Hawaiian Electric C&I demand response and battery economics

Hawaiian Electric’s three utilities serve businesses on Oahu, Maui County and Hawaii Island under Schedules G (small), J (medium) and P (large power), each priced by island (effective rate summary). The PUC approves every rate and program, and independent producers and aggregators sell to Hawaiian Electric under contract. Hawaii Energy, the state’s efficiency program, pays separate rebates (Hawaii Energy commercial rebates).

Every deep dive on this site has one feature that changes how its economics read. For Hawaiian Electric’s business customers it is the shape of the bill. On the mainland, a large site’s demand charge is often a third or more of the bill, and flexibility is mostly about cutting peaks. On Oahu, the energy cost recovery factor alone was 29.06¢ per kWh in October 2026 (Oahu ECRC filing), up from about 18¢ in early 2026. It passes fuel and purchased-power costs straight through, month by month.

For a 500 kW site running at a 60% load factor, the demand charge is about 17% of the bill and the fuel adjustment about 68%. A battery can cut the demand charge, but on a flat energy rate it cannot cut the kWh: every kWh it stores is bought at the same price and loses about 10% in the round trip. Solar can cut it, and time-of-use rates would let a battery profit from shifting. The PUC’s advanced rate design study included business time-of-use schedules, with a default rollout still to be scheduled (PUC advanced rate design).

Fast DR pays $5 per kW-month for up to 40 one-hour events a year or $10 for up to 80, plus 50¢ per kWh reduced, adjusted for performance, for sites that can drop at least 50 kW within 10 minutes on weekdays from 7 a.m. to 9 p.m. (program rules). A 50 kW site earns at least $3,000 a year whether or not an event is called (Fast DR FAQ). In 2025 it had 35 customers and 5.26 MW, mostly military sites, hotels, condominiums, retailers and a water utility, and paid $427,658 in incentives; Oahu spent about $326,000 of a $1.21 million budget (2026 CER report).

BYOD Plus is open to commercial customers with a new battery charged from on-site renewables, at $400 per kW upfront (BYOD Plus tariff). In 2024, Hawaii Energy’s Power Move added rebates of up to $250 per kWh for commercial batteries dispatched from 6 to 8:30 p.m. alongside Battery Bonus (Power Move rules); check whether a current cycle pairs with BYOD Plus.

Stacking here means combining the bill, Fast DR, BYOD Plus and the federal credit. With no wholesale market, there is no capacity payment to add and no double-pay rule to navigate between the utility and an ISO.

Stacking needs care, depending on M&V methodology. Fast DR measures reductions against a 10-day average baseline, and BYOD Plus verifies a daily two-hour discharge from the battery’s own data. A battery that runs every evening for BYOD Plus raises its own evening baseline in Fast DR.

The Schedule P demand charge is worth about $384 per kW-year, more than three times Fast DR’s top tier. BYOD Plus looks generous upfront but asks for 200 kWh of discharge every day from a 100 kW commitment. On a flat 35¢ energy rate, the round-trip losses on that cycling cost about $3k a year, which offsets much of the incentive over ten years.

The site’s line above is only half of the deal. The developer pays the full $240k, carries maintenance, insurance and performance risk, and prices all of it into the contract to earn a return on its capital (Morgan Lewis). Third-party storage contracts usually run 15 years or more (Peak Power), and lenders treat 15- to 20-year terms as financeable (Illinois Power Agency). The chart below values each deal from the developer’s side.

With 25% of savings left to the site, a 15-year deal covers about 89% of the developer’s cost on our model. At the modeled cost, a developer cannot earn 8% and still leave the site a share of demand savings. Battery-service offers are not priced the other way around, as a fee on top of handing over the savings: shared-savings providers promote a guaranteed share from day one (Gridwealth Electric), and Peak Power’s projects in Westchester, New York, split bill savings and market revenue with the building owner (NYSERDA case study). A deal that cannot fund a share is usually not offered at all. A guaranteed 15% share would need an installed cost about 12% lower, near $211k, or a larger site where cost per kWh falls; providers such as Peