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Stage 3 Oahu RFP Questions & Answers

Hawaiian Electric (sometimes also referred to as the "Company") provides the answers below, based on the best information available at the time an answer is posted, which may not reflect the scope and requirements of the final RFP. Prospective Proposers should review this Q&A page periodically to check for updates, additions, clarifications and/or corrections to any of Company's prior responses. Each Proposer is solely responsible for reviewing the final RFP (including all attachments and links) and all responses on this Q&A page. Each Proposer is also solely responsible for thoroughly investigating and informing itself with respect to all matters pertinent to the RFP, the Proposer's Proposal, and the Proposer's anticipated performance under the applicable power purchase agreement. It is the Proposer's responsibility to ensure it understands all requirements of the RFP and to seek clarification if the RFP's requirements or the Company's requests or responses are not clear. Accordingly, a potential Proposer may not rely upon a prior response that may be clarified or corrected in a subsequent response. Efforts will be made by the Company to highlight subsequent clarifications and corrections to prior responses, but potential Proposers are ultimately responsible for monitoring this Q&A page and to inquire with the Company regarding any perceived inconsistencies or contradictory information. Finally, a Proposer's submission of information to the Company will not be independently confirmed by the Company. All Proposers must separately request confirmation of receipt of submitted information if desired by any Proposer.

Q1:

[Posted 5/23/22] Please provide clarification regarding the fuel storage requirement, as the requirements in Section 1.2.3 of the Oahu Stage 3 RFP and Section 14 of Attachment Y in the Draft Model Firm PPA (Oahu) do not match. Is the fuel storage requirement 47 days as stated in the RFP, or 30 days as stated in the Model Firm PPA?

A1:

The requirement for fuel storage on Oahu is 47 days, as stated in Section 1.2.3 of the Oahu Stage 3 RFP. The Draft Model Firm PPA (Oahu) will be updated to reflect the requirement of 47 days for fuel storage in the next filing of the Oahu Stage 3 RFP.

Q2:

[Posted 7/12/22] Please confirm if the treatment of hosting capacity in the Oahu and Maui Stage 3 RFPs will be the same as the Hawaii Island Stage 3 RFP.

A2:

Confirming that the treatment of hosting capacity in the Oahu and Maui Stage 3 RFPs will be the same as the Hawaii Island Stage 3 RFP.

Q3:

[Posted 8/16/22] May a third party manage the community benefits fund required by the Oahu and Maui Stage 3 RFPs?

A3:

Yes, it is acceptable to involve a third party to manage the community benefits fund, as stated in Section 4.4.2 of the Oahu and Maui Stage 3 RFPs.

Q4:

[Posted 8/16/22] Is an endowment fund for the lifetime of a project acceptable with respect to the community benefits package? The annual allocation of funds would be based on community needs at the time and thus could change yearly. This also ensures equitable and fair distribution across the community so that not one organization becomes reliant or expects to receive funds. If managed by a third party, the executor of the fund would provide an annual report justifying the fund disbursement.

A4:

This would be subject to the preferences of the host community and not determined by Hawaiian Electric.

Q5:

[Posted 8/16/22] Please provide an example of the use of a community benefit funding host, as referenced in Exhibit 1 of the May 2, 2022 filing.

A5:

Hawaii Community Foundation is an example of an eligible non-profit organization that has experience administering community benefit funding.

Q6:

[Posted 11/29/22] When will Hawaiian Electric be providing information on available transmission line capacity on Maui or Oahu?

A6:

Hawaiian Electric will provide information on available transmission line capacity on Maui or Oahu upon request and if such information is available. At this time, injection capacity information for the Stage 3 Oahu and Maui RFPs is not yet available. Injection capacity information will be available when the final Stage 3 Oahu and Maui RFPs are issued and will be publicly filed in Docket No. 2017-0352. If your team is interested in specific points of interconnection on Company-owned lines or substations, please provide the proposed point of interconnection and proposed project size (in MW). When providing the proposed point of interconnection, please provide a specific location (i.e., address, TMK number, etc.) in addition to a map of the parcel identifying the proposed point of interconnection. Once identified, the RFP team will review these proposed points of interconnection and notify you if there is enough capacity to host the proposed project.

