skip to main content

Selling Power to the Utility

CBRE RFP Questions & Answers

For LMI, Tranche 1, Molokai and Lanai CBRE RFPs

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


Q1:

[Posted 09/2020; Updated 02/16/2021] For Lanai, would a proposal for less than 3MW of CBRE be considered, or a proposal which provides a tiered CBRE credit rate based on the amount of CBRE subscribership?

A1:

The 3MW requirement is based on the Commission's directives in Order No. 37070. As stated in Section 1.2.3 of the revised draft Lanai CBRE RFP filed October 6, 2020:

The proposed Projects must reserve 3 MW of the contract capacity for the Project's CBRE portion (the "CBRE Project"). Throughout the term of the Renewable Dispatchable Generation Power Purchase Agreement (RDG PPA), the Proposer shall endeavor to achieve 3 MW of CBRE subscriptions at all times and will be required to accept eligible CBRE subscriptions up to 3 MW. Notwithstanding the required 3 MW CBRE Project capacity, only the first 1 MW of CBRE Project capacity shall be subject to the CBRE Project subscription requirements for (a) number of CBRE Subscribers, (b) limit on percentage of Unsubscribed RDG for the CBRE portion of the Project, (c) minimum percentage of residential Subscribers and (d) any Proposer-submitted Low to Moderate Income ("LMI") Subscriber percentage for the CBRE Project. Accordingly, and to ensure understanding of the above, at least 1 MW of CBRE subscriptions is required for purposes of determining whether liquidated damages are assessed under Rule 29, and the CBRE Project will not be measured or assessed liquidated damages on CBRE subscriptions above 1 MW. Such provisions are more fully set forth in the RDG PPA.

The revised draft Lanai CBRE RFP follows the proposed Tariff Rule 29 which sets up a tiered compensation system for unsubscribed interests based on the unsubscribed percentage above 15%. That being said, a tiered CBRE credit rate based on subscribership will not be considered.

Q2:

[Posted 09/2020; Updated 02/16/2021] For Lanai, would a proposal for less than 40% of residential CBRE be considered, or a proposal which provides a tiered CBRE credit rate based on the percentage of residential subscribership?

A2:

In the revised draft Lanai CBRE RFP filed on October 6, 2020, the requirement was updated based on the required 1 MW of subscriptions for the CBRE Project. Therefore, proposed Projects must reserve a minimum of 0.4 MW for residential Subscribers. Preference will be given to proposed Projects that reserve an amount greater than 0.4 MW for residential Subscribers through evaluation of the Non-Price scoring criteria. A tiered CBRE credit rate based on residential subscribership will not be considered.

Q3:

[Posted 09/2020] For the Lanai and Molokai RFPs, would the RFP team consider extending the due date for the three line diagram to match the due date specified in Section 5.1.2 for the IRS models, which is 30 days after final award?

A3:

The Company has extended the due date for three-line diagrams for the Molokai and Lanai RFPs to match the due date for the IRS models, which is 30 days after selection of the Final Award Group. For the Oahu, Hawaii and Maui LMI RFPs, the due date for the three-line diagram will remain at the deadline of Proposal submission.

Q4:

[Posted 09/2020] How do I get an exception if the property is located in a Tsunami Evacuation Zone? Location has available hosting capacity and near distribution circuits.

A4:

An exception to the Eligibility Requirement in Section 4.2 of the RFP draft will not be granted for properties located in a Tsunami Evacuation Zone.

Q5:

[Posted 09/2020; Updated 02/16/2021] What is the Company seeking on Lanai and can the CBRE portion be a separate facility?

A5:

As stated in the introduction to the Request for Proposal for Variable Renewable Dispatchable Generation Paired with Energy Storage and CBRE for the Island of Lanai: "The total amount of variable renewable dispatchable generation being solicited in this RFP is 35,800 megawatt hours ("MWh") annually of photovoltaic ("PV") paired with energy storage in a single project. The energy storage must be sized to store at least 70 percent of the photovoltaic energy. Of the total amount of capacity being solicited a minimum of 3 MW must be reserved for Community-Based Renewable Energy ("CBRE").

No, the CBRE portion cannot be a separate facility. The Company plans to select a single project in the Final Award Group.

Q6:

[Posted 10/2020; Updated 04/26/2021] Can you confirm the only two RFPs being released this year are the Lanai and Molokai RFPs? I see RFPs for Hawaii, Maui, and Oahu in the tariff, but nothing on the website indicating there is anything more coming up besides Lanai and Molokai.

A6:

On March 30, 2021, the Companies filed updated draft RFPs for the CBRE program, which cover Oahu, Maui, Hawaii Island, Lanai and Molokai in accordance with Order No. 37592 (PDF) issued by the State of Hawaii Public Utilities Commission (Commission). The RFPs are subject to Commission approval. Timing of issuance, as well as the substance of the RFPs, will therefore depend on Commission approval and any associated Commission guidance.

