Selling Power to the Utility
- Sustainability Report
- Our Clean Energy Portfolio
- Community Meetings
- Selling Power to the Utility
- Grid Modernization Technologies
- Integrated Grid Planning
- Integration Tools and Resources
CBRE RFP Questions & Answers
For LMI, Tranche 1, Molokai and Lanai CBRE RFPs
Hawaiian Electric (sometimes also referred to as the "Company") provides the answers below, based on the best information available at the time an answer is posted, which may not reflect the scope and requirements of the final RFP. Prospective Proposers should review this Q&A page periodically to check for updates, additions, clarifications and/or corrections to any of Company's prior responses. Each Proposer is solely responsible for reviewing the final RFP (including all attachments and links), all responses to on this Q&A page and thoroughly investigating and informing itself with respect to all matters pertinent to the RFP, the Proposer's Proposal, and the Proposer's anticipated performance under the applicable power purchase agreement. It is the Proposer's responsibility to ensure it understands all requirements of the RFP and to seek clarification if the RFP's requirements or the Company's requests or responses are not clear. Accordingly, a potential Proposer may not rely upon a prior response that may be clarified or corrected in a subsequent response. Efforts will be made by the Company to highlight subsequent clarifications and corrections to prior responses, but potential Proposers are ultimately responsible for monitoring this Q&A page and to inquire with the Company regarding any perceived inconsistencies or contradictory information. Finally, a Proposer's submission of information to the Company will not be independently confirmed by the Company. All Proposers must separately request confirmation of receipt of submitted information if desired by any Proposer.
[Posted 9/2020; Updated 2/16/2021] 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?
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.
[Posted 9/2020; Updated 2/16/2021] 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?
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.
[Posted 9/2020] 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?
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.
[Posted 9/2020] 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.
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.
[Posted 9/2020; Updated 2/16/2021] What is the Company seeking on Lanai and can the CBRE portion be a separate facility?
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.
[Posted 10/2020; Updated 4/26/2021] Can you confirm the only two RFPs being released this year are the Lanai and Molokai RFPs? I see RFPs for Hawaii, Maui, and Oahu in the tariff, but nothing on the website indicating there is anything more coming up besides Lanai and Molokai.
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
[Posted 10/2020; Updated 4/26/2021] If a project utilizes storage, can a developer propose a system that its size is greater than the available capacity of the distribution line that it is interconnecting to? If the answer is yes, how many hours of storage is required?
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.
[Posted 10/2020; Updated 4/26/2021] If a project design is sized to be smaller than available capacity of a line (what LVM shows), does it still need to pair it with storage? Could a project get rejected if designed with no storage?
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.
[Posted 10/2020; Updated 6/16/2021] If the Locational Value Maps are not able to provide the available hosting capacity on a distribution circuit, will a general question asking what the maximum available hosting capacity for that distribution circuit be entertained?
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 email@example.com and provide the following Project specifics:
- a map showing the Point(s) of Interconnection,
- the capacity of the PV generation (MW), and
- (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.
[Posted 10/2020; Updated 2/15/23] 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.
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.
[Posted 11/2020; Updated 2/16/2021] 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?
Please see Q&A #20 below.
[Posted 12/2020] Can multiple projects be located on the same parcel of land or TMK?
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.
[Posted 12/2020; Updated 2/16/2021] 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.
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.
[Posted 12/2020; Updated 2/16/2021] 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?
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.
[Posted 12/2020; Updated 4/26/2021] For the Molokai CBRE RFP (as filed on 9/8/20), in Appendix H Interconnection Facilities and Cost Information, please advise whether the scope of work and costs listed in Section 2.3 Typical CBRE SLD Interconnection Costs (Projects 1MW or greater) should be included as a cost for a project proposed at the Palaau Generating Station or if the $600k cost listed in Section 2.4 Palaau Interconnection Costs is inclusive of what is listed in Section 2.3. Please provide clarification as needed to properly identify and estimate the interconnection cost for a project proposed at Palaau Generating Station.
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.
