Selling Power to the Utility

Stage 3 Hawaii 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.


[Updated 4/20/22] The draft RFP filed on October 15, 2021 identified a Technical Status Conference on October 29, 2021. Did that status conference occur?


A virtual community meeting was held on October 28, 2021. Its recording can be viewed on YouTube at this link: virtual community meeting. A virtual Technical Conference was held on April 14, 2022 as proposed in the March 18, 2022 filing of the 2nd draft of the Stage 3 Hawaii RFP. A recording of the Technical Conference has been posted to YouTube for those who might have missed it or wish to view it again.


[Posted 4/20/22] Are you able to point out the location of the two substations identified in the 1st draft of the RFP as potential points of interconnection? They were the Puueo and Kanoelehua substations.


The Puueo substation is located on TMK: 326007001. The Kanoelehua substation is located on TMK: 322058019. The substations take up only a portion of the TMK parcels, with other structures occupying other parts of the parcels (e.g., power plants). The TMKs and these aerial images should assist you to locate where the substations reside on the TMKs. Both substations are in the Hilo area.

Puueo Substation

Puueo Substation

Kanoelehua Substation

Kanoelehua Substation


[Posted 4/20/22] For Keamuku substation, for the transmission and fiber line relocations from existing site to the new site (3 line relocations) – is there a layout for these configuration changes showing where the lines are being realigned to and where the substation is being relocated?


At the Technical Conference, the presenter reiterated the Keamuku SLDs (attachments 7-9 of Appendix H) would not be ready until the next draft of the RFP. However, this high-level layout was shared in the presentation:

Appendix H

Please note the exact layout is subject to change based on where the new substation is located.

  • For one gen-tie line, the initial buildout of the substation will be a 3-bay, 9-breaker breaker-and-a-half (BAAH) substation with space to expand to a 5-bay, 15-breaker BAAH substation in the future.
  • For two gen-tie lines, the initial buildout of the substation will be a 4-bay, 11-breaker BAAH substation with space to expand to a 5-bay, 15-breaker BAAH substation in the future.
  • For three gen-tie lines, the initial buildout of the substation will be a 4-bay, 12-breaker BAAH substation with space to expand to a 5-bay, 15-breaker BAAH substation in the future.

The costs in Appendix H assume the new substation is built adjacent to the existing substation but the Company has no land rights in the area so it is upon the Proposer to propose a new site for the substation. Sites that are not adjacent to the existing substation may have higher costs for the line relocations. Proposers can use the information in Section 2.3 of Appendix H to estimate the Company costs for supporting the Proposer-build line relocations/extensions if the substation is not located adjacent to the existing substation.

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.


[Posted 4/20/22] Are both CBRE and Stage 3 Hawaii projects able to co-exist on a single substation (subject to impact studies and appropriate mitigations and overall available MW capacity)? Will substations that have existing solar interconnected along its distribution lines, either behind-the-meter or direct-tie like CBRE, have any impact on the amount of solar capacity that can interconnect at the transmission level of the substation?


CBRE and Stage 3 projects may co-exist on single substations subject to the detailed analysis required to fully study the impact of projects on the networked transmission and distribution systems. Yes, in general, all generation affects the power flows on the interconnected grid, regardless of location. The amount of generation connected to the distribution-side of the substation will determine the level of impact to capacity on the transmission lines. This must be analyzed on a case-by-case basis. The relationship between amount of generation connected to distribution and the amount of capacity on the transmission lines is not correlated one-to-one, due to the nature of the interconnected grid, and is dependent on specific locations and circumstances.


[Posted 4/26/22] In the technical conference it was mentioned that now HELCO is looking for 65 MW on big island which 60 MW of it should be on the Hilo side. Does it mean that only 5 MW will be awarded to the projects on the west side?


Not necessarily, the Stage 3 target of 65 MW is derived as the capacity needed to meet target energy reserve margin requirements for the entire system, whereas the east-side target of 60 MW is an active power capacity target intended to balance generation on the east and west side of the island and support cross-island transmission stability. In short, a portfolio of resource(s) that are equivalent to 200-325 GWHs annually are likely to also fulfill the 65 MW active power capacity target, and the total active power capacity of the portfolio of projects may actually be more than 65 MW, assuming all or a portion are fulfilled by non-firm resources. Conversely, a 65MW firm resource could have the ability to fulfill both the energy and active power capacity need.

The east-side target of 60 MW is an active power capacity target meant to supplement the island’s existing geographically balanced generation resources and result in a balanced distribution of future generation between East and West Hawaii. Approximately 60 MW is sought on the east side of Hawaii to 1) provide needed voltage support to East Hawaii, and 2) bring the available resources in East and West Hawaii into balance providing resiliency by diversifying locations of these critical resources.


[Posted 4/26/22] What happens if the proposals submitted for the east side do not add up to 60 MW? Does HELCO award the balance of 65 MW to the projects sited in the west side?


