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.


Q1:

[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?

A1:

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.

Q2:

[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.

A2:

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

Q3:

[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?

A3:

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.

Q4:

[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?

A4:

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.

Q5:

[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?

A5:

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.

Q6:

[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?

A6:

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.

Q7:

[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?

A7:

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.

Q8:

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

A8:

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).

Q9:

[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.

A9:

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.

Q10:

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

A10:

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.

Q11:

[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?

A11:

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.

Q12:

[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?

A12:

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.

Q13:

[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.

A13:

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.

Q14:

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

A14:

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.

Q15:

[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?

A15:

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).

Q16:

[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?

A16:

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).

Q17:

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

A17:

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.