[Posted 12/2020; Updated 2/16/2021, 4/26/2021] For both the Molokai CBRE RFP (as filed on 9/8/20) and Lanai RFP (as filed on 10/6/20), are costs associated with the Revenue Metering Package mentioned in the RDG PPA and Mid-Tier SFC included as a cost in Appendix H? If so, please point to the section and if not, please provide an estimate as to what this cost would be for the equipment and installation.
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.
[Posted 1/2021] 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.
Below are revisions and clarifications to item 4.b. of Appendix F:
- 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.
- PV panels may not be installed under existing lines for safety and operational reasons.
- 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.
- 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.
- 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.
- Guy wires should have at least 2.5ft clearance on each side of the guy and should extend at least 3ft past the anchor.
- 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.
[Posted 2/16/2021] Please confirm the TMK of the Company-owned Palaau site on Molokai.
The TMK for the site is (2)5-2-011:031.
[Posted 2/16/2021] 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.
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.
[Posted date 2/16/2021] Please provide an update to the schedule for releasing the CBRE RFPs.
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.
[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).
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.
[Posted 4/26/2021] Would the Company be open to renewing or signing a new contract with Seller at the end of the 20 year term of the Power Purchase Agreement, given that the PV infrastructure will likely be viable for another 10-15 years?
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.
[Posted 4/26/2021] The cost of pumping water for irrigation has made farming a particular site unfeasible. Can we develop a CBRE Facility on this land to help provide water to this location more economically?
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.
[Posted 6/2/2021] How is a Project’s capacity (MW) determined?
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.
[Posted 6/2/2021] For interconnection at the Palaau Power Plant site on Molokai, please clarify whether a project between 1 MW and 2.2 MW requires two points of interconnection. The final note on the single line diagram included as Attachment 3 to Appendix B of the Molokai CBRE RFP states, “No single point of failure from the plant shall result in a decrease in net electrical output greater than 2.2 MW. In addition to meeting this requirement the plant shall be segmented in equally sized capacities.”
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.
[Posted 6/2/2021] Please confirm if degradation related to the renewable generation facility should be taken into account for the NEP RFP Projection and how responses that do not incorporate degradation will be evaluated.
Further, please confirm that how the NEP RFP Projection should account for losses from the energy storage component, such as during charging and discharging or auxiliary consumption.
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.
[Posted 7/26/2021] The Lanai CBRE Phase II RFP stipulates use of a 73 acre site owned by Pulama Lanai. This site references a pending land use application (A19-809) within the RFP to change the zoning from agricultural to heavy industrial. Are there any updates on the status of this application as the last update on the LUC website was on 12/1/2020 (withdrawal of final EA without prejudice)? Will the RFP schedule be amended should the rezoning effort be abandoned by Pulama Lanai?
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.
[Posted 8/10/21] I am attempting to approximate how the cost of electricity for Molokai will be impacted by a solar project installed under the CBRE program. Earlier this year there was a meeting at which Maui Electric presented and briefly mentioned that changes to the subscribers' bills would also be reflected in the O&M section of their costs. Could you share any further details about how the O&M costs will be affected by the CBRE project?
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.
[Posted 8/10/21] Now that travel restrictions are lifting statewide, is there any potential for lifting the site visit restriction pre-bid so that some members of our team may be able to visit the Palaau site on Molokai in the coming months?
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.
[Posted 8/10/21] Are there any additional studies or information that Hawaiian Electric has about the Palaau site that you could share at this time? The end of Appendix H, Page 3 of the CBRE Molokai RFP refers to the possibility of additional documents available upon request. Anything from soil studies to cultural reports would be very welcome, when and if possible.
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.
[Posted 10/12/21] For Mid-Tier projects, is there a maximum credit rate?
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.
[Posted 10/12/21] For Mid-Tier projects, the Lump Sum Payment accounts for the Net Energy Potential and availability of BESS actual output, and this fully loaded lump sum determines the credit rate? So for example, if we bid $2M lump sum payment, that would include both the Battery availability and the Net Energy Potential.
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.
[Posted 10/12/21] For a Mid-Tier project, instead of getting a $/kWh rate – the subscriber would get an actual dollar amount so if they had a subscription for 2% of the capacity, in this example, they would receive a $40k annual credit, or $3,333.33/month on their bill?
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.
