Selling Power to the Utility

Questions & Answers

We believe that one of the main drivers of success of the competitive bidding process is to ensure transparency in that process. We believe that seeking the input of stakeholders and working collaboratively with such stakeholders to refine and improve the process will lead to successful RFPs.

We hope that the following answers to stakeholder questions will be helpful to potential Proposers and others interested in our RFPs. In order to ensure that information provided by the Companies is shared fairly with all Proposers, we are utilizing this page as a repository for questions and answers. While we aim to provide answers to all questions asked, it may not be feasible to respond directly to each question or comment submitted. Instead, similar questions may be consolidated so as to provide more helpful information. Questions specific to a particular project that might give a competitive advantage or contain confidential information may not be answered here or may be reframed in such a way as to be made available to the general public. Questions not relevant to these RFPs or questions received late in the process which do not allow for the Companies to provide an adequate answer may also not be answered here.

RFPs

R1:

Could you please confirm whether the Company-owned Kahe Site is limited to 9.5 acres or whether a larger acreage can be assumed, if necessary, for the Project?

A:

The Company is open to offering more land adjacent to the outlined area of the Company-owned Kahe Site. However, the land beyond this outlined area is significantly sloped and may not be suitable for siting project facilities. We are also not offering land on other portions of the Company property not directly adjacent to the Kahe Site.

R2:

Is the PowerAdvocate Proposal submission for variations different than in Stage 1?

A:

Yes, the submission process for Stage 2 is different from Stage 1. In Stage 1, each proposal variation required a Proposer to create separate and distinct user names and submit each proposal variation separately under different user names. In Stage 2, Proposers may submit a Proposal with up to four variations (variations of pricing terms, Facility size, with/without storage, differing levels of grid-charging capabilities) under one user name. All variations within a Proposal must be proposed on the same site and use the same generation technology to be considered the same Proposal (under the same Proposal Fee). See RFP Section 1.8 and RFP Appendix B, Sections 1.1, 2.0, and 3.0.

Note for Oahu/Hawaii Island:
For each of the four variations, an additional variation with Contingency Storage may be proposed if the only change is the addition of a Contingency Storage component. Thus, potentially up to eight variations (four variations without Contingency Storage, and four mirrored variations with Contingency Storage) can be submitted under one user name and one Proposal Fee.

R3:

Can we connect a project to an existing 138 kV substation?

A:

Standalone Storage projects (with or without Contingency Storage) and Paired projects (intended to meet the Storage Requirement (as such term is defined in the RFP) and/or Contingency Storage) will only be allowed to interconnect to the offered 138 kV substations, and interconnection into other existing substations will not be considered for this RFP. Generation only projects or Paired projects (not intended to meet the Storage Requirement and/or Contingency Storage) may be allowed to interconnect to existing substations. See Section 3.11.3 of the RFP.

R4:

In section 2.13 Experience and Qualifications of RFP Appendix B, it is requested that we provide evidence that project participants have worked jointly on other projects. Could you provide an example of how to fill in the table that's provided in the section or advise if a modified format would be acceptable?

A:

Please use the table format as instructed in RFP Appendix B section 2.13.1. The intent of this table is for bidders to clarify who on their team meets each of the experience categories below and the relevant projects or projects they worked on that best showcases their related experience. An individual or entity can meet one or more experience categories. A general example on how to fill out this table is provided below for reference.

R5:

Where should we send questions regarding the RFP, interconnection, or the process to?

A:

The Independent Observer for this RFP has requested that all communication going forward be channeled through the PowerAdvocate Messaging function (Electronic Procurement Platform) instead of via the RFP Email Address. If you have not done so already, please register as a PowerAdvocate Supplier and email to the RFP Email Address your Company Name and username. You will then be added as a Supplier to PowerAdvocate RFP event. Once allowed into the Event, all communication and responses to questions will be conducted through the PowerAdvocate Messaging function/tab.

R6:

Does the Certificate of Good Standing and the Federal and State tax clearance certificates need to be dated within a certain period of time to be valid for this Stage 2 RFP?

A:

Yes, the Certificate of Good Standing from the State of Hawaii Department of Commerce and Consumer Affairs and Federal and State tax clearance certificates must be dated within 60 days of the date of your proposal submission. Also, a Certificate of Vendor Compliance issued from the Hawaii Compliance Express (HCE) eliminates the need to obtain both a Certificate of Good Standing and Federal and State tax clearance certificates, and will be accepted in your Proposal submission in lieu of those. The Certificate of Vendor Compliance must also be issued within 60 days of the date of your proposal submission.

R7:

In the Oahu RFP, does the 200 MW mentioned in the introduction refers to the maximum amount of storage you are looking?

A:

Specific to Oahu, the 200 MW mentioned in the Introduction is not a maximum amount, and instead refers specifically to the amount of MW capacity sought in the Oahu RFP to replace the capacity from an existing firm generator, which the RFP refers to as the "Storage Requirement". With regards to the Storage Requirement, the RFP specifically provides, "The total amount of energy storage being solicited in this RFP is the capability to store and discharge energy equivalent to at least 1,200 MWh per cycle via a total nameplate capacity of at least 200 megawatts ("MW"). This MW and MWh storage capability is referred to herein as the "Storage Requirement"." The Companies are also seeking renewable energy generation projects paired with storage not intending to meet the requirements of the RFP Storage Requirement. The storage from these paired projects would be above and beyond the Storage Requirement being sought and there is no specific target for this storage. Selection would be dependent on evaluation and benefit cost analysis of proposed projects with storage and proposed projects without paired storage competing to meet the variable renewable dispatchable generation MWh solicited in the Oahu RFP.

R8:

For the Oahu RFP, can you please describe what is meant for a Project to be black start capable?

A:

Black start capability for Oahu is not a requirement for projects being proposed but a preference for standalone energy storage projects or energy storage paired with generation facilities. If a Project is not already designed to be black start capable, the RFP asks to specify the cost to enable back start. The Company would expect a Project providing black start on Oahu to have the ability to provide power to the Company's grid without relying on any services or energy from the Company's grid to recover from a total or partial shutdown. When the Company's grid blacks out, the Project may experience during start-up (if the Project remains connected) or while connecting, step changes in load and other transient and dynamic conditions as it picks up load without support from other resources on the system. If the project wants to be considered as a black start resource, the PSCAD and PSSE models provided in the time required under the PPA would need to be able to model the black start capability. Other than as mentioned, the Company has not at this time designed requirements for the black start capability and are looking to Proposers to explain how their solution will provide the service and the functionality their design can provide.

R9:

For the Oahu RFP, how many inverters out of the total will need to have black start capability?

A:

100% of the inverters is preferred to allow the storage to run at full capacity unless some inverters can operate in grid following mode while other inverters run in black start/grid forming mode.

R10:

For the Oahu RFP, are there requirements on how the inverters are supposed to switch from normal operation to black start?

A:

If the Company's grid blacks out and the Project's facility shuts down, the Company wants the facility to transition to and start in black start mode. Transition from black start back to normal is preferred to be online, bumpless, and seamless.

R11:

A Proposer states they are currently not registered in the State of Hawaii, and asks if they can state in the Proposal that they will provide the Certificate of Good Standing and the requested tax clearances if their proposal is ultimately selected as a winning proposal. Will that meet the RFP eligibility requirements?

A:

No, the Eligibility Requirements for this RFPs specify that the Proposer must provide as part of its Proposal submission, a Certificate of Good Standing from the State of Hawaii Department of Commerce and Consumer Affairs and federal and state tax clearance certificates for the Proposer. Please also note that the Company's response (R6) in the Q&A section of the RFP Website states that a Certificate of Vendor Compliance issued from the Hawaii Compliance Express will be accepted in lieu of these required items.

R12:

Is a Project required to be located outside of the Extreme Tsunami Evacuation Zone?

A:

No, Project infrastructure does not need to be located outside of the Extreme Tsunami Evacuation Zone. Refer to Section 1.2.5 in the Oahu and Maui RFPs, and 1.2.6 in the Hawaii RFP for tsunami-related requirements.

R13-R16 are Kahe Site Related Questions

R13:

Could you advise on the setbacks and easement rights for the 138 kV transmission lines crossing the Kahe site?

A:

The Kahe Site is located entirely within Hawaiian Electric owned TMK 9-2-049:006 and so there are no easements for the existing 138 kV transmission lines that cross the north end and the middle of the Kahe Site. As there are no easements for the existing lines, the Proposer should follow the setbacks shown on the attached diagrams.

R14:

Could you advise on the setback and easement rights for any other transmission/distribution lines crossing the Kahe Site (12 kV, 46 kV)?

A:

Currently, there are three 138 kV lines (one de-energized; used as a training site), one 46 kV and 12 kV line, and one 12 kV line crossing the Kahe Site. As there are no easements for the existing lines, the Proposer should follow the setbacks shown on the attached diagrams.

R15:

Would Hawaiian Electric be open to relocating those lines to optimize the available area?

A:

While in general, Hawaiian Electric would be open to considering relocation of lines for a project, the Proposer would need to bear all costs for relocation and take into consideration the time necessary to complete the relocation work, as well as regulatory and other approvals that may be necessary. Considering the timelines for standalone energy storage for this Oahu RFP (GCOD no later than June 1, 2022), relocation of the 138 kV transmission line is not feasible. (Note: Relocation of lines will not only affect the available area but also the adjoining properties.) As the 138 kV transmission line running through the center of the Kahe Site cannot be feasibly moved, the Kahe Site is essentially two smaller sites adjacent to each other. A Proposer must take this into consideration in determining whether the actual available square footage is suitable for a Proposer's needs.