Not necessarily. Again, the company seeks to acquire the energy and capacity targets to meet target energy reserve margin needs for the entire system from all resources connected to the system, east and west. The company will strive to acquire the active power capacity desired on the east side, understanding the envisioned future portfolio shows this east side system need. This east side need will not necessarily limit the active power capacity added to either side of the island, as all resource additions will contribute to the annual energy target and overall system capacity needed to meet the energy reserve margin targets.


[Posted 4/26/22] The high-level map provided also shows 34 kV lines. Does that mean that developers are allowed to interconnect to 34 kV lines as well?


No, as stated in 1.2.9 of the RFP, Projects must either interconnect to the Hawaii Electric Light System at the 69 kV transmission-level via the transmission lines identified in Section 2.2.1 or via one of five existing Company substations the Company will offer available space at. On the high-level map provided, the allowed interconnection locations are depicted in red (and called out in the figure’s legend). Other lines, generating stations, or substations were shown for locational reference only.


[Posted 5/20/22] Would you please provide us with the capacity available on every one of the transmission lines and substations?


Consistent with the degree of specificity required pursuant to Section 2.2.1 of the RFP, in order to provide the requested available MW capacity information, the Company requires you to identify the specific location(s) of each point of interconnection at which you propose to interconnect your project(s).


[Posted 5/20/22] In Section 4.3 Threshold Requirements, Item 7, it says, “…at a minimum, Proposers must conduct and provide an Archaeological Literature Review of existing cultural documentation filed with the State Historic Preservation Division and a Field Inspection Report which identifies any known archaeological and/or historical sites within the project area. If sites are found, Proposers must provide a plan for mitigation from an archaeologist licensed in the State of Hawaii. An Archaeological Literature Review and Field Inspection Report should ideally be submitted at the appropriate Proposal Due Date in Table 1. However, if it is not submitted with the Proposal, these must be submitted three weeks before the Selection of Priority List date in Section 3.1, Table 1. Please confirm that a mitigation plan will not be expected at the time of bid and that an Archaeological Literature Review and Field Inspection prepared by an expert in the field will suffice to fulfill Threshold Requirement Item 7.


The purpose of this request is to clearly show that the developer is serious about archaeological and cultural resources of the proposed project site. Clarification – the Archaeological Literature Review done by the Proposer or their consultant does not need to be filed with the State of Hawaii Preservation Division (“SHPD”) for review or approval. The Archaeological Literature Review is essentially a summary of and reference to the existing cultural documentation previously filed with SHPD.

Having done a Field Inspection Report, if sites are found, we would expect there would be recommendations by the Archaeologist consultant for mitigation efforts. The evaluation team would like to review how the developer would mitigate or approach the project knowing archaeological and cultural discoveries were found in the literature research and/or field investigations that are present on the project site. The strategy to mitigate archaeological and cultural concerns are important to the success of the project.

If a full mitigation plan is not included in the Proposal, having some discussion of a plan for mitigation will score higher than a proposal with no plan for mitigation.


[Posted 5/20/22] Please provide information on transmission lines or substations not offered in the RFP.


The Company does not find it productive to respond to questions on portions of the system that are not being offered for interconnection.

The Company invested resources to conduct studies to identify those certain transmission lines and substations which would provide the least burdensome interconnection to prospective proposers. The Company has identified the transmission lines and substations in the RFP to streamline the process, and are now entertaining questions from prospective proposers to identify the available MW capacity at specific points of interconnection on those lines/substations.

Points of interconnection not on those transmission lines or substations are expected to incur significantly more structural investments for interconnection. Should a prospective proposer nevertheless choose to interconnect to a line or substation not identified in the RFP, the Company is open to discussing the construction impacts of new infrastructure (e.g., constructing a new line at the prospective proposer’s cost) that will be necessary to accommodate their interconnection location when specifics of their project are shared. However, in alignment with prior feedback received to streamline the interconnection process, the Company strongly encourages bidders to utilize the interconnections to the offered lines and substations for this RFP. Bidders have the added benefit of having more information on these points of interconnection with remote substation requirements that can be provided for line interconnections, and site-specific single-line diagrams for substation interconnections.


[Posted 5/20/22] Please provide criteria requirements and definition of single point of failure for projects >30MW. Can gen-ties be routed on the same double circuit/triple circuit structures? If yes, any requirements to structure type. If no, what separation do structures have to have if in same corridor? Any firewall requirements between transformers in the same substation fence in terms of single point of failure?


Single point failure for RFP projects means any failure that happens inside the RFP project and at the project’s point of interconnection shall not cause net active power reduction measured at the point of interconnection greater than 30 MW. It is the Proposer’s responsibility to determine how to design their facilities to meet the single point of failure criteria. However, it would be a violation of that criteria if the gen-tie lines on a shared structure carry more than 30MW in total.


[Posted 6/2/22] If a proposed 30 MW project is interconnected to a point of interconnection with 20 MW of available MW capacity, can the additional 10 MW be shifted with longer than 4 hour duration storage to comply with the transmission line’s available MW capacity limitations?