Please note that the final version of the RFP will govern the scope and requirements sought in this RFP and will be issued after the PUC approves the Company's proposed final RFPs. The Company's response will be provided in the interest of time and therefore will only reflect the Company's current understanding. Accordingly, the response may not reflect the scope and requirements of the final RFP. It is incumbent upon Proposers to follow up with any additional questions if they believe differences in the final RFP may change the nature of their original question or the Company's response.

Q7:

[Posted 1/24/23] Three line diagrams required per the RFP would require extensive time above and beyond typical requests for a proposal. The Lanai and Molokai RFPs allowed three-line diagrams to be submitted within 30 days after selection of the Final Award Group. Will the Company allow a similar concession?

A7:

The RFP Appendix B Proposer’s Response Package Section 2.11.2 instructs Proposers to “provide all project single line and three line diagram(s) with the Proposal submission.” Single line diagrams are required with each Proposal response package. However, the Company will allow delaying the submission of its three line diagrams until after Final Award Group selection, but must be submitted within 30 days after notification to the Final Award Group.

Q8:

[Posted 2/6/23] Section 1.2.11 of the RFP states, “No single point of failure from the Facility shall result in a decrease in active power output measured at the Project’s POI greater than 142 MW.” Furthermore, Section 4.2, Item #11 states, “No single point of failure from the Facility shall result in a decrease of active power output measured at the Project’s POI greater than 142 MW.” However, the Oahu Stage 3 RFP Appendix B - “Proposer’s Response Package,” Section 2.0 Proposal Summary Table - Item #15 states, “The Proposer hereby certifies that no single point of failure from the Facility shall result in a decrease of active power measured at the Facility point of interconnection greater than 30 MW. (Yes/No)”. Please confirm the correct single point of failure.

A8:

The single point of failure for this RFP is 142 MW, as per Section 1.2.11 and Section 4.2, Item #11 of the RFP. The 30 MW noted in Appendix B, Section 2.0 - Proposal Summary Tables, Item #15 is incorrect.

The updated Appendix B (the only update being the single point of failure change to 142 MW) has been uploaded into Power Advocate and also to the Stage 3 Oahu RFP Documents webpage.

Q9:

[Posted 2/15/23] Please clarify if the community benefits package can be submitted as a work-in-progress if the Proposer is in ongoing discussions with established host community leaders and stakeholders to identify community needs and priorities. Are Proposers allowed to refine community priorities and CBP recipient organizations beyond Final Award Selection? As there will be many community outreach activities after award selection and leading up to project in-service dates of N.L.T. 2029 and 2033, ideally the package will continue to be developed as more input is gathered to ensure benefits are relevant and pertinent when projects are placed into service.

A9:

Yes, the Community Benefits package can be submitted as a work in progress, as communications with the community are expected to be ongoing, and community priorities may change. The Stage 3 Oahu RFP team will evaluate the proposed framework and process that will be used to meaningfully engage with communities in identifying needs and actions to support those needs. Proposers are allowed to refine community priorities and CBP recipient organizations beyond Final Award Selection.

Q10:

[Posted 2/15/23] What specific elements of the community benefits package (CBP) need to be included at bid submittal? E.g., Does the Proposer need to identify specific beneficiaries and how much is allocated to each and for what purpose at bid submission? Some items listed in the RFP seem premature if the Proposer is in ongoing discussions with community leaders and/or is not selected to the Final Award Group, beyond which public meetings are to be convened to receive input on the proposed CBP and the proposed project.

The RFP references “intended beneficiaries of the funds, including recipients and the area(s) in which the funds will be directed.”

The RFP also states that “preference will be given to Proposers who have:

  • Already identified established contacts to work with the local community,
  • Have used community input to incorporate changes to the final design of the Project and mitigate community concerns,
  • Have proposed a community benefits package (including details of the community recipients and benefits package), OR
  • Have community consultants as part of the Project team doing business in Hawaii that have successfully worked with communities in Hawaii on the development of two or more energy projects or projects with similar community issues.
  • These criteria are aligned with the Company’s community engagement expectation whereby all developers will be required to engage in community outreach prior to signing a Stage 3 Contract 47 with the Company. This process is also outlined in RFP Section 5.3. Further information and instructions regarding expectations for the Community Outreach Plan are included as Attachment 5 and 6 to Appendix B.”

A10:

The specific beneficiaries, funds to be allocated to each, and for what purpose, is not required to be included at bid submittal. The further along a Proposer is in the process of developing its CBP, the higher its CBP will be rated in the evaluation. Please see Appendix B, Section 2.8.1 for specifics on the Community Benefits Package.

