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Selling Power to the Utility

CBRE RFP Questions & Answers

Hawaiian Electric (sometimes also referred to as the "Company") provides the answers below, based on the best information available at the time an answer is posted, which may not reflect the scope and requirements of the final RFP. Prospective Proposers should review this Q&A page periodically to check for updates, additions, clarifications and/or corrections to any of Company's prior responses. Each Proposer is solely responsible for reviewing the final RFP (including all attachments and links), 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] Can you confirm the only two RFPs being released this year are the Lanai and Molokai RFPs? I see RFP's 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:

No, pursuant to PUC Order No. 37070 and pending approval of the final RFPs by the Commission, the Company plans to issue up to 8 RFPs this year. The Company filed the following 5 RFPs for approval by the Commission on September 8 (which we expect to be approved by the PUC and issued by the Company before the end of 2020):

  • CBRE Low- and Moderate-Income Request for Proposals for Oahu
  • CBRE Low- and Moderate-Income Request for Proposals for Maui
  • CBRE Low- and Moderate-Income Request for Proposals for Hawaii
  • 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

The Company plans to file the following 3 draft RFPs for review by the Commission and stakeholders on October 9 (which we hope will (but may not) be approved by the PUC and issued by the Company prior to the end of 2020):

  • CBRE Request for Proposals for Oahu
  • CBRE Request for Proposals for Maui
  • CBRE Request for Proposals for Hawaii

Please see Order No. 37070 (PDF) for more information.

Q7:

[Posted 10/2020] 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 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 storage component can be used to provide energy to the Company during other times that are beneficial to the system. The storage component of a Paired Project must be sized to support the Facility's Allowed Capacity (in MW) for a minimum of four (4) continuous hours throughout the term of the RDG PPA or Mid-Tier SFC.

For example, for a 2 MW facility, the storage 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 RDG PPA or Mid-Tier SFC.

Further refer to section 3.10.1 of the proposed LMI RFPs which instructs 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 energy storage 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 or wind Capacity.

Q8:

[Posted 10/2020] 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 their Proposal. Pursuant to Section 1.8.2 of the LMI RFP 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 O of the CBRE RFPs which provide 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] 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:

If a Proposer submits an email to cbrerfp@hawaiianelectric.com and provides Project specifics:

  1. a map showing the Point of Interconnection,
  2. the type and size of generation, 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.

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] 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:

The costs in sections 2.3 and 2.4 are independent of each other and should not be combined. The cost in section 2.3 is based off of a typical interconnection (Attachment 2) and the cost in section 2.4 is based off of the requirements in that section.

Q16:

[Posted 12/2020; Updated 02/16/2021] 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:

Sections 2.2, 2.3, and 2.4 of Appendix H in the Molokai CBRE RFP (as filed on 9/8/20) and Section 2.2 of Appendix H in the Lanai RFP (as filed on 10/6/20) include the costs for the revenue metering package.

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.