CBRE RFP Questions & Answers

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.

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.

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.

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.

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.

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

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.

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.

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.

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. [Update] Based on more recent data, $60k to $120k represents a more likely range for the SIS cost for projects interconnecting to distribution or subtransmission circuits.

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. [Update] Based on more recent data, $50k to $75k represents a more likely range for the FS cost for projects interconnection to distribution or subtransmission circuits.

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.

Please see Q&A #20 below.

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.

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.

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.

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.

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.

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.

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

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.

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.

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.

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.

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.

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.

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.

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.

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.

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

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.

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.

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.

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.

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.

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.

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.

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.

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

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.

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.

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.

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.

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.

After reviewing the RFP requirements, Company acknowledges some inconsistency between the RFP and Appendix B with respect to the noted items. The following requirements should apply to both Tranche 1 and LMI dedicated CBRE RFP’s for Oahu, Maui, and Hawaii Island. The RFP and Appendix B will be revised accordingly.

For Projects at least 250 kW and less than 1 MW in size, Project single line and three line diagrams, and an equipment list shall be submitted with the Proposal. Within 30 days of selection to the Final Award Group, such projects shall also submit a completed Project Interconnection Requirement Study Data Request worksheet, which can be found in Appendix B, Attachment 2, all project diagram(s), models for equipment and controls (see Appendix B, Attachments 3 and 6), list(s) identifying components and respective files (for inverters and power plant controller), and complete documentation with instructions.

For Projects greater than or equal to 1 MW in size, a completed Project Interconnection Requirement Study Data Request worksheet, which can be found in Appendix B, Attachment 2, all project diagram(s), models for equipment and controls (see Appendix B, Attachments 3 and 6), list(s) identifying components and respective files (for inverters and power plant controller), and complete documentation with instructions must be submitted with the Proposal submission. Within 30 days of selection to the Final Award Group, final submissions, to incorporate any updates to the information described above that was submitted in with the Proposal, shall be made, and shall be in compliance with the Project data and modeling requirements included in Section 5 of the RFP.

The Tranche 1 (non-LMI dedicated) RFP has no maximum project size, nor a requirement that multiple projects be selected, so it is possible for a single project to be awarded all 75 MW of the program capacity for Oahu. However, please note that projects are required to interconnect at the distribution (12 kV or lower) or sub-transmission (46 kV or lower), which limit the ability to accommodate such a large project on one circuit. Conceivably, a potential 75 MW project would require two interconnection points on two different circuits in order to be viable.

Based on the current language of the draft Rule No. 29, a master-metered building serving LMI customers, such as one serving renters under the Hawaii Public Housing Authority, would be eligible to count toward the 100% LMI requirement of the LMI CBRE RFPs. It would also qualify as an LMI anchor tenant. However, it would not count toward the 60% residential requirement as the master-metered account would be a commercial account, and only residential customers (Schedule R, TOU-R, TOU-RI, TOU EV, or any other residential rate option) count toward the residential subscribers requirement. The Company is also reviewing potential changes to Rule No. 29 that would permit the building in the scenario described in this quest to qualify as residential. Any such change, if made, will be reflected in a future filing with the PUC.

Subscribers will receive bill credits equivalent to their subscription percentage of the project’s lump sum payment. This will be shown directly on the subscriber’s utility bill and will be administered by Hawaiian Electric based on information provided by the Subscriber Organization. Subscriber Organizations are responsible for updating the Subscriber roster list and the appropriate Subscriber allocations based on their subscription size. Also, if the Subscriber Organization bills any Subscriber for items based on the agreement between the Subscriber Organization and the Subscriber, that would be administered separately and directly by the Subscriber Organization.

Under the Renewable Dispatchable Generation (RDG) PPA for the CBRE program, reserve shutdown hours are not equivalent to curtailment. Curtailment is not determinative for payment/compensation and, in fact, is no longer relevant, as Hawaiian Electric will have full dispatch rights over the facility under the RDG PPA. The lump sum payment is based on availability and performance of the facility in response to Company dispatch. As long as the system is available to the utility and performing in accordance with its performance standards, bill credits based on the lump sum payment will be provided to the subscriber.