Q11:

[Posted 2/16/23] HECO has provided indicative hosting capacity for various 46kV feeders. Given that the auxiliary power will likely be sourced from a point of connection identical to or in close proximity to the feeder accepting the project output, should developers interpret that hosting capacity to reflect the gross (nameplate) output of the proposed asset, or net (gross less auxiliaries)?

A11:

Proposers should compare the available hosting capacity using the net output from the proposed asset. Proposers must also keep in mind that interconnection studies are still required to determine the full extent of mitigation required, if any.

Q12:

[Posted 2/16/23] Within Appendix H, there are references to attachments in which only Attachment 1 is labeled. The remaining pages following Attachment 1 do not indicate Attachment number. May we please request you update the Appendix with the appropriate referencing and resend?

A12:

An updated Attachment H file, which includes the Attachment numbers on each page, has been uploaded to the Stage 3 Oahu RFP Documents page.

Q13:

[Posted 2/27/23] Appendix B Section 2.10.1.1 notes “For Generation Facilities, provide the projected hourly annual energy potential production profile of the Facility14 (24 hours x 365 days, 8760 generation profile) for the provided RFP NEP Projection.” NEP projection is for renewable variable only?

A13:

Yes, requirements around NEP projection only apply for renewable variable projects, not firm.

Q14:

[Posted 2/27/23] Appendix B Section 2.10.1.2 notes “Provide the sample rate of critical telemetry (i.e. frequency and voltage) based on inputs to the facility control systems.” Please provide a definition of this sample rate as no reference of the same is made in the RFP or firm PPA.

A14:

The sample rate of telemetry is the rate at which the company’s SCADA equipment/RTU would be able to poll and receive data from the facility.

Q15:

[Posted 2/27/23] Appendix B Section 2.10.1.3 notes “Provide a description of the Facility’s capability to be grid-forming and have black start capability.” Please clarify whether grid-forming is applicable to firm generation and if so, how.

A15:

In the performance standards, “Grid Forming” is intended to describe a behavior from inverters to simulate the innate support response from synchronous machines. For synchronous machines, the additional synthetic “Grid Forming” requirement is not needed.

Q16:

[Posted 2/27/23] Appendix B Section 2.10.1.4 notes “Provide the explanation of the methodology and underlying information used to derive the Project’s NEP RFP Projection, including the preliminary design of the Facility and the typical meteorological year file used to estimate the Renewable Resource Baseline, as required in Article 6.6 of the applicable model Stage 3 Contract. The explanation of the methodology should include, but not be limited to, the long-term resource data used, the gross and net generation MWh, and assumptions (loss factors, uncertainty values, any grid or project constraints).” NEP projection for renewable variable only?

A16:

Yes, requirements around NEP projection only apply for renewable variable projects, not firm.

Q17:

[Posted 2/27/23] Appendix B Section 2.10.15 notes “Active Power Control Interface: Describe the means of implementing active power control and the Power Possible, including the contribution to the dispatch signal from paired storage, if any. Provide the Proposer’s experience dealing with active power control, dispatch, frequency response, and ride-through.” Please provide a definition of ‘power possible’ and advise if this applies to firm generation.

A17:

Power Possible is the maximum amount of power that the facility can produce at any time and may also apply to firm generation. For example, for combustion turbines environmental conditions such as high ambient heat and humidity may limit the power the generator can produce. Power possible should reflect these limitations.

Q18:

[Posted 3/3/23] Is there capacity on the Wahiawa-Mililani 46kV line?

A18:

No, there is zero capacity on the Wahiawa-Mililani 46kV line. The Company has identified this 46 kV line as a conflict to the system’s single point of failure criteria. The currently installed generation in this area (at 138 kV) already exceeds the single point of failure requirement, and adding generation downstream of the 138 kV lines will add to this impact. This is an update to the information provided in the 46kV Hosting Capacities summary (Exhibit 16, filed in Docket No. 2017-0352 on January 20, 2023).

Q19:

[Posted 3/7/23] Section 8.1 of the Stage 3 model PPA form includes this term: “Because the Facility must be available to respond to Company Dispatch, neither the Seller nor the Facility may consume any energy generated by the Facility.” This implies that Seller must service all auxiliary loads for the PV/BESS inverters and BESS cooling system using energy from the grid at the retail rate of power (instead of self-servicing at the cost of power generated by the Facility). If this is the intent then Bidders should be notified as such. Alternatively, if this term should be read to imply a restriction only with respect to the energy made available as part of the Facility, but an overbuild for auxiliary load servicing is allowed under the PPA, then this should be clarified.