The Company has also developed a Navigation Guide (PDF) to assist with identifying various parts of each RFP, which include:

  • CBRE Low- and Moderate-Income Request for Proposals for Oahu, Maui and Hawaii Island
  • CBRE Tranche 1 Request for Proposals for Oahu, Maui, Hawaii Island
  • CBRE Request for Proposals for the Island of Molokai
  • Request for Proposals for Variable Renewable Dispatchable Generation Paired with Energy Storage and CBRE for the Island of Lanai

Q7:

[Posted 10/2020; Updated 04/26/2021] If a project utilizes storage, can a developer propose a system that its size is greater than the available capacity of the distribution line that it is interconnecting to? If the answer is yes, how many hours of storage is required?

A7:

In general, proposed Project output cannot exceed the available distribution circuit hosting capacity limit during the daytime hours of 8am to 5pm. The proposed Project output at all other hours (5pm to 8am) cannot exceed the identified conductor limit (less any existing or expected generation sources available during those hours prior to the GCOD). For example, a solar resource paired with storage, and proper controls in place, may interconnect to a distribution circuit with a stated hosting capacity of zero provided that only an acceptable energy level, if any, is exported during the hours of 8am and 5pm and the export of power, if requested by the Company, does not exceed the conductor limit after 5pm.

Notwithstanding any economic impact in the evaluation of such project proposal, the addition of storage could be used to mitigate daytime constraints between the hours of 8am and 5pm; for example, sufficient storage to store 100% of produced energy during this period on a daily basis could mitigate the inability of the Company System to accept any energy during the daytime hours by permitting the export of such energy to the Company System at night, subject to the conductor limit.

Ultimately, with the explanation above, the short answer to the first question is yes, a developer may propose a paired system (generation paired with battery storage) with a proposed generating output that is greater than the available capacity of the distribution line that it is interconnecting to, however, such a proposal will be evaluated taking into consideration all such constraints, and will be compared to other proposals which may not be subject to similar constraints. Also, please note, any such circuit constraint must be mitigated using the Seller's proper local control scheme, and with allowance for future adjustment at the direction of the Company. As to the second question, please see below with the caveat that the requirement is a minimum -- how much storage above the minimum for any particular system will still be the decision of the proposer.

Refer to Section 1.2.11 of the proposed LMI RFPs which states:

The storage battery energy storage system (BESS) component of a Paired Project will be charged during periods when full potential export of the generation component is not being dispatched by the Company, and the BESS component can be used to provide energy to the Company during other times that are beneficial to the system. The BESS component of a Paired Project must be sized to support the Facility's Allowed Capacity (in MW) for a minimum of four (4) continuous hours1 throughout the term of the RDG PPA or Mid-Tier SFC.

For example, for a 2 MW facility, the BESS component must be able to store and discharge at least 8 MWh of energy at 2 MW in a cycle throughout the term of the Mid-Tier SFC.

Please also refer to section 3.10.1 of the draft LMI RFP, which includes the BESS sizing requirement for inclusion of PV capacity above the Allowed Capacity in the NEP:

For Paired Projects, the energy generated by the Facility in excess of Company dispatch but below the Facility's Allowed Capacity that is stored in the Facility's BESS component and can later be discharged to the POI [point of interconnection] considering the BESS Contract Capacity and Maximum Rated Output should be included in the NEP RFP Projection. Any energy in excess of what is allowed to be delivered to the POI and would exceed the BESS Contract Capacity shall be excluded from the Net Energy Potential. To achieve this objective, the BESS Contract Capacity (MWh) must be at least four times the MW Capacity of the installed PV Capacity.

1 Proposed projects on Lanai must include storage sized to store at least 70% of the photovoltaic energy.

Q8:

[Posted 10/2020; Updated 04/26/2021] If a project design is sized to be smaller than available capacity of a line (what LVM shows), does it still need to pair it with storage? Could a project get rejected if designed with no storage?

A8:

The Proposer is solely responsible for the development and design of its Proposal and whether to include storage is the Proposer’s option in the LMI and Tranche 1 RFPs. The evaluation process explained in the respective RFP’s will be used to determine which proposals are selected to the Final Award Group. Storage is not a threshold requirement in the LMI and Tranche 1 RFP’s and a proposal will not automatically be rejected if it does not include storage. Pursuant to Section 1.8.2 of the draft Tranche 1 and LMI RFPs, the Company invites Proposers to submit up to a total of two variations of their Proposal for each Proposal Fee submitted. A Proposal with or without storage or variations in pricing terms may be offered as variations. Please also refer to Appendix I of the draft CBRE RFPs, which provide a high level Grid Needs Assessment to assist you in designing your proposal.

To answer your question as to whether a project could get rejected if designed with no storage, the answer is no, except on Molokai and Lanai where storage is a requirement. For the LMI RFPs, the project will not automatically be rejected if there is no storage in the Proposal. However, for the islands, solar projects are combined with storage primarily to allow for energy shifting. The storage provides the ability to shift energy production to periods of higher demand. There is a substantial amount of solar energy existing and more planned in the near term. Therefore, without storage, the Company will be unable to directly accept all the energy production due to limited system demand during solar production hours. (For this reason, a storage sized at approximately four times the solar capacity is recommended to allow deferral to higher production periods). The absence of storage may limit the Company's ability to dispatch the full NEP when a paired project may mitigate the system load constraint. The detailed evaluation as outlined in Section 4.7 of the LMI RFP will evaluate the benefits and costs to dispatch a project.

