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Developers press HECO on interconnection, sizing, financing and community donations
Summary
Developers and commission staff used the technical conference Q&A to press Hawaiian Electric on interconnection bay capacity, whether projects can exceed RFP targets at specific substations, PV+storage sizing rules, community‑benefit donation math and fuel cost pass‑through for combustion/biofuel projects.
A technical session of the Public Utilities Commission docket provided detailed back‑and‑forth between developers, commission staff and Hawaiian Electric technical leads about practical implementation of the IGP RFP.
On interconnection, Hawaiian Electric explained that a transmission substation is partitioned into bays; once a project occupies a bay, the bay is effectively reserved even if installed equipment does not use the bay’s maximum rated capacity. Staff said the downstream transmission system is not automatically reserved at the bay’s maximum rate — actual limits depend on installed breakers and line sizing — and developers must model equipment ratings when proposing to use a bay.
Stakeholders asked whether a project could propose capacity in excess of the RFP’s target for a location (for example, a 100 MW project where the RFP seeks 80 MW at that substation). HECO said projects are not strictly limited to the exact sizes requested and could be evaluated if the additional capacity makes sense in the selection models; whether such a larger project would be selected depends on evaluation results and grid models.
On paired systems, Hawaiian Electric clarified generating units must meet the minimum nameplate (for firm generation projects that threshold is 5 MW) and storage is expected to match the power rating and provide four hours of duration. For community benefits, HECO said the exhibit’s $3,000 per megawatt per year metric applies to standalone storage measured by megawatts of power (and for paired systems the donation is based on the facility’s MW rating, not separately on each co‑located asset if they constitute one facility).
On combustion/biofuel projects, HECO confirmed fuel costs are forecasted for evaluation and that fuel‑cost mechanisms in final contracts are typically pass‑throughs subject to commission approval; fuel supply contracts and their forecasts are part of the detailed evaluation and the PUC must consent to any fuel contracts in the PPA.
Developers asked for more explicit draft language on co‑located projects that share an interconnection or PPA; HECO said it would clarify that language in a subsequent draft and hold a follow‑up technical conference if needed. No formal actions or approvals were taken during the Q&A; the company and HSEO will file additional materials to the docket.
Next steps: HECO to clarify draft language on co‑located projects, file IR responses, and the PUC to determine whether additional technical sessions or structured comment sets are needed.