A project proposing to a point of interconnection with an available MW capacity of 20 MW cannot have a contract capacity more than 20 MW as the company needs the flexibility from its procurements to export the full contract capacity from all procurements, to support reliability, adequacy of supply and resilience. For a paired generation with energy storage project, the storage must be a minimum of four times the net nameplate capacity. Additional storage may be offered for increased duration, but the Company will not allow the installation of additional generating capacity to increase the contract capacity beyond the identified point of interconnection’s available MW capacity.


[Posted 8/26/22] In Order 38479 issued on June 29, 2022, the PUC stated on page 24 that the “Commission does not find it reasonable to restrict interconnection to certain substations or transmission lines if the option exists for a proposer to include the cost of transmission network upgrades into their proposal.” On page 25 the Commission also states, “The Commission so orders the Companies to clarify whether the available sites are recommendations or requirements for interconnection of the project.” Please clarify whether Proposers can seek interconnection to transmission lines or transmission substations outside of the 18 transmission lines and 5 transmission substations offered in the May 31, 2022 draft of the RFP.


In the Stage 3 Hawaii RFP drafts submitted thus far, the Company intended the eighteen (18) offered 69 kV transmission lines and five (5) offered substations to be requirements for interconnection of a proposed project. In its February 25, 2021 response letter to the PUC’s letter to begin development of a Stage 3 RFP for Hawaii island, the Company proposed ways to streamline the procurement and interconnection process in this next RFP. Consistent with that objective, a way to provide Proposers with more upfront information, is to identify existing substation sites for interconnection and exclude sites requiring major transmission upgrades. This focused approach provided the Company the ability to execute a capacity analysis of the allowable interconnection locations and provide more timely and detailed information to Proposers than was available in the Stage 1 and Stage 3 RFPs. Further, the known interconnection locations allowed the Company to pre-identify remote substation requirements, which is typically identified in the Facility Study phase of the Interconnection Requirement Study. Focusing the interconnection location variables would also streamline the evaluation stage by preventing overly expansive combinations of portfolios for evaluation.

However, in Order 38479, the Commission states that it “does not find it reasonable to restrict interconnection to certain substations or transmission lines if the option exists for a proposer to include the cost of transmission network upgrades into their proposal.” Other potential Proposers have also commented on and submitted requests for the desire to pursue interconnection at other non-offered locations on the Company’s transmission system. The Company will, therefore, make the offered transmission lines and transmission substations identified in Section 2.2.1 recommendations for interconnection. But the Company will allow Proposers to propose interconnection to other 69 kV transmission lines and 69 kV substations as long as Proposers include the cost of transmission network upgrades into the Proposal as the Commission states. Proposers should be aware, however, that there will be less upfront information available for 69 kV transmission lines and 69 kV substations not offered in the RFP. Also, estimated costs available in Appendix H are customized for the offered transmission lines and substations, and might not capture all the cost estimates necessary for other transmission lines and substations. In addition, the timeliness to requests for information outside of the offered lines and substations will likely require more time to gather and the level of detail available will be less, posing increased risk of uncertainty for those choosing to interconnect to other non-offered locations.


[Posted 9/1/22] Why is HECO reverting from the way it allowed developers in the Stage 2 RFP to calculate NEP RFP Projection?


This RFP is intended to better clarify the NEP RFP Projection in order to receive proposals that are consistent in terms of proportion of storage to installed capacity and avoid imbedded assumptions regarding company dispatch in the NEP. The prior RFP instructions led to various interpretations and incorrectly including generating capacity production in excess of contract capacity. The intent of the NEP is to commit the net energy potential of the generation facility at the point of interconnection, without requiring any assumption on dispatch and use of storage. It instructs that the NEP is to include all generation assuming it is able to be provided to the POI. The storage has no impact on the potential to generate energy. The storage benefit is calculated in the production model which will model the ability to defer energy export to periods of higher demand, if the System is not able to take energy at the time of production. The storage sizing must be a minimum of four hours duration at net nameplate capacity. If all the generating capacity is declared and committed to by the Proposer, i.e., the net nameplate capacity is equal to the contract capacity, and all energy from that equipment is assumed to be made available at the POI, then the inclusion of storage would make no difference to NEP. The NEP RFP Projection would differ from including storage only if the Proposer is assuming some net nameplate capacity is not capable of exporting directly to POI, and there is a built-in assumption that excess capacity can be shunted to the storage – a dispatch assumption. The proposed 8760 hourly generating profile should not include values outside of solar production hours as again, the dispatch and use of storage will be derived from the modeling and is not to be assumed in the NEP. The use of storage to defer production from the generating equipment will be determined by the dispatch model, and not an input assumption by the Proposer.


[Posted 9/1/22; Corrected 9/7/22] For the Stage 3 RFP, can energy generated in excess of the Allowed Capacity that is sent to the Facility’s storage component and later be discharged to the system be included in the NEP RFP Projection?


No. In order to ensure that the generating equipment assumed in the NEP is maintained and operating, as measured in the availability calculations, then all generating equipment assumed in the NEP must be represented in the Contract Capacity. (There is no Allowed Capacity term in the revised Stage 3 Hawaii/Maui RDG PPA).