[Posted 10/12/21] Does the subscriber’s savings rate vary per month? For example, if the System is 50% unsubscribed or only has 3 subscribers, is the Subscriber’s bill credit impacted in addition to the payments to the Subscriber Organization?
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.
[Posted 10/12/21] Please confirm there is only one “revenue stream” – or source of payment in the Mid-Tier Standard Form Contract and that is through the Lump Sum Payment? (For example, there is no additional payment directly for Battery, etc.)
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.
[Posted 10/12/21] Are CBRE projects on Oahu eligible for the SDP tariff (Rule 31)?
No, CBRE projects are not eligible to participate in the SDP program.
[Posted 10/12/21] Is there a bidders list that I may obtain to allow my team to supply proposals and solutions to the those bidding this project?
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.
[Posted 10/12/21] Could you list the models needed for the 5MW interconnection applications?
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.
[Posted 10/12/21] Will any site reports, such as an archaeological report and geotechnical report be provided for the designated Pulama Lanai site?
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.
[Posted 10/12/21] Is the most current estimate for the Final RFP Issue date is September 14, 2021 (as specified page 18 in the redline, “Draft Request for Proposals for Community-Based Renewable Energy Tranche 1, March 30, 2021”)?
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.
[Posted 10/12/21] Is the minimum residential subscription ratio for a CBRE Project 40% residential/60% anchor subscribers or 60% residential/40% anchor subscribers?
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.
[Posted 11/15/21] In the Draft Final CBRE Phase II RFP for Oahu, Maui & Hawaii Island filed on 8/25/21, Section 5.1.1 of the RFP appears to contradict Appendix B Section 2.11 Interconnection Submittal Requirements and the Q&A posted on 9/20. Appendix B Section 2.11 states that IRS data request worksheets and ‘all’ project diagrams shall be provided at proposal submission. However, in section 5.1.1 of the RFP it states that these documents shall be submitted within 30 days after final award group. Can you please clarify the due dates for the single line diagram, three line diagram, IRS data request worksheets, and models for equipment and controls?
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.
[Posted 11/15/21] Can a single project be awarded the entire 75 MW of program capacity for Oahu?
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.
[Posted 11/15/21] Does the RFP allow a Subscriber Organization to subscribe a master-metered building that is serving residential LMI customers (i.e., renters in Hawaii Public Housing Authority) and have those renters count towards the 100% LMI subscriber commitment?
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.
[Posted 12/21/21] For Mid-Tier projects, including LMI projects, what are the means/mechanisms for subscriber compensation with regard to bill credits and customer billing? Draft documents seem to indicate a utility-managed single billing process with no billing involvement for Subscriber Organization (other than subscriber acquisition and monthly reporting to Hawaiian Electric).
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.
[Posted 12/21/21] For Mid-Tier projects, including LMI projects, please confirm that full bill credits will be provided to subscribers for any period in which the projects are curtailed by the utility (Reserve Shutdown Hours).
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.
[Posted 12/21/21] For Medium/LMI projects: does the CBRE program allow the offering of bill credit discounts or additional savings?
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.
[Posted 12/21/21] Please provide any updates regarding Pulama Lanai’s Petition to Amend the Land Use District Boundaries referenced in Appendix F (Description of the Pulama Site) of the Lanai CBRE RFP.
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.
[Posted 12/21/21] Over the 20 year life of a CBRE project, program modifications may be needed due to market conditions. Will selected projects be able to modify their program offering subsequent to enrolling subscribers and will the CBRE Portal accommodate program offering changes? If so, how?
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.
[Posted 1/10/22] Please advise if a sample CSAT for a PV and BESS facility can be provided for review and reference.
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.
[Posted 1/10/22] During the Molokai & Lanai CBRE Phase 2 RFP Technical Training for Contracts held on December 8, 2021, the SLD included as Appendix H, Attachment 1 of the Lanai CBRE RFP was shown. This SLD shows two radial lines connecting into the Miki Basin switchgear. However, during the Q&A portion the following questions were asked:
- Are the two tie lines to Miki Basin more than 10MVA each? Answer- That’s the minimum requirement is that they’d support the export of as much as 10 MVA.