Subscriber bill credits are fixed based on the subscriber’s percentage allocation of the Renewable Dispatchable Generation PPA Lump Sum Payment. There are no other options or alternatives under the CBRE program for additional bill credits. Additional bill credits may be available if a Subscriber purchases or subscribes to a higher subscription amount or allocation. However, Hawaiian Electric is unsure what “additional savings” is referring to in this context other than a higher subscription amount.

A 2nd Draft Environmental Assessment, dated November 2021, has been posted to the State of Hawaii Land Use Commission website. Information found in this document is for use at the Proposer’s sole discretion.

Tariff Rule No. 29 (which governs Phase 2 of the CBRE program) does not include any specific accommodations for adjusting programmatic offerings during the lifetime of a project. The CBRE portal was built according to the CBRE Framework issued by the PUC. Any changes to a Subscriber Organization’s program offerings, managed within the portal, such as quotes and fee structures, would have to be done within the current capabilities of the CBRE portal. Hawaiian Electric cannot advise further without more clarity on what type of changes to the program offerings might be proposed. Generally speaking, the portal does not prohibit the Subscriber Organization from changing its contract with a Subscriber, as those agreements are managed by the Subscriber Organization and the Subscriber without the utility administrator. We do not have a portal sandbox, but suggest referencing the recorded sessions and presentation decks available publicly on our Shared Solar webpage for further detail.

The Company will not be making a sample CSAT available prior to selection of the winning proposal. Given the size of the project to be selected relative to the size of the Lanai grid, aspects of prior CSATs may not be indicative of what will be needed for this project. However, input from the chosen developer will be considered in deciding on the final CSAT plan.

The minimum requirement for both feeders is that they can accommodate 10 MVA each as discussed in Sections 1.2.6 and 1.2.9 of the RFP. Should one feeder become unavailable, the facility should be designed such that output from the facility can still be directed through the other feeder, so that the utility may continue to dispatch the facility as needed, up to the capacity of the remaining feeder. To clarify, neither feeder is required to be able to accommodate the full MW output of the facility, assuming that output is greater than the 10 MVA minimum requirement for each feeder. The portion of the system shown on the SLD does not show any of the facility design beyond the required two feeders to Miki Basin. The assumption that “the SLD provided indicates two separate systems each tied to a separate feeder” is not correct, and as discussed during the contracts training, the feeds ARE NOT expected to be connected to separate systems within the facility. Although the SLD does not show the facility design in any detail beyond the feeder requirements, as discussed during the training, the minimum net export requirement, the single point of failure requirement, and the availability of just two feeds into Miki basin, inherently require the facility to have a normally closed tie between the two feeds to ensure the loss of a single feed when exporting above 4.4 MW will not result in the loss of more than 2.2 MWs for a single point of failure (a feed). In the event of an outage on the utility-owned portion of a feeder not caused by the Subscriber Organization or the Facility, the Facility would not be penalized for any resulting decrease in capacity; although nothing more than 2.2 MW reduction should be experienced for a single feeder outage given the facility interconnection design requirements outlined in the RFP and further explained above.

Hawaiian Electric would like to correct and clarify the responses to those questions. As noted in both the Molokai and Lanai CBRE RFPs, projects must include a Battery Energy Storage System (“BESS”) and, as a result, other technologies would not be acceptable for this RFP, including hydrogen based energy storage. In addition to limiting storage solutions to a BESS, the RFPs both state that Hawaiian Electric will only consider Proposals utilizing technologies that have successfully reached commercial operations in commercial applications (i.e., a PPA) at the scale being proposed. Proposals should include any supporting information for the Company to assess the commercial and financial maturity of the technology being proposed.

Hawaiian Electric provides the corrections shown below, which remove the use of “Allowed Capacity” and “Maximum Rated Output” as defined terms. These changes apply to Section 3.10.1 of the RFP body (see Image 1 below), and Section 2.2.4 of Appendix B (see Image 2 below). Additionally, in Section 2.2.4 of Appendix B, “BESS energy capacity (MWh),” has been replaced with “BESS Contract Capacity (MW/MWh),” consistent with Attachment A of the Lanai RDG PPA. These changes do not materially change the requirements of the RFP.

Section 2.2.4 of Appendix A, was also updated to correctly state that the BESS must have an energy capacity of at least 70% of the average daily energy output of the PV facility, consistent with the requirements included in the RFP.