R16:

Will it be possible to put the project's step up transformer in the Kahe power plant's yard?

A:

No, there is no available space in the Kahe Power Plant yard for purposes of this RFP. Step-up transformers must be located within the space being made available by the Company for the Proposer's project.

R17:

For purposes of cost estimation, are the Hawaiian Electric project management costs included in the estimated provided for in Appendix H?

A:

No, the Company's project management costs are not included in Appendix H estimates. Project management cost estimates cannot be provided because they vary between projects and depend on the complexity of the project. Examples of factors that influence project management costs include (but are not limited to), the extent to which project-specific design, procurement and construction details have been finalized and incorporated into the Proposal submission, including the required computer models; and the status of obtaining permits/approvals/land rights/etc. (as required). Information that is not available at the time of Proposal submission or is subsequently changed, and thus requires an update to the submitted information, increases the amount of project management costs. Developers are responsible to estimate these costs on their own based on the state of their project development.

R18:

For the Hawaiian Electric Oahu RFP what Power Factor should we assume for our project at the POI? Does Hawaiian Electric require dynamic reactive compensation or static reactive compensation to achieve the above Power Factor at the POI?

A:

The Company does not provide an assumed Power Factor. The Facility must be capable of automatic voltage regulation to maintain system voltage at the point of regulation while meeting the Reactive Power Control and the Reactive Amount requirements specified in Sections 3(a) and 3(b) of Attachment B of the Model RDG PPA (see Appendix J of the Oahu RFP).

R19:

Would Hawaiian Electric be amenable to a proposed project sited on the space available in one of the offered substations' yard?

A:

No, for the purposes of this RFP, all equipment required for a Proposer's project must be sited within the Proposer's project site.

R20:

I can't seem to find the required PPA initial term and extension term. I assume the initial term is 20 years can you confirm.

A:

The Proposal Contract Term will be determined by the Proposer, and shall be indicated in the Proposer's response to Item 8 in the Proposal Summary Table shown in Section 2.0 of Appendix B. Variations of a Proposer's base variation Proposal may include a different Proposal Contract Term length in accordance with RFP Section 1.8.3. As set forth in Section 12.1 of the Model PPA (Appendix J of the RFP), any proposed extension of the term of the PPA will require PUC approval and, as such, will need to be negotiated between the parties and submitted to the PUC no later than one year prior to the expiration of the initial term of the PPA. In addition, it is the Company's expectation that the pricing for any extended term will be reduced in recognition that Seller will have recovered its capital and financing costs.

R21:

For the Oahu RFP, in considering the Kahe site as a potential project site for standalone storage, is there an expectation that the developer will execute a long term lease with the Company? If yes, any indication of the rent payment?

A:

Please see Section 3.11.2 and Appendix F of the RFP, which provide that Proposers proposing to use the Kahe Site shall be required to agree to specific terms and conditions for such use (TCU), the form of which is attached as Attachment X to the model ESPPA (see Appendix K of the RFP).

There will be no rental payment associated with a Proposer's use of the Kahe Site. However, as stated in Appendix F, Proposer will be required to bear other upfront and ongoing costs associated with the use of the Kahe Site as reserved in the TCU or the model ESPPA, including, without limitation: (1) baseline assessments of the Kahe Site, either a Phase 1 or Phase 2 environmental assessment and, as necessary, archaeological study; and (2) applicable physical and data security requirements.

R22:

What does it mean to have two transmission line terminations? Does it mean one system should be connected in two places (2 POI) to the same transmission line?

A:

The "two transmission line termination" requirement means that a Project must be connected to two independent transmission lines at a single Point of Interconnection. Projects must interconnect to an existing transmission line in a 4-breaker ring bus that is configured in a breaker and-a-half scheme (refer to Attachment H). For Projects on Maui and Hawaii Island, this 4-breaker ring bus arrangement must be connected to two independent Company 69 kV transmission lines. In addition, a Project must be interconnected such that the single point of failure limitation is maintained (as discussed above). Refer to the diagram below for an example Hawaii Island interconnection configuration showing the two transmission line terminations.

69 KV Transmission Line Diagram

R23:

Are any of the quoted costs in Appendix H deemed to be network upgrades and are they reimbursable?

A:

The per-unit cost figures provide in Appendix H are intended to be used to provide an approximate, estimated cost (not a detailed project estimate) for interconnecting a proposed Project to the Company System. As Section 2.3.4 of the RFP provides that the Proposer is responsible for all costs required to interconnect a Project to the Company System (including the cost of all Interconnection Facilities), these costs are not reimbursable.

R24:

Per Sections 6 a. and b. of RFP Attachment I (Rule 19 Tariff), should we show pricing with and without utility interconnection costs?

A:

The pricing elements in a Proposal should account for a proposed Project's interconnection costs, which shall be borne by the Proposer pursuant to Section 2.3.4 of the RFP.

R25:

Is there a standard O&M cost that we should assume in our pricing for maintaining utility provided interconnection facilities?

A:

No, the Companies do not have a standard Operation and Maintenance cost that can be applied to all Projects. Ongoing Operation and Maintenance charges will include preventive and corrective maintenance that could vary based on the Interconnection Facilities specified for the Project and can also vary from year to year based on corrective maintenance events.

R26:

Could you provide an example of a one-line showing an electrical set up that meets the single point of failure and segmentation requirements in the RFP?

A:

Please see below for a one-line diagram that meets the RFP's single point of failure and segmentation requirements.

Line Diagram - Double Point Failure

R27:

Please provide further guidance on the types of documents that will be sufficient to show compliance with the RFP's FASB ASC 810 requirement.

A:

Set forth below is general information on how the Companies will analyze proposals under Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") Topic 810, "Consolidation." To allow the Companies to verify that a proposed Project will not cause the company to be subject to consolidation, a proposer should provide information that supports the position that the conditions necessary for consolidation, as outlined and described below, will not triggered by the proposer's Proposal. For example, a quantitative assessment of all holders of variable interests of the entity, and/or a determination of the entity that directs the most significant activities and absorbs the most risk (for purposes of determining the primary beneficiary of the entity) would be instructive in the Companies' consolidation analysis. The Companies' preference for the source of the quantitative assessment and/or determination is as follows:

  1. Third-party accounting firm (highest preference)
  2. Third-party law firm
  3. Internal accounting or legal assessment and/or determination (lowest preference)

Consolidation Overview:

  • The Companies are required to consolidate an entity in which a Company is the primary beneficiary of the entity. (ASC 810-10-25-38A)
  • A Company is the primary beneficiary of an entity if it holds a variable interest in the entity and has 1) the power to direct the entity's most significant activities that impact its economic performance, and 2) an obligation to absorb/or right to receive significant losses/benefits of the entity. (ASC 810-10-25-38A)
  • The Companies will perform a consolidation analysis to determine if it is the primary beneficiary of an entity.
  • Consolidation analyses must be reassessed continuously.

Business-Scope Exception (ASC 810-10-15-17(d)):

  • Entities that are businesses are excluded from the application of ASC 810 unless:
    • The Companies were involved in the formation/design of the entity; or
    • Substantially all of the activities of the entity involve or are conducted on behalf of the Companies; or
    • The Companies provide more than half of the equity, subordinated debt, or other forms of subordinated financial support to the entity; or
    • Entity's activities are related to securitizations, asset-backed financing, leasing, etc.
  • The Companies' consolidation analysis will involve obtaining information from the entity to determine whether the business-scope exception is applicable.

Documentation to Support Consolidation Analysis:

  • Does agreement with the entity represent a variable interest in the entity?
    • Provide assessment on whether arrangement provides the Companies a variable interest in the entity. A variable interest results from an economic arrangement that gives a Company the right to the economic risks and/or rewards of an entity – or its "variability." A variable interest is a contractual arrangement or other agreement that does not give rise to or create variability in the fair value of the entity's net assets and operations; rather, it absorbs or has rights to some or all of that variability. Changes in the fair value of most assets and operating liabilities (usually caused from changes in operating cash flows) create variability in the entity's net assets. Contractual arrangements or investments that do not create variability in the fair value of the entity are variable interests since the counterparty or investor absorbs the risks and rewards of the entity's activities.
    • FASB defines a variable interest as a "contractual, ownership, or other pecuniary interest in an entity that change with changes in the fair value of the legal entity's net assets exclusive of variable interests."
    • A variable interest is a contractual arrangement or other agreement that does not create variability (economic risk) in an entity, rather it absorbs variability in the entity.
    • Some examples of variable interests include equity investments, debt instruments, guarantees, power purchase agreements, operation and maintenance contracts, service contracts, and capital leases.
  • Will the Companies have the ability to direct the entity's most significant activities that impact its economic performance?
    • Identify which activities most significantly impact the success of the entity and who has the power to direct those activities.
    • For example, under a purchase power arrangement, an entity's significant activities may include control of day-to-day operations, plant dispatch, fuel procurement, etc.
  • Will the Companies have the ability to absorb losses or the right to receive benefits of the entity that could potentially be significant to the entity?
    • Provide documentation on whether the Companies will have the ability to absorb significant losses (or risks) of the entity.
    • For example, under a purchase power arrangement, an entity may pass losses to the Companies by the way its pricing is structured where an entity's variable costs are passed to the Companies.

R28:

What standards for relay settings and protection coordination studies (including fuse selection and AC/DC schematic trip schemes) are used by the Companies?

A:

Industry standards used by the Company for relay settings and protection coordination include:

  • IEEE 399 (3002 series) Power system studies, including short circuit and coordination studies.
  • IEEE 242 (3004 series) Protection and Coordination, including overcurrent coordination.
  • IEEE C2 (ANSI C2) National Electrical Safety Code.
  • NFPA 70 National Electrical Code.