Q9:

[Posted 10/2020; Updated 06/16/2021] If the Locational Value Maps are not able to provide the available hosting capacity on a distribution circuit, will a general question asking what the maximum available hosting capacity for that distribution circuit be entertained?

A9:

Regardless of whether hosting capacity information is available via the LVMs, “Proposers are encouraged to inquire about the viability of interconnecting a proposed Project at a specific location.” (See Section 2.2.1 of the LMI and Tranche 1 CBRE RFPs and Section 2.2 of the Molokai CBRE RFP.) Proposers should submit an email to cbrerfp@hawaiianelectric.com and provide the following Project specifics:

  1. a map showing the Point(s) of Interconnection,
  2. the capacity of the PV generation (MW), and
  3. (if applicable) the size of BESS (MW/MWh);

The Company will respond whether that Project appears to be capable of interconnection, pending later load flow analyses and a detailed IRS that could reveal other adverse system impacts.

Steady state modeling is used to determine the available hosting capacity when the Locational Value Maps do not provide the information. The modeling analysis requires time and specifics on interconnecting a Project to determine whether the Project can safely fit onto the circuit, or if a violation or constraint occurs when adding the proposed Project. Thus, general inquiries asking what the maximum available hosting capacity is for a distribution feeder cannot be entertained – modeling of all circuits on all islands for all ranges of projects has not been performed.

Limitations in resources require requests to be queued. In fairness to all developers, requests will be queued in the order they are received. A developer may submit only one request at a time, but that request may include up to 5 scenarios. Once results for a request are provided to the developer, that developer may then submit additional requests.

Developers considering multiple projects in close proximity, should be aware that one of their projects may impact the other if both are selected, and that submitting requests for the combined impact multiple nearby projects (3 maximum) constitutes a separate scenario subject to the limit of 5. For example, the items below would constitute 3 separate scenarios:

  • Site 1: 2 MW PV + 2 MW / 8 MWh BESS
  • Site 2: 1 MW PV with no BESS
  • Site 1: 2 MW PV + 2 MW / 8 MWh BESS & Site 2: 1 MW PV with no BESS

When submitting multiple scenarios, developers should list them in order of priority. The Company will try to provide responses in that order but does not guarantee that the scenario results will always be returned in the prioritized order.

[For Oahu Only] Any requests for information on circuit capacity on sub-transmission lines will also count as a separate scenario.

Additionally, if you have more than one request, please indicate the order of priority with which our team should begin to address your questions. We will then provide you the results as they become available in your priority order.

Q10:

[Posted 10/2020] Can the Company provide an approximate cost of the IRS costs for a CBRE project? It is understood the costs are highly site dependent, however the bidders would greatly appreciate a range of estimates for the costs before the bidding deadline.

A10:

Although the Company cannot provide an estimate of the costs for system impact study (SIS) and facility study (FS) (together, the Interconnection Requirements Study or IRS) for each individual proposal, the Company understands that these costs must be considered in the development of Proposals.

Cost of the SIS: The scope of the SIS can greatly vary depending on many factors, including but not limited to the size or location of the project, equipment used, the state of equipment models, interconnection constraints, and potential mitigation. Given the numerous variabilities in scope of the SIS, the associated cost of the SIS will vary greatly as well. Based on limited historical data, which have not been adjusted to current year dollars, SIS cost on past projects interconnecting to distribution circuits have ranged from $35k to $100k.

Cost of the FS: The scope and therefore cost of the FS also varies, depending on the circumstances and specifics of the project in question. Based on limited historical data, which have not been adjusted to current year dollars, FS cost on past projects interconnecting to distribution circuits have ranged from $35k to $50k.

Providing these ranges does not guarantee that the FS and SIS costs would fall within the stated ranges. The estimated costs are provided solely to assist potential proposers with a high level estimate, and in no way should these figures be used as a firm or guaranteed cost.

Q11:

[Posted 11/2020; Updated 02/16/2021] With the PUC amending the procedural schedule on October 8, 2020 to incorporate a period for parties and participants to submit comments until October 26, 2020, will the RFP team be issuing an amended RFP schedule for the LMI, Molokai, and Lanai RFPs being that it that a final RFP was not issued on October 20, 2020? Can you please advise what the impact and adjustments will be to the final RFP date, proposal due dates, and selection of final award groups and contract negotiations start date?

A11:

Please see Q&A #20 below.

Q12:

[Posted 12/2020] Can multiple projects be located on the same parcel of land or TMK?