Image 1: Lanai CBRE RFP Body, Section 3.10.1

Image 2: Lanai CBRE RFP, Appendix B, Section 2.2.4 (partial)

The example you are referring to appears to address the maximum subscription size that may be available to any given Subscriber (See Part 1, Section B.7 of Proposed Tariff Rule 29). How that subscription size (in kW) translates into a subscription percentage is dependent on how the Subscriber Organization (SO) calculates such percentage based on its program and the Subscriber Agreement between Subscriber and SO. That being said, please refer to the terms of Tariff Rule 29 or the applicable model PPA’s for any limitations on how a Subscriber’s subscription size translates to such Subscriber’s percentage interest.

Purely as an example, on a simple basis, a Subscriber's percentage interest in a Project’s CBRE Capacity could be equal to (and as simple as), the Subscriber’s interest in the project (kW) divided by the total capacity of the Project (kW). For example, if a Subscriber holds a 10 kW interest in a 1,000 kW facility, the “Subscriber’s Percentage Interest” in the Dedicated CBRE Capacity” would be 1%.

In the last part of the question, it seems you are proposing converting a Subscriber’s kW subscription to an annualized kWh amount and calculating a percentage based on a projected annualized MWh calculation for the Project as a whole. There are no rules prohibiting this, but that would be a contract term between Subscriber and SO specified in the Subscriber Agreement, which the Company does not have insight into. Additionally, the CBRE portal requires that subscriptions be entered as kW values, so while it is up to the Subscriber Organization on how to allocate project capacity to Subscribers, it must be converted to the kW equivalent to be compatible with the portal. Under the Tariff Rule 29, the SO is responsible for informing Company of each Subscriber’s percentage interest.

The energy requirement identified in the RFP (35.8 GWh) is not a measured/metered value, but is the minimum requirement for the Project’s Net Energy Potential RFP Projection. As described in the Lanai RDG PPA, Net Energy Potential is, “[t]he estimated single number with a P-Value of 95 for the annual Net Energy that could be produced by the Facility based on the estimated long-term monthly and annual total of such production over a ten-year period. The Net Energy Potential is subject to adjustment as provided in Attachment U (Calculation and Adjustment of Net Energy Potential) to this Agreement, but in no circumstances shall the Net Energy Potential exceed the NEP RFP Projection.” Essentially it is the amount of annual energy the PV has the potential to produce, and is not impacted by how much energy the utility dispatches to the grid or is stored in the BESS. Please see Attachment U of the Lanai RDG PPA for more information on Net Energy Potential and how it is calculated and adjusted during the term of the PPA.

Yes. Section 1.2.3 of the RFP describes the scope of the CBRE Project, and Section 3.0 of Appendix B identifies information required to be included in the Proposal associated with the CBRE Program. The Proposal’s design of its CBRE Program to be offered to potential Subscribers should be reflective of one that must recruit and serve enough Subscribers for a project with 3 MW of CBRE program capacity.

As described in Section 1.2.6 of the RFP, each feed/POI must be sized to accommodate at least 10 MVA and there must be exactly two feeds. Although the SLD does not show the facility design in any detail beyond the feeder requirements, the minimum net export requirement, the single point of failure requirement, and the availability of just two feeds into Miki basin, inherently require the facility to have a normally closed tie between the two feeds to ensure the loss of a single feed when exporting above 4.4 MW will not result in the loss of more than 2.2 MWs for a single point of failure (a feed).

The energy requirement identified in the RFP (35.8 GWh) is not a measured/metered value, but is the minimum requirement for the Project’s Net Energy Potential RFP Projection. As described in the Lanai RDG PPA, Net Energy Potential is, “[t]he estimated single number with a P-Value of 95 for the annual Net Energy that could be produced by the Facility based on the estimated long-term monthly and annual total of such production over a ten-year period. The Net Energy Potential is subject to adjustment as provided in Attachment U (Calculation and Adjustment of Net Energy Potential) to this Agreement, but in no circumstances shall the Net Energy Potential exceed the NEP RFP Projection.” Essentially it is the amount of annual energy the PV has the potential to produce, and is not impacted by how much energy the utility dispatches to the grid or is stored in the BESS. Please see Attachment U of the Lanai RDG PPA for more information on Net Energy Potential and how it is calculated and adjusted during the term of the PPA.

This question is best answered by a tax expert familiar with the applicable federal and state tax laws. The Company makes no representation or warranty as to the availability of tax breaks, tax credits or other incentives that may be available to a particular developer of a CBRE project. However, please see Section 1.2.18 of the Tranche 1 CBRE RFP and/or Section 1.2.17 of the LMI CBRE RFP, which state, “If selected, Proposers shall pursue all available applicable federal and state tax credits. Proposal pricing must be set to incorporate the benefit of such available federal tax credits. However, to mitigate the risk on Proposers due solely to potential changes to the state’s tax credit law before a selected project reaches commercial operations, Proposal pricing shall be set without including any state tax credits. If a Proposal is selected, the PPA for the project will require the Proposer to pursue the maximum available state tax credit and remit tax credit proceeds to the Company for customers’ benefit as described in Attachment J of the RDG PPA or the Mid-Tier SFC. The applicable PPA will also provide that the Proposer will be responsible for payment of liquidated damages for failure to pursue the state tax credit.” Ultimately, available tax breaks, credits or other incentives must be determined by the proposer, taking into account such proposer’s individual tax situation. If selected, however, it will then be the responsibility of the developer to pursue such incentives and to turn over such incentives to Company for the benefit of customers in accordance with the terms and conditions of the applicable PPA for the Project.

No, there are no “prevailing wage” requirements in the CBRE RFPs. However, based on feedback received from stakeholders through community meetings initiated by the PUC as discussed in the letter filed on January 11, 2022 in Docket 2015-0389, the Company is considering revising the Community Outreach non-price criterion to encourage Proposers to use local labor and pay a prevailing wage. Any such changes will be reflected in future updates to the RFPs filed with the PUC.

The NEP RFP Projection is the estimated energy (MWh/year) that can be expected to be produced 95% of the time, over a 10-year period. While it may appear so, the terms “annual” and “over a 10-year period” are not contradictory. “Annual” refers to the energy generated in one year, reflected in the units of the NEP (MWh/year) metric the Company requires this project to be calculated for – specifically, the P95 projected annual net energy. The “10-year period” refers to the interval in which this projection is examined over. It is the developer’s responsibility to determine the methodology and assumptions for calculating the NEP RFP Projection for their project. Also see Attachment U of the RDG PPA for calculation and adjustment of NEP.

1. Upon selection to the Final Award Group, the Company will present the Proposer with an IRS Letter Agreement. The IRS Phase will start upon receipt of the executed Letter Agreement, all required data, and payment. Execution of the PPA will not take place until after the IRS is complete.
2. The timeline for the 30% design & review for COIF will begin after the IRS Letter Agreement is executed by the Proposer and a kickoff meeting has been held between the Proposer and Company.
3. To clarify, both parties have roles during this phase. The Company would be reviewing the COIF design drawings prepared and submitted by the Proposer for each design phase. It would be the Proposer’s responsibility to address the Company’s comments and update the design drawings as necessary. There could be delays in the process if the Proposer does not address the Company’s comments or submit design drawings to the Company in a timely manner.
4. Construction of COIF can start 3 months after Issued for Construction (IFC) Design & Review is complete.
5. Acceptance testing is required to energize the facility, and the CSAT requires energization, so the CSAT must follow acceptance testing.

Note: Preparation of models, documentation, and related information may take longer than 30 days, and Proposers shall allow adequate time for this submittal requirement.

If a Proposal proposes using Area A and Area B, and the Proposals is selected in accordance with the RFP, the project would be allowed to have its equipment, including racking structures, traverse the boundary between Area A and Area B, with no distinct boundary or fence required to remain between those areas. However, the requirements for both Area A and Area B listed in Appendix F must still be met, including the relocation of the visitor parking lot and security gate.

RTE losses should not be included in the calculation of a project’s NEP RFP Projection, so to the extent BESS auxiliary loads contribute to a project’s RTE losses, they should not also be accounted for as a reduction to NEP. That being said, auxiliary loads that must be served by the Facility in order to safely and reliably generate its energy that will inherently reduce the projected energy delivered to the point of interconnection, should be accounted for in determining the appropriate NEP. See Section 3.10.1 of the RFP regarding losses and auxiliary loads with respect to the NEP.

Because the proposed Lump Sum Payment should assume no impact from any state tax credits, there will be no adjustments to the Lump Sum Payment. As further described in Attachment J, Section 7 (Tax Credit Pass Through) of the Lanai RDG PPA, “Seller expressly acknowledges and agrees that it shall not seek to amend the Contract Pricing.” The payment to the Company of such tax credits will be for the benefit of its customers, and not Hawaiian Electric. Pursuant to the terms specified in Attachment J of the model PPA, Seller will be permitted to deduct reasonable costs incurred to obtain Seller’s maximum available tax credit.

The use of a P95 NEP RFP Projection over a 10-year period is consistent with industry standards. Recognizing the term of the PPA to be 20-years, it is the responsibility of the developer to ensure their facility can meet their contractual commitments for the duration of the PPA.

The Company notes the following: (1) Execution of the Mid-Tier SFC will not occur until after the IRS has been completed; and (2) A number of the specified tasks may be completed in parallel with others that will shorten the overall timeframe (assuming there are no unexpected delays). For example, (1) procurement can start 3 months after IFC design is complete, and (2) construction could be occurring in parallel with procurement. Construction duration is dependent on Company scope as well as construction required for the proposer facilities. The duration is a rough estimate of both proposer and Company construction combined where proposer construction could also be occurring in parallel with procurement. Q&A 62 has been updated to reflect this information.

The Company recognizes that even taking the above items into account, the 18-month timeline may be challenging and has filed a request to the PUC to extend the 18-month timeline to 24-months. We have also requested to extend the deadline for bid submittals by 2-weeks to March 1, 2022. The results of any decision from the Commission on this matter will be posted to the Molokai CBRE RFP page.

While a project’s capacity for any given proposal is uncapped and capacity of the selected project(s) do not count toward the Phase 2, Tranche 1 program capacities for the respective islands, a lack of a total capacity target does not mean that all proposals will be selected. Proposals must still past numerous threshold criteria specified in the RFP documents and will still be evaluated against each other. Selection of proposals for the Final Award Group will be based on scoring from numerous price and non-price factors, including cost benefits to customers, proven technology, community outreach, and numerous other factors specified in the RFP documents. While it is conceivable that all proposals could receive identical scores, proposals will still be evaluated against system needs, ease of interconnection, interconnection costs, locational diversity needs and factors under which, ultimately, will result in one or more proposals being selected and one or more proposals not being selected.

Hawaiian Electric has and will continue to promote the CBRE program, which it also refers to as “shared solar” in its marketing efforts. The specific nature of these efforts is on-going but does include program awareness through customer newsletters and Hawaiian Electric’s shared solar website. However, it is incumbent on Subscriber Organizations to also make efforts to find subscribers, and it will ultimately be the responsibility of the Subscriber Organizations to ensure they meet the requirements of the program, such as the percentage of residential subscribers.

No for all three questions. At this time, SOs are required to use the CBRE Portal to confirm subscriber eligibility, enroll and maintain subscriber rosters, approve project generation and SO invoices to Hawaiian Electric. Hawaiian Electric uses the CBRE Portal to administer bill credits to Subscribers. Payments between the Subscriber Organization and Subscriber are handled outside of the CBRE Portal.

It is the responsibility of the Subscriber Organization to replace a Subscriber. Subscriber Organizations are encouraged to keep their projects as subscribed as possible; and may incur penalties on unsubscribed energy payments. The CBRE Portal does facilitate the transfer of subscriptions between the Subscriber and a new eligible subscriber.

The CBRE Portal assists Subscriber Organizations in transferring a subscription to a different service address on the same island, to another eligible customer on the same island, or back to a Subscriber Organization when a customer is no longer eligible. The responsibility lies with the Subscriber Organization to accurately maintain their subscriber roster in the CBRE Portal. If a Subscriber were to move to a different island, they would still have to notify Hawaiian Electric to stop service. The Subscriber Organization would receive a notification in the CBRE Portal that the customer has moved out, and would then need to initiate a “buyout” in the CBRE Portal.

It is up to the Subscriber Organization to decide how much they will charge subscribers for an interest in their project, and how they will structure that agreement (e.g. Pay-up-front or Pay-as-you-go). The aggregate percentage interest held by Subscribers will ultimately dictate how much of the Lump Sum Payment will be paid to the SO for unsubscribed energy. This agreement is outside of the agreement between Hawaiian Electric and the Subscriber Organization through which Hawaiian Electric will make the applicable Lump Sum Payment, which will be in the form of bill credits to subscribers, and payments for unsubscribed energy to the Subscriber Organization (less any liquidated damages).

Hawaiian Electric does not currently have plans to facilitate payments between the Subscriber and Subscriber Organization.

Developers should not submit projects beyond which it believes it can reasonably find subscribers as the withdrawal of projects selected to the Final Award Group could impact other selected projects. In addition, for future procurements (including draft documents filed as part of its Stage 3 procurements), Hawaiian Electric has incorporated penalties in the evaluation process for developers who withdraw projects selected to the Final Award Group.

No, residential customers must have individual electric accounts on a residential rate schedule.

Each individual electric account is counted as a Subscriber toward the minimum of four individual Subscribers; therefore a master metered building would count as one Subscriber.

The Subscriber Organization will be paid for unsubscribed energy subject to reduced payments if the project does not meet the subscription requirements. However, to help create a timeframe where Subscriber Organizations can enroll their subscriber base without any reduced payments, from the date of commercial operations, a Subscriber Organization has a 6-month grace period for small projects (under 250kW) and a 9-month grace period for mid-tier and large projects. Once those timeframes have passed the project must meet the requirements of the tariff (e.g., a minimum of 4 subscribers, minimum residential requirement, no more than 15% unsubscribed energy, and other commitments that may be made by the project) or be subject to reductions in the payments for unsubscribed energy so long as such requirements continue to not be met.

The proposal should affirm that proposed Facility will meet the required performance standards. This information should be substantiated by including, in the response package, applicable sections of supporting documentation that shows the equipment is capable of meeting the performance standards. The proposal should include information required to make this determination in an organized manner to ensure this evaluation can be completed within the evaluation review period.

For Section 2.10.15 of Appendix B, the proposal should include a summary table and/or narrative describing the major equipment and provide documentation which may including the manufacturer data sheets or any other manufacturer documentation. This information is in addition to any information taken from the manufacturer documentation and inserted into other section of the proposal as described in the response to question #3 above.

The NEP RFP Projection should include all energy the Facility can generate and deliver to the point(s) of interconnection, up to the Allowed Capacity. The NEP RFP Projection is not impacted by the BESS.

The Company would like to correct its reference to the “State Land Use Classifications,” and state that the zoning will be determined based on the county zoning districts applicable to the project’s selected site. As not all county zoning districts fall clearly into the identified zoning options, the Company has reviewed each county’s designations and have assigned them to a specific category. The Company also corrects the language in the RFP to add “apartment” to “apartment mixed-use” as shown in track changes below. Proposers may inquire with the Company on which category a particular county zoning district falls into by contacting the Company at cbrerfp@hawaiianelectric.com.

Please see the response to each item below:

1. All information requested as part of Section 2.10 of Appendix B must be submitted with the proposal.
2. For a project greater than 1 MW, all of the items listed in Section 2.11.3 must be provided with the proposal:
   1. Completed Project Interconnection Requirement Study Data Request worksheet;
   2. All project diagram(s);
   3. Models for equipment and controls;
   4. List(s) identifying components and respective files (for inverters and power plant controller). Respective files can include equipment spec sheets, product manuals, etc.
   5. Complete documentation with instructions. This includes any model documentation, self-test documentation of models per Appendix B Attachment 3, user manuals/instruction for the models, or any other documentation you may feel necessary.
3. As noted in Section 2.11.3 of Appendix B, “Models for equipment and controls” must be submitted with the proposal. Attachment 3 of Appendix B describes the model requirements and review process for model submittals.
4. As noted in Section 2.11.3 of Appendix B, “Models for equipment and controls” must be submitted with the proposal. Attachment 6 of Appendix B provides details about the models that are required based on the size of the project and interconnection voltage. The third column on Page 1 of Attachment 6 provides this information for projects greater than or equal to 1 MW that are interconnecting at 12 kV.

Section 1.2.17 requires that Proposal pricing incorporate the benefit of available federal tax credits. State tax credits should not be accounted for when determining Proposal pricing. Awarded projects will be required to pursue available state tax credit and remit tax credit proceeds to the Company for customers’ benefit. Please see the Q&A items #59 and #66 for further information.

The reference to Attachment J was specific to the RDG PPA. For the Mid-Tier SFC, the equivalent language can be found in Attachment B. We apologize for any confusion.

