Hawaii: paying for home batteries to replace a coal plant

The AES Hawaii coal plant supplied about 16% of Oahu’s energy in 2020 (Hawaii State Energy Office). Its 30-year contract ended in September 2022. Hawaiian Electric warned that the retirement would lift bills by about 7%, or roughly $15 a month for a typical home (Hawaiian Electric).

The replacements were late. Several solar-and-storage projects slipped, and planners expected the biggest evening shortfalls in 2023 (VEIC). Oahu’s peak comes after sunset, about 6 to 8:30 p.m., when rooftop solar has gone quiet. In June 2021, the Hawaii Public Utilities Commission (PUC) approved an emergency program to fill that gap (Utility Dive).

Without enough evening supply, the grid operator has to shed load: rolling blackouts. Oahu came close on July 31, 2024, when an outage at the Kalaeloa plant triggered blackout warnings. Conservation, storage and demand response cut about 40 MW that evening (state Division of Consumer Advocacy update, Honolulu Star-Advertiser).

Every evening kilowatt-hour is also expensive. Oahu’s time-of-use rate charged 46.3¢ per kWh on peak in December 2024 (TOU-RI rate history). In October 2026, a 500 kWh residential bill was $246.44, close to 49¢ per kWh, as fuel costs rose (October 2026 fuel adjustment filing). The permanent fix was utility-scale storage: Kapolei Energy Storage, 185 MW and 565 MWh, began operating more than a year after the coal plant closed (Canary Media). A second, 142 MW project followed (Kapolei Energy Storage II).

The PUC’s Order No. 37816 created the Scheduled Dispatch Program, sold to customers as Battery Bonus (PUC distributed energy programs page). It opened on Oahu in July 2021 and on Maui in May 2022. Unlike Puerto Rico’s program, it did not use batteries already installed. It paid customers to add a new battery to rooftop solar and commit part of its output (Battery Bonus fact sheet).

Demand was strong. The program passed its Oahu cap on December 13, 2023 (cap announcement). Contractors rushed to finish: at the end of 2024, more than 1,600 applications were still in progress, and extensions ran into 2025 (Hawaiian Electric 2024 review). Hawaiian Electric also earned a performance incentive for grid services under its performance-based regulation: $36,160 in 2022 and $1.05 million in 2023 (RMI’s performance incentive tracker).

This is the nuance that defines the program. Battery Bonus never calls an event. Each battery is programmed once, at installation, to discharge at a fixed time every day. Hawaiian Electric staggers start times so the fleet ramps by about 2 MW a minute rather than all at once at 6:00 p.m. It then checks after the fact, using smart-meter data, whether each home delivered.

1. The schedule is cheap to run. No aggregator, no dispatch platform and no live telemetry. The installer sets the schedule.
2. The utility cannot see or change it in real time. Tesla systems could only be scheduled in 15-minute steps, so a 6:04 p.m. start became 6:15 p.m. Reassigning start times to fit could have spread the program from 5:00 p.m. to after 7:00 p.m. (2024 review, program operations).
3. Other software can override it. On storm days in October 2024, Tesla’s Storm Watch feature charged many batteries from the grid ahead of the weather, raising load rather than lowering it. The utility said the result could have been worse on a typical weekday with less reserve.
4. Minute-level coordination is hard. Hawaiian Electric’s own lesson: “Minute level dispatch very difficult to do” (NASEO presentation slides).

For planners, a committed kilowatt was not a firm kilowatt. Hawaiian Electric’s 2023 adequacy filing counted only 15 MW of Battery Bonus toward Oahu’s needs (adequacy of supply report). A year later, the utility’s own rough estimate of daytime solar export shifted into the evening was the same 15 MW. Customers still received full pay on their committed kW.

The evaluation found several causes. Many “timing issue” systems began 5–10 minutes early or 10–15 minutes late, mostly because of the 15-minute Tesla scheduling limit. About 4% of participants had committed more than 10 kW, more than a typical home battery’s continuous output of about 5 kW. The average commitment across the program is about 7.5 kW per customer. An August 2024 audit sent notices to 50 customers, and all returned to compliance by year-end (2024 annual review, audit results).

The 2025 follow-up was no more reassuring. Using January–October 2025 meter data, 63% of systems exported at least 2 kWh in their window every month, the equivalent of 1 kW; only 4% consistently exported at 70% or more (2026 annual review, performance section).

The household side was generous. A 5 kW commitment earned $7,250 over 10 years in upfront pay and credits, a meaningful share of a battery’s cost. Hawaiian Electric’s presentation adds a second benefit: lower monthly bills, with 47% of participants carrying a growing negative bill balance (Hawaiian Electric slides). Those are gross payments, not profit: the household paid for the battery and gives up two hours of stored energy every evening.

The replacement programs show how much the pay mattered. BYOD Level 1 opened in April 2024. Installers did not market it because they did not think it offered enough value, and by the end of 2024 not one customer was enabled (the utility’s 2024 review). The PUC approved BYOD Plus in March 2025: $400 per kW upfront, $800 for low- and moderate-income homes, export credit at the retail rate for customers not on net metering, a customer-chosen two-hour window and a five-year term (BYOD Plus page, BYOD tariff). Thirteen months in, it had 334 customers and 2.78 MW, more than half of them income-qualified (monthly enrollment report). The utility expects slower residential uptake after the federal residential tax credit expired at the end of 2025 (program goals report).

Aggregator programs had their own trouble. Swell Energy closed in 2024; Hawaiian Electric declared it in default and terminated its contracts in January 2025 (Hawaiian Electric emerging technologies page). That left 1,241 residential participants whose batteries the utility could not control, with incentives paused (2026 review, aggregator section). Battery Bonus, with no middleman, did not face that risk.

Per committed kW, Battery Bonus looks cheap: about $145 a year, below New England’s $275 pay-for-performance rate. But the utility pays on commitment, and the grid gets delivery. Dividing by Hawaiian Electric’s own estimate of what shifted, the cost rises to about $454 per kW a year. Hawaiian Electric’s 2025 benefit-cost analysis reached the same place: the grid-service programs as a group scored below 1.0, “primarily due to SDP’s high incentive expenses” (2026 annual program review).

It still did its job. It added tens of megawatts of evening battery output across thousands of homes during the year between coal and Kapolei, without new transmission or a power plant. Ratepayers paid a premium for speed and for a fleet that will keep discharging every evening until the early 2030s.

Both islands turned to home batteries when generation fell short. They made opposite design choices. See our Puerto Rico LUMA case study.

Related: what Hawaiian Electric pays today in our Hawaiian Electric residential deep dive and C&I deep dive, and how other programs pay for verified performance in the New England ConnectedSolutions case study.