A12:

Multiple projects can be located on a single parcel of land or TMK as long as each project has a separate point of interconnection with the utility's electrical grid. If projects on the same parcel share a point of interconnection, their respective capacities will be combined and treated as a single project. See the "Co-location" section of the draft Rule 29 filed on September 8, 2020 in Docket 2015-0389.

Q13:

[Posted 12/2020; Updated 02/16/2021] The Lanai RFP (as filed on 10/6/20) solicits 35,800MWh of PV paired with energy storage, however all subsequent references to the P95 NEP projection do not reference this amount, and within the RDG PPA the amount is listed as a blank to be filled in (Attachment U 1b). Please confirm whether a P95 NEP of 35,800MWh per year is a threshold criterion or non-price criterion of the RFP and if so, whether there is a minimum amount of energy sought and what this value is.

A13:

The Lanai RFP (as filed on 10/6/20) solicits 35,800 MWh of PV paired with energy storage, thus the P95 NEP for a single project must be at least 35,800 MWh in order to meet the solicitation.

Q14:

[Posted 12/2020; Updated 02/16/2021] For the Lanai RFP (as filed on 10/6/20), please clarify whether the daily discharge energy capacity of the BESS must be equal to or greater than 70% of the daily average of the proposer's P95 annual net energy production (NEP) projection. In other words, should the BESS discharge energy capacity in MWh >= (P95 annual NEP in MWh)/365 days x 0.7?

A14:

The BESS Contract Capacity must be capable of storing and discharging 70% of the PV produced energy. For an average day, this would mean the Net Energy Potential divided by 365 days times 0.70.

Q15:

[Posted 12/2020; Updated 04/26/2021] For the Molokai CBRE RFP (as filed on 9/8/20), in Appendix H Interconnection Facilities and Cost Information, please advise whether the scope of work and costs listed in Section 2.3 Typical CBRE SLD Interconnection Costs (Projects 1MW or greater) should be included as a cost for a project proposed at the Palaau Generating Station or if the $600k cost listed in Section 2.4 Palaau Interconnection Costs is inclusive of what is listed in Section 2.3. Please provide clarification as needed to properly identify and estimate the interconnection cost for a project proposed at Palaau Generating Station.

A15:

Appendix H (Interconnection Facilities Cost and Schedule Information) was broadly updated both in content and in organization in the draft CBRE RFPs filed by the Companies on March 30, 2021 in Docket No. 2015-0389. As a result, this specific question is no longer applicable, and instead, the Company recommends prospective proposers review the revised document in its entirety. Section 2.1C of the revised Appendix H (PDF) addresses projects interconnecting to the Pala‘au Generating Station.

Q16:

[Posted 12/2020; Updated 02/16/2021, 04/26/2021] For both the Molokai CBRE RFP (as filed on 9/8/20) and Lanai RFP (as filed on 10/6/20), are costs associated with the Revenue Metering Package mentioned in the RDG PPA and Mid-Tier SFC included as a cost in Appendix H? If so, please point to the section and if not, please provide an estimate as to what this cost would be for the equipment and installation.

A16:

Appendix H (Interconnection Facilities Cost and Schedule Information) was broadly updated both in content and in organization in the draft RFPs filed on March 30, 2021 by the Companies in Docket No. 2015-0389. Please review the revised document in its entirety. The costs shown in Appendix H include estimates for all of the Company’s work based on the listed assumptions. This includes costs for revenue metering work which are embedded in the Substation & Meter Baseline Costs (Item 21 in Appendix H for Lanai, and Items 1, 10, and 21 in Appendix H for Molokai) and shown in the corresponding single line diagrams included as attachments to Appendix H. Appendix H for each CBRE RFP can be found via the Navigation Guide (PDF) the Company developed to assist developers with finding specific sections of the draft RFPs filed on 3/30/21.

Q17:

[Posted 01/2021] The Molokai CBRE RFP (as filed on 9/8/20), Exhibit 8, Appendix F Description of Available Sites, Page 3 states that: "Proposers must observe a 20' horizontal clearance on one side of 12 kV conductor and poles. PV may be installed under the existing 12 kV lines, but requires a minimum 8' vertical clearance from the conductors for personnel safety. This is per Hawaiian Electric Standard 41-5010 and will require Company review and approval. Proposers may request this standard from Company." Please confirm whether these requirements are complete and referencing all applicable standards.

A17:

Below are revisions and clarifications to item 4.b. of Appendix F:

  1. Vehicular access (for the Company's bucket/boom trucks) and working clearances should be provided to all existing overhead Company facilities to allow for safe and efficient maintenance and replacement of those facilities.
  2. PV panels may not be installed under existing lines for safety and operational reasons.
  3. Hawaiian Electric Standard 41-5010 does not apply, as that standard is for substations. NESC 2002 clearances are required at a minimum, but those clearances may need to be larger to account for working clearances.
  4. On one side of the 12kV line plan for 25ft horizontal working clearance to the nearest energized facility (typically the edge of the crossarm or outside conductor). This clearance space shall extend 40ft past any dead-end pole. This space is for the Company's large vehicles to set up and operate to perform work on the lines.
  5. On the other side of the 12kV line, plan for 10ft horizontal working clearance to the nearest energized facility. This clearance shall extend 10ft past any dead-end pole.
  6. Guy wires should have at least 2.5ft clearance on each side of the guy and should extend at least 3ft past the anchor.
  7. Please note that the clearances provided above are typical clearances and do not take into account site-specific details. They are to be used for planning purposes only and are subject to change depending on the specific circumstances once the Company reviews any proposed layout. The larger clearance between the NESC required clearances and the working clearances described above shall be used.

Q18:

[Posted 02/16/2021] Please confirm the TMK of the Company-owned Palaau site on Molokai.

A18:

The TMK for the site is (2)5-2-011:031.

Q19:

[Posted 02/16/2021] How many customers does Hawaiian Electric serve on Molokai? Of those, how many have Distributed Energy Resources (e.g. rooftop solar) installed, and how many are currently enrolled in the LIHEAP program? Please provide a breakdown of residential and commercial customers, if possible.

A19:

Hawaiian Electric serves approximately 3,300 customers (2,700 residential) on the island of Molokai, of which approximately 450 customers (420 residential) have Distributed Energy Resources installed. Approximately 200 customers are approved for the LIHEAP Energy Credit program.

Q20:

[Posted date 02/16/2021] Please provide an update to the schedule for releasing the CBRE RFPs.

A20:

On January 29, 2021, the Commission issued Order 37592, directing the Company to work with the Parties and Participants in the CBRE proceeding to develop recommendations for improvements to the interconnection process and other specified aspects of the CBRE program. These recommendations are due by March 30, 2021, and comments to those recommendations are due by April 14, 2021. Therefore, it is unlikely that the RFPs will be issued until a period of time after April 14, 2021. The Company cannot speculate with any more specificity on when the RFPs will be released at this time.

Q21:

[Posted 3/22/21] Please provide any additional information that will assist in defining the boundaries for the Company-owned site on Maui (Waena), as shown in Exhibit C of Appendix F of the draft Maui Tranche 1 RFP (filed 12/1/20).

A21:

The boundaries for the site are approximately 1,150 ft at its widest (on the sides running parallel to Waiko Road), and approximately 340 feet deep (toward the interior of the property, away from Waiko Road). Developers would be allowed to use up to 8.65 acres of land.

Q22:

[Posted 04/26/2021] Would the Company be open to renewing or signing a new contract with Seller at the end of the 20 year term of the Power Purchase Agreement, given that the PV infrastructure will likely be viable for another 10-15 years?

A22:

The term of the respective power purchase agreements for the CBRE program have been set by the Commission. Whether such term may be extended will be subject to further Commission guidance and order. The Companies cannot speculate on the prospect of an extended term for CBRE projects after the initial 20-year term ordered by the Commission.

Q23:

[Posted 04/26/2021] The cost of pumping water for irrigation has made farming a particular site unfeasible. Can we develop a CBRE Facility on this land to help provide water to this location more economically?

A23:

Section 8.1 of the Draft CBRE Model RDG PPA states that “[b]ecause the Facility must be available to respond to Company Dispatch, neither the Subscriber Organization nor the Facility may consume any energy generated by the Facility.” Similar language can also be found in Section 5.A of the Mid-Tier SFC. As a result, energy generated by a PV facility participating in the CBRE program cannot be used to provide energy for farming operations or any other purposes.

Q24:

[Posted 06/02/2021] How is a Project’s capacity (MW) determined?

A24:

A Project’s capacity is the net maximum output (MWac) of the Facility at the point(s) of interconnection, based on: nameplate power rating of energy generating equipment; expected losses in delivery of power to the point(s) of interconnection; and/or any project control system involved in managing the delivery of power to the point(s) of interconnection. This value, subject to verification by the Company, will determine how a project is evaluated relative to the terms and requirements of the RFP, including, but not limited to: classification as a Mid-Tier or Large Project, ability to interconnect to a distribution circuit, impact to circuit hosting capacity, and validation of the maximum output levels used to calculate the NEP RFP Projection. For the purposes of calculating the NEP RFP Projection it should be assumed all energy is being delivered directly to the point(s) of interconnection from the renewable resource as it is generated and never in excess of the Project’s capacity, independent of the existence of any storage device. In the applicable PPA, this value will be the default Contract Capacity.

The definition above applies regardless of whether a project includes a battery component, also referred to as a “paired project.” However, please note that paired projects without control systems to limit their output to the Project capacity will be evaluated at the highest possible combined net power output of the PV generation and the battery component for performing circuit level analysis.

A Project’s capacity should be entered in Line 4 of the Summary Table in Section 2.0 of Appendix B of each CBRE RFP.

Q25:

[Posted 06/02/2021] For interconnection at the Palaau Power Plant site on Molokai, please clarify whether a project between 1 MW and 2.2 MW requires two points of interconnection. The final note on the single line diagram included as Attachment 3 to Appendix B of the Molokai CBRE RFP states, “No single point of failure from the plant shall result in a decrease in net electrical output greater than 2.2 MW. In addition to meeting this requirement the plant shall be segmented in equally sized capacities.”

A25:

Projects located at the Palaau site between 1 MW and 2.2 MW would not require two points of interconnection, since a single point of failure would not result in a decrease in net electrical output greater than 2.2 MW. The note that the project must be “segmented in equally sized capacities” is intended as a requirement for projects greater than 2.2 MW only. By way of example, a proposed 2.5 MW project should be segmented into two 1.25 MW sized capacities with a separate point of interconnection for each in order to satisfy the two requirements in the quoted excerpt.

Q26:

[Posted 06/02/2021] Please confirm if degradation related to the renewable generation facility should be taken into account for the NEP RFP Projection and how responses that do not incorporate degradation will be evaluated.

Further, please confirm that how the NEP RFP Projection should account for losses from the energy storage component, such as during charging and discharging or auxiliary consumption.

A26:

The discussion below applies to all of the CBRE RFPs (LMI, Tranche 1, Molokai, Lanai) and applicable PPAs (All-Island Mid-Tier SFC, Oahu RDG PPA, Lanai RDG PPA).

The Company does not specifically require that degradation of the generation facility be included in the NEP RFP Projection as part of a Proposal. However, it is the responsibility of Proposers to properly account for factors which may impact the potential output of their proposed Facility. Further, adjustments to the NEP RFP Projection will be assessed by an Independent Evaluator (IE) during the course of Project development and operations in accordance with the applicable PPA; therefore, not including factors such as degradation, which can be legitimately included in an IE’s evaluation, would be at the Proposer’s risk. As noted in the footnote to Section 3.10.1 of the CBRE RFPs:

“If a Proposal is selected to the Final Award Group and an RDG PPA or Mid-Tier SFC is executed between the Company and the Proposer, the NEP RFP Projection will be further evaluated at several steps throughout the process as set forth in the RDG PPA or Mid-Tier SFC, and adjustments to the Lump Sum Payment will be made accordingly. Additionally, because the Company will rely on an accurate representation of the NEP RFP Projection in the RFP evaluation, a one-time liquidated damage as described in the RDG PPA or Mid-Tier SFC will be assessed if the First NEP benchmark is less than the Proposer’s NEP RFP Projection. After the Facility has achieved commercial operations, the performance of the Facility will be assessed on a continuing basis against key metrics identified in the RDG PPA or Mid-Tier SFC. See Article 2 and Attachment U of the RDG PPA or [Section 4.B and Attachment D of the] Mid-Tier SFC.”

Also, Attachment U, Section 4(e) of the RDG PPA provides that as part of the operational energy production report, or OEPR, “estimates of future Facility availability (taking into account anticipated maintenance) and losses (such as system degradation and balance of plant losses) are applied in order to calculate the Net Energy Potential.”

Regarding battery losses and auxiliary loads, Section 3.10.1 of the CBRE RFPs state, “[a]ny losses that may be incurred from energy being stored and then discharged from the BESS (round trip efficiency losses) should be excluded from the NEP RFP Projection, but the NEP should consider auxiliary loads in developing the value relative to the POI.” In other words, the NEP should not be reduced by anticipated round trip efficiency losses, but it should be reduced by auxiliary loads of the PV system.

Q27:

[Posted 07/26/2021] The Lanai CBRE Phase II RFP stipulates use of a 73 acre site owned by Pulama Lanai. This site references a pending land use application (A19-809) within the RFP to change the zoning from agricultural to heavy industrial. Are there any updates on the status of this application as the last update on the LUC website was on 12/1/2020 (withdrawal of final EA without prejudice)? Will the RFP schedule be amended should the rezoning effort be abandoned by Pulama Lanai?

A27:

The Company has confirmed that Pulama Lanai has withdrawn the Final Environmental Assessment (FEA) in support of its petition to rezone the site of the proposed Miki Basin Industrial Park from Agricultural to Light and Heavy Industrial (LUC A19-809). Even though the rezoning petition appears to be on hold, the Company will not be amending the RFP schedule at this time as it appears that rezoning will not be necessary in order to site a solar photovoltaic energy generating facility on the subject parcel. Proposer is encouraged and recommended to seek appropriate counsel to confirm this assessment. The Company is not in a position to comment or provide guidance on this issue other than the understanding noted above, which Proposer should confirm with its own due diligence. In addition, to the extent that the FEA has been made publicly available, the information provided in the FEA may still provide useful information for Proposers that could result in more informed bids based on the results of the FEA.

As a reminder, the RFP requires developers to identify all required government permits and approvals, and disclose them in their proposals as part of their Environmental Compliance and Permitting Plan and the selected developer would be responsible for obtaining any such permits and approvals.

Q28:

[Posted 8/10/21] I am attempting to approximate how the cost of electricity for Molokai will be impacted by a solar project installed under the CBRE program. Earlier this year there was a meeting at which Maui Electric presented and briefly mentioned that changes to the subscribers' bills would also be reflected in the O&M section of their costs. Could you share any further details about how the O&M costs will be affected by the CBRE project?

A28:

We believe that you are referencing the following graph which was presented by Maui Electric at a meeting earlier this year.

Contributing Cost Components to Customer Rates, Molokai

Please note that this graph was shown for illustrative purposes and these components are not actually broken out on a customer’s bill. The point being made at the meeting was that the cost of fuel is a significant driver of the cost of electricity. Fuel prices can fluctuate or have sustained periods of increases or decreases, both of which can cause considerable change in customer rates and bill amounts. As the use of resources that rely on fuel are lessened by the use of renewable energy, customers will start to see more stable bills as fuel becomes less of a driver of customer bills. The Company does not anticipate that a CBRE project alone would have a significant impact on O&M costs included in customer rates, since a CBRE project will not eliminate the need for the current resources on the Molokai system.

Q29:

[Posted 8/10/21] Now that travel restrictions are lifting statewide, is there any potential for lifting the site visit restriction pre-bid so that some members of our team may be able to visit the Palaau site on Molokai in the coming months?

A29:

Regarding in-person site visits, at this time the Company will not be allowing visits to the Palaau site. Even though travel restrictions have been lifted or relaxed, the recent surge in Hawaii COVID-19 infections has resulted in the Company re-examining in-person meetings, including in-person site visits. The Company will consider site visits in the future, if the Company believes it can be accomplished while maintaining the health and safety of its employees, interested developers, as well as the residents of Molokai. As a site visit is currently not possible, the Company is looking to provide additional information, to assist potential bidders, which may include photographs and/or videos. Parties interested in receiving additional site information should contact us at CBRERFP@hawaiianelectric.com. Please note than an executed NDA may be required to receive the additional information to be offered so it would be advisable for interested parties to seek to execute the NDA at this time.

Q30:

[Posted 8/10/21] Are there any additional studies or information that Hawaiian Electric has about the Palaau site that you could share at this time? The end of Appendix H, Page 3 of the CBRE Molokai RFP refers to the possibility of additional documents available upon request. Anything from soil studies to cultural reports would be very welcome, when and if possible.

A30:

As of its next filing of the CBRE Molokai RFP, which will be by August 31, the Company intends to make available two reports that were prepared in support of the Molokai Variable Renewable Dispatchable Generation RFP that was issued in 2019. The Company will entertain requests for these reports after August 31st.

One report is a Preliminary Subsurface Investigation, and the other is an Archaeological Literature Review and Field Inspection Report. They will be described further in Appendix F – Description of Available Sites. Proposers should note that because these reports were prepared for a previous RFP, some of the information is focused on an area of the Palaau site that is different than the portion that has been made available as part of the CBRE RFP.

If, based on the information provided in Appendix F of the forthcoming RFP filing, proposers are interested in receiving a copy of these studies, they may request a copy through CBRERFP@hawaiianelectric.com. Please note, that any party requesting these documents must have an executed CBRE NDA with the Company, as these reports will be provided pursuant to the terms of conditions of that NDA. Proposers are encouraged to complete a CBRE NDA prior to release of the reports so that the reports may be released immediately upon request.

Q31:

[Posted 10/12/21] For Mid-Tier projects, is there a maximum credit rate?

A31:

There is no pre-determined maximum credit rate. Also, to clarify, the credits received by the customer will be calculated based on their pro-rated interest in the CBRE project, and not as a per kWh credit rate.

Q32:

[Posted 10/12/21] For Mid-Tier projects, the Lump Sum Payment accounts for the Net Energy Potential and availability of BESS actual output, and this fully loaded lump sum determines the credit rate? So for example, if we bid $2M lump sum payment, that would include both the Battery availability and the Net Energy Potential.

A32:

The Lump Sum Payment is paid in return for the full dispatchability of the Facility (PV+BESS) subject to the performance requirements set forth in the Mid-Tier SFC, including demonstrating the NEP. No additional payment is made based on the Facility’s actual output.

Q33:

[Posted 10/12/21] For a Mid-Tier project, instead of getting a $/kWh rate – the subscriber would get an actual dollar amount so if they had a subscription for 2% of the capacity, in this example, they would receive a $40k annual credit, or $3,333.33/month on their bill?

A33:

This is generally correct assuming the credit does not exceed the Subscriber’s eligible charges as described in the Company’s proposed tariff Rule No. 29, Part II, Section C.7 (filed with the CBRE RFPs). In that case, the value of excess credits will be carried over to the next billing period(s) within the current 12-month period, as a CBRE bill credit, and applied to the Subscriber’s electric bill. A reconciliation will be made at the end of every 12-month period, and any CBRE bill credit that remains unused will be extinguished.

Q34:

[Posted 10/12/21] Does the subscriber’s savings rate vary per month? For example, if the System is 50% unsubscribed or only has 3 subscribers, is the Subscriber’s bill credit impacted in addition to the payments to the Subscriber Organization?

A34:

With the exception of limited situations as described in the Company’s tariff Rule No. 29, Part II.C.2 and the Mid-Tier SFC (e.g., Performance Metric LDs, process to determine NEP, or errors in allocation or billing inaccuracies), and disclosed by the Subscriber Organization in the Disclosure Checklist to subscribers, the monthly credits do not change. The Liquidated Damages for not meeting the performance and program requirements are assessed against the Subscriber Organization’s portion of the monthly Lump Sum Payment, and the subscriber’s allocation is not affected unless the Performance Metric LDs are unpaid by the Subscriber Organization.

Q35:

[Posted 10/12/21] Please confirm there is only one “revenue stream” – or source of payment in the Mid-Tier Standard Form Contract and that is through the Lump Sum Payment? (For example, there is no additional payment directly for Battery, etc.)

A35:

Correct, the Lump Sum Payment is the only payment that the Company provides. However, please note that the Lump Sum Payment is paid out through payments to the Subscriber Organization for unsubscribed energy, and to the Subscribers, in the form of bill credits, for their portion of the subscribed energy.

Q36:

[Posted 10/12/21] Are CBRE projects on Oahu eligible for the SDP tariff (Rule 31)?

A36:

No, CBRE projects are not eligible to participate in the SDP program.

Q37:

[Posted 10/12/21] Is there a bidders list that I may obtain to allow my team to supply proposals and solutions to the those bidding this project?

A37:

The identity of bidders remains confidential throughout the RFP process, with only the selected proposal being made public after its selection. Therefore, a bidders list will not be made available for the Lanai RFP, nor any of the CBRE RFPs.

Q38:

[Posted 10/12/21] Could you list the models needed for the 5MW interconnection applications?

A38:

As shown in Appendix B, Attachment 6 of the CBRE Tranche 1 RFPs filed on August 25, 2021, the model requirements for projects 5 MW or larger are: PSS®E Generic, PSS®E User Defined, PSCAD, and ASPEN.

If the facility will be grid-forming, the additionally required models are: Grid Forming PSCAD and Grid Forming PSS®E.

However, it should be noted that based on the Commission’s Order No. 37954 issued on September 3, 2021, changes to the list of required models may be necessary. Any such changes will be reflected in future updates of the CBRE RFPs to be filed with the Commission.

Q39:

[Posted 10/12/21] Will any site reports, such as an archaeological report and geotechnical report be provided for the designated Pulama Lanai site?

A39:

No new reports have been, or are planned to be, commissioned by the Company with regards to the Pulama site. Two reports that were completed in 2019 in support of the Stage 2 Lanai RFP (which was not ultimately released) will be made available upon request to interested developers. One report is a Preliminary Subsurface Investigation, and the other is an Archaeological Literature Review and Field Inspection Report.

Proposers should note that the Stage 2 Lanai RFP was planned for an adjacent location to the Pulama site identified in the current Lanai CBRE RFP and therefore the information in these reports is not necessarily indicative of the conditions at the Pulama site.

Please note that any party requesting these documents must have an executed CBRE NDA with the Company, as these reports will be provided pursuant to the terms of conditions of that NDA. Requests for these reports should be sent to LanaiCompetitiveBidding@hawaiianelectric.com.

Q40:

[Posted 10/12/21] Is the most current estimate for the Final RFP Issue date is September 14, 2021 (as specified page 18 in the redline, “Draft Request for Proposals for Community-Based Renewable Energy Tranche 1, March 30, 2021”)?

A40:

No, the CBRE Phase 2 Tranche 1 RFPs was not be issued on September 14, 2021 as indicated in the draft final RFPs filed by the Company on March 30, 2021. Since that filing, the Company filed updated RFPs on August 25, and 31, 2021, which included updated schedules. These RFPs assumed that the RFPs would be approved after 15 days, based on the Commission’s Order No. 37879, which stated that this would be the case, “unless the Commission orders otherwise.” However, on September 3, 2021, the Commission issued Order No. 37954, which suspended the 15-day approval portion of Order No. 37879. As a result, the Company is currently unable to provide an issuance date for the final RFPs.

Q41:

[Posted 10/12/21] Is the minimum residential subscription ratio for a CBRE Project 40% residential/60% anchor subscribers or 60% residential/40% anchor subscribers?

A41:

The requirements regarding residential Subscribers differ between the CBRE LMI RFP and the other CBRE RFPs. The CBRE LMI RFP requires that all Subscribers meet the LMI requirements as described in Part III of Tariff Rule No. 29. Rule No. 29 also requires 60% of the project’s capacity be reserved for residential Subscribers. This RFP applies to Oahu, Maui, and Hawaii Island.

The other CBRE RFPs – Tranche 1 (non-LMI dedicated) for Oahu, Maui, and Hawaii Island, Molokai, and Lanai – require that 40% of the project’s capacity be reserved for residential Subscribers. Those RFPs do not have any requirement that Subscribers qualify as LMI Subscribers. They do, however, give preference to projects that commit to residential subscriptions above the 40% requirement, as well as to projects that commit to reserving capacity for LMI Subscribers.