No, third parties can submit UOT track proposals as either Asset Transfer or Build-Own-Transfer but not both. Utility Self-Developed proposals are only an option for Duke Energy-owned and developed projects.
2024-GEN 00036 Published On: 09/23/2024
Question: Can you confirm how you will be evaluating sites pre-shortlisting prior to the start of the Phase 1 RSC for what the scoring rubric describes as "Consideration for target COD date and risk of significant increase in interconnection cost reallocation"?
Answer: This is one of many scoring components for the 2024 RFP projects. During Step 1, prior to the Phase 1 RSC Cluster study, scoring for this component will be based on projected CODs and the bidder’s current interconnection status.
2024-GEN 00035 Published On: 09/20/2024
Question: Does the 2024 RFP have an early winner selection path for projects with serial IAs and no NUs that are deemed to be price competitive?
Answer: No, there will be no Early Winner process for the 2024 RFP.
2024-GEN 00034 Published On: 09/20/2024
Question: If we are unable to submit fees through the interconnection portal, can we use Duke's wiring instructions from the 2023 RFP?
Answer: No, do not use the wiring instructions provided for the 2023 RFP. Use of the Interconnection Portal for payments is strongly encouraged.
The DEP and DEC banking information has been updated. Please request the new wiring instructions from the RFP Manager or through the 'Submit Questions' section of this website.
2024-GEN 00033 Published On: 09/20/2024
Question: Can MPs use a bond to pay the Pre-COD and/or Post-COD Performance Assurance? And does the Post-COD Performance Assurance security decrease over time?
Answer: Surety bonds are not accepted for Pre-COD Performance Assurance. The Companies will review any security for Post-COD Performance assurance and provide feedback to the PPA customer. Post-COD Performance Assurance does decrease over time.
2024-GEN 00032 Published On: 09/19/2024
Question: If a project is shortlisted, it will be required to submit a Proposal Security. The Proposal Security will be released (i) after all Winners have accepted their offers and no additional Finalist will be invited, if the Proposal is not selected as a Finalist; or (ii) if the Proposal is selected as a Finalist, upon completion of the contracting phase of the RFP, including execution of the applicable Asset Acquisition Agreement. Shortlisted projects that are notified as Finalist will have 30 days to execute a LOI. Finalists that execute a LOI will have 5 business days to provide an additional LOI security of 3% of the asset price, which is released upon executing the applicable definitive agreement (i.e. the APA.). Section 11 of the LOI allows for termination by either party at its discretion. Can Duke please clarify that if the LOI were terminated by Duke’s discretion per section 11 of the LOI, that both the full Proposal Security and the additional LOI Security of 3% of the asset purchase price will be returned fully to the seller?
Answer: The Release of the applicable Proposal Security and/or LOI Security will depend on the facts and circumstances giving rise to the termination of the LOI; provided however, if Duke terminates unilaterally and exclusively for its convenience (without cause arising from breach of the terms of the RFP and/or the LOI), the LOI and Proposal Security will be released in the normal course.
2024-GEN 00031 Published On: 09/19/2024
Question: From Duke Energy Business Practice: Studying Storage Interconnection Requests in DEC and DEP: 1. Can a Stand-Alone Storage be co-located with a Solar PV source and share the main GSU, gen-tie and breaker terminal at POI? If not, which interconnection facilities can be shared by the Solar PV and the BESS (if any), while the BESS is a Stand-Alone generating facility? What are the corresponding metering requirements for the PV and the BESS under this co-located configuration? 2. Can the BESS in an SPS facility charge from the PV as well as from the grid? 3. Paragraph 2 of 1.2. states "In the solar plus battery example, the battery is charged when solar generation exceeds the power injected to the grid" - Does this imply that the BESS of an SPS facility can only charge from the co-located PV? If so, then the PV should be sized to more than 140% in response to the 2024 RFP requesting BESS to be 35-40% of PV? 4. In a SPS facility can the PV and BESS share the main GSU, gen-tie and breaker terminal at POI? If not, which interconnection facilities can be shared by the Solar PV and the BESS (if any)? What are the metering requirements for the PV and the BESS? 5. For the 2024 RSC/RFC, can the IC request simultaneous discharge operation of the PV and the BESS?
2024-GEN 00030 Published On: 09/13/2024
Question: Are cash and letter of credit the only options for LOI Security under the UOT track, or would surety bonds be accepted as well?
Answer: Pursuant to Appendix J (form LOI and Term Sheet), acceptable additional security for selected asset acquisition proposals shall be in the form of cash or letter of credit in form and substance reasonably acceptable to DEC/DEP. Surety bonds are not acceptable.
2024-GEN 00029 Published On: 09/13/2024
Question: The form PPA outlines Pre-COD Performance Assurance as 4% of the total projected revenue based on the Part A Price, and Post-COD Performance Assurance as 2% of the total projected revenue based on the Part A Price. Will the total projected revenue take into account the full allowable uncompensated curtailment amounts of 5% for DEC and 10% for DEP, or do these security amounts not contemplate curtailment in the calculation of total projected revenue?
Answer: Curtailment is not included in the calculation; Duke Energy uses the MWhr provided by the bidder.
2024-GEN 00028 Published On: 09/12/2024
Question: As a follow up to FAQ - 2024-GEN 00025, do we need to provide proof of this authorization to execute a PPA or LOI as part of our bid response?
Answer: If the bidder entity in the RFP is not the owner of the project, please submit proof of authorization to execute a PPA or LOI should the project be selected in the RFP.
2024-GEN 00027 Published On: 09/12/2024
Question: Does the interconnection request need to be sized the same as the RFP application project? For example, could we submit a 200 MW project to the Duke interconnection queue but the project submitted to this RFP is 150 MW?
Answer: The Interconnection Request and the RFP bid need to align. The project studied in the Resource Solicitation Cluster must be the same sized project bid into the RFP. For information related to Proposal Size Flexibility, please see DEC DEP 2024 RFP Document, Section G “Proposal Size Flexibility”.
2024-GEN 00026 Published On: 09/11/2024
Question: Can you please add BYD to the Approved Vendor List? Also, is there a reason why CATL was removed from the AVL for the 2024 RFP? Can you please add it back?
Answer: Appendix H (AVL) only applies to Utility Ownership Track (“UOT”) proposals. A thorough and complete review of suggested vendors is not able to be performed prior to the bid submittal deadline. For module manufacturer requests, please provide relevant spec sheets, PAN files and other relevant product information. For storage equipment, please provide all relevant technical and business materials. All UOT proposals must use equipment from the AVL and submit a conforming bid; however, if a bidder wishes to provide a bid price reduction by substituting a non-AVL equipment provider (non-conforming proposal), they can do so using the notes section of the bid form.
Duke Energy has made a public commitment to voluntarily stop specifying CATL batteries by 2027. Duke Energy reserves the right to make changes to the AVL.
2024-GEN 00025 Published On: 09/11/2024
Question: Does the bidder of a project need to be the upstream owner of the project entity?
Answer: No, but the bidder must have the authority to execute a PPA or LOI for the project to be offered in the RFP.
2024-GEN 00024 Published On: 09/11/2024
Question: How will Duke treat projects that either (a) are submitted as non-EC UOT projects and receive EC status after submission or (b) are submitted as EC UOT projects but then lose status between submission and award the following year?
Answer: Bidders are asked to affirm if a project will quality for the Energy Community IRA bonus provision on the UOT bid forms, along with space to provide documentation and evidence. The RFP Evaluation Team will rely upon this information provided by the Bidder. Bidders are able to provide updated information in the Bid Refresh process. Due to the risk that a project’s eligibility for Energy Communities may change year to year where the Energy Community is based upon the unemployment rate qualifications option, the RFP Evaluation Team will not include the Energy Communities adder when evaluating LCOEs, considering the risk that a project may no longer qualify post RFP selection. Should a UOT project qualify for Energy Communities post RFP selection, those increased tax benefits would be passed along to customers.
2024-GEN 00023 Published On: 09/10/2024
Question: Please confirm the preferred cycles for the hybrid systems this year. Last year the scoring sheet offered a bonus for additional cycles that does not appear to be there this year.
Answer: BESS cycle guidance is provided in Appendix Q-1 and the Scoring rubric is provided in Appendix F. The bonus points for exceeding 365 equivalent cycles per year have been removed for the 2024 RFP as compared to the 2023 RFP.
2024-GEN 00022 Published On: 09/10/2024
Question: For the 2024 RFP/RSC bid window, does the SPS submission need to account for 2 (two) separate main power transformers, one for the Solar PV component and one for the BESS component, with AC-coupling at the high-side of those transformers? Or can the AC-coupling take place at the medium voltage, thus allowing for a single main power transformer?
Answer: One main power transformer is acceptable for a solar plus storage facility submission.
2024-GEN 00021 Published On: 09/09/2024
Question: Can you confirm that if a UOT track proposal were to be selected as a Winner that it would need to hold both the Step 2 Proposal Security and the LOI Security until the execution of the applicable Asset Acquisition Agreement? Or would the Proposal Security be released at the time of LOI execution, and just the LOI Security would be held until execution of the Asset Acquisition Agreement?