[Posted 9/1/22] Could HECO allow for a DC Coupled solar plus storage system to use a different methodology to calculate NEP which does allow for the benefit of the BESS?


No. The Company is seeking consistent proposals. AC/DC proposals will be evaluated equivalently. The benefit of the BESS is captured in the production modeling. If seller intends to install a larger amount of capacity to produce a certain NEP, then that must be represented and committed to within the bid proposal as the Contract Capacity, and the storage size matched to the Net Nameplate Capacity used to ensure that Contract Capacity (i.e., 4 hours at Net Nameplate Capacity).


[Posted 11/23/22] Is an easement an acceptable form of demonstrating Site Control, as required by Section 4.3 of the RFP?


Yes. An easement is an acceptable form of demonstrating Site Control, noting all forms of site control (including an easement) would still need to be reviewed to confirm exclusivity, terms of conditions, etc.


[Posted 12/19/22] Would it be possible to receive Word versions of the Appendices J thru M (Model PPAs) for the Stage 3 Hawaii Island RFP, referenced at the link below? I didn’t see links to the Word versions for Stage 3 available.


The soft copies of the Model PPAs are available for download through the Electronic Procurement Platform (PowerAdvocate/Wood Mackenzie Sourcing Intelligence). Proposers, after registering on Sourcing Intelligence as a Supplier, must request access to the Stage 3 Hawaii RFP event via email. Identify in the email the company name and username under which the Proposer has registered. The Proposer will then be added to the event. Proposers can then find the soft copies on the “Download Documents” tab in the event.


[Posted 12/19/22] In Section Non-Price Criteria and Scoring’s Cultural Resource Impacts criteria, it say, “Should the Project Proposal cite a previously completed cultural assessment of the area, a copy of the assessment document should be included.” The Proposer seeks to clarify the requirement for this criteria.v In our study of proposed sites, initial reports, in some cases include the citation of dozens of documents and previously completed assessments which are hundreds of pages long, making it burdensome to include copies of each. As such, Proposer seeks to clarify whether a hyperlink to a downloadable version of previously completed cultural assessment documents cited would be sufficient.


The Company will not accept hyperlinks to a downloadable version of cited documents for previously completed cultural assessments of the Proposal’s Project area to support its Cultural Recourse Impacts evaluation. Section 3.4.2 of the RFP provides that “[t]he Company will rely only on the information included in the Proposals, and additional information solicited by the Company to Proposers in the format requested, to evaluate the Proposals received. Evaluation will be based on the stated information in this RFP and on information submitted by Proposers in response to this RFP. Proposals . . . must provide all referenced material if it is to be considered during the Proposal evaluation.” Thus, all information applicable to the Proposal and required in response to the RFP, including the information required by Section of the RFP regarding Cultural Resource Impacts (e.g., complete copies of any cited assessment documents), must be included in the Proposal submission.


[Posted 12/19/22] Is there a Microsoft Word version of the Proposer's Response Package you can provide? I didn't see one in the provided documents.


A MS Word template of the Appendix B Proposers Response Package has been uploaded into the “Download Documents” tab in the RFP event in the Electronic Procurement Platform (PowerAdvocate/Wood Mackenzie Sourcing Intelligence). Please use the file labeled “Proposers Resp Pkg Word Template IPP”.


[Posted 12/19/22] Previous PPA’s have been approved for 25-year initial terms so can proposers submit a proposal with 25-year terms in this RFP?


Yes, no Stage 3 Contract term is specified in the Hawaii RFP so one could propose a 25-year term.


[Posted 12/22/22] We want to ensure we will be compliant with this Eligibility requirement: "The Proposer must provide a Certificate of Vendor Compliance from the Hawaii Compliance Express with their Proposal that is current (dated and issued no earlier than 60 days of the date of Proposal submission). A Certificate of Good Standing from the State of Hawaii Department of Commerce and Consumer Affairs and also a federal and Hawaii state tax clearance certificates for the Proposer may be substituted for the Certificate of Vendor Compliance.”

  1. We are able to provide this Certificate of Vendor Compliance currently from the parent company which is the 100% owner of the Proposer, which does not itself have this certification. Is it acceptable for the tax clearance to come from the parent company of the Proposer?
  2. Additionally, related to meeting the site control requirements, is it acceptable for the site control documents (LOI or Option Agreement) to be executed by a special purpose, project level entity that is also wholly owned by the same parent company of the Proposer?
  3. Can the financial capability compliance come from the parent of the Proposer?


  1. No, the Certificate of Vendor Compliance (or, in lieu of the foregoing, the good standing certificate and the federal and state tax clearance certificates) should be provided with respect to the named Proposer, not an affiliate of the named Proposer.
  2. No, site control should be demonstrated with appropriate documentation (e.g., LOI or option agreement) executed by the named Proposer, not an affiliate of the named Proposer.
  3. Yes, the financial capability compliance for the RFP requirements can be based on the parent of the Proposer entity.


[Posted 1/25/23] Does HECO add general excise tax to the COIF costs in Appendix H or can we assume it is included?