A19:

In the Stage 3 Hawaii RFP's Q&A, the Company tried previously to clarify its intention on that sentence within the RFP Appendix J RDG PPA Article 8 stated above. The Company clarified the intention is to procure projects designed to provide full dispatch of contract capacity to the Company at the POI under all operating conditions within the facility. The Company expects that the project Contract Capacity and/or BESS Contract Capacity take into account serving its auxiliary and station load needs of the facility so that the committed capacity shall be met at all times without reductions while serving the facility needs. Because the sentence in Section 8.1 continues to cause confusion, it can be lined out when submitting proposed modifications in the Microsoft Word red-line version of the RDG PPA. The Proposer is reminded that the Project must still meet all other terms of the RDG PPA. To the extent the Project does use energy from its facility for auxiliary and station load needs, the plant should be sized accordingly to account for such even during low production periods. And as covered in Article 2.14 Sales of Electric Energy by Company to Seller of the RDG PPA, sales of electric energy by Company to Seller shall be required to be paid for and governed by an applicable rate schedule filed with the PUC.

Q20:

[Posted 3/13/23] If proposers are proposing projects that will interconnect to a 46 kV line, can they propose a project that is higher than the available MWs shown in the 46kV hosting capacity summary?

A20:

Per section 1.2.10 of the RFP, all proposers must inquire about the transmission line available MW capacity or substation conditions. If a proposer is interested in interconnecting to a 46 kV line, and the proposed project is larger than the available MW capacity per the 46kV hosting capacity summary, Hawaiian electric can assist the proposer by looking into the viability of (1) upgrading the 46 kV line in order to increase capacity, or (2) by assessing the proposed project size at the proposed point of interconnection, which may impact the available capacity amount.

Q21:

[Posted 3/22/23] Can Hawaiian Electric begin engineering during the IRS phase, before execution of a contract?

A21:

Hawaiian Electric will offer early engineering. If Proposers elect to engage in early engineering, a written commitment will be required at the time of final award group selection and upfront payment for early engineering work will be required. As early engineering will be done in conjunction with the IRS, all early engineering work will be done at the developers risk. Early engineering will commence with a preliminary Facility Study to identify scope of work, assumptions and responsibilities (separate and prior to the final IRS Facility Study). Early engineering will also include Company review of engineering design, and other project support, associated with the Company Owed Interconnection Facilities.

Q22:

[Posted 3/23/23] The introduction to Appendix B, Attachment 3 states, "This document summarizes requirements of generation facility technical model submittals for request for proposals for variable renewable dispatchable generation and energy storage and describes the review process for model submittals." Is Appendix B Attachment 3 applicable for Firm project as well?

A22:

Yes, Appendix B, Attachment 3 applies to all projects, including firm.

Q23:

[Posted 3/24/23] What are the Notices and Limitations of the interconnection information provided to potential proposers, by Hawaiian Electric, prior to bid submission?

A23:

Proposers should be advised that the Stage 3 Oahu specific information provided to proposers are subject to the following limitations and notices. Please note that these Oahu specific limitations and notices have been updated, and may not be the same as past limitations and notices that were distributed.