R29:

If a foreign corporation incorporates a new entity in the state of Hawaii for the purposes of this RFP and does not have financial statements available, is it acceptable to submit audited financial statements of either of the new Hawaii entity's parent company or the parent of the foreign corporation's parent company?

A:

If audited financial statements are not available for the Proposer-entity, audited financial statements for the parent company may be provided. If the audited financial statements are in foreign currency, please have the statements translated into US dollars. Please also ensure that all statements are provided in English.

R30:

In the Stage 1 RFP for Maui, the maximum point of failure for projects was 30 MW. Is there some reason the limit is now only 20 MW in the Stage 2 RFP?

A:

The revision of the maximum point of failure for Stage 2 Maui projects was made to address various operational concerns. Maui is a relatively small island with a number of system sensitivities to consider as a result, such as a very small frequency bias. While the sudden loss of 30 MW on Maui's system would trigger an underfrequency condition large enough to require load shedding to maintain system stability, the sudden loss of 20 MW would create a less severe frequency depression that the system can recover from on its own and without shedding any load. As more facilities come online, each with an inherently large single point of failure, there is a larger risk on the system for such frequency depressions and disturbances to occur. Additionally, operational considerations such as cycling generation for routine maintenance and maintaining the amount of available generation also factored into the decision to revise the maximum point of failure for proposed projects. With these considerations in mind, the decision was made to require Stage 2 projects to adhere to a 20 MW maximum single point of failure.

R31 and R32 apply to the Hawaii Island RFP only

R31:

Please provide the historical frequency data for 2 second data resolution samples referenced in Attachment B, Section 9.d.v of the Model ESPPA. Does this section indicate that the BESS will only be dispatched via frequency response (i.e. an inverter-based response) and not via SCADA commands?

A:

While providing contingency response, the BESS will charge/discharge as a local response to frequency in accordance with response deadband and other tuning parameters as opposed to charging and discharging to match the dispatch from the Company's SCADA control system. However, the BESS will also be required to support an alternate mode of operation as an energy resource. During these times, it will be charged or discharged via SCADA commands as described in Section 1(g) (Active Power Control Interface) of Attachment B of the Model ESPPA while also providing a standard droop response. NOTE: Pursuant to Section 1.2.19 of the RFP, the requested information has been provided.

R32:

Is there a minimum duty cycle requirement for contingency storage proposals? How often does the Company anticipate using the contingency storage for energy rather than for contingency reserve? Will contingency storage proposals that provide more full cycles be evaluated more favorably than contingency proposals that provide fewer full cycles?

A:

In lieu of specifying a required duty cycle, proposers are asked to review the historical frequency data for the Company's system to provide context for the system's characteristics. The storage resource sought in this RFP is fast proportional contingency reserve. Proposals will be evaluated on their ability to support the expected level of frequency response deemed necessary as determined by the historical data of the system. Generally, the ability to provide more cycles will be preferred. However, this characteristic is only one of many factors that will be considered during the RFP evaluation process, and it cannot be stated that, in all cases, a contingency proposal that provides more cycles will be evaluated, as a whole, more favorably than a contingency proposal that provides fewer cycles. Additionally, use of the proposed storage as an energy resource would be expected to be infrequent, as it would interfere with the use of the proposed storage as a contingency reserve.

R33:

Are there any penalties to Proposers if the organizational structure of the Proposer changes after the Proposal is submitted?

A:

There is no penalty to Proposers if changes to a Proposer's organizational structure are required following proposal submission. However, to the extent an organizational change is anticipated at the time a proposal is submitted, a Proposer should disclose that information in its proposal. If and when the organizational change occurs, the Proposer should inform the Company of the change, even if the change occurs after the Proposal Due Date. The Company reserves its right to reassess the proposal based on any new information provided. If the organizational changes affect a Proposal's Eligibility and Threshold Requirements, the Proposal may risk falling into non-conformance with the RFP requirements. It is the responsibility of the Proposer to consider how such changes will affect a Proposal's Eligibility and Threshold Requirements.

R34:

Per Section 3.10.1 of the RFP, could you please clarify the NEP RFP Projection that should be provided for a project with storage? Specifically, we are wondering if a project is oversized with respect to the Facility's Allowed Capacity, whether the excess energy that is generated above the Allowed Capacity which may be sent to the Facility's storage component and then later discharged and exported to the system should be included in the NEP RFP Projection that is provided for the project.

A:

Yes, any energy that is generated in excess of the Allowed Capacity that is sent to the Facility's storage component and can later be discharged to the system should be included in the NEP RFP Projection that is provided for the project. The NEP RFP Projection should not, however, include any assumed losses incurred from the energy storage component.

Please refer to the figure below:

NEP RFP Projection Graph

The following question applies to the Oahu RFP only

R35:

For the 46 kV circuits on Oahu, two different levels of allowed hosting capacity were provided. One that is associated with the daytime hours of 8am to 5pm and a higher value for the nighttime hours from 5pm to 8am. Given this, could a Proposer propose a project where the majority of the energy produced by its generation during the daytime hours would be stored in the Facility's storage component such that it would not exceed the daytime limit, but then be dispatched up to the nighttime limit during those hours?

A:

Yes, Proposers may propose projects as described. Additionally, the NEP RFP Projection that is provided for the project should include all of the energy stored in the storage component during the daytime hours and made available for dispatch during the nighttime hours. The NEP RFP Projection should not, however, include any assumed losses incurred from the energy storage component.

Please additionally refer to the figure below:

Maximum Output Allowed Diagram

R36:

What PPA should we markup if we are proposing a biofuel or other non-variable resource?

A:

The Companies do not have an alternative form of RDG PPA that can be used for markup purposes for a biofuel or other non-variable resource generation project. Therefore, only the model photovoltaic or wind PPAs attached as appendices to the RFP can be used for markup purposes (either form may be used). The Companies note that the RDG PPA or ESPPA proposed modification non-price criteria provides: "Technology-specific or operating characteristics-required modifications, with adequate explanation as to the necessity of such modifications, will not jeopardize a project's ability to achieve the highest score."

The Companies would like to clarify that the language in Chapter 1 of the RFP stating that "[i]f the proposed Project utilizes a technology other than PV or wind and/or contains components that are not encompassed by the RDG PPA, then the terms of the RDG PPA will be modified to address the specific technology and/or component" reserves the right of the Companies to make changes to the model RDG PPA form to include requirements applicable to the technology proposed. For a biofuel or other non-variable resource, these changes may include, but are not limited to, the addition of requirements for the availability of a project's fuel source and fuel supply and to replace the concept of availability with the concept of capacity for firm resources. If the Project is selected for the Final Award Group, the parties would negotiate any such necessary changes to reflect the different technology during PPA negotiations.

R37:

If we are proposing a project that sources fuel as the renewable technology, such as a biofuel or biomass generation project, what information regarding the fuel should we provide in the RFP response?

A:

For generation projects that utilize qualified renewable energy resources such as biofuels or biomass, the Companies will need to see the following information in the Proposal:

  1. Fuel Supply Plan. The Companies require a minimum of 30 days' fuel storage on the islands of Maui and Hawaii and 45 day's fuel storage on Oahu for their own generation units and expect the same from a Proposer. However, Proposers may propose greater than or less than 30 days (45 days for Oahu), with justification that the fuel supply plan is sufficient in the event of a supply chain disruption. The Companies reserve the right to determine whether the fuel supply plan provides adequate assurance of continuous operation of the Facility.
  2. Detailed information on the source of the fuel.
  3. Detailed information on the type of fuel.

Proposals must also address requirements in the PPA, the Companies' Environmental Policy (as defined below), applicable government approvals and equipment manufacturer specifications relating to the Facility. "Environmental Policy" shall mean, collectively, (1) the Hawaiian Electric Companies' Procurement of Biofuel from Sustainably Produced Feedstock (prepared by Hawaiian Electric and NRDC, dated August 2013), and (2) the Roundtable on Sustainable Biofuels (RSB) Principles and Criteria for Sustainable Biofuel Production (prepared by the Roundtable on Sustainable Biofuels 2010) (RSP reference code: [RSB-STD-01-001 (Version 2.0)]).

R38:

Does the Company have a preference for the term length for standalone storage?

A:

The Company does not have a preference for the length of the contract term for standalone storage projects. The Proposal Contract Term will be determined by the Proposer, and shall be indicated in the Proposer's response to Item 8 in the Proposal Summary Table shown in Section 2.0 of Appendix B. Variations of a Proposer's base variation Proposal may include a different Proposal Contract Term length in accordance with RFP Section 1.8.3.

Additionally, there is no required extension term for standalone storage projects. As set forth in Section 3.1 of the Model Energy Storage Power Purchase Agreement (Appendix K of the RFP), any proposed extension of the term of the PPA will require PUC approval and, as such, will need to be negotiated between the parties and submitted to the PUC no later than one year prior to the expiration of the initial term of the contract. In addition, it is the Company's expectation that the pricing for any extended term will be reduced in recognition that Seller will have recovered its capital and financing costs.

R39:

Which IRS Data Request Form should be completed and submitted for a standalone storage project?

A:

Fill out all sections of the PV IRS Data Request Form that are applicable to your proposed storage facility. In reviewing the completed data request form, the Company will be looking for information regarding the proposed design and operations of the storage facility, as well as detailed models for system impact analyses of the proposed storage facility.

The following question applies to the Oahu RFP only

R40:

Requesting clarification on the term "Facility must be segmented in equally sized capacities" in section 1.2.7 for the Oahu standalone storage RFP for project size greater than 135MW. Does that mean for a 150 MW project without FFR, could the segmentation be as follows?

Option A:

  • POI 1: 100MW
  • POI 2: 50MW



OR

Option B:

  • POI 1: 75MW
  • POI 2: 75MW

A:

The equally sized capacities from Section 1.2.7 dictates Option B.

R41:

Please confirm that the "Measurement Period" for the purpose of all performance guaranteed metrics under the ESPPA implies a monthly measuring period?

A:

No, as described in the Schedule of Defined Terms in the ESPPA, the Measurement Period applicable to the performance metrics (except the performance metric for fast frequency response, if applicable) is a period of three (3) calendar months.

R42:

Can Hawaiian Electric elaborate on what is meant by "Data in lieu of conducting Capacity and RTE tests"? Attachment T indicates that the proponent can reference operational data to demonstrate performance instead of performing formal capacity and RTE tests. Is the operational data based on proponent's experience with operating other assets of similar size and services?

A:

The operational data that can be used to demonstrate performance in lieu of conducting formal capacity and RTE tests is the operational data from the contracted Facility, and not the operational data of another separate asset/facility. As described in Attachment T of the ESPPA, the operational data, highlighting (1) Facility output to show capacity and (2) charging/discharging of the Facility to show RTE, should reflect the operations of the contracted Facility between the Facility and the point of interconnection.

The following question applies to the Oahu RFP only

R43:

Fast Frequency Response Performance Measurement. Can Hawaiian Electric elaborate further on the definition of "instance of the Facility failing to satisfy the FFR Performance Metric". It currently says for "each instance" of bad performance, proponent owes 25% of the FFR portion of the payment. How is an "instance" defined?

A:

While the term "instance" is not defined in the subject provision of the PPA (Section 2.11), in context, it should be interpreted to mean each "time". To be more specific, an "instance" would be a system contingency event (loss of generation) that requires FFR to be deployed.

R44:

Does an energy storage integration company need to have a Hawaii Contractors License to be able to provide design, engineering and project management services?

A:

It is the responsibility of the Proposer to comply with all applicable laws and regulations and the Proposer should consult with their legal counsel, contractors, and/or engineers on this issue.

R45:

Can the Company provide the required energy storage capability curves associated with Exhibit B-2 of Appendix J for a Standalone Storage system?

A:

The Company does not provide energy storage capability curves to Proposers. These energy storage capability curves should be provided by the Proposer based on the inverters that are intended for use at the proposed Facility.

R46:

As per RFP Section 4.3 Threshold Requirement Assessment, Site Control, the following is stated regarding non-exclusive parcels:

The binding commitment does not need to be exclusive to the Proposer at the time the Proposal is submitted and may be contingent upon selection of the Proposal to the Final Award Group. If multiple Projects are provided a binding commitment for the same Site, the documents granting the binding commitments must not prevent the Company from choosing the Proposal that otherwise would have been selected."

How will the Company choose a project for the Priority List and Award stage if there are competing projects overlapping in full or partially on the same TMK?

A:

For selection to the Priority List, competing projects that overlap (fully or partially) on the same TMK will not be eliminated based on project location. As described in Chapter 4 of the RFP, projects will be evaluated using a multi-step process. If a project satisfies both the Eligibility and Threshold Requirements of the RFP Sections 4.2 and 4.3, the project will move to the Initial Evaluation phase. The Initial Evaluation, described in RFP Section 4.4, does not consider whether projects are sited at the same TMK. Therefore, if multiple competing projects that overlap on the same TMK pass the Initial Evaluation phase, such projects could be selected to the Priority List even though they are located at the same or overlapping sites.

Even if multiple projects that are located at the same or overlapping sites are selected to the Priority List, the Detailed Evaluation will ensure that projects located on the exact same site and projects that have overlapping footprints are not all selected to the Final Award Group. During the Detailed Evaluation (discussed in RFP Section 4.7), the Company will evaluate the collateral consequences of the implementation of a combination of Projects, including consideration of the geographic diversity, resource diversity, interconnection complexity, and flexibility and latitude of operation control of the Projects.

The following question applies to the Oahu RFP only

R47:

Can you confirm that for any alternative proposals including Contingency Storage (FFR-1), that the maximum MW with a single point of failure is still 135 MW?

As an example, can you confirm it would not be allowable to have a 135 MW project with an additional 50 MW of Contingency Storage, for a total of 185 MW using a single point of interconnection?

A:

Provided the point of interconnection has the available capacity, a 135 MW project that provides energy capacity on a continuous basis can share the same point of interconnection with a 50 MW project that provides FFR for a total of 185 MW using a single point of interconnection. Energy from the 50 MW contingency storage project will only be deployed in response to a system contingency for 30 minutes or until replacement reserves are online. Thus, there does not need to be any segmenting of this project. However, all inverters, transformers and associated equipment must be sized to export all 185 MW at any given time. A detailed Interconnection Requirements Study, when performed, may reveal other adverse system impacts that may further limit a project's ability to interconnect and/or further limit the net output of the Facility.

R48:

Will the names of the equity participants providing written commitments as stated in 2.3.2.3 Appendix B RFP be made public?

A:

Details of a Project Proposal, including the name of equity participants, will not be disclosed to the public during the proposal evaluation process.

Please refer to Section 3.12.1 of the RFP for instructions and information on designating confidential information within a Proposal. Please note that per Section 3.12.1 of the RFP, the Company reserves the right to share any information, even if it is marked as confidential, to its agents, contractors, or the Independent Observer for the purpose of evaluating the Proposal and facilitating potential contract negotiations.

The following question applies to the Oahu RFP only

R49:

Do you have any preferred size for the Standalone storage project to be proposed in Kahe Site?

A:

The Company does not have any preconceived sizing expectations for storage projects proposed at the Kahe Site. It is up to the Proposer to perform due diligence on potential project locations, including the Kahe Site, during the preparation of their Proposals to determine for itself whether such locations are suitable for a potential project and its size.

R50:

"For standalone energy storage or energy storage coupled with generation facilities, the functionality and characteristics of the storage must be maintained throughout the term of the PPA. To be clear, Proposers may not propose any degradation in storage capacity or storage efficiency in their Proposals."
Does this statement preclude the developer from overbuilding on the Battery Energy Storage System?

A:

No, the statement is not intended to preclude a developer from overbuilding its battery energy storage system. Ensuring that there is no degradation in storage capacity or efficiency over the term of the PPA could be accomplished in a number of ways, including overbuilding. The particular manner in which this requirement is achieved is ultimately up to the developer to include in its Proposal.

R51:

Relating to the pricing requirements of Section 3.9.4 and 3.9.5 of the RFP, could Hawaiian Electric confirm that it is intended to include a "Price for Purchase of Electricity" in the proposed PPA?

A:

As stated in the RFP, a Proposer has the option to propose a "Price for Purchase of Electric Energy" for net energy delivered from the variable generation resource, i.e., energy payment, but is not obligated to do so. The proposed Price for Purchase of Electric Energy will be evaluated by the Company along with other aspects of the Proposal. If a Proposal is selected for the Final Award Group, and if the Proposer and the Company are able to reach agreement on the PPA, the Price for Purchase of Electric Energy would be reflected in the PV or wind RDG PPA, as applicable, along with the Lump Sum Payment. The model PV and wind RDG PPAs include drafting notes for language that would apply if project includes an energy payment (e.g., see Section 2.1 of the model PV+BESS RDG PPA). The ESPPA only offers the Lump Sum Payment and there is no Price for Purchase of Electric Energy.

R52:

Which variable generation resources are allowed to include a "Price for Purchase of Electric Energy" in the proposed PPA?

A:

A proposer has the option to propose a Price for Purchase of Electric Energy for any generation resource utilizing the model RDG PPA.(There will be no energy payment for standalone energy storage.) See the response to question R51 above.

R53:

Referring to Section 4.4.1 of the RFP, could you please provide a definition of "facilities' energy arbitrage capability"?

A:

A facility's energy arbitrage capability is its annual proposed energy storage MWh rating (e.g., storage rating in MW multiplied by hours of energy storage duration, multiplied by number of days in a year).

R54:

"For the initial price analysis, an equivalent energy price (Levelized $/MWh) will be calculated for each renewable generation and renewable generation with energy storage proposal based on information provided in the Proposal including the Lump Sum Payment ($/year), Price for Purchase of Electric Energy ($/MWh), and the Net Energy Potential ("NEP") RFP Projection (MWh) information defined in RFP Sections 3.9 and 3.10. For energy storage only proposals, a levelized energy price (Levelized $/MWh) will be calculated or each energy storage Proposal based on information provided in the Proposal including the Lump Sum Payment ($/year), and the facilities' energy arbitrage capability." Referring to Section 4.4.1 of the RFP and beyond what is stated, could you please provide the formulas you will use for calculating the LEP for standalone storage and renewable dispatchable generation proposals?

A:

As stated in Section 4.4, "[t]he Company will employ a closed-bidding process for this solicitation in accordance with Part IV.H.3 of the Framework where the price and non-price evaluation models to be used will not be provided to Proposers." However, for the price analysis, the Company notes that, on a general basis, a levelized cost of energy ($/MWh) will be calculated for each Proposal, which is the net present value of the anticipated payments to the Proposer divided by the net present value of the Net Energy Potential of a generation project or the facility's energy arbitrage capability of an energy storage only project (see the response to question R53).

R55:

Is there any upward adjustment in case the facility production is higher than the NEP?

A:

In the event that the Initial NEP OEPR Estimate, as defined in the model RDG PPA, is less than the Seller's NEP RFP Projection, the model RDG PPA affords the Seller a limited period during which it will have an opportunity, by having a Subsequent OEPR to obtain an adjustment to the NEP OEPR Estimate used to calculate the Lump Sum Payment. However, any such adjustment would be subject to (i) the cap on any upward adjustment imposed by the limitation that the estimate of Net Energy Potential that is used to calculate the Lump Sum Payment shall not exceed the NEP RFP Projection and (ii) the risk that any Subsequent OEPR might result in a downward adjustment to the NEP OEPR Estimate used to calculate the Lump Sum Payment.

R56:

"Provide the details of the major equipment (i.e. batteries, inverters, battery management system), including, but not limited to, name of manufacturer, models, key metrics, characteristics of the equipment, and performance specifications." Referring to Section 2.10.15 of the RFP Appendix B, must the supplier list provided at due date be binding?

A:

Section 3.10.4 of the RFP states, "The Proposer agrees that no material changes or additions to the Facility from what is submitted in its Proposal will be made without the Proposer first having obtained prior written consent from the Company. Evaluation of all Proposals in this RFP is based on the information submitted in each Proposal at the Proposal Due Date. If any Proposer requests any Proposal information to be changed after that date, the Company, in consultation with the Independent Observer, and in consideration of whether the evaluation is affected, will determine whether the change is permitted."

R57:

In the IRS Data Request forms, could you please specify what should be entered into the "Deployment strategy/schedule" field under item 5) Energy Storage System?

A:

That field can be left blank.

The following question applies to the Oahu RFP only

R58:

"The amount of energy discharged from any energy storage component (standalone or one paired with a generation component) in a year will be limited to the energy storage contract capacity (in MWh) multiplied by the number of Days in that year." Does the "limit of maximum yearly discharge from the energy storage component" for Section 1.2.13 apply identically both on Storage Requirement and Contingency Storage (FFR) components?

A:

For Oahu, yes, the Company is treating the Storage Requirement and Contingency Storage function's maximum yearly discharge limit the same.

R59:

Referring to the ESPPA Article 8 Charging Energy Obligations, "So long as the State of Charge is less than 100%, Seller shall take all actions necessary to accept the Charging Energy, as delivered by Company by manual dispatch or automatic signals" Does "100% of State of Charge" refers to the Contract Capacity or the physical installed capacity (i.e. Contract Capacity + oversize needed to ensure performance standard)?

A:

As defined in the ESPPA, "State of Charge" references the energy in the BESS as a percentage of the Contract Capacity. It does not take into account any BESS overbuild that the developer elects to undertake to ensure the facility's compliance with applicable performance standards/requirements.

R60:

Can you please clarify if the three-line diagram needs to submitted with the proposal package or can that be submitted together with the IRS models?

A:

Per Section 2.10.1 of RFP Appendix B, a three-line diagram for the proposed project is required to be submitted with the proposal package on the Proposal Due Date.

R61:

Per Section 5.1 of the RFP and Section 2.11 of Appendix B, can you please confirm that the PSSE/ASPEN/PSCAD models (the "Models") are required at the following times:

  1. For Project with a GCOD in 2022: The Models are required to be submitted with 60 days after the IPP Proposal Due Date (currently November 5, 2019 at 2:00pm HST).
  2. All other Projects: The Models are required to be submitted within 60 days after Selection of Final Award Group (currently May 8, 2020).
    For example, for projects proposed with a GCOD of December 2025, the Models will be required within 60 days after Selection of the Project to the Final Award Group.

A:

We can confirm the accuracy of Items 1 and 2 in your request. For the example provided, a project with a proposed GCOD of December 2025 will be required to submit the required items specified in Section 5.1 of the RFP and Section 2.11 of Appendix B of the RFP within 60 days after selection of the Final Award Group.

R62:

Is a modification to the GCOD considered a minor variation?

A:

A change to a Proposal's commercial operations date would be considered an acceptable variation of a base Proposal, so long as the proposed variation is for a project that is located on the same Site and using the same generation technology as the base Proposal. As stated in RFP Section 1.8.3, variations of a Proposal's pricing terms are also acceptable, subject to the requirements in Section 1.8.3.

R63:

Per Section 1.8.3 it is implied that Proposers can submit multiple technologies for the same Site, so long as Proposer pays $10,000 for each alternative technology. Is it allowable for a Proposer to submit two $10,00 bid fees for the same Site, using two different technologies, along with two fully completed IRS application packages for each technology?

A:

Yes, a Proposer may submit two separate Proposals for the same site with different technologies (including different storage technologies) as long as the Proposer pays the Proposal Fee for each Proposal. Each Proposal must be complete with all required submission information, including a complete package of IRS Data Request worksheets and single line diagrams.

R64:

Will Hawaiian Electric allow Proposers to submit pricing whereby lump sum pricing is based upon current tariffs in place for a certain storage technology, with a clearly defined reduction in pricing should the tariff be removed at a later date?

A:

No, as stated in Section 3.9.1, pricing cannot be specified as contingent upon other factors.

R65 and R66 apply to the Oahu RFP only

R65:

Could you please confirm whether the Contingency Storage must be separate from the storage capacity for standalone storage projects and whether it will require a separate interface to control and separately manage the Fast Frequency Response portion?

A:

No, for Oahu, the physical components of the Contingency Storage and Storage Requirement functions do not have to be physically separate. Provided appropriate controls are designed to ensure both Contingency Storage functions and Storage Requirement functions are achieved, the functionality of both can be provided through common physical components. Also, if the Contingency Storage and Storage Requirement functions are not physically separate, the interconnection and storage ratings must ensure that the functionality of both can be performed simultaneously. Note, this answer does not apply to Contingency Storage for Hawaii island, which has its own specific requirements.

R66:

If a standalone energy storage facility providing both Storage Requirement (e.g., 10 MW/40 MWh) and Contingency Storage (e.g., 10 MW/5 MWh) components, could both components share the same 10 MW of inverters, transformers, and other AC equipment? Both Storage Requirement Contingency Storage components would be controllable through an integrated site-level controller.

A:

No, regular storage and contingency storage cannot share the same inverters and the Facility must have sufficient interconnection capacity, e.g., transformer capacity, to provide the regular storage service and the contingency response at the same time because the contingency response can be called upon at any time including when the regular storage system is being dispatched at maximum output. In other words, if a Facility is comprised of a 10 MW regular storage system and a 10 MW contingency storage system for example, the Facility must be capable of exporting 20 MW at any time. A detailed Interconnection Requirements Study, when performed, may reveal other adverse system impacts that may further limit a project's ability to interconnect and/or further limit the net output of the Facility.

R67:

How is the deposit for the IRS Agreement determined? Is it a % of the total estimated cost to interconnect?

A:

The IRS deposit is intended to cover the entire estimated cost of the IRS "system impact" scope of work as of commencement of the IRS Agreement. It is not a percentage of the total estimated cost to interconnect. A substantial part of the cost includes activities that are project-specific, such as for checkout and testing of each developer's set of detailed project models in PSSE, PSCAD and ASPEN. Transmission & Distribution Planning and Interconnection Services will estimate internal and consultant costs with reference to prior IRS experiences of similar work. This estimated average cost will be a part of the deposit and will be assigned to each project individually, so that actual costs can be tracked to each project account. The deposit also covers IRS system impact analyses where the scope is determined in part by reference to the quantity or portfolio of projects selected in the RFP; part or all of the work is in the form of group studies that consider the combined effects from interconnecting all of the portfolio of projects. Based on estimates from Company resources and consultants, these estimated costs will be prorated across the projects and will be part of the deposit as well. These estimated cost items comprise the basis for the deposit that is expected to cover all parts of the IRS relating to system impact. The subsequent work for the IRS "facilities studies" will be estimated by Engineering and Project Management and conducted under a separate agreement with a separate required deposit.

R68:

Could you please provide us with a Certificate of Vendor Compliance form per Section 2.1 of RFP Appendix B?

A:

The Certificate of Vendor Compliance is not a form to fill out, but rather a certificate that is issued by the State Procurement Office that can be obtained through the Hawaii Compliance Express service at https://vendors.ehawaii.gov.

R69-R73 apply to the Maui RFP only

R69:

Please confirm if the single point of failure limitation is for 20 MW or 30 MW for Maui?

A:

The single point of failure for projects on Maui is 20 MW. Note 9 in Section 2.2.1.2 of Appendix H incorrectly states the single point of failure and should read 20 MW.

R70:

What will the developer be financially responsible for in the new substation to interconnect a Waena Storage project to the Company's system?

A:

Developers proposing projects at the Company's Waena site will be financially responsible for interconnection-related site prep and equipment, including but not limited to:

  • Extension of site access road for access to designated storage site; potential additional costs (shared on a pro rata basis) for traffic mitigation improvements (see Response to R71 below)
  • Circuit breakers
  • Bus disconnect switches
  • Line PTs
  • Take off structures
  • Line relays, control switches, control panels
  • Communications equipment
  • DFRs, meters, PQ meters

See Section 2.3.4 and Appendix F of the RFP.

R71:

Has the Company consulted with the Maui Department of Planning, and specifically the Maui Fire Department, about their requirements for site access and on-site water supply at Waena?

A:

No, the Company has not had any recent conversations with the Maui Department of Planning or the Maui Fire Department regarding the Waena site. The developer should conduct its own due diligence and consult with the Maui Department of Planning and the Maui Fire Department as may be necessary.

There were previous discussions with Maui County Public Works related to traffic related requirements for the Waena site. These requirements include the line of sight requirements, deceleration lane, and driveway entrance requirements that will be addressed under Maui Electric's Waena Switchyard project. Pursuant to the terms of Attachment X (Company-Owned Site) of the model ESPPA, the selected developer will share in the costs to design, construct, operate, and maintain such improvements on a pro rata basis. Please see the Unilateral Agreement and Declaration for Conditional Zoning regarding these required improvements.

R72:

Please confirm the developer is not responsible for the entire construction of the new Waena switchyard.

A:

Confirmed – the developer is not responsible for the entire construction of the new Maui Electric switchyard at Waena. It is the developer's responsibility to design and construct the necessary project interconnection equipment within the Maui Electric Waena switchyard. Depending on the construction schedule for the switchyard, the developer's design and construction could occur parallel to Maui Electric's design and construction process.

R73:

For the standalone storage on a company owned site, can you confirm which substation bay we should plan on connecting to or should we just make an assumption for now?

A:

For the Waena site on Maui, a specific substation bay has not been designated at this time. It is acceptable to make an assumption for the purposes of preparing your Proposal. The Company will work with the selected Proposer to finalize the interconnection design within the yet-to-be-completed Company switchyard currently planned at the Waena site.

R74:

For Government/Public Lands, can you please elaborate on the type of credible and viable plan required to present evidence of site control?

A:

The Company recognizes that it may not be feasible for the Developer to obtain the required site control from a governmental agency within the timeframe of the Proposal. Therefore, the Company would like to see a plan of how the Developer intends to acquire site control within the timeframe required by the applicable RDG PPA or ESPPA. The details of such plan will vary depending on a number of factors, including, without limitation, the different governmental agencies involved, and the site-specific requirements and/or restrictions related to the site. As such, it is impossible for the Company to elaborate on what may be sufficient from a planning standpoint for the site in question. Under this limitation, however, the Company would generally look for evidence of the steps taken toward acquiring site control for the site, which may include correspondence, letters of intent, option rights, permits, approvals, authorizations, commitments (conditional or otherwise) or other items from the applicable government agency with the authority to grant the required site control to use of government land for the Project. The plan would be reviewed to determine the feasibility of obtaining site control for the project (1) for the proposed use by the Developer and (2) within the time required under the applicable RDG PPA or ESPPA.

R75:

Is it acceptable to provide only one set of models at the timeframes required in Section 5.1 of the RFP? This set of models would have grid forming inverters, however the models would not show black start response. Should we be selected to the Final Award Group, we would work to develop a model for black start together with the Company.

A:

Any models that are submitted to the Company should accurately represent the Proposer's Project, utilizing the most up-to-date modeling information provided by the manufacturers. Section 5.1 of the RFP states that for Projects with a proposed GCOD in 2022, the models shall be submitted within 60 days after the submission of the Proposal. For all other Projects, the same complete submittal shall be due within 60 days after selection to the Final Award Group.

For Projects that propose black start capabilities, one set of the Project models representing the normal mode and including grid forming functionality must be submitted within the timeframes specified in Section 5.1. The models that represent the Project's black start mode will be allowed to be submitted at a later date. However, if those models are not received with sufficient time to evaluate prior to GCOD, then the Proposer will not be eligible for the black start rider costs specified in their Proposal submission and PPA.

R76:

From RFP Appendix B Section 2.11.1 - It is not clear which questions on the "IRS_Data_Request_Form" are applicable to the "Models for equipment and controls, list(s) identifying components and respective files (for inverters and power plant controller), and complete documentation with instructions" that can be submitted 60 days later. Will you please tell us exactly which questions can be responded to 60 days after our submittal?

A:

The requirement to provide models is covered in item 7) of the IRS Data Request Forms. The models and model-related documentation identified in item 7) are what can be submitted by the due dates identified in Section 5.1 of the RFP (i.e., 60 days after submission of Proposal for Projects with a proposed GCOD in 2022, or 60 days after selection to the Final Award Group for Projects with a proposed GCOD after 2022). Confirmation that the models and model-related documentation shall be submitted as required under Section 5.1 of the RFP can be inserted into those fields. The rest of the IRS Data Request worksheets and project single line diagram(s) shall be submitted with your Proposal.

R77:

RDG PPA, Article 2.5 (b) PV System Equivalent Availability Factor Performance Metric and Liquidated Damages says: "For each one-tenth of one percent (0.001) by which the PV System Equivalent Availability Factor for such LD Period falls below the PV System Equivalent Availability Factor Performance Metric, an amount equal to 0.001917 of the Applicable Period Lump Sum Payment for the last calendar month of such LD Period"

Could you please provide a definition of Applicable Period LSP? Is it equal to the Adjusted MLSP?

A:

The Applicable Period Lump Sum Payment is defined in the Schedule of Defined Terms of the model PPA. With respect to the total Lump Sum Payment, as adjusted in accordance with Attachment J of the model PPA, the Applicable Period Lump Sum Payment is the portion of the total Lump Sum Payment that is payable for (1) the last calendar month of a rolling 12-month period (i.e., LD Period or MPR Assessment Period, as defined in the model PPA) or (2) the three months of the BESS Measurement Period in question, also as defined in the model PPA.

R78:

RDG PPA Article 14.4 Operating Period Security says: "To guarantee the performance of Seller's obligations under the Agreement for the period starting from the Commercial Operations Date to the expiration or termination of this Agreement, Seller shall provide satisfactory operating period security to Company in the amount of $75/kW based on the Contract Capacity"

For purposes of calculating the required security, does "Contract Capacity" reflect only the nameplate capacity of the generation asset? If Contract Capacity should include BESS capacity, should it be based on rated hourly discharge?

A:

For purposes of calculating the required security, the "Contract Capacity" is the same capacity value (in MW) used to complete item 4 of the Proposal Summary Table in Appendix B of the RFP (labeled as the "Net AC Capacity of the Facility (MW)" in the Summary Table).

The following question applies to the Hawaii Island RFP only

R79:

Could you please clarify us the Point-of Interconnection requirement? The RFP Section 2.2.1 reports the following example:

"For example, a Project must interconnect through a minimum of two transmission lines and no single point of failure resulting in a loss of more than 30MW; however depending on but not limited to, factors such as location of the Point of Interconnection, system load, generating unit dispatch, and transmission line contingencies, the Project may require more than two transmission line termination."

Does it mean that, even if the Allowed Capacity of the Project is below the threshold requirement for a single point of failure (i.e. 30MW), the Project will always require two (2) transmission line terminations, disregarding of the size of the proposed Facility?

A:

Yes, regardless of the size of the proposed Facility, a minimum of two transmission lines (and no single point of failure resulting in a loss of more than 30 MW) will be required (although depending on the circumstances, a Project may require more than a two transmission line termination. Projects with an Allowed Capacity below the size for the single point of failure requirement (i.e. 30 MW for the Hawaii Island RFP) must interconnect to an existing 69 kV transmission line in a 4-breaker ring bus configured in a breaker-and-a-half scheme. See the single line diagram below.

Line Diagram - Single Point Failure

R80:

Is the annual Lump Sum payment that the project will receive subject to a general excise tax like the revenue from the PPA? If so, at what rate?

A:

The Company's understanding is that the Lump Sum Payment would be subject to applicable Hawaii taxes. The Company, however, has not taken any affirmative steps to confirm this statement with the Hawaii State Tax Office. Each Proposer must determine their appropriate tax liability with their own tax consultants, including whether general excise tax is applicable to the Lump Sum Payment, and if so, what the appropriate rate would be.

R81:

We need to understand what the utility's position is with respect to house loads of the facility. Specifically, is it acceptable that facility loads (HVAC, admin bldg., lights, fans, etc) be provided by onsite generation (or storage) or is it a requirement that such loads be handled by a Company feed to the site? If so, what is the Rate Schedule that we would be subject to?

A:

No, facility power relying solely on onsite generation would not be allowed for projects sought in this RFP. For a generation project, a standby generator will be permitted (pending the Company's review and approval) for backup station power at the plant as long as there are at least two station power transformers fed from the grid, such that the loss of one transformer or associated equipment does not require station power to be supplied by the standby generator. Furthermore, the project must be designed such that no power generated by the standby generator will be allowed to be fed to the Company's grid.

However, if the project requires the construction of a new interconnecting switching station, the backup station power for the switching station cannot be supplied by a standby generator and must be from an independent distribution feed, since the switching station will become an integral part of the the Company system.

Additionally, if a generation project shares station power with the interconnecting switching station, the switching station requirements will govern, i.e., an independent distribution feed will be required.

The applicable rate schedule would depend on the amount of load/demand.

R82:

Can the Proposal Fee be paid via a wire transfer or bank draft?

A:

No, the Proposal Fee must be in the form of a cashier's check or equivalent from a U.S.-chartered bank made payable to "Hawaiian Electric Company, Inc." (or "Maui Electric Company, Ltd." or "Hawaii Electric Light Company, Inc." as appropriate) and must be delivered and received by the Company by 2:00 pm (HST) on the Proposal Due Date. The check should include a reference to the Proposal(s) for which the Proposal Fee is being provided. Proposers are strongly encouraged to utilize a delivery service method that provides proof of delivery to validate delivery date and time.

R83:

Instead of requiring the developer to estimate the cost of Company-owned interconnection facilities using the various interconnection equipment cost estimates provided in the RFP, and incorporate those costs into annual lump sum offer price would the Company instead consider providing all bidders with an estimate that all bidders should use for an interconnection at each substation?

A:

No, the Company will not be providing any estimates beyond the approximate per-unit cost figures provided in Appendix H of the RFP. Project cost estimations, including those with respect to the Company-owned interconnection facilities, are the responsibility of the Proposer.

R84:

Does the Company have any concerns if the PPA were to qualify as a capital lease?

A:

It is the Company's assumption that any PPA signed following the Model RDG or Model ESPPA terms are likely to be considered a lease under FASB 840. The Company's primary concern regarding accounting treatment of a PPA signed following the Model RDG or Model ESPPA is whether a project and PPA will cause the Company to be subject to consolidation as set for in FASB 810. See Section 4.3 of the RFP.

R85:

Is the Certification of Counsel required to be completed if we use internal counsel only?

A:

Proposers whose legal counsel represent multiple unaffiliated proposers are required to submit the signed certification. If your internal counsel does not meet this criteria, you do not need to submit the certification.

R86:

The Company has specified that bidders should submit prices without factoring in the state tax credit. However, for the purposes of comparing the proposed pricing in Stage 2 proposals on an apples-to-apples basis with prices of previous projects, will the Company be asking bidders to state what state tax credit they expect to receive? Or if not, what standard assumption will the Company be making about the expected Hawaii tax credit (e.g. 70% refundable) in order to calculate Stage 2 proposed energy prices on a consistent and comparable basis?

A:

Per Commission directive, the RFPs do not require proposers to submit pricing that assumes state tax credits are received. The RFPs also do not require proposers to state the amount of anticipated state tax credits. Accordingly, the Companies will not be asking for such information, nor will they be making assumptions to calculate comparative pricing. The Companies understand that this may not provide an apples-to-apples comparison with previous procurements and do not intend to complete such a comparison.

R87-R88 apply to the Maui and Hawaii Island RFP only

R87:

Does cutting an existing transmission line and interconnecting both sides to the new switchyard, thus creating two independent transmission lines, fulfill the "two transmission line termination" requirement for Maui and Hawaii Island?

A:

Yes, cutting an existing 69 kV transmission line and interconnecting both sides to the new switchyard creates two independent transmission lines which would satisfy the two transmission line termination requirement in the RFP. Please refer to R335, below, for guidance in selecting the appropriate quantity of 69 kV breakers.

R88:

Regarding configuration of the switchyard, the response to RFI R22 indicates a "4-breaker ring bus that is configured in a breaker and-a-half scheme"; however, the sketch attached to that response shows a 6 breaker configuration. Could you clarify the requirement?

A:

Projects with a single point of interconnection ("POI") require a 4-breaker ring bus in a breaker and a half configuration. Projects with two (2) POIs require two (2) breaker and a half schemes. The single line diagrams below show the interconnection requirements for a project with one (1) point of interconnection (POI) and two (2) POIs.

(1) One (1) POI, 4-breaker ring bus in a breaker and a half configuration:

Line Diagram - Single Point Failure

(2) Two (2) POIs, two (2) breaker and a half schemes:

Line Diagram - Double Point Failure

R89:

If an organization has already executed an NDA for the RFP, is a potential Proposer who is a fully-owned subsidiary of that organization also required to execute an NDA?

A:

Although the potential Proposer is a fully-owned subsidiary of an organization with an existing NDA for the RFP, we ask that the Proposer submit its own NDA prior to the Proposal Submission date or as part of a Proposer's Response Package.

R90 and R91 apply to the Maui RFP only

R90:

What is the timing of the Waena Switchyard completion and are we to assume that we will interconnect through this substation?

A:

The Waena switchyard has a tentative date-in-service of September 2022, which is subject to PUC approval. Proposers may assume that a standalone storage project located at the Waena site will interconnect through the proposed Waena switchyard. The Company will work with the selected Proposer to finalize the interconnection design within the Company switchyard.

R91:

Please clarify the two transmission line requirement in 2.2.1 In reviewing Exhibit A of Rule 19 in Appendix I. Also in terms of interconnection costs in Appendix H does the Network Cost of $7.1M include all the relevant costs associated with two interconnections or would we need to assume double this number? It seems that if we are at the 20MW single point of failure we would not need two transmission lines as we would be limiting the single point of failure to 20MW

A:

The "two transmission line termination" requirement means that a Project must be connected to two independent transmission lines at a single Point of Interconnection. A proposed 20 MW project would still require an interconnection to two transmission lines under this requirement. Projects must interconnect to an existing transmission line in a 4-breaker ring bus that is configured in a breaker and-a-half scheme (refer to Appendix H of the Maui RFP). For projects on Maui, this 4-breaker ring bus arrangement must be connected to two independent Company 69 kV transmission lines. In addition, a Project must be interconnected such that the single point of failure limitation is maintained.

The cost of $7.1 million as listed in Section 2.2.1.1 of Appendix H to the Maui RFP is an estimated figure for the cost of building a Company-owned switching station with four (4) 69 kV circuit breakers arranged in a breaker-and-a-half configuration, terminations for two (2) Company-owned 69 kV transmission lines, and one (1) interconnection to a developer-owned renewable energy project. This is the required interconnection arrangement for a 20 MW project. If a project will be larger than the 20 MW single point of failure for Maui, a second interconnection to the developer-owned renewable energy project built into the same Company-owned switching station should be factored into the substation interconnection cost for the Proposal. The estimated $7.1 million substation interconnection cost would not necessarily be doubled in order to host a second interconnection within the same Company-owned switching station.

R92:

With respect to demonstrating Proven Technology, what information pertaining to the manufacturer is required to be submitted?

A:

For the purposes of Appendix B, Section 2.12, manufacturer information, including the experience of the equipment manufacturer, is not required. Other sections of Appendix B, however, including but not limited to Section 2.3.2.2 and Section 2.10.15, and the Interconnection Requirements Study Data Request forms, require Proposers to provide equipment manufacturer information.

Please note that Appendix B, Section 2.12, is intended as a check to ensure that the technology proposed is viable and can reasonably be relied upon to meet the objectives of the RFP. The Proposer must include sufficient documentation to demonstrate instances where the technology being proposed has successfully reached commercial operations at the scale being proposed, and for the Company to assess the commercial and financial maturity of the technology being proposed.

R93:

REFERENCE: RDG PPA Attachment U, Section 1(d) (NEP IE Estimate, Liquidated Damages and Seller's Null and Void Right)
If the circumstances in Section 1(d) prevail i.e. NEP RFP Projection is higher than the NEP IE Estimate or Company Designated NEP Estimate, as applicable, but the Seller does not declare the PPA null and void, then in relation to the liquidated damages payable (i.e. $10 for every MWh by which the NEP RFP Projection exceeds the First NEP Benchmark), are such damages limited only to the initial Contract Year and no further liquidated damages are payable? Please confirm.

A:

Yes, the liquidated damages described in Attachment U, Section 1(d) are only assessed once based on the degree by which the NEP RFP Projection exceeds the First NEP Benchmark for the initial Contract Year.

R94:

REFERENCE: RDG PPA Attachment U, Section 2 (Initial OEPR)
Are we right to understand that the Initial OEPR would be required for every project, following the Initial NEP Verification Date i.e. the first Day of the calendar month following the fifteenth (15th) calendar month after the Commercial Operations Date? Is there any discretion on the part of the Company regarding whether or not to run an Initial OEPR or is the intention that every project would be obliged to have an Initial OEPR? Is the Initial OEPR a once-only event? In the absence of a technical change (as described in Attachment U, Section 3(a)), is the Company entitled to unilaterally request Subsequent OEPRs?

A:

Yes, an Initial OEPR is required for every Project; there is no discretion on the part of the Company regarding this requirement. The Initial OEPR is prepared only once, but subsequent OEPRs may be required by the Company or requested by the Seller pursuant to Attachment U, Section 3 of the model RDG PPA. In the absence of a technical change as described in Attachment U, Section 3(a) of the model RDG PPA, the Company cannot unilaterally require or request a Subsequent OEPR.

R95 applies to the Oahu RFP only

R95:

“Under Appendix H, there doesn't seem to be an option for 2.2.2 Substation Interconnection Costs for standalone energy storage or generation paired with energy storage that intend such storage to meet the Company's Storage Requirement, for a 46 kV line interconnection. What costs should be assumed?”

A:

Standalone energy storage or generation paired with energy storage projects that intend such storage to meet the Company’s Storage Requirement must interconnect at the 138 kV level, and therefore estimates were not provided for such interconnections at the 46 kV level in Appendix H.

R96:

For station service (i.e non-charging energy for the BESS) is it possible to meter through the same GSU's that serve the BESS?

A:

No, a separate meter will be required for station power.

R97:

We understand the RFP requests stamped single-line and three-line diagrams. The drawings we are producing are preliminary, not for construction, and as such we would generally not stamp them until further engineering has been completed. Will the Company accept un-stamped drawings as eligible under the RFP?

A:

No, as specified in Section 2.10.1 of the RFP’s Appendix B, the project design shall include diagrams (including single-line diagram, three-line diagram) approved by a Professional Electrical Engineer registered in the State of Hawaii.

R98:

Per Attachment U, Section 1.a, if the OEPR's NEP is an estimate of the long-term total of production over the facility's first ten years, is it right to assume that we'll arrive at an NEP, using P95 values, that reflects production at roughly Year 5? Is there a problem if this NEP remains the same from the start of contract year 4 until the end of the term?

A:

It would not be correct to assume that the P95 value for production of a facility over a ten-year time period roughly reflects production from the facility in Year 5. Rather, the P95 value represents the energy that the facility is expected to be able to generate in any given year with a probability of exceedance of 95%. This is a common approach that is used in the industry for project due diligence.

It is not necessarily problematic under the Renewable Dispatchable Generation (RDG) PPA structure if the NEP remains the same from the start of contract year 4 until the end of the term. Please note that the NEP is not continually assessed throughout the contract term. Rather it is evaluated at several steps near the beginning of the term as described in Attachment U of the model RDG PPA to verify the capability of the facility; thereafter, subsequent evaluations may be or are required to be undertaken under limited circumstances described in Section 3 of Attachment U of the model RDG PPA. Ongoing performance of the facility throughout the term of the contract is then evaluated using the performance metrics that are identified in Article 2 of the model RDG PPA, which are unrelated to the NEP.

R99:

What is the estimated cost of the IRS Study?

A:

The cost of the IRS depends on a number of factors, including the portfolio and quantity of projects that are selected to be studied and the quality of the required models provided by proposers, but it is roughly estimated to be in the range of $160,000 to $210,000.

R100 applies to the Oahu RFP only

R100:

We are proposing a generation project paired with storage that will not reach COD until 2023. Our understanding is that this project will NOT be eligible to meet HECO's storage need. Please confirm? Also, is HECO still interested in the option of charging this project from the grid during the first five years of commercial operations, for projects with COD 2023 or later? Or is this option only desired for projects than can meet HECO's storage need parameters?

A:

Yes, the GCOD later than 6/1/2022 would make this not eligible to meet the Storage Requirement need in the RFP. Yes, the Company is still interested in the option of grid charging the storage during the first five years of commercial operations even for generation paired with energy storage projects with GCODs later than 6/1/2022.

R101:

Where do we find the PSCAD Technical Memo and the Transient Overvoltage (TrOV-2) policy?

A:

The PSCAD Technical Memo can be found in the RFP’s Appendix B Attachment 5. It has also been placed into PowerAdvocate’s “1. Download Documents” tab. The TrOV-2 policy identified in the IRS data Request Forms can be found here. A link in that document will take you to “Attachment F – Transient Overvoltage Guidelines”.

R102:

Can we submit our Interconnection Request using PSLF instead of PSSE software?

A:

No, the Company requires the models requested in the IRS Data Request Forms.

R103:

Can we submit a complete package of IRS Data Request and single line diagram only for the base case proposal or is it also required for the variations?

A:

For each variation, if any of the Proposal information differs from the base variation, then it must be identified as specified in the format instructions in Appendix B of the RFP. IRS Data Request forms and single line diagrams are subject adhere to the same requirements. If aspects of the variation are identical to the base proposal, then they do not need to be resubmitted. However, if information differs for a variation, then the required information for the variation needs to be submitted.

R104:

Can you confirm that multiple proposals for multiple sites can be submitted under a single Power Advocate username? Per the response to R2, we understand that each project is limited to one site, and one technology, per Bid Fee. Can you please confirm that so long as we comply with RFP Sections 1.8 and RFP Appendix B that we may submit multiple Proposals under the same Power Advocate username?

A:

No, different sites or different technologies will necessitate different proposals with separate Proposal Fees and separate PowerAdvocate registrations and Supplier accounts. (Review the instructions and requirements in RFP Appendix B.)

A variation of a Proposal (that can be submitted under the same PowerAdvocate registration) would be variations of pricing terms, facility size, with or without storage, etc. at the same site using the same technology and adhering to all the requirements in the RFP (including Section 1.8).

R105:

Reference: Clarification Q&A R34, RFP - Section 3.10.1
Please confirm the statements below:

  1. For a renewable generation + energy storage (RES + ESS) facility, it is possible to oversize the generation capacity (e.g. MW of a PV power plant) above the Allowed Capacity.
  2. When the RES (e.g. PV power plant) is producing at higher power than the Allowed Capacity, in any event the excess cannot be dispatched into the grid and it shall be diverted to the ESS, up to the maximum capability of the ESS to accept the excess (until SoC max). The energy produced beyond this capability shall be curtailed;
  3. All the energy produced by the RES shall be included in the NEP estimation, regardless of whether it is generated at higher power than the Allowed Capacity, as long as the ESS has enough storage capability to accommodate the excess.
  4. The NEP shall not be corrected to account for losses due to ESS charging and discharging, including auxiliary consumption during stand-by.
  5. Please confirm that “Facility’s Allowed Capacity” of 3.10.1 of the RFP has the same meaning of “Allowed capacity” of the clarification R34
  6. In case production in excess of the Allowed capacity is expected due to renewable generation system oversizing, would an ESS oversizing also be required to accommodate the excess energy coming from the RES (on top of it being able to discharge energy for 4 hours at power equal to Allowed Capacity)?

A:

  1. Yes. To be clear, however, the import (i.e., ESS drawing energy from the grid) and export of the Facility must be self-curtailed by the Facility to the Allowed Capacity.
  2. Yes, the Facility must self-curtail so that it never exceeds the Allowed Capacity.
  3. Yes, confirmed.
  4. Yes, confirmed.
  5. Yes. Both have the same meaning as the Allowed Capacity defined in the model PPA.
  6. No, storage is not required to be oversized above the 4 hour requirement identified in RFP Section 1.2.10 in the case where production in excess of the Allowed Capacity is expected. However, proposers may optionally choose to propose a larger ESS if significant over generation with respect to the Allowed Capacity is expected and if they feel that a larger size would be required in order for the Company to be able to utilize all of the energy generated from the Facility.

R106:

Reference: RFP - Section 1.2.11
In RFP Section 1.2.11, the following is stated: “For energy storage components that are paired with generating facilities, during the period that allows the Project to maximize and capture the benefits of the federal Investment Tax Credit (“ITC”) for the energy storage system, the Proposer can design and specify the amount, if any, of grid charging for the energy storage system.” Being the energy storage a bidirectional system, it is, in principle, always able to charge from the grid. Shall we therefore assume that the amount of grid charging specified by the Proposer is already included in the energy storage components 4 hours discharge requirement, without any oversizing specifically for the grid charging amount?

A:

Yes. The intent of that paragraph in Section 1.2.11 is to offer a Proposer the option to offer the benefits of a partially grid-charged storage facility while still qualifying for some portion of the federal ITC.

R107 applies to the Maui RFP only

R107:

Is there any flexibility to allow developers more land than the 1.8 acres for a standalone storage project at the Waena?

A:

Maui Electric is willing to consider developers' requests for additional land at the Waena site. Please refer to Q6 on the Waena Site Visit Questions and Answers page.

R108:

For the storage component of a PV + Storage bid, does HECO have a preference for AC or DC connection?

A:

The Company conveys no preference on the question of AC or DC coupled storage.

R109:

Will the Company consider proposal submission for a 25 year term for a project bid into the 2019 RFP?

A:

The Company does not have a preference for the length of the contract term for proposed projects. A 25 year contract term may be proposed. The Proposal Contract Term will be determined by the Proposer, and shall be indicated in the Proposer's response to Item 8 in the Proposal Summary Table shown in Section 2.0 of Appendix B. Variations of a Proposer's base variation Proposal may include a different Proposal Contract Term length in accordance with RFP Section 1.8.3.

R110:

Are there file size limitations for uploads?

A:

As stated in Step 4 of Section 1.2 in Appendix B of the RFP, there is no limit to the number or size of files that can be uploaded. Multiple files may be grouped into a .zip archive for upload. Please refer to Appendix B of the RFP for additional information.

R111:

Is the lump-sum price in a proposal intended to include the PV panel degradation factor (i.e. 0.5%/year) such that the dollar amount would remain flat over the term of the PPA? Or should the lump-sum payment proposed ignore degradation because the lump-sum payment will be reduced annually by the Company based on the degradation factor?

A:

The lump sum payment is intended to remain constant over the term of the PPA. The lump sum payment will be subject to downward adjustments per the conditions of the RDG PPA. A degradation factor is accounted for in the RDG PPA in the application of the MPR Performance Metric and associated liquidated damages.

R112 applies to the Maui and Hawaii RFPs only

R112:

In the 2019 HELCO Wind RDG PPA for the Island of Hawaii and Maui, the ramp rate definition differs slightly than for Oahu. In the case of a wind only bid, we would like to confirm that the downward ramp requirement allows for a rapid loss of wind resource as an exception to the 2MW/minute ramp rate threshold. Would HELCO be willing to consider a slight modification to the Ramp Rate Performance Standard language to clarify that a rapid loss of wind resource is an acceptable exclusion from the 2MW/minute downward ramp threshold?

A:

The ramp rate requirements in the Hawaii Island and Maui Model Wind PPAs are intentionally different from that of Oahu. Given that the smaller systems on Maui and Hawaii Island are attempting to achieve significant contributions from variable renewable resources in the near term, new resources cannot put a greater ramping burden on other resources and are expected to self-mitigate their uncontrolled resource-driven ramping. While a large load shifting storage is not necessarily required to be paired with a new wind project, a smaller storage device or potentially other ancillary equipment that can keep the uncontrolled ramp within the 2MW limit must be provided.

R113:

The term “Environmental Derate” is capitalized but not defined in the Wind PPA. Can HELCO please provide the intended definition of the term (Environmental Derate), or is it expected that the Proponent will provide its own definition?

A:

The Performance Index metric specified in the Model Wind RDG PPA utilizes an information model defined in Figure D.4 of the 2019 North American Electric Reliability Corporation (NERC) GADS Wind Turbine Generation Data Reporting Instructions. Proposers may propose a definition for the Environmental Derate term to be included in the Wind RDG PPA, however this definition should be consistent with its usage in the NERC GADS Wind Data Reporting Instructions.

R114:

We intend to submit multiple proposals using distinct IDs. Under each account should we upload the same sets of documents i.e. Confidentiality NDA's, Certificate of Good standing etc. or should we just upload that once in the primary account and only the distinct proposal and any files specific to that proposal under the other IDs?

A:

Each proposal must be complete. Proposal variations (submitted within a single PowerAdvocate Supplier company/username) will identify only the distinct information that differs from the base variation (per the instructions in Appendix B of the RFP). But separate proposals must provide all requested information to be complete.