The COIF cost estimates provided in Appendix H do not include general excise tax. The Proposer will have to account for general excise tax on top of the costs in Appendix H.


[Posted 1/25/23] 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?


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.


[Posted 1/25/23] We executed an earlier April 2022 Mutual Confidentiality and Non-Disclosure Agreement (“MNDA”) for this RFP, and noticed the Stage 3 Hawaii RFP was released with a July 2022 MNDA version in Appendix E. Do we need to execute this July 2022 version of the MNDA?


If the project you will propose into the Stage 3 Hawaii RFP still fits within your description of the project in the Background section of the April 2022 MNDA executed, then you do not need to execute another MNDA. However, if the project you will propose is different (technology, location, size) than the description in the Background section of the April 2022 MNDA, then you will need execute the July 2022 MNDA version in RFP’s Appendix E. Please find an MSWord doc version of the July 2022 MNDA to fill in here on the “1. Download Documents” tab of the Electronic Procurement Platform.


[Posted 1/25/23] The Model PV+BESS references Attachment B, and specifically Performance Standards that should be contained in Section 3 of Attachment B. However, Attachment B is effectively empty and just refers to Project Specific Addendums. APPENDIX B contains modelling requirements, but we are looking for actual Operational Specifications/Performance Standards for the BESS, should there be a more substantial Attachment B in the Model PV+BESS PPA that includes this information?


For the Performance Standards for the PV+BESS RDG PPA, please see Section 3 of Attachment B of the Project Specific Addendum for the RDG PPA (Appendix J-1 of the RFP). Also, please note that updated model Stage 3 Contracts (including the Appendix J model PV+BESS RDG PPA and the Appendix J-1 PSA for RDG PPA) were made available on January 6, 2023. Please see the most recent post on the RFP Website.


[Posted 1/25/23; Updated 3/6/23] In Appendix J of the RFP – Power Purchase Agreement for Renewable Dispatchable Generation (PV+BESS), Article 8 – Company Dispatch, Section 8.1 General. The Company has added the following language which differs from the Stage 2 PPA: “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.” Proposer respectfully asks for clarification of the intent of this addition.


The Company seeks new renewable dispatchable generation projects in this RFP. The structure of the RDG PPA intends to provide monthly payments to the Proposer by the Company (e.g., Lump Sum Payment) based upon the energy potential of the Facility, regardless of the actual energy dispatched. In exchange, the utility maintains full dispatch control of the Facility as needed. The Company intends to use all Projects selected for the Final Award Group in accordance with the performance and dispatchability requirements described in the model stage 3 Contracts to meet various grid needs.

[Update 3/6/23] 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 can 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. Proposers are reminded that the Project must still meet all other terms of the RDG PPA. To the extent a 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. Further, 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.


[Posted 1/25/23] Can the Company please provide updated attachments 3-9 for Appendix H reflecting updates made to the Stage 3 Hawaii RFP transmitted to the PUC on January 6, 2023?


No updates were made to Appendix H Attachments 3, 4, 5, 6, 7, 8, and 9 single line diagrams. They have not changed since first offered to developers in the Stage 3 Hawaii RFP.


[Posted 1/25/23] Also related to the January 6, 2023 updates, HECO posted line item 131 (which was to be added to Appendix H Section 2.3C). It reads:”69kV OH Final Span for Termination to Existing Substation by Company (Attachments 3-4)” Can HECO please confirm that ‘Attachment 3’ refers to Kanoelehua SLD and ‘Attachment 4’ refers to Puueo SLD and that line item 131 is only applicable to an interconnection at those two locations?


Sorry about the confusion. “(Attachment 3-4)” was an error on the January 6, 2023 webpage post. It was removed from the webpage post on January 13, 2023. The cost item is applicable to any existing substation (except the Keamuku rebuild), and does not include any upgrades or reconfigurations of existing substations.


[Posted 2/17/2023] We are trying to understand if HECO is requiring both real and reactive overcurrent capability. The way the section is written, we initially thought it was asking for 1.6x of the real current from the BESS contract capacity. However, we also read the following section and were led to believe that the only need is for reactive current. Can you please advise on exactly what is required?


The Short-term Overcurrent Capability is defined in terms of the ratio of the total Facility BESS Inverters steady state apparent power capability [MVA] to the active power Contract Capacity [MW] of the Facility times the Per unit BESS overcurrent capability that the Facility BESS inverters can sustain for at least 5 seconds. Because apparent power [MVA] can be any combination of active and reactive power depending on the equivalent impedance drawing the current, this capability is expected to be met for all possible combinations of active and reactive current that would achieve the required Short-term Overcurrent Capability of 1.6 pu. While this capability is most often expected to be deployed when a fault occurs on the system and since faults tend to draw a higher amount of reactive current than active current, this requirement will likely most often be met through the deployment of reactive current but to fully meet the requirement additional deployment of active current up to the Short-Term Overcurrent Capability limit is expected as provisioned in the following sentence of Section 3(h) (Short-Term Overcurrent Capability) of Attachment B of the RDG PPA PSA:

“During a disturbance condition, i.e., operating in an off-nominal set-point voltage mode, priority shall be given to reactive current injection with any residual capacity being supplied as active current.”