- If one Miki Basin tie line is down does all the PV/BESS need to be connected to the remaining tie line? Answer- Yes, that would be the expectation.
Since the SLD provided indicates two separate systems each tied to a separate feeder, and the RFP requirements do not discuss the ability to supply the full Facility capacity when one line is unavailable, can you please clarify the requirement and SLD, if the information provided in the 12/8 meeting is correct?
Also please confirm that in the event of a utility-owned feeder outage (as depicted in the SLD provided), that the Facility would not be penalized for the reduction in capacity that the line outage would cause.
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.
[Posted 1/10/22] In the Molokai & Lanai CBRE Phase 2 RFP Technical Training for Contracts, questions were asked regarding whether there are any technology limitations on energy storage (at 48:05), and whether hydrogen based energy storage would be acceptable (at 54:25). Please clarify these responses which indicated an openness to any commercially viable energy storage technology that meets the performance requirements.
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.
[Posted 1/10/22] In the Lanai CBRE RFP, the terms “Allowed Capacity” and “Maximum Rated Output” are both referenced as being defined in the RDG PPA. However, neither is included as a defined term in the Lanai RDG PPA (though Section 3.2 is titled Allowed Capacity). Additionally, in Appendix B of the RFP, Proposers are requested to provide the “BESS energy capacity (MWh)” with a requirement that it is a “minimum of 4 times the net nameplate capacity.” This contradicts the RFP which states that the BESS, “must be able to store and discharge 70 percent of the PV produced energy…” Please clarify the above items.
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)
[Posted 1/10/22] The Lanai RDG PPA provides the following definition for “Subscriber Allocation”: For each Subscriber during each calendar month, such Subscriber's beneficial share of the Contract Capacity as represented by such Subscriber's percentage interest in the Dedicated CBRE Capacity, which percentage reflects such Subscriber's allocable portion of the CBRE LSP Payment for such month.
Can you please define how the ‘subscriber’s percentage interest’ in the dedicated CBRE capacity is calculated? Is it based on the subscriber’s average 3-12 months of prior usage measured immediately prior to application submission as mentioned in Rule No. 29, annualized then divided into the total energy requirement of 35,800MWh?
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.
[Posted 1/13/22] How/where is the energy requirement (35.8 GWh) measured? Does the PV need to meet that capacity alone or can it be shared by the PV & storage? Does the energy requirement of 35.8 GWh need to be met in year 1 or year 20?
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.
[Posted 1/13/22] Does the reservation of 3 MW of capacity for the CBRE program need to be reflected in the Proposal, and if so, how?
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.
[Posted 1/13/22] The example SLD and costs shown in Appendix H, Attachments 1 and 2, provide an example of a 17.5MW system with two feeders to the utility. We interpret this to mean that distribution lines can exceed the 2.2MW single point of failure limit, otherwise at least 4-5 separate POIs would be required to meet this capacity used in the aforementioned example. Is it correct that each transformer needs to be less than 2.2 MW but each POI can take much more than that? Say 10 MW each?
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).
[Posted 1/20/22] With regards to the Lanai CBRE RFP, how will the Company determine what the 3MW CBRE carve out is in relation to the entire project and its equivalent reduction to the Lump Sum Payment?
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.
[Posted 1/25/22] Will the owner of the CBRE facility be entitled to get tax breaks and other incentives including the ITC (federal tax credit) and the Hawaiian State Tax Credit? Are there any other incentives we missed and would be available to us?
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.
[Posted 1/25/22] Are the LMI and Tranche 1 CBRE RFPs considered prevailing wage projects?
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.
[Posted 1/26/22] The CBRE RFPs define the NEP RFP Projection as follows: “The NEP RFP Projection associated with the proposed Project represents the estimated annual net energy (in MWh) that could be produced by the Facility and delivered to the Point of Interconnection over a ten-year period with a probability of exceedance of 95%.”
The use of the term “annual” and “over a ten-year period” appear to be in conflict. Please clarify.
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.
[Posted 2/1/22; Updated 2/10/22] With regard to the schedule included in Appendix H of the Molokai CBRE RFP, please provide responses to the following questions:
- Will Model Validation start as soon as all required data and payment is supplied by the proposer (i.e. is there any delay between Contract Execution and IRS Phase beginning?)