  1. Capacity limits are interdependent and assume no additional new generation at the other substations/lines.
  2. New individual generators (or N-1 contingency) should not be larger than the existing largest loss of generation contingency or the SPOF on Oahu Island (142 MW).
  3. The substation capacity limits are dependent on specific resource scenarios assumed in the 138 kV injection study. The 46 kV and 138 kV circuit capacity limits are dependent on specific resource scenarios assumed in the 138 kV injection study, and the 46 kV analysis.
  4. Capacity limits can be impacted by other resource procurement RFPs, separate from the Stage 3 Renewable Dispatchable Generation Procurement RFP.
  5. Any system upgrade information to increase substation or circuit hosting capacity is subject to change based on the results of the IRS.
  6. Capacity limits are based on conductor thermal ratings (normal and emergency ratings) applied in normal and contingency scenarios from preliminary load flows.
  7. Capacity limits are subject to change if more than one project is awarded. New capacity limits may be identified during the detailed evaluation phase of the RFP and final mitigation requirements will be determined in the system impact studies.
  8. For firm generation proposals, synchronous generators require a minimum of 1 phase Line PT for synch check. Inverter-based generation requires 3-phase line PTs for synch check.
  9. As part of the selection process, additional load flow analyses will be performed that could evaluate multiple projects that interact with each other and potentially reduce the available capacity at the identified substation or transmission/distribution lines. A detailed Interconnection Requirements Study, when performed, may identify system impacts that limit the project’s ability to interconnect and/or further limit the net output of a project without upgrades. The Company does not guarantee any project output or ability to connect based on information provided prior to the completion of an IRS.
  10. Proposers should familiarize themselves with the information offered in Appendix H of the RFP. Additional upgrades may be identified as necessary in the IRS.
  11. While Company has endeavored to provide more information into potential costs associated with interconnection, Proposer must still complete its own due diligence on other potential costs/expenses associated with interconnecting its project to the Company’s system, including but not limited to, acquisition of land rights, including easements and rights of entry, the status of existing lines and poles and the ownership thereof (all are not necessarily Company-owned) and physical site limitations. Proposer is encouraged to engage in the process early and ask questions where the Company may be involved or have an interest in the issue.

Q24:

[Posted 3/31/23] If a plant has more than one fuel supply option, or multiple potential combinations for fuel supply, does describing the options count towards the proposal variation count?

A24:

While different fuel options and/or combinations may be described within a singular Proposal, if such different fuel supply options and/or combinations affect the Proposal’s pricing terms, facility size, or GCOD, a separate variation must be submitted. So long as the Site and generating technology are the same, only one Proposal Fee is required to be submitted for up to three variations of the Proposal, one of which being the base variation of the Proposal. Variations which propose a different generation technology or Site, however, will be deemed a separate Proposal, and a separate Proposal Fee must be paid for each such Proposal.

Q25:

[Posted 3/31/23] Please clarify the 7-day vs. 14-day fuel requirement if there is a pipeline built to the site. If a pipeline is built, does additional offsite fuel storage need to be procured/ reserved, or does access to a gas utility's fuel supply network, via the pipeline, in itself meet the requirement of the RFP?

A25:

Per section 1.2.3, "If offsite storage connected via pipeline is utilized, or is otherwise immediately accessible, the on-site requirement can be reduced to seven (7) days of 16 hours of Full Load operation with the additional 7 days off site. In no event will there be less than seven days of fuel (based on 16 hours of operation) available on site.” The requirement to have 30 days of fuel may include the 7 days of off-site fuel. In other words, you may have 7 days worth of fuel stored on-site, and 23 days worth of fuel stored off-site. For those Proposals with a generation component operating on fuel, Proposers will need to commit and (except for biofuel proposals) provide evidence, which may take the form of contracts, that the fuel will be secured for the duration of the Firm PPA term.

Q26:

[Posted 4/13/23] Why is there no hosting capacity at Kalaeloa Substation when there previously was 140 MW?

A26:

As outlined on Page H-10 of Appendix H in the May 2, 2022 Draft Stage 3 Oahu RFP, capacity at the Kalaeloa Substation will only be available if new generation will be replacing the existing IPP generation that is currently interconnected to this substation. However, the existing IPP entered into a new 10-year Power Purchase Agreement, which will render zero available capacity for new interconnection until November of 2032. Should a proposer plan to propose a replacement project (e.g., new generating resource) connecting to this point after November 2032, the maximum capacity for a replacement generating resource is limited to the single point of failure (142 MW), and would be re-evaluated and confirmed in the bid evaluation.

Q27:

[Posted 4/17/23] Can you please clarify the requirement to include biofuel pricing in a proposal? The RFP states that, "Proposals operating on biofuel do not need to include the cost of biofuel in their Proposal cost, but those Proposals must provide a biofuel price forecast. The Proposal will not have to guarantee the biofuel forecast pricing..."

This language is seemingly contradicted in Attachment J of the PPA, which states that "Fuel Component = Fuel Component [BASE] x [fixed escalation rate]." To us, this implies that we would be held to the BASE x escalation rate, which is inconsistent with the language in the RFP. Unless, the above statement in Appendix J applies only to Non-Biofuel fuels.

Can you please clarify?

A27:

The Fuel Component formula in Appx J of the PPA is incorrect. The revised Fuel Component calculation (for biofuels only) should be "Fuel Component = Fuel Component Base x [escalation rate]".