To summarize the Short-Term Overcurrent Capability requirement is expected to be able to be fully met by active current capability or reactive current capability or any combination of the two and the amount deployed will be determined by the equivalent system impedance at the time of the event. During the IRS, the system impact study (SIS) will determine the appropriate current control between reactive and active current during the fault ride-through and recovery stage within the 1.6 pu Short-Term Overcurrent Capability minimum requirement (i.e., more detailed requirements regarding active and reactive current may result).

SUPPLEMENTAL FROM DEVELOPER on A30: It appears the new requirement for The Short-term Overcurrent Capability may require the addition of several BESS inverters to the project if their inverters do not provide the required overcurrent capability. Adding more inverters could increase costs significantly, and we want to make sure that all prospective proposers are aware of this impact.


[Posted 2/17/2023] Appendix H was provided to give developers insight into HECO interconnection costs and to ensure they have all the costs in their estimates. Do we need to prove that we have checked-in with your team about interconnection costs? If so, how do we prove that?


There is no requirement that the Proposer is required to check in with the RFP Team about interconnection costs. The RFP Section 2.3.4 states, “Proposers are required to include in their pricing proposal all costs for interconnection and equipment expected to be required between their Facility and their proposed POI. Appendix H includes information related to Company-Owned Interconnection Facilities and costs that may be helpful to Proposers…” And the RFP’s Section’s State of the Project Development and Schedule states, “…The Company will specifically look to see if the Proposer has included all of the cost line items from Appendix H applicable to the Project type for Company-Owned Interconnection Facilities. An example of what the Company is looking for is identified in Appendix H, Attachment 1. Proposals that do not appear to include all the applicable cost line items from Appendix H that are reasonable for a project of the size proposed may result in a lower ranking for this criterion as it may reflect risk that the Project cannot be built on time and for the price proposed by the Proposer. The Company reserves the right to discuss any cost and financial information with a Proposer to ensure the information provided is accurate and correct. The Company may require an attestation from the Proposer that they understand their proposed interconnection costs do not appear accurate to the Company and should the Proposer continue and is selected that the Proposer shall be responsible for the final determination of interconnection costs whether or not it is higher than what the Proposer has included in its Proposal.”

In the RFP Section 1.2.8, however, “Proposers must inquire about the transmission line available MW capacity or substation conditions for all lines and substations.” Also, see the instructions in the RFP’s Appendix B for the Proposal Summary Table items 24 and 24a, and Section 2.2.4.


[Posted 2/17/2023] Is that Project Summary table in section 2.8.5 of the RFP required as part of the bid, or only after selection to the final award group? Also, is the Powerpoint presentation of the Community Outreach section part of the bid required as part of the bid or only after selection to the final award group?


The Project Summary table is intended to make all the information about the project visible in a single tabular form on the project’s webpage and as part of each Proposer’s public Community Outreach Plan. Though the Company would prefer to see the information as part of the Proposer’s Proposal, it will not require it at Proposal submission but will require it for all that are selected to the Final Award Group. The PowerPoint template is to assist developers when they perform project presentations where those presentations must include all the information on the Project Summary table.


[Posted 2/17/2023] Is a solar and storage project required to provide black start capability, as indicated in the model PPA?


Yes. The RFP’s Section 2.1.2 states, “Black start capability26 is required for Generation Projects using synchronous machines, Paired Projects and Standalone Storage Projects.” See also footnote 26 on black start. A PV+BESS or Wind+BESS project is a Paired Project as defined in RFP Section 1.2.1 and therefore is required to have Black Start capability per section 2.1.2 of the RFP.


[Posted 2/17/2023] What numbers are you looking for in 4a in section 2a “Installed Nameplate Capacity”? Can you please provide an example?


Per Appendix J-1 of the RFP, the RDG PPA PSA, Attachment A, Section 5(c), it says:

Installed Nameplate Capacity: Shall be the aggregate sum of the net nameplate active power capability of all generator and converter equipment installed.

The Installed Nameplate Capacity of this Facility shall be: __kW

For example in an AC Coupled PV+BESS Paired Project that has a net capability of 30,000 kW of PV Inverters and a net capability of 30,000 kW of BESS inverters and 30,000 kWDC of installed Solar panel and BESS capability (net to inverters) the Installed Nameplate Capacity would be 60 MWAC and 30 MWDC.

Or for example in an AC Coupled PV+BESS Paired Project that has a net capability of 30,000 kW of PV Inverters and a net capability of 30,000 kW of BESS inverters and 33,000 kWDC of installed Solar panel capability and 30,000 kWDC (net to inverters) the Installed Nameplate Capacity would be 60 MWAC and 33 MWDC.

Or for example in an DC Coupled PV+BESS Paired Project that has a net capability of 30,000 kW of PV+BESS (shared) Inverters and 33,000 kWDC of installed Solar panel and 33,000 kWDC of installed BESS capability (DC net to/from BESS and/or inverters) the Installed Nameplate Capacity would be 30 MWAC and 33 MWDC.

Note that per section 1.2.11 of the RFP the BESS Net Nameplate Capacity MW (AC and DC) must be sized equal to or greater than the PV system Net Nameplate Capacity. In the case of a DC coupled system, this means equal to or greater than the installed net DC Solar Panel capacity, along with the BESS energy storage requirement of the 4 hours at the installed net DC capacity. For example, in the DC coupled example provided above the BESS Contract Capacity (MW/MWh) would be expected to be 30 MW / 142 MWh (33MW*4h) to meet this requirement.


[Posted 2/22/2023] There is conflicting guidance on the size of BESS that must be paired with a Wind project for the Hawaii Stage 3 RFP. Section 1.2.11 of the Stage 3 Hawaii RFP Main Body (page 6/7) states that it must be 2 hours and equal to the same Net Nameplate Capacity of the Facility. It says:

The storage component of a Paired Project must be sized to support the Facility’s Net Nameplate Capacity (in MW) for at least two (2) continuous hours for a Wind+BESS Project or at least four (4) continuous hours for a PV+BESS Project throughout the term of the respective RDG PPA and support a minimum of 365 full charging/discharging cycles per year (or 366 full charging/discharging cycles per leap year).

Conversely, the Appendix J-1 model PSA for RDG PPA for Maui/Hawaii Attachment A 4.(f) (page A-4) states that for Wind + BESS projects the minimum capacity for a BESS is 1/3 of Net Nameplate Capacity of the Facility for a minimum of two hours. It says:

The BESS Contract Capacity (MW) shall not be less than one-third (1/3) the Net Nameplate Capacity.

Please advise on the minimum BESS Size for a paired Wind + BESS project.


The Company recognizes the inconsistency. The applicable language in the Appendix J-1 model PSA for RDP PPA for Maui/Hawaii for that statement for Wind+BESS is incorrect. Wind projects are not required to be paired with storage, however, if they are then please ensure your project complies with the RFP requirement of 1.2.11 stating, “The storage component of a Paired Project must be sized to support the Facility’s Net Nameplate Capacity (in MW) for at least two (2) continuous hours for a Wind+BESS Project … throughout the term of the respective RDG PPA and support a minimum of 365 full charging/discharging cycles per year (or 366 full charging/discharging cycles per leap year).”

If you are submitting proposed modifications in a Microsoft Word red-line version of the RDG PSA, you may red-line that sentence consistent with your Proposal design and RFP Section 1.2.11.


[Posted 2/22/2023] If an existing facility currently does not adhere to the Stage 3 Hawaii RFP requirement in Section 1.2.9 where 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 30MW, is it exempt from that interconnection requirement if it submits a Proposal in the Stage 3 Hawaii RFP?


In Chapter 1 of the RFP, states existing projects maintain the rights to use their existing interconnection facilities and points of interconnection. Thus, if the existing facility does not increase the capacity its existing facility currently generates and does not propose any difference to their facility technology, then the Company could maintain an exception to the single point of failure requirement within Section 1.2.9. An Interconnection Requirements Study would still be required to bring anything up to current interconnection standards and additional upgrades may be required.

If an existing facility proposes any difference to their technology, then it will depend on the type of facility and the differences proposed as to whether the Company will allow the exception to the single point of failure requirement within Section 1.2.9. The existing facility should contact the Company to clarify whether its specific change would maintain the exception or not.


[Posted 3/10/2023] Is it acceptable to build a project that is located on the edge of, but still within, the tsunami evacuation zone when the final elevation of the infrastructure and/or final grade will be above the tsunami evacuation zone height. The project would therefore no longer be located within the tsunami risk zone due to its final elevation.


No, per Section 4.2 Eligibility Requirements Item 12, the proposed Project infrastructure and POI must be located outside the 3.2 feet sea level rise exposure area (SLR-XA) as described in the Hawaii Sea Level Rise Vulnerability and Adaptation Report (2017), not located within a Tsunami Evacuation Zone, and not located within the Hawaii Department of Land and Natural Resources flood map’s flood zones A, AE, AEF, AH, AO, VE.


[Posted 3/10/2023] Will the Company be providing a redlined version of the February 28, 2023 update for the full Appendix J-1 (and specifically Attachment B) for the Stage 3 Hawaii? Will it be provided in .docx format?


Redlines of the Stage 3 Contracts updated in the February 28 filing can be found on the RFP Webpage ( Within the top post dated March 1st, there’s links to Book 1, Book 2, Book 3 which are the filed files. Appx J-1 in the Stage 3 Hawaii RFP is the Maui/Hawaii RDG PSA and the redlines to that should be Exhibit 8 in that March 1 filing toward the end of Book 2. Only the pdfs of the redlines for all are provided.