Regarding potential changes to the Federal Investment Tax Credit, pursuant to Section 1.2.17, Proposal pricing should incorporate the benefit of the Federal ITC at the time of proposal submission. Due to the speculative nature of any potential change to the Federal ITC and the timing of this RFP, no contingency has been provided to account for any future changes to the Federal ITC. Additionally, no variation would be applicable if that variation proposes pricing that is “contingent upon other factors,” including changes to federal tax policy as described in Section 3.9.1.

Section 5.1.2 provides the timing and data requirements for the IRS and is intended to cover any projects requiring an IRS. This could include smaller projects with different data deliverables due at the time of proposal compared to larger projects. In the case of a project greater than 1 MW, those data deliverables that are due with the proposal should be updated within 30 days of being named to the Final Award Group “to incorporate any updates to the information submitted in response to Section 2.3.1” (see Section 5.1.1).

The “Available Circuit Capacity” threshold assessment is correct, and as noted in Section 2.2.2, projects interconnecting to 46 kV circuits are encouraged to inquire about available MW capacity prior to their bid submission. To be consistent with the threshold assessment requirements, Section 2.2.3 should be amended to remove the option to upgrade the 46 kV conductor as shown below.

As noted in Section 1 of Appendix H, “For the purposes of the LMI RFP, the Company will be responsible for the costs of Company-Owned Interconnection Facilities (COIF), subject to any limitations, as described in Section 1,” which is consistent with the instruction to proposers to exclude these costs from their Proposal pricing. However, COIF costs are provided in Appendix H to allow Proposers to estimate the potential costs for COIF, based on the project’s design, which will be incorporated in the evaluation when determining a project’s overall economic impact on the electric system. Costs in Appendix H that are stated as being the responsibility of the developer, however, should be included in Proposal pricing.

Regarding the excerpt cited from Section 1.3 of Appendix H, the reference to “Items 3, 4, and 5 below” are references to those respective parts of Section 1.3, and not references to the “series of costs in various tables” found in the remaining portion of Appendix H.

Except for the areas noted in Section 4.4.2, Item 4 of the RFP (i.e., Hana, Maui or Koolaupoko moku, Oahu), it is up to the Proposer to identify and describe the critical infrastructure or community resilience hub(s) that could benefit from islanding capabilities in response to Section 2.5.6 of Appendix B (Proposer’s Response Package). Please see the Locational Value: Non-Wires Alternative and Community Resilience Non-Price Criterion in Section 4.4.2, Item 4 of the LMI and Tranche 1 CBRE RFPs for more information.

The Companies confirm the 2020 census tract data should be used until more current census data is available. The 2010 data referenced in footnote #6 of the Tranche 1 CBRE RFP should not be used.

In instances where a neighborhood is split into two census tracts and one tract is not adjoining the tract where the project site is located, individuals in the tract that is not adjoining would not be included in the census tracts eligible for priority enrollment. Customers from such tract can be enrolled after the 3-month Priority Period.

Each month the Subscriber Organization will be responsible to verify that the project invoice generated in the CBRE Portal accurately reflects the project details. The Lump Sum Payment will be applied via bill credits for the Subscribers, and paid to the SO for unsubscribed energy, less any penalties or liquidated damages. There are no payments from the Subscriber to the SO related to the Lump Sum Payment. Any payment from the Subscriber to the SO for the Subscriber’s interest in the project, is solely between the Subscriber and the SO subject to the agreement between those parties.

Yes, the Subscriber will be charged for energy consumed based on their applicable rate schedule (e.g. Schedule R – Residential). The Bill Credits they receive as part of the CBRE program will offset the amounts owed for energy consumed, subject to the limitations set forth in Rule No. 29.

No. As described in Sections 2.3.3 and 2.3.4 of the Tranche 1 RFP, Proposers will be responsible for “all costs required to interconnect a Project to the Company System,” which includes Company-Owned and Seller-Owned Interconnection Facilities. This is not impacted by the amount of capacity the Proposal dedicates to LMI customers, though projects that do make commitments to dedicate capacity to LMI customers will be given preference as described in Sections 1.2.4 and 4.4.2 of the RFP.

This question is not applicable to the Tranche 1 CBRE RFP and was inadvertently included in Table 2.0. Proposers should answer “NA” for this question.