Answer: For a selected UOT proposal, pursuant to RFP Document Section V.J.3, the Step 2 Proposal Security will be released upon execution of the applicable definitive agreement (i.e the Asset Purchase Agreement (“APA”) or the Build Transfer Agreement (“BTA”)). Additionally, pursuant to RFP Document Section VII.F, market participants are required to provide additional LOI security of 3% of the asset bid price within 5 business days of executing the LOI, which will also be released upon executing the applicable definitive agreement (i.e. APA or BTA).
2024-GEN 00020 Published On: 09/05/2024
Question: Under this RFP, Duke has the right to terminate the PPA under Section 20.1.2, if the System Upgrade Costs in the executable version of the Interconnection Agreement are greater than 125% of the SUC estimate in the RSC Phase I Study results. Does Duke have to exercise this right to terminate the PPA under Section 20.1.2 before the Seller has to make the M4 payment deposit under the RSC process with DEP Transmission?
Answer: No, State projects will have paid M4; the “M4” deposit is due 10 days after receiving the Facilities Study results for the state jurisdictional projects.
This is described in Section 4.4.10.4 of the North Carolina Interconnection Procedures ncip-appr-oct292021-eff-oct112021-searchable.pdf (duke-energy.com) and in Section 5.3.10.4 in the SC Appendix CS.
2024-GEN 00019 Published On: 09/04/2024
Question: As a follow-up to FAQ 2024-GEN-00008, how will Duke ensure that BESS bids are comparable? Much like Duke requires all bidders to use a consistent platform (PVSyst) and even provides modeling parameters for production data, how will Duke verify if BESS performance estimates (losses, auxiliary load, degradation, etc.) provided by bidders in Appendix Q2 consistently complied with the modeling requirements in Appendix Q1?
Answer: Similar to solar only evaluations, SPS bids will be evaluated with tools that are designed for the evaluation of the BESS degradation. Market Participant provided information will be utilized as inputs and all of the proposals will be evaluated with a consistent approach.
2024-GEN 00018 Published On: 09/03/2024
Question: For an SPS bid, the RFP requires a BESS at about 40% capacity of the solar PV. What assumptions about discharge for the BESS and solar PV should we make? For instance, if the BESS is grid charged, will there be operating scenarios in which the PV and BESS will discharge simultaneously? In other words, should our maximum interconnection be the sum of the max PV capacity and the BESS capacity or should we assume the combined discharge will never exceed the PV, since the BESS will be used during low solar hours?
Answer: For the solar plus storage projects, DEC and DEP will use the maximum output of the solar facility for purposes of interconnection study. Using an 80MW solar facility paired with 32 MW of BESS as an example: the solar generating facility’s maximum output at the Point of Interconnection should not exceed 80MW, because in the interconnection study assumptions made by DEC and DEP, the BESS will not discharge when the solar facility is generating at its full capacity. For more information on how DEC and DEP study solar plus storage projects, please see the OATI Oasis posting “Duke Energy Business Practice: Studying Storage Interconnection Requests in DEC and DEP”at Storage_Studies_-_Duke_Energy_Business_Practice_2022-10-26.pdf (oati.com).
2024-GEN 00017 Published On: 08/30/2024
Question: Would a project be able to submit two 75 MW projects (either under the PPA or UOT track) that are located on sites next to each other and targeting the same transmission line?
Answer: Two projects interconnecting on separate transmission lines does not alleviate the requirements of the FERC 1 mile rule, which does not distinguish between the same transmission line or not. Projects owned by the same Interconnection Customer shall be in compliance with the FERC guidelines for the projects to be considered as qualifying facilities. Please also review the 2024 RFP, Section IV.B for additional guidance on PPA proposals. Note also if there are two projects in close proximity to each other, a multi-breaker switching station will likely be needed to connect into the transmission line.
2024-GEN 00016 Published On: 08/22/2024
Question: How is CRA managing confidentiality of project information for bidders that previously were shortlisted but did not either get selected or choose to execute a PPA or LOI for a UOT bid. Duke would have access to things like POIs, landowner information, cost estimates, design and other EPC information as well as a variety of other project information that could be used to create an unfair advantage?
Answer: All information provided by a Market Participant for a Utility Ownership Track Proposal is subject to the confidentiality agreement signed by the parties at the time of bid submittal. Further, for both the 2023 and 2024 RFP processes, the RFP established separation requirements pursuant to which (i) Utility Ownership Team members (which develop Utility-Developed Proposals) will not be involved in or responsible for the economic evaluation of any Proposals (which will be performed by the Independent Evaluator and the Duke Evaluation Team); and (ii) a separate Utility Bid Sub-Team that will solely and exclusively be responsible for any pricing refreshes to any Utility-Developed Proposals or Asset Transfer Proposal after Step 1 (i.e. don’t not have access to any Build-Own-Transfer Proposals).
More information is available in Section V.E of the 2024 RFP.
2024-GEN 00015 Published On: 08/22/2024
Question: Can you confirm that the $1.5M cap on Winners' Fees refers to the total of all Winners' Fees combined and that it is not capping the Winners' Fee per project at $1.5M per project. The most that a Winners' Fee would be for a project would be $1.5M divided and allocated on a pro-rata basis in solar MW among all Winners, correct?
Answer: Correct, the total Winners’ Fee is capped at $1.5 million, see 24 DEC DEP RFP Document, Section VIII Winners' Fee.
2024-GEN 00014 Published On: 08/19/2024
Question: For a UOT SPS proposal, a significant overbuild on day 1/COD will be required to maintain the BESS Performance Guarantees for the first 15 years of asset life without the ability to augment. Please confirm you are asking bidders to overbuild the BOT option to include enough extra batteries to cover degradation over the first 15 years of the asset life. Would Duke be open to a 2-7 year overbuild in conjunction with additional buildable acreage to accommodate additional BESS equipment in order to meet original nameplate capacity?
Answer: Technical requirements for UOT SPS proposals can be found in Appendix Q1. Appendix Q1 provides that “Cell replacement is only allowed at year 15. No other augmentation or replenishments are allowed throughout 15-year project life.” UOT SPS bidders are required to adhere to Appendix Q1, which does not permit cell replacement during the 15-year operating period for the BESS.
2024-GEN 00013 Published On: 08/13/2024
Question: Would Duke be open to a portion of a bigger facility as PPA and remainder as UOT, under a shared or separate POI? The RFP mentions "full output of Facility" under the PPA track, but any clarifications is appreciated here.
Answer: Yes, Duke Energy would consider a bigger facility split into a PPA (maximum output 80MW) and the remainder UOT as long as the POI is separate for each. Each unit requires its own metering and telemetry.
2024-GEN 00012 Published On: 08/07/2024
Question: If a project is located in a cooperative territory and a Duke Energy transmission line crosses the territory and would be used for interconnection, can this project be included in the RFP?
Answer: Facilities must be located in the Duke Energy Carolinas, LLC (DEC) or Duke Energy Progress, LLC (DEP) North Carolina or South Carolina service territory and must also physically interconnect with the DEC or DEP transmission system.
2024-GEN 00011 Published On: 08/07/2024
Question: Can you please confirm that Network Upgrade costs should not be included in the proposal price for an Asset Transfer? Additionally, would an Asset Transfer proposal be required to provide Network Upgrade security and hold that cost until closing if selected?
Answer: The proposal price provided by an Asset Transfer project should not include any Network Upgrade costs; new projects bidding into the 2024 RFP and participating in the Resource Solicitation Cluster will not know their Network Upgrades cost at the time the proposal price is due to be submitted. An Asset Transfer proposal would be required to provide M4 security to cover the cost of Network Upgrades once the Facilities Study is complete. The Asset Transfer proposal will also be responsible for executing and maintaining an Interconnection Agreement, including any additional securities that may be required under such Interconnection Agreement, until the Interconnection Agreement is assigned to DEC/DEP at closing of the definitive Asset Purchase Agreement.
Asset Transfer proposal that bids in the 2024 RFP with a fully executed Interconnection Agreement shall be solely responsible for the cost of any interconnection facilities and System Upgrades assigned to it under its Interconnection Agreement and shall bid accordingly as participation in the 2024 RFP will not alter any contractual obligations included in the MP’s executed Interconnection Agreement.
2024-GEN 00010 Published On: 08/02/2024
Question: Is there an updated estimated curtailment schedule that Duke can share based on the prior schedule that was shared in the 2023 RFP?
Answer: The updated File for Annual Solar Curtailment Estimates Due to Excess Energy is now posted here. All solar-only PPAs will be subject to the 5%/10% non-reliability curtailment rights as specified in the PPA. Other possible curtailment events include reliability curtailments for transmission events (these are infrequent and impact resources local to the transmission constraint that are exacerbating the constraint), and reliability curtailments for excess energy (these will presumably grow as more solar is on the system). From the modeling work that supports the Companies’ 2024 Carolinas Resource Plan filed on 1/31/2024 for Portfolio P3 Fall Base, we are providing year over year solar curtailment estimates due to excess energy (as a percent of the total solar generation). Please note that these figures are modeled assumptions and outputs based upon a snapshot in time as of when the modeling was produced and numerous factors can impact the need for curtailment in the future. Resource Solicitation/Procurement participants should review the terms of the applicable solar-only PPA for terms and conditions related to resource curtailment.
2024-GEN 00009 Published On: 07/31/2024
Question: re: 2024 RFP, can Duke provide up to date historical solar curtailment in its sub regions?
Answer: DEC and DEP publicly file quarterly reports with the NCUC providing historical solar curtailment data in Docket Nos. E-2, Sub 1178 Docket Details (ncuc.gov) and E-7, Sub 1175 Docket Details (ncuc.gov). Please note all solar-only PPAs will be subject to the 5%/10% economic curtailment rights as specified in the 2024 RFP PPA.
2024-GEN 00008 Published On: 07/29/2024
Question: In the evaluation of UOT bids for SPS Facilities, will Duke perform its own independent battery modeling to ensure that the requirements of Appendix Q1 and Q2 are met? If so, is there a specific tool that Duke uses for this modeling?
Answer: In the evaluation of SPS UOT bids, the utility’s Evaluation team will use the data provided in forms Appendix Q1 and Appendix Q2 by the Bidder to evaluate the operational profile and degradation of the BESS. No single specific tool or model is utilized for the evaluation.
2024-GEN 00007 Published On: 07/26/2024
Question: Can you confirm the following requirement applies only for UOT track proposals and not for PPA track proposals? "Bidders are expected to provide valid due diligence terms through mid-2028 (July), or longer, with a minimum of 18 months of a construction term and a minimum of 35 years of an operating term commencing at placed in service (if lease agreement);"
Answer: This requirement is listed in Section IV.A of the 2024 RFP, which only applies to UOT proposals.
2024-GEN 00006 Published On: 07/24/2024
Question: Can an MP submit a project under the UOT that does not meet the site control requirements outlined in Section IV.A of the 2024 RFP, provided that the project has a signed interconnection agreement from a previous serial process and the site due diligence term is sufficient to achieve the ISD under the interconnection agreement? I.e., can an MP submit a project that has site control through 2027, if the project COD is 2027?
Answer: Yes, an MP may bid a project into the UOT track that has site control through 2027; however, the proposal will be scored accordingly. Site control requirements are provided in “Section IV Proposal Tracks, A. Utility Ownership Track Proposal” bullet 6 -
"Provide sufficient and satisfactory site control rights for the Facility including delivery to the Point of Interconnection (POI) to develop and construct the proposed Facility within the timeframe laid out in the RFP. Bidders are expected to provide valid due diligence terms through mid-2028 (July), or longer, with a minimum of 18 months of a construction term and a minimum of 35 years of an operating term commencing at placed in service (if lease agreement);”.
There are other factors beyond just a fully executed interconnection agreement that may impact a project’s construction lead time, such as equipment availability, construction subcontractor availability, outage coordination, etc. As such, all UOT projects will be scored in accordance with the requirements provided.
2024-GEN 00005 Published On: 07/17/2024
Question: Is the maximum size project allowed to bid into this RFP 80 MWac? Will projects larger than 80 MW not be allowed?
Answer: For a power purchase agreement (PPA) track project, the maximum size is up to and including 80 MWac (based on the interconnection request) in both DEC and DEP. However, projects bidding into the Utility Ownership Track (UOT) of the RFP can be larger than 80 MWac (and any project greater than 80 MWac would be submitting their interconnection request as a FERC jurisdictional project).
2024-GEN 00004 Published On: 07/16/2024
Question: I’m trying to understand whether bat studies are required prior to RFP submission or only if the project is selected in the [2024] RFP. The RFP requirements and FAQ GEN 00070 on https://www.dukeenergyrfpcarolinas.com/FAQ/General contradict each other. Thanks in advance for clarifying. From the tariff: UTILITY OWNERSHIP TRACK PROPOSALS In addition to the requirements in Section III, Proposals for Facilities in the Utility Ownership Track must also meet all of the following: Include a habitat assessment and onsite acoustic survey for all listed and proposed to be listed bat species, as well as any bat species listed or proposed to be listed after the issuance of this RFP within bidder scope. Duke Energy, as project owner, shall have the ability to review and approve the scope of said studies before authorized. The U.S. Fish and Wildlife Service ("USFWS") has listed or proposed to be listed several bats species with habitat range in North and South Carolina. These species include the Indiana Bat (Myotis sodalist) and Northern Long-eared Bat (Myotis septentrionalis), both currently listed as endangered. The tricolored bat (Perimyotis subflavus) is proposed to be listed in the fall of 2023 as either a threatened or endangered species.
Answer: To clarify the guidance provided in GEN 00070 and 00007 for the 2023 RFP, for Asset Transfer and BOT bids, the Seller (the Market Participant) will be required to complete habitat assessment(s) and onsite acoustic survey(s), as established in Section IV.A. This will be the responsibility of the Market Participant and must be completed, along with all other applicable scope, as a condition to close pursuant to the applicable definitive agreement (Asset Purchase Agreement or Build Transfer Agreement). So, the assessment and surveys do not need to be completed prior to bidding a project into the RFP.
2024-GEN 00003 Published On: 07/16/2024
Question: Is the habitat assessment and acoustic survey for bats required prior to RFP submission for UOT projects? Considering the changing habits of bats which often change roosts seasonally, can it be assumed that a habitat assessment and acoustic survey will be required every year for the same project?
Answer: The habitat assessment and onsite acoustic survey requirements established in Section IV.A of the RFP, which apply to Utility Ownership Track projects, are not required to be completed prior to bid submission. The RFP provides guidance for bidders to plan to complete the habitat assessment and an onsite acoustic survey as part of their scope submission; whether and how often an assessment or survey will be required to be updated will depend on project specifics and then-current rules and regulations .
For additional information please see 2024-GEN 00003 and Q&As from the 2023 RFP - GEN00006, GEN00007 and GEN 00070.
2024-GEN 00002 Published On: 07/10/2024
Question: To clarify, for the 2024 RFP only the UOT proposals need to submit a habitat and onsite acoustic survey for all listed and proposed to be listed bat species, correct? PPA proposals are not required to submit that bat species information?
Answer: Correct, the habitat assessment and onsite acoustic survey requirements estimated in Section IV.A of the RFP only apply to Utility Ownership Track projects.
For additional information please see GEN00006, GEN00007 and GEN 00070, available at www.dukeenergyrfpcarolinas.com/FAQ/General.
2024-GEN 00001 Published On: 06/17/2024
Question: This question is regarding the upcoming 2024 RFP. Will Duke permit projects on local coop infrastructure to wheel power to them in this RFP?
Answer: Facilities must be located in the Duke Energy Carolinas (DEC) or Duke Energy Progress (DEP) North Carolina or South Carolina service territory and will physically interconnect with the DEC or DEP transmission system.
2024-DOC 00035 Published On: 11/08/2024
Question: The options outlined in the new document “Summary of Extra Facilities (2024 RFP).pdf” are different from what we have seen in the past. Specifically, on all previous Interconnection Agreements we have seen, the Standard Option in each service area is based on a multiplier of the full estimated cost of Interconnection Facilities (to be updated based on actual cost at the time of delivery), rather than being based on a Cost Difference, as stated in your document. Can you confirm how the Cost Difference is calculated? Additionally, in all previous Interconnection Agreements, both the Standard Option and Prepayment Option in all service areas were calculated to approximately equal a NPV of 1.6 X the full estimated cost of Interconnection Facilities (to be updated based on actual cost at the time of delivery). Can you confirm the target NPV and discount rate for the current Standard and Prepayment Options?
Answer: The ‘cost difference’ referred to in the question and the Summary of Extra Facilities (2024 RFP).pdf document corresponds to how the Standard Option is calculated and applied in the Interconnection Agreements. Cost difference refers to the difference between the installed costs for the facilities necessary to meet the Interconnection Customer’s request and the installed cost of facilities which would be furnished for standard delivery. When applied to Interconnection Agreements, cost difference is equal to the full estimated cost of Interconnection Customer’s Interconnection Facilities.
As an example, assuming the projects in question are located in DEC’s North Carolina service territory, both the Standard Option and Prepayment Option are calculated to approximately equal a NPV of 1.6 X the full estimated cost of Interconnection Facilities (to be updated based on actual cost at the time of delivery). Note the NPV is subject to change based on the utility’s latest rate case filed in the applicable state and service territory. As your project progresses, feel free to reach out to the Renewable Integration Team to see what payment options are available.
2024-DOC 00034 Published On: 10/01/2024
Question: One of the CPs for the Asset Purchase Agreement is that "Seller shall have obtained all Permits required for the siting and construction of the Project". Does this include non-discretionary permits, or is this only referring to discretionary permitting? Because the Buyer would ultimately be responsible for the final design and construction under the Asset Purchase structure, it would make more sense for administerial, non-discretionary permitting to be obtained after closing by the Buyer.
Answer: The bidder is responsible for all local discretionary permitting and any permitting requirements that predate detailed design and engineering (i.e. final site plan and stormwater permits).
2024-DOC 00033 Published On: 09/23/2024
Question: Could Duke clarify whether the liquidated damages that Seller owes if it fails to achieve COD by the Second COD Date (i.e., 75% of the Default Liquidated Damages) are in addition to, or instead of, the Per Diem Liquidated Damages?
Answer: The 75% of the Default Liquidated Damages are in lieu of the per diem Liquidated Damages for a total of 100% of the Default Liquidated Damages. In no event would Buyer be entitled to collect more than the full Default Liquidated Damages under Section 20.5.
2024-DOC 00032 Published On: 09/23/2024
Question: Could Duke clarify its intent with the Second COD Date liquidated damages provisions in the PPA? As drafted, it is possible that liquidated damages may equal 4% of the total projected PPA revenues (i.e., the Default Liquidated) even if the Facility reaches COD by the date that is 180 days after the First COD Date. Is this the intent?
Answer: The intent is to incentivize the Seller to achieve COD as quickly as possible. If the Seller fails to achieve COD by the First COD Date, they would have the option to continue performance under the PPA. Upon payment of 25% of the Default Liquidated Damages, Seller would be provided with up to an additional 180 days to reach COD and would incur liquidated damages at a per diem rate (75% x Default Liquidated Damages ÷ 180). If Seller is unable to reach COD until the 180th day of the extension, then the entirety of the Default Liquidated Damages would have accrued (25% + 75% = 100%), but the PPA would remain in effect. If the Seller fails to achieve COD by the 181st day after the extension, the PPA would terminate and Seller would owe the remaining 75% of the Default Liquidated Damages in lieu of the per diem LDs for a total of 100% of the Default Liquidated Damages.
2024-DOC 00031 Published On: 09/23/2024
Question: In the Solar Only PPA The First COD Date is 90 days following the in-service date of the interconnection facilities and system upgrades and can be extended on a day-for-day basis due to Force Majeure. However, the Operational Milestone Schedule exhibit references the First COD Date being subject to day-for-day extension “for any delays not caused by the Seller”. This extension is not referenced elsewhere in the PPA. Cold Buyer please clarify Seller’s First COD extension rights (i.e., when is Seller entitled to First COD schedule relief)?
Answer: The First COD Date as referenced in Section 20.5.1 (Failure to Achieve First COD Date), means the deadline for Commercial Operation Date specified in Exhibit 3 (Operational Milestone Schedule) as extended (if applicable) in accordance with the Operational Milestone Schedule. I.e., if the COD deadline is extended in accordance with the operational milestone provision, the Seller would not owe liquidated damages unless and until the extended date was missed.
2024-DOC 00030 Published On: 09/23/2024
Question: The Operation Milestone Schedule EOD in the Solar Only PPA (Section 19.8) allows for “extensions pursuant to the terms of Section 20.5”, though the Operational Milestone Schedule exhibit states that the First COD Date is subject to day-for-day extension “for any delays not caused by the Seller”. Could Duke please clarify whether the Operation Milestone Schedule EOD is subject to the extensions referenced in the Operational Milestone Schedule exhibit?
Answer: The deadline for the Commercial Operation Date, as specified in Exhibit 3 (Operational Milestone Schedule), has a built-in extension provision for delays not caused by the Seller. If the COD deadline is extended in accordance with the operational milestone provision, the Seller would not be in default unless and until the extended date was missed.
2024-DOC 00029 Published On: 09/23/2024
Question: The covenants in Section 6.2 of the Solar Only PPA are subject to indemnification by Seller in addition to being EODs of Seller, but it is not clear whether the limitation of liability against consequential damages is applicable to these covenants. Could Duke please clarify whether the limitation of liability against consequential damages is applicable to the covenants in Section 6.2?
Answer: Section 22.2 makes clear that where no measure of damages is expressly provided, the obligor’s liability is limited to direct actual damages and that neither party is liable for consequential damages. Section 6.2 does not specify a measure of damages and therefore the limitations set forth in Section 22.2 are applicable.
2024-DOC 00028 Published On: 09/20/2024
Question: To clarify based on the response to 2024-DOC 00024, an Asset Transfer bid is able to leave the entire SOLAR PROJECT SPECIFICS (Technology) section blank?
Answer: 2024-DOC 00024 clarified that Asset Transfer proposals do not need to provide the 35 year energy (MWH) forecast and PVSyst report (rows Solar Only Bid form 281-318). Asset Transfer proposals are still required to provide answers to the inverter equipment included in the interconnection application, all other SOLAR PROJECT SPECIFICS (Technology) section inputs can be answered with “N/A” per the bid form instructions. BOT proposals are instructed to provide responses to all bid form cells within this section.
2024-DOC 00027 Published On: 09/19/2024
Question: Can you expand on line 210 of the of the UOT SPS bid input form: "Provide the Project's Investigation into the Availability of Communications Required for Transmission, Such as OPGW, Fiber (Dedicated or Third-Party)"? Specifically, which speeds, and which internet types should we screen our project areas for? Are you only looking for fiber for instance? Where can this information be obtained from?
Answer: For UOT projects specifically, DEC and DEP Transmission no longer accept third party telecommunications solutions and instead require all UOT projects to utilize Duke Energy-owned telecommunications, regardless of the project having an executed Interconnection Agreement or not at the time of bid submittal. For projects submitting interconnection requests into the 2024 RSC, the response to line 210 on the bid form should be “project being studied in the 2024 RSC”. For projects not submitting into the 2024 RSC and that have instead executed interconnection agreements, please address the project’s plan for communications including transmission transfer trip. Additional information for inverter based resources is available on OASIS https://www.oasis.oati.com/duk/index.html in the folder “Generator Interconnection Information\IBR Interconnection”.
2024-DOC 00026 Published On: 09/19/2024
Question: In the General section of the bid forms, does "Current Project Owner" refer to the ultimate parent owner(s) of the project?
Answer: Correct, as well as the direct owner.
2024-DOC 00025 Published On: 09/19/2024
Question: Our team had a question about the credit support requirements as it relates to the UOT bid track, please see below: Exhibit A-1 and Exhibit A-2 of Appendix J contemplate the terms of required Credit Support due by the Seller under following execution of either the APA or BTA. Conversely, Appendix K (APA) does not contemplate any such Credit Support requirements (whereas Article 9 of Appendix M (BTA) does include Credit Support for the BOT). Can you confirm that under the BOT, Credit Support will be required to be posted by the Buyer, but under the UOT, no such Credit Support will be required by the Seller following the execution of the APA? Alternatively, if there is Credit Support requirements for the Seller under the APA agreement, please provide the details of those requirements including the proposed language that would be included under the APA.
Answer: Under the APA, the Company does not require the Seller to post any credit support, whence executed. Under the BTA, the Company reserves the right to fully evaluate the credit worthiness of the Seller and any Parent entities to determine the credit support requirements, typically credit security under the BTA, whence executed will not be less than 35% letter of credit or parent guaranty. Under the BTA, typically Buyer credit support is not needed, considering the Buyer is the regulated utility (DEC or DEP).
2024-DOC 00024 Published On: 09/19/2024
Question: Can you confirm that Asset Transfer bids should leave the annual production part of the bid form blank since the Utility Ownership Team will develop and provide the IE with the proposal's energy production profile?
Answer: Correct, the Annual Plant Production (P50) subsection of the UOT Bid Input Forms can be left blank for Asset Transfer proposals. It is part of the SOLAR PROJECT SPECIFICS (Technology) section, which is not required for Asset Transfer bids.
2024-DOC 00023 Published On: 09/17/2024
Question: In the UOT Bid Form there is a space for confirmation of transmission interconnection station design. Can you clarify whether this is referring to the facility side of the POI or if this is referring to the utility side of the POI?
Answer: Bidders should provide detail whether the transmission interconnection station design is a tap station, ring-bus station, or an existing substation. The Utility Ownership Team needs to understand the design of the transmission substation so that a proper cost estimate can be developed and included in the Companies’ cost estimate to construct the proposed project.
2024-DOC 00022 Published On: 09/12/2024
Question: To clarify based on the updates to the PPA track bid forms made recently: The PPA PVsyst guidance sheet sets availability losses to 0%, but planned outage impacts still need to be included in PPA proposal production profiles despite not being contemplated in the guidance sheet, correct?
Answer: Correct.
2024-DOC 00021 Published On: 09/12/2024
Question: Item 9 in Exhibit A-2 of the LOI states that “Additional credit support, either in the form of a parent guarantee or letter of credit, will be required to secure the obligations of Seller under the APA…” Can Duke please provide more details on the amount and form of an acceptable parent guarantee or letter of credit referenced in this section of the LOI? Is this section referring to the LOI security of 3% of the asset price or is this an additional security amount?
Answer: The same letter of credit guidance is applicable to all 2024 RFP security requirements, although different letter of credit and parent guarantee templates may be appropriate based on the particular type of security required (i.e. security required pursuant to the RSC study process, PPA, or otherwise).
2024-DOC 00020 Published On: 09/12/2024
Question: Can you please provide a checklist of all the documents required for RSC and RFP submission for Solar-Only and SPS projects - specifically to PPA track? I could not locate an NDA document among the RFP document.
Answer: Please reference the Bid Input Forms, the documents required for the RFP submission are listed there. The NDA document is now posted at 2024-RFP-Documents (dukeenergyrfpcarolinas.com).
2024-DOC 00019 Published On: 09/12/2024
Question: Is there an NDA that should be signed for this year's RFP? The 2023 RFP had a specific NDA in the documents and there does not appear to be one for the 2024 RFP.
Answer: Yes, the 2024 NDA is now posted in the 2024 Documents linked here 2024-RFP-Documents (dukeenergyrfpcarolinas.com).
2024-DOC 00018 Published On: 09/11/2024
Question: Exhibit A-4 is called "PPA guidance PVsyst Parameters and Modeling Assumptions on the 2024 RFP: Documents page of the CRA website, but this document is only referenced in the UOT Bid Input Form. Should this guidance be used for the production profiles of PPA track bids as well? Furthermore, can you clarify whether planned outage impacts should be included in the PVsyst files for all bids, whether PPA track or UOT track, and if so, why is the availability loss set to 0% on the Exhibit A-4 guidance document (unless that guidance is only for UOT bids, indicating that UOT bids should not include planned outage impacts in their PVsyst files)?
Answer: All proposals must provide an energy production forecast. See RFP Document Section IX.C. As provided in 2024-DOC 00012, the PVSyst guidance provided in Appendix I (EPC Exhibit A-4) applies to both PPA Track and UOT projects. PPA Track bidders are expected to include their own outage assumptions into their energy forecasts; the energy forecast provided in the bid submittal will be used as the energy forecast in the PPA, if selected. Note also that UOT projects must ensure compliance with EPC Exhibit A-4, which will then be reviewed and evaluated by the Utility Ownership Team.
2024-DOC 00017 Published On: 09/10/2024
Question: In the Financial Information section of the RFP response form, there is a line for a Dunn and Bradstreet Identification Number. Does this number need to be tied to the specific project entity or would a Dunn and Bradstreet number from the project's parent company be sufficient?
Answer: If the project entity does not have a Dunn and Bradstreet number, such number should be provided for the project's parent company.
2024-DOC 00016 Published On: 09/10/2024
Question: In the UOT Bid Input Form, for the line item "Describe any Applicable Timber Rights and Impact to Construction," does this item pertain to 3rd party or non-landowner timber rights or claims that are of public record? Or, is this specific to any timber rights in the specific landowner agreements?
Answer: Any and all timber rights, whether held by a third party or granted to the landowner under a site control agreement, should be disclosed.
2024-DOC 00015 Published On: 09/10/2024
Question: In the UOT Bid Input Form, would you please elaborate on what is meant by "Are Any Site Control Agreements Contingent in Any Way?"
Answer: The Companies are looking for any site control agreement information and if it is contingent in any way. For example, contingent upon any specific events, or consents, or other series of events, including approvals, or milestones, pursuant to said site control agreement. Any and all information related to those contingencies should be disclosed.
2024-DOC 00014 Published On: 09/09/2024
Question: What is the target date for Asset Transfer track proposals to have fully executed acquisition agreements? The RFP document states the target date is December 31, 2024, but I am assuming that is a typo. The form Asset Purchase Agreement lists an executed IA as a Condition Precedent to closing, so it seems like the target date could not be before August of 2026.
Answer: The contracting deadline for Asset Transfer proposal is December 31, 2025. RFP Document section VII.F (first paragraph on page 31), should read “The Utility Ownership Track acquisition Proposals will have 30 calendar days to execute a LOI (provided as Appendix J), with a target date of fully executed asset acquisition agreements by December 31, 2025.” Not 2024. Yes, all UOT acquisition Proposals are required to have fully executed Interconnection Agreements as a closing condition under the definitive agreements.
2024-DOC 00013 Published On: 09/06/2024
Question: Could you please clarify if Solar Anywhere is acceptable for any of the proposal tracks?
Answer: Solar Anywhere is not acceptable. Please refer to guidance provided in FAQs 2024-DOC 00009 & 2024-DOC 00004. Meteonorm or SolCast are acceptable.
2024-DOC 00012 Published On: 09/06/2024
Question: Could you please clarify which proposal tracks these modeling requirements apply to: Exhibit A-4 – PPA guidance PVsyst Parameters and Modeling Assumptions?
Answer: The modeling assumptions document provides guidance for the PPA proposals and is required for the UOT proposals.
2024-DOC 00011 (revised 08/30/2024) Published On: 08/28/2024
Question: Can you confirm that production model meteorological data must be sourced from Meteonorm? Are alternate sources such as Solar Anywhere acceptable? Does this requirement apply to all tracks (PPA, UOT, BTO)?
Answer: Please refer to guidance provided in FAQs 2024-DOC 00009 & 2024-DOC 00004, available at www.dukeenergyrfpcarolinas.com/2024-FAQ/2024-Documents. Meteonorm or SolCast are acceptable. Solar Anywhere will not be acceptable.
2024-DOC 00010 Published On: 08/22/2024
Question: Is an electrical model required with the proposal submission? Where can I find more information on the model requirements?
Answer: For PPA proposals, review the "PPA guidance PVsyst Parameters and Modeling Assumptions" document, available at https://www.dukeenergyrfpcarolinas.com/2024-RFP-Documents.
2024-DOC 00009 Published On: 08/21/2024
Question: For the PVsyst requirements, is there a reason why the Meteo File Data Source changed from SolCast (DEC & DEP 2023 RFP) to Meteonorm (DEC & DEP 2024 RFP)? Last year, some bidders subscribed to SolCast solely to participate in the DEC & DEP 2023 RFP.
Answer: For Exhibit A-4 – Attachment – PVsyst Parameters and Modeling Assumptions: Based on Market Participant feedback from the 2023 RFP regarding the requirement to use a Meteo File Data Source service that requires a fee, Duke Energy reevaluated suppliers and found Meteonorm acceptable. Meteonorm weather files are available within PVsyst and require no additional subscription or financial burden. However, Duke Energy will still accept Solcast as an alternative weather source for purposes of the 2024 RFP.
2024-DOC 00008 Published On: 08/19/2024
Question: Regarding the UOT technical guidance discussed in Appendix I-1, can Duke confirm if the 100' project boundary setback includes the fence?
Answer: The 100’ setback is intended to denote a setback from the property line where equipment is typically not permitted or for general good practice not advisable to site. Project fencing is generally assumed to be allowable within this 100’ setback guidance.
2024-DOC 00007 Published On: 08/19/2024
Question: Are SLDs required to be stamped by a PE?
Answer: Yes, the single line diagram (SLD) provided should be a signed, stamped drawing.
2024-DOC 00006 Published On: 08/13/2024
Question: The Approved Vendor List (AVL) says that Sungrow inverters "may be considered if submitted as a cost alternative line item." Can you please explain what this means and how it should be done?
Answer: Sungrow inverters are currently an acceptable inverter supplier on the AVL on a project by project exception basis.
For Asset Transfer proposals, Market Participants are able to submit Utility Ownership Track proposals utilizing Sungrow inverters; however, the Utility Ownership Team reserves the right to require the Market Participant to change the inverter supplier to an AVL compliant supplier upon request.
For BOT proposals, Market Participants must submit a proposal utilizing an AVL compliant supplier (TMEIC or SMA); however, they may also provide a bid alternative with Sungrow as a “separate cost alternative line item.” Only one bid form is required, and the price difference should be clearly noted by the Market Participant. The Utility Ownership Team then has discretion to accept the bid alternative with Sungrow or not.
2024-DOC 00005 Published On: 08/12/2024
Question: Is a site plan required for projects submitting into the UOT Asset-Transfer track? If so, what are the site layout requirements? Are they all included Appendix I1? Will there be any forthcoming site layout requirements as seen in the '23 RFP Appendix I1?
Answer: Minimum technical deliverables for Asset Transfer proposals are provided in Appendix I-1. A site plan is not required, however, Market Participants are encouraged to include one in their proposal submittal if one is available.
2024-DOC 00004 Published On: 08/09/2024
Question: On subsection "C. PRODUCTION ESTIMATES" of section "IX. ADDITIONAL INFORMATION" of the "DEC DEP 2024 RFP Document", it is mentioned that all Proposals should see Appendix I in connection to the PVSyst requirements or specifications. However, on the RFP's website (https://www.dukeenergyrfpcarolinas.com > 2024 RFP: Documents), there is no such Appendix I. Could you please clarify which exact document Market Participants have to review in connection to the PVSyst requirements or specifications? Thank you!
Answer: For PPA track bids, the MP is responsible for the development and submittal of a proposal’s PVSyst production profile in accordance with the guidance included in the Appendix L – Solar BESS EPC Agreement Exhibits. Please see the 2024 RFP Document titled “PPA guidance PVsyst Parameters and Modeling Assumptions.pdf” taken from the Appendix L – Solar BESS EPC Agreement Exhibits and now available for MPs on the 2024 RFP Website.
Appendices I1-I4 apply to UOT bids only. For Asset Transfer bids, the Utility Ownership Team will develop and provide the IE with the proposal’s energy production profile. For BOT projects, the MP is responsible for developing and providing the PVSyst production profile in accordance with the guidance of Appendix I2.
2024-DOC 00003 Published On: 07/29/2024
Question: In the 2024 RFP, the title "C. REQUIREMENT TO BID SPS RESOURCES AS NEW SOLAR-ONLY" implies that SPS projects are required to also bid as solar-only. Is this interpretation correct?
Answer: Correct, all projects submitted in the 2024 RFP will be required to submit a solar-only proposal and may opt to also submit a solar-plus-storage proposal. This requirement is unchanged from the 2023 RFP.
2024-DOC 00002 Published On: 07/24/2024
Question: Will projects that failed to submit a NOIR by August 15 be disqualified from participating in the RFP?
Answer: No, respondents for projects will not be disqualified if they failed to submit the Notice of Intent to Respond form by August 15. Respondents are encouraged to submit this non-binding form by the due date.
2024-DOC 00001 Published On: 07/16/2024
Question: The RFP mentiones "Grid locational guidance identifying transmission constraints" will be available on the IE webiste. Where can I find that?
Answer: The grid locational guidance document is now available on the IE's website, https://www.dukeenergyrfpcarolinas.com/2024-RFP-Documents
2024-INT 00031 Published On: 10/30/2024
Question: If the Transmission Provider’s cost for the estimated network upgrades specified in the completed, executable version of the Interconnection Agreement is greater than 125% of the estimated cost of these network upgrades calculated during Phase 1 of the Resource Solicitation Cluster (the “Excess Network Upgrade Costs”), and the Buyer (Duke) exercises the right to terminate the PPA under Section 20.1.2, what happens to the pre-COD deposit posted by the Seller? What is the process including number of days to refund it to the Seller?
Answer: Pre-COD performance security for a PPA project is typically in the form of cash or a letter of credit. This security will be released by Duke Energy in the event the PPA is terminated due to excess network upgrade cost. The form of security will impact the timeline for its release. The companies will sign a Mutual Termination Agreement, and the release will be part of the MTA. Duke Energy will endeavor to return the security as soon as reasonably possible after the contract termination, but in no event later than the end of the Security Period set forth in Section 5.7 of the PPA.
As an estimate, a letter of credit release takes about 10 business days; a cash refund will take about 30 days.
2024-INT 00030 Published On: 10/14/2024
Question: If a market participant is shortlisted for Step 2, then the MP has to pay the proposal security and an M1 initial security deposit. The M1 Security is equal to $50,000 plus $1/KWAC for project size > 50 KWAC, and is paid by a market participant prior to the 2024 RSC Phase 1 Study. How does the market participant get this M1 security deposit back? In cash or is it applied towards other payments? When?
Answer: The RFP Document explains that all third party MPs that are invited to the “short list” and elect to move into Step 2 of the evaluation process must post Step 2 Proposal Security and that the M1 security applies to the calculation of the Step 2 Proposal Security. Section J(3) of the RFP Document explains the release of this security under a number of factual scenarios.
2024-INT 00029 Published On: 10/14/2024
Question: A study deposit of $50,000 plus $1/KWAC for project size > 50 KWAC is paid by a market participant as part of the application for 2024 RSC Interconnection Request. How does the market participant get this deposit back? In cash or applied towards other payments? When?
2024-INT 00028 Published On: 10/08/2024
Question: For an MP with a PPA track bid participating in the 2024 RSC, are the estimated POI related network upgrades such as Switching Equipment and Modify Relay and Communication Equipment to be included in the Part A/C or Part B/D bid price? The 2023 RSC Study Reports break out the network upgrades into several categories, POI, Remote End, Telecommunications, and Power-Flow Thermal; are only the Power-Flow Thermal Network Upgrades reimbursable through the Part B/D pricing or the Total Network Upgrades estimate from the study report?
Answer: Switching Equipment and Relay and Communication Equipment are considered network upgrades in most cases. For standard cost estimates please see “DEC DEP Standard Interconnection Cost Estimates” document posted June 28, 2024 at 2024-RFP-Documents (dukeenergyrfpcarolinas.com). The standard interconnection facilities costs do not include the network upgrade costs. Part B/D covers all items identified as network upgrades, not just thermal network upgrades. Accordingly, please include costs for System Equipment and Modify Relay and Communication Equipment in the Part B/D bid price. Please also see "DEC DEP 2024 RFP Document," Section VI.A (Proposal Pricing and Bidding - Controllable PPA Proposal Pricing), available here: 2024-RFP-Documents (dukeenergyrfpcarolinas.com).
2024-INT 00027 (revised 09/27/2024) Published On: 09/27/2024
Question: In the document “DEC/DEP Standard Interconnection Cost Estimates,” it states: "Estimates do not include financial multipliers or applicable sales tax. The Interconnection Agreement will identify the Customer's selection of financial arrangement—Monthly Charge or Total Prepayment—and the estimated costs for the financial arrangement." Our question pertains to the financial arrangements mentioned, specifically the Monthly Charge or Total Prepayment options. Based on our experience with LGIAs from prior procurement cycles, we’ve encountered the following scenarios:
For DEC:
For DEP:
This means the interconnection costs will be approximately 1.6 times than the provided estimated facilities costs. While this information has been included in Appendix 2 of previous LGIAs we've signed, we have not found this specific detail in any public documents related to this procurement. Given the significant financial impact this has on bidders' pricing, we believe it is crucial to have clear and up-to-date guidance.
We are confident that both Duke Energy and Charles River Associates aim to ensure all bids are submitted in good faith and based on consistent information. To that end, could Duke please provide Market Participants with the current and complete guidance on the available financial arrangements for both DEC and DEP?
Answer: Please see “Summary of Extra Facilities (2024 RFP).pdf” included on the 2024 FAQ Documents webpage. It provides the relevant interconnection facilities charge payment options that are currently available to NC and SC Interconnection Customers in DEC and DEP under applicable service regulations. The effective interconnection facilities charge payment options will be reflected in Appendix 2 of executed Interconnection Agreements. Please note that these payment options are subject to change based on order of the jurisdiction’s governing body (the North Carolina Utilities Commission or South Carolina Public Service Commission) and the payment options applicable to a Market Participant/Interconnection Customer will be based on the payment options that are effective at the time the Interconnection Agreement is tendered.
2024-INT 00026 Published On: 09/26/2024
Question: One question on RSC application. Is the “site control verification form” required for the application? All the GLAs of the project are valid and currently in diligence period, available to be uploaded.
Answer: Yes, site control verification is one of the requirements for the Interconnection Request to be considered complete. This is required by the close of the 2024 RFP bid window on September 30, 2024, see DEC DEP RFP Document, “Section V. RFP PROCESS, D. 2024 RFP-SPECIFIC RESOURCE SOLICITATION CLUSTER” available in the 2024 RFP Documents.
2024-INT 00025 Published On: 09/25/2024
Question: I am unable to identify in the SC Duke DISIS appendix of the transmission tariff, what contsitutes a material modifcation to a project. Specifically, are reductions allowed without penalty between Phase 1 and Phase 2 of the DISIS as non material modifications? Or at other stages?
Answer: Material Modification is defined in Appendix CS as follows:
A modification to machine data or equipment configuration or to the interconnection site of the Generating Facility that has a material impact on the cost, timing or design of any Interconnection Facilities or Upgrades. Material Modifications include project revisions proposed at any time after receiving notification by the Utility of a complete Interconnection Request pursuant to Section 1.3.3 that 1) alters the size or output characteristics of the Generating Facility from its Utility-approved Interconnection Request submission; 2) may adversely impact other Interconnection Requests with higher Queue Numbers, or may adversely impact another Interconnection Customer who is part of the same Cluster where the utility is implementing the Definitive Interconnection Study Process. In addition to the list of modifications to an Interconnection Request identified in the SC GIP that are not indicia of a Material Modification, a change in the point of interconnection to a new location or new voltage level, where requested by the Utility and agreed to by the Interconnection Customer pursuant to Section 5.3.6, is not a Material Modification.
Further information on what does and does not constitute a Material Modification can be found in Attachment 1 of the South Carolina Interconnection Procedures Glossary of Term’s definition of Material Modification.
2024-INT 00024 Published On: 09/23/2024
Question: For projects offered as Asset Transfer with an executed Interconnection Agreement, will Duke reimburse spent Interconnection costs outside of the offered Asset Transfer price or should these be included in the offer?
Answer: An Asset Transfer proposal with an executed Interconnection Agreement will be solely responsible for the cost of any Interconnection Facilities and System Upgrades assigned to it under its Interconnection Agreement and shall bid accordingly as participation in the 2024 RFP will not alter any contractual obligations included in the MP’s executed Interconnection Agreement.
The bid Asset Purchase Price should account for the bidder’s financial obligations under the Interconnection Agreement and the bidder should disclose how much of the bid Asset Purchase Price includes Interconnection Agreement costs, so that the Utility Ownership Team does not double count costs between the bid Asset Purchase Price and expected project costs for Interconnection Facilities and System Upgrades. Pursuant to the LOI and form Asset Purchase Agreement, yes, the bidder does get reimbursed for costs incurred under the Interconnection Agreement (i.e. cash deposits made to the Transmission Provider).
2024-INT 00023 Published On: 09/23/2024
Question: My question is about the generator power flow model in PSSE for a new large generation interconnection application with an inverter-based system. Should the PSSE load flow model be a test case (a simplified model provided by the inverter manufacturer), or should it represent the actual power plant we are submitting the application for?
Answer: Please see responses to FAQs 2024-INT 00015, 2024-INT 00019 and 2024-INT 00021.
2024-INT 00022 Published On: 09/23/2024
Question: Can you provide support on the RSC application? My main query is once I log in the portal, I am not sure which option to select within the Interconnection request for a SPS project. Should it be “NC/SC Distribution Greater then 20Kw”? Generally, which information is required in the application? Below are all the steps I have done so far. 1 Portal https://dukeenergy.my.site.com/ 2 Section “Interconnection Request” https://dukeenergy.my.site.com/s/interconnection-request 3 As application Type, which should it be? “NC/SC Distribution Greater then 20Kw” Or The other options available? 4 In general, what information is required for this application?
Answer: Please see the slides provided at the Pre-Solicitation Bidders Conference, they are located in the Stakeholder Materials (dukeenergyrfpcarolinas.com), starting at slide 14 there are screenshots to guide you through the RSC application on the Interconnection Portal.
2024-INT 00021 (revised 10/24/2024) Published On: 09/20/2024
Question: For a new large generation interconnection application with an inverter-based system, I found on your website that we need to submit the inverter and power plant controller models in PSS/E (*.dyr file). Could you please confirm if a plant model (*.raw or *.sav file) is also required?
Answer: A sample implementation test case shall be included.
2024-INT 00020 (revised 09/19/2024) Published On: 09/19/2024
Question: What do you want us to select below in the Battery Operation section in the Interconnection Application for an SPS project? Considering the fact that Duke on the offtake side is the one that controls the battery operations?
Answer: These fields are not relevant for projects in the RFP. Our recommendation is to “Dispatch” for the Modes of Operation and “Other” for the Control Narrative.
2024-INT 00019 Published On: 09/19/2024
Question: Do we need to submit a generator power flow model for each interconnection request?
Answer: Yes, PSSE models are required. For projects bidding as both SPS and Solar only, both PSSE models are needed. See 2024-INT 00015.
2024-INT 00018 Published On: 09/16/2024
Question: Can you confirm that if FERC approves the Order 2023-A Compliance filing, the readiness requirement to get into the Facilities Study (15% Network Upgrades) and the readiness requirement at IA execution (20% Network Upgrades) both need to be included in the price of the UOT proposal. Can you also confirm whether Duke accepts surety bonds as an acceptable form of credit for these readiness requirements? The Order 2023-A Compliance Filing seems to allow surety bonds, but the Duke Energy Policy on Security for FERC Generators on OASIS seems to contradict that.
Answer: As provided in 2024-GEN 00011 and 2024-INT 00013, all UOT proposals will also be responsible for completing the interconnection study process, including providing any study deposits (such as M4) and executing and maintaining an Interconnection Agreement, as well as providing any additional securities that may be required under such Interconnection Agreement, until the Interconnection Agreement is assigned to DEC/DEP at closing. If Duke Energy’s FERC Order No. 2023-A compliance filing is approved, FERC Interconnection Customers may provide surety bonds to meet the referenced readiness requirements as long as the surety bond is in a form reasonably acceptable to Duke Energy. To maximize the efficiency of this process, Duke Energy has developed a form of surety bond that is reasonably acceptable and will be provided to customers upon request. The Duke Energy Policy on Security for FERC Generators on OASIS is applicable to FERC Generators that progress through the interconnection process (after readiness referenced is provided) to LGIA execution. Please see 2024-INT 00006 for information on the readiness requirements.
2024-INT 00017 Published On: 09/16/2024
Question: As a follow up to FAQ 2024-GEN 00020, if the Seller makes the M4 payment deposit under the RSC process with DEP Transmission within 10 days after receiving the Facilities Study results. Following which, if the System Upgrade Costs in the executable version of the Interconnection Agreement are greater than 125% of the System Upgrade Cost (SUC) estimate in the RSC Phase I Study results, and Duke exercises the right to terminate the PPA under Section 20.1.2, what happens to the Interconnection Application under the RSC process? Does it continue under the RSC, and can the Seller proceed to execute the Interconnection Agreement? a. If yes, what are the potential offtake alternatives for the Seller? PURPA PPA and Corporate PPA sleeved through Duke's potential Green Source Advantage Choice. Any other alternatives? b. If no, will the project get withdrawn from the RSC as well and in that case, will the Seller get full refund of the M1 and M4 deposits made under the RSC?
Answer: In the unlikely event that Duke exercises the right to terminate the PPA under Section 20.1.2 subject to the facts provided in the question, then the Generating Facility cannot continue in the Resource Solicitation Cluster. In accordance with Section 4.4.2 of the NCIP and Section 5.3.2 of the SCGIP, where a Generating Facility is rejected in a Resource Solicitation Cluster Process administered separately from a Definitive Interconnection System Impact Study Cluster, the Generating Facility shall lose the Queue Position it held as part of the Competitive Resource Solicitation. Again, Duke believes such an event to be very unlikely. If such situation does arise, Duke will address refundability of the M1 and M4 deposits in accordance with the NCIP and SCGIP.
2024-INT 00016 Published On: 09/13/2024
Question: For FERC-jurisdictional IRs to the RSC, is the site control acreage requirement based on MWac or MWdc?
Answer: “Site Control Guidance – Eff 10.26.2023.pdf” is a site control acreage guidance document posted on the DEP and DEC OASIS sites, the values are based on MWAC.
2024-INT 00015 Published On: 09/11/2024
Question: Are PSSE standard library (generic) models and PSSE User-Defined models required as part of the RSC interconnection application submission (NC/SC State Interconnection) for the Controlled PPA track? Where can I find the PSSE modeling guidelines?
Answer: PSSE models are required. If the PSSE models are not included with the initial Interconnection Request submission, the interconnection study team will request them during the Customer Engagement Window as this information is required for the Resource Solicitation Cluster study performed by Transmission Planning. Sections 7h and 8h of the Inverter Based Resource Data Request form located on the OASIS site (Duke_Energy_Inverter_Based_Resource_Data_Request_Form_(DEC,DEF,DEP).pdf (oati.com)) provides guidance for inverter and reactive power PSSE modeling.
2024-INT 00014 Published On: 09/10/2024
Question: Could you please clarify and reference the section in the RFP documents where it says when are the i) Interconnection Request RSC study deposit, and ii) RSC “M1” Security; released or refunded?
Answer: In Appendix O Section I “e. Each Interconnection Request will require an RSC study deposit as established in Attachment K 4.1.2 of the LGIP, NCIP 1.5.1.2, and SC GIP Appendix Duke CS 2.1.” This deposit is made at the time of the application before September 30, 2024. M1 is an equivalent amount, and that payment is due in January 2025 for projects invited to Step 2 of the RFP. See RFP Document at Section X.J. Any refunds will be processed in accordance with Sections 6.3.3 of the NCIP and SCGIP, and Section 16.4 of Attachment K to the LGIP. The security payment will be refunded once all accounts are settled.
2024-INT 00013 Published On: 09/10/2024
Question: For a UOT track submission, should we anticipate the M4 Milestone payment to be included into our overall purchase price amount or will the M4 payment be allocated in the Interconnection Cost Reimbursement Payment?
Answer: Please refer to the guidance provided in 2024-GEN 00011 and guidance provided in the RFP Document and stakeholder sessions regarding payments and fees associated with the 2024 RFP. All UOT proposals will also be responsible for completing the interconnection study process, including all study deposits (such as M4) and executing and maintaining an Interconnection Agreement, including any additional securities that may be required under such Interconnection Agreement, until the Interconnection Agreement is assigned to DEC/DEP at closing of the definitive agreement. So yes, the bidder will be responsible for making the M4 payment. Bidders have been instructed that their bid pricing is inclusive of any interconnection study deposits, i.e. the Asset Purchase Agreement or Build Transfer Agreement purchase price.
2024-INT 00012 Published On: 09/09/2024
Question: Wanting to follow up and clarify the response to FAQ 2024-INT 00011: Will the RSC only accept state-jurisdictional requests?
Answer: The Resource Solicitation Cluster (RSC) is limited to projects participating in the 2024 RFP; both FERC jurisdictional and State jurisdictional projects may participate in the RFP and therefore submit Interconnection Requests into the RSC. For projects looking to be a Qualifying Facility (QF) and sell all of their output to Duke Energy sized 80MW looking to bid PPA Track, a State jurisdictional Interconnection Request application for NC or SC shall be completed for purposes of participating in the 2024 RFP. For projects greater than 80MW looking to bid into the Utility Ownership Track (UOT), a FERC jurisdictional Interconnection Request application shall be completed for purposes of participating in the 2024 RFP. The response to FAQ 2024-INT 00011 is clarifying that FERC jurisdictional projects not participating in the 2024 RFP shall submit Interconnection Request applications during the next DISIS window, and not into the RSC.
2024-INT 00011 Published On: 09/06/2024
Question: Understanding that FERC jurisdictional projects (80MW+) will be allowed to submit into the RFP via the UOT bid track only, will this also mean that FERC jurisdictional projects (80MW+) would be allowed to submit for an interconnection queue position during this RSC window?
Answer: No, the Resource Solicitation Cluster is open for Solar and Solar plus Storage projects participating in the 2024 RFP. The next opportunity to participate in the Definitive Interconnection System Impact Study (DISIS) begins January 1, 2025.
2024-INT 00010 Published On: 08/22/2024
Question: For FERC-Jurisdictional IRs, is there a requirement for ERIS vs NRIS? And if we choose NRIS on the IR, will there be a chance to switch to ERIS after Phase 1?
Answer: ERIS and NRIS are terms that are only applicable to the FERC-Jurisdictional generator interconnection study process. Market Participants submitting FERC-Jurisdictional bids (UOT only) into the 2024 RFP are required to request NRIS (Network Resource Interconnection Service) to deliver their full capacity and energy output to serve native load customers. The Large Generator Interconnection Procedures allow for a FERC customer to request both NRIS and ERIS studies, but the FERC-jurisdictional UOT winner(s) that proceed in the RSC and RFP will be required to have NRIS service.
2024-INT 00009 Published On: 08/09/2024
Question: Are Asset Transfer Proposals that are also bidding into the PPA track the only Asset Transfer projects that can submit State-Jurisdictional interconnection requests? Or could an Asset Transfer Proposal that is not also bidding into the PPA track follow the same path of going through the whole State-Jurisdictional process, terminating the State-Jurisdictional Interconnection Agreement, and then executing an LGIA?
Answer: Pursuant to Section IV.B of the RFP, PPA Track proposals must be sized over 20 MWac in DEC or over 40 MWac in DEP and up to and including 80 MWac, among other things. If a project is bidding a proposal into both the UOT Track and the PPA Track, and the project size is therefore between 20-80 MWac, the interconnection request (IR) submitted should be a state jurisdictional IR. Pursuant to Section IV.A of the RFP, projects bidding UOT-Track only and not also PPA Track must have a FERC-jurisdictional interconnection request under the Companies’ FERC Joint OATT Attachment K Large Generator Interconnection Procedures.
2024-INT 00008 Published On: 08/09/2024
Question: If an Asset Transfer Proposal were to be selected with a State-Jurisdictional IR, would the Market Participant be able to terminate the associated State-Jurisdictional Interconnection Agreement and execute the necessary LGIA without going through a re-study? Can you explain the process of converting the State-Jurisdictional IA to an LGIA?
Answer: If an Asset Transfer Proposal were to be selected with a State-Jurisdictional IR, the Market Participant would first work with the Utility Ownership Team to execute a letter of intent, followed by the definitive agreement (Asset Purchase Agreement (“APA”)). Then per the APA, the Market Participant is responsible for completing all interconnection studies and execution of an interconnection agreement (“IA”). The Market Participant will execute a State-Jurisdictional IA, which coinciding with closing under the APA, will be terminated and the Market Participate will execute a FERC-Jurisdictional IA. The FERC IA is then assigned to DEC or DEP at APA closing. The conversion of a State-IA to a FERC-IA must be commensurate with the sale of the project assets to the utility and is highly coordinated between the Renewable Integration Team, the Utility Ownership Team and the Market Participant. The Renewable Integration Team is the best resource for questions related to the interconnection agreement.
2024-INT 00007 Published On: 07/23/2024
Question: We reviewed the recently posted Locational Guidance document, which was very helpful. In the document, Duke stated that any additional generation in the Brunswick County region would cause additional, unacceptable limitations in the operation of the Brunswick nuclear generators. Moreover, the transmission solutions to fix these limitations would cost +$100 million. Can you confirm a rough radius of this region? If projects are +50 miles away, would they still trigger these upgrades?
Answer: The Brunswick limitation is for new generation connected directly to any of the 8 transmission lines connected to / coming out of Brunswick Plant. It is not a mileage radius around the plant.
2024-INT 00006 (revised 07/24/2024) Published On: 07/23/2024
Question: The 2024 RFP is scheduled to extend past Duke Energy's FERC O2023-A compliance filing effective date i.e. 11/1/2025. Will this RSC process be affected by these planned tariff changes? What are the changes expected for this RSC process?
Answer: If FERC approves the Order 2023-A Compliance filing with effective date 11/1/2025, FERC interconnection customers would have 60 days to comply with the order. If the 2024 Resource Solicitation Cluster (RSC) follows the same schedule as the 2023 RSC and a Phase 3 restudy is not required, then the 2024 RSC Phase 2 study would likely end in early November, 2025. The readiness requirements to move to Facilities Study would therefore be administered pursuant to the new Large Generator Interconnection Procedures (LGIP) effective 11/1/2025. The Order 2023-A Compliance filing includes a readiness requirement of 15% of the facility’s assigned Network Upgrade costs in order to move to the Facilities Study phase in the form of an irrevocable letter of credit, cash, a surety bond, or other form of security that is reasonably acceptable to Duke Energy. This financial readiness requirement is based upon a different calculation than the calculation included in the currently-effective LGIP.
2024-INT 00005 Published On: 06/27/2024
Question: If an MP is bidding SPS into the 2024 RFP, should they submit a Solar-Only interconnection request to the RSC including the SPS configuration documents (SLDs, site layouts, etc.) as attachments, or should they submit an SPS interconnection request including the Solar-Only configuration documents as attachments?
Answer: The MP should submit an SPS Interconnection Request during the Open Enrollment Window into the Resource Solicitation Cluster (RSC). The Interconnection Request submitted into the RSC must be for one generating facility and the facility can elect to bid as both solar only and SPS. One facility cannot bid multiple solar only and multiple SPS sizes or configurations. For additional information related to submitting an Interconnection Request in the RSC, please see Appendix O, Section I – “New Interconnection Request during 2024 RSC Bid Window”.
2024-INT 00004 Published On: 06/03/2024
Question: Will projects with an interconnection agreement from a previous DISIS be able to participate [in the 2024 RFP] without participating in the resource solicitation cluster? Or is the RSC required for all participants regardless of Interconnection status?
Answer: For eligibility requirements for the 2024 RFP, please see Section V. RFP Process, D. 2024 RFP-Specific Resource Solicitation Cluster of the RFP document, available at www.dukeenergyrfpcarolinas.com/2024-RFP-Documents.
2024-INT 00003 Published On: 05/20/2024
Question: In the 2024 draft RFP, under section B. Requirements specific to Solar Only Facilities, part (a) states that a project qualifies for the RFP if it has a “fully executed Interconnection Agreement with DEC or DEP and have participated in the serial interconnection study process.” Since a DISIS has been completed and projects might have an IA executed under that process, will the 2024 RFP amend the current language to include projects from earlier DISIS processes?
Answer: The Companies are not accepting projects in the 2024 RFP that have an executed Interconnection Agreement under a prior cluster study process.
2024-INT 00002 Published On: 04/19/2024
Question: Can you please confirm that projects planning to participate in the upcoming 2024 RFP and associated RSC should not enter into DISIS at this time?
Answer: Projects that plan to participate in the upcoming 2024 RFP will be required to participate in the 2024 Resource Solicitation Cluster (opening in August) and not the 2024 DISIS.
2024-INT 00001 Published On: 04/19/2024
Question: In the upcoming 2024 RFP if my project is selected as a finalist, but the RSC Phase 1 report indicates it would not able to reach commercial operation until after the RFP’s target time (presumably 11/30/2029), can my proposal decline the offer and have our proposal security refunded?
Answer: As currently contemplated, the Commercial Operation Date for 2024 RFP Winning Bids is November 30, 2029. Under the current version of the proposed 2024 RFP, a bidder may decline a winning bid offer and have their proposal security released if the 2024 RSC Phase 1 report indicates the project would have an online date past the assumed RFP target date (11/30/2029) due to network upgrade, contingent facilities, and interconnection facilities construction.