- Will the timeline for the 30% Design & Review Start immediately after FS is complete?
- Does the proposer have any role in approving/reviewing in the Engineering Phase or is it just the Company reviewing its engineering contractor's work? I am trying to determine if there would be any delays between milestones due to Proposer inputs in the Engineering Phase or if the milestones just flow one after the other immediately.
- Will construction start immediately after procurement is complete?
- Can the CSAT start before the Acceptance testing of the COIF if the proposer's generation facility construction is complete before the COIF construction is complete or does it need to follow after Acceptance testing?
- 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.
- 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.
- 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.
- Construction of COIF can start 3 months after Issued for Construction (IFC) Design & Review is complete.
- Acceptance testing is required to energize the facility, and the CSAT requires energization, so the CSAT must follow acceptance testing.
[Posted 2/1/22] With regard to the Molokai CBRE RFP, please confirm when the following documents are required to be submitted: single line diagrams, three line diagrams, interconnection data request worksheets, models for equipment and controls, lists identifying components and respective files, and complete documentation with instructions.
Please see Appendix B to the RFP and the table below
|250 kW||>250 kW|
|Single line diagram||Due with Proposal||Due with Proposal|
|Three line diagram||Due within 30 days of Final Award||Due within 30 days of Final Award|
|Interconnection Data Request worksheets||Due within 30 days of Final Award||Due with Proposal|
|Models for equipment and controls||Due within 30 days of Final Award, if requested||Due within 30 days of Final Award|
|Lists identifying components and respective files||Due within 30 days of Final Award||Due within 30 days of Final Award|
|Complete documentation with instructions||Due within 30 days of Final Award, if requested||Due within 30 days of Final Award|
Note: Preparation of models, documentation, and related information may take longer than 30 days, and Proposers shall allow adequate time for this submittal requirement.
[Posted 2/1/22] In Appendix F of the Molokai CBRE RFP, a map with three distinct areas is shown in Attachment 2, with Area A and Area B having an adjacent boundary. If a proposer chooses to use both Areas A & B, can racking structures and other equipment traverse the boundary (treating A & B as one area) or does a distinct boundary or fence need to remain between A & B?
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.
[Posted 2/2/22] In the Lanai CBRE RFP, the NEP is stated to not include the RTE associated with the BESS. If the BESS does not have a separate auxiliary power feed and auxiliary power usage is only provided and calculated within the RTE, can the NEP be specified with 0 for auxiliary loads so long as the resulting RTE is above the minimum requirements?
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.
[Posted 2/2/22] Since the state tax credit proceeds will be passed to the Company, will there be an in-kind adjustment to Seller’s costs or payments? As noted in the CBRE RFPs, “…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. The PPA will also provide that the Proposer will be responsible for payment of liquidated damages for failure to pursue the state tax credit.”
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.
[Posted 2/2/22] Why is the NEP calculated at 10 years when the RDG PPA is a 20-year term?
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.
[Posted 2/10/22] Regarding the Molokai CBRE RFP, Section 10.I (Project Completion) of the Mid-Tier SFC says that the project must reach COD within 18 months of contract execution or incur late fees. However, the timeline in Section 4.1 of Appendix H does not appear to support completion within the required 18 months. Please reconcile these two items.
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.
[Posted 3/29/22] Please provide clarification on the LMI CBRE RFP and its uncapped capacity. Is there a price threshold for which HECO will no longer accept applications? How is the RFP process run with unlimited capacity?
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.
[Posted 4/27/22] Does Hawaiian Electric intend to provide any marketing support for CBRE subscriber acquisition? For example, will Hawaiian Electric send out mailers or direct people to the CBRE website?
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.
[Posted 4/27/22] Are Subscriber Organizations (SO) required to use the CBRE portal, or can SOs opt out entirely? Are SOs required to collect payment through the portal (training suggests no), and is it actually possible to collect payment through the portal?
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.
[Posted 4/27/22] When a subscriber disenrolls from CBRE, will Hawaiian Electric take any action to replace the subscriber, or is it entirely the Subscriber Organization’s responsibility to replace subscribers?
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.
[Posted 4/27/22] Please confirm that a subscriber's interest will be automatically transferred to a new address if they move within the same island and the interest will be automatically terminated if they move to a different island.
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.
[Posted 4/27/22] Our understanding is that Subscriber Organizations (SO) have discretion as to how much of a discount to offer subscribers relative to the Lump Sum Payment (LSP). In effect, this means that SOs that provide less savings to subscribers will receive a higher percentage of their LSP bid as revenue. Is this correct?
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).
[Posted 4/27/22] Are there any plans to allow for Subscriber Organizations to collect payment from subscribers through Hawaiian Electric bills in order to reduce collection risk?
Hawaiian Electric does not currently have plans to facilitate payments between the Subscriber and Subscriber Organization.
[Posted 4/27/22] We are considering submitting multiple proposals, which, in aggregate, may exceed the volume of subscribers that we will be able to enroll. Is it permissible to submit proposals for all potential sites, and plan to withdraw certain bids if the awarded projects exceed the number of subscribers we will be able to enroll?
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.
[Posted 4/27/22] Do buildings with multiple residents under one meter, such as apartment buildings, count toward the minimum residential requirement in Rule 29?
No, residential customers must have individual electric accounts on a residential rate schedule.
[Posted 4/27/22] How does a building with multiple residents under one meter count towards the requirement in Rule 29 of minimum number of Subscribers?
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.
[Posted 4/27/22] What happens if the Subscriber Organization cannot meet the minimum requirement of four Subscribers or the minimum residential requirement in Rule 29?
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.
[Posted 5/3/22] How do Proposers typically prove “capability of Meeting Performance Standards? In terms of Reactive Power Control, Ramp Rate, Over/Under Voltage, etc.
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.
[Posted 5/3/22] Are manufacturing data sheets sufficient for “details of the major equipment”?
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.
[Posted 5/3/22] Section 3.10.1 of the RFP states that “[f]or 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 considering the BESS Contract Capacity and Maximum Rated Output should be included in the NEP RFP Projection.”
This implies that BESS must be factored into the NEP calculation. However, Exhibit B Section 2 of the RFP states that “[f]or 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.”
Can HECO clarify whether the BESS is to be factored into the NEP RFP Projection, or whether the NEP RFP Projection should ignore the BESS and assume that all energy below the Contract Capacity is delivered to the POI and fully dispatched?
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.
[Posted 5/3/22] The description of the Land Use and Impervious Cover non-price criterion in Section 4.4.2 of the LMI and Tranche 1 CBRE RFPs indicates a preference for projects on sited with certain zoning designations, “under the State Land Use Classification.” However, the State Land Use Classifications do not differentiate between the zoning options identified (e.g. industrial, commercial, apartment mixed use). Please clarify how the company will administer this portion of the Land Use and Impervious Cover non-price criterion.
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 firstname.lastname@example.org.
[Posted 5/10/22] For projects greater than 1 MW ins size interconnecting at the distribution level, please clarify what interconnection details and modeling are required at the time of RFP response submission vs. what is required within 30-days of notice of award or later for projects that require an Interconnection Requirement Study and/or System Impact Study.
- Section 2.10 - all performance related questions
- Section 2.11
- Interconnection Data Request Worksheet (Appendix B - Attachment 2)
- Project Diagrams
- List identifying components and respective files
- Complete documentation and instructions
- Items listed in Appendix B Attachment 3 (Hawaiian Electric Facility Technical Model Requirements and Review Process document)
- Items listed in Appendix B Attachment 6 (Model and IRS Scope table) that are not associated with diagrams and equipment data sheets already provided under 2.10 or 2.11 above.
Please see the response to each item below:
- All information requested as part of Section 2.10 of Appendix B must be submitted with the proposal.
- For a project greater than 1 MW, all of the items listed in Section 2.11.3 must be provided with the proposal:
- Completed Project Interconnection Requirement Study Data Request worksheet;
- All project diagram(s);
- Models for equipment and controls;
- List(s) identifying components and respective files (for inverters and power plant controller). Respective files can include equipment spec sheets, product manuals, etc.
- 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.
- 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.
- 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.