[Posted 3/21/2023] Please confirm that the extent of the single line described below will provide the Company with sufficient information to evaluate our submission at this stage of the RFP:

  1. Include in a single line:
    1. Point of Interconnection (POI)
    2. Interconnection Facilities (Company-Owned and Seller-Owned)
    3. AC Feeders to the Seller-Owned facilities from the Seller-Owned generation and/or storage system.
    4. Major Generation or storage equipment (e.g., PV inverters, Battery inverters, AC conductors to/from/between inverters)
  2. Can be excluded in single line:
    1. Downstream design elements (e.g., DC design elements such as DC wiring and hardware, PV panel configurations, and battery configuration)


The Company will not require the particular downstream design elements you mention in your request (i.e., DC wiring and hardware, PV panel configurations and battery configuration) in the single line diagrams. However, other downstream design element information, such as the PV DC size rating, BESS DC MWh capacity, and other information identified in Appendix B Proposers Response Package (e.g., items identified in Section 2.2.4 Overview of the proposed Facility or Equipment) is required within your Proposal.


[Posted 3/21/2023] If an existing facility plans to submit a proposal in response to the Stage 3 RFP of their existing facility without any electrical modifications, please confirm that Hawaiian Electric have working electrical models for the facility to support a forthcoming IRS.


No, an existing facility will need to submit electrical models as part of its Proposal in response to this RFP. The RFP requires that any existing project’s Proposal meet all of the terms of this RFP, including submission of the models that support the Interconnection Requirements Study and as required in Section 2.11 of Appendix B to the RFP. The expectation is that all Proposers, even those with existing facilities, meet all the model requirements in this RFP. As such, models previously provided to the Company , will not be sufficient for meeting the requirements under this RFP.


[Posted 3/21/2023] With the updated Hawaii Island PSA and its additional requirements, does HECO have an updated list of simulations that goes along with the latest versions of the PSAs? In other words, with the new addition of IEEE P2800 requirements, what specific tests should be simulated in PSSE-PSCAD benchmarking studies?


The Company is not updating the contents of the model review at this time.


[Posted 3/22/2023] Can Hawaiian Electric begin engineering during the IRS phase, before execution of a contract?


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.


[Posted 4/17/2023] (Follow-up from Q&A27) Please confirm whether BESS auxiliary loads self-serviced by the Facility should be subtracted from the NEP RFP Projection. The below indicates that the Contract Capacity and BESS Contract Capacity must be sized to be maintained despite aux/station loads, but does not specifically say whether the NEP RFP Projection shall be reduced by such amounts accordingly. In all other instances, the use of the BESS is to be ignored when determining the NEP RFP Projection. Does this also apply to the use of PV generation for servicing BESS aux loads?


Per Section of the RFP, “The NEP RFP Projection should be reduced by anticipated maintenance and losses such as System degradation and balance of plant losses.” Balance of plant losses are expected to include all electrical losses and station service (or auxiliary loads) incurred in the Facility in order to deliver the generated energy to the POI assuming all were to be delivered to the POI as it is being generated from the renewable resource. Further, Section states, “The NEP RFP Projection should ignore any contributions from the energy storage component of the Facility.” Ignoring the contribution of the energy storage component (BESS) in the NEP RFP projection is expected to ignore not only the arbitrage function of the BESS but also the auxiliary load and round trip losses of the BESS as those are expected to be completely captured in the round trip efficiency of the BESS component and would be enforced through the RTE Ratio Performance Metric.


[Posted 4/17/2023] In Appendix H Section 2.5, regarding backup communications, can you please confirm licensed radio is acceptable?


For transmission level connected projects, the acceptable backup communication would be a separate fiber cable, microwave, or a leased service (services acquired from a 3rd party telecom carrier that might offer low latency point-to-point circuits or IP data connection). The backup communications must also be transport diverse to the new switching station with a minimum six (6) feet physical separation. The same communication cabinet, Item 202 in Appx H, can be used for both the primary and backup communication. We apologize for the confusion. Leased radio for backup communication for a transmission level connected project is not acceptable and should not have been mentioned as an option in Appendix H.


[Posted 4/17/2023] For an existing facility, are all Detailed Instructions for Community Outreach Plan (Appendix B Attachment 5) applicable to existing infrastructure? Or, are those primarily for new development? Are only certain portions applicable to existing infrastructure? With respect to the environmental/cultural impact assessments, if the proposed project is already constructed and operating, what, if any, assessment is applicable?


Yes, existing facilities are held to the same RFP requirements as newly proposed projects. The Stage 3 Hawaii RFP requires that “[a]ny existing project’s Proposal must meet all of the terms of this RFP”, which includes all requirements for Community Outreach and Cultural Resource Impacts. If assessments required by this RFP have been conducted for an existing facility in the past, and those assessments are still applicable to the project as proposed for this RFP (e.g., contract term) and otherwise comply with the RFP’s requirements, they can be submitted as part of the Proposer’s Proposal. Please note, however, any assessment submitted will still be subject to and evaluated against the RFP’s requirements and scored accordingly.


[Posted 4/17/2023] Regarding Summary Table in 2.0, can you define item 4a-DC capacity? Does it include storage as well since it’s mentioned?


Yes, 4a should include both storage and generation. But for storage, please identify both MW and MWh; for generation, just MWdc.