[Posted 5/10/22] Section 1.2.17 of the RFP LMI and Tranche 1 RFPs request that proposal submit pricing without incorporating the State's Tax Credit. The same section mentions that the pricing should be set to incorporate any changes after award and the availability of tax credits - correct? This section references Attachment J of the Mid-Tier SFC - however, that is blank and "reserved".
Similarly the Federal Investment Tax Credit (ITC) is on a sunset schedule. Projects that do not start construction by 12/31/2023 and/or that are placed in service after 12/31/2025, are only eligible for a 10% Federal ITC. Given the RFP award schedule and subsequent interconnection study and procurement process for final selected projects, 10% is the most likely ITC they will receive. However, there are on-going discussions within US Congress for either extensions or new Federal ITCs that could be applicable to an awarded project. Section 3.9.1 of the RFP does not allow pricing contingencies (Pricing cannot be specified as contingent upon other factors (e.g., changes to federal tax policy or receiving all Investment Tax Credits assumed). How then should bidders plan for any changes to the ITC that could have a beneficial impact to Hawaiian Electric and the CBRE subscribers? Should bidders make a "variation" proposal assuming a higher ITC (e.g. the 22% ITC level is extended for 10 years)?
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.
[Posted 5/10/22] The RFP has a number of areas that refer to the models and interconnection studies and suggest they will only be associated with awarded projects such as in Section 5.1.2 of the RFP.
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).
[Posted 5/11/22] In the LMI CBRE RFP, the “Available Circuit Capacity” threshold assessment (Section 4.3, Item 8) indicates that for projects interconnecting at the transmission or subtransmission level there must be enough available MW capacity for a project to pass the threshold assessment. However, Section 2.2.3 appears to allow for the possibility for Oahu projects interconnecting at 46 kV to upgrade the conductor of that circuit if it is a viable option.
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.
[Posted 5/13/22] Section 2.3.3 of the LMI RFP says "Costs for Company Owned Interconnection Facilities should not be included in the Proposal pricing, unless specified in Appendix H." Sec 1.3 of Appendix H then says that "Except for costs agreed to be paid by Company under Items 3, 4, and 5 below, Proposer shall be responsible for the design, procurement, and construction of all facilities at the Proposer’s project site" before listing a series of costs in various tables on pages 6-19 of Appendix H.
Please clarify if CBRE proposals pricing submitted should reflect those costs, as applicable, on pages 6 - 19 of Appendix H.
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.
[Posted 5/13/22] Would it be possible to identify the Critical Infrastructure or Community Resilience hubs near these sites as requested in Section 2.5.6 of Appendix B of the LMI and Tranche 1 CBRE RFPs?
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.
[Posted 6/9/22] In Rule 29 for all islands states that, “[c]urrent State of Hawaii census tract information shall be used to determine the priority census tracts.” Please confirm that this should be interpreted that the 2020 census tract data should be used, not the 2010 data referenced in footnote #6 of the Tranche 1 CBRE RFP should not be used.
Further, please clarify in instances where a neighborhood is split into two census tracts and one tract is no longer considered ‘adjoining’ to the project site that these individuals should be excluded from consideration for priority enrollment, or would exceptions be granted on case by case basis?
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.
[Posted 7/12/22] Will the Subscriber Organization (SO) only bill HECO for the Lump Sum Payments or will the SO also be billing the Subscriber?
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.
[Posted 7/12/22] Will Hawaiian Electric continue to bill the Subscriber for periodic kWh consumption, as under existing conditions, except to provide the Subscriber a Bill Credit in accordance with the RFP?
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.
[Posted 8/3/22] In the Tranche 1 CBRE RFP, will the costs of Company-Owned Interconnection Facilities (COIF) be “waived” (or paid for by the Company) for projects committing to all capacity being reserved for LMI customers?
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.
[Posted 8/10/22] The Tranche 1 CBRE RFP, Appendix B, Table 2.0, Item 18 asks if “[t]he Proposer hereby certifies that the Project is dedicated to LMI Subscribers with a minimum 60% dedicated to LMI Customers as described in Section 1.2.3 of the RFP.” Section 1.2.3 of the RFP does not describe this requirement. How should a Proposer respond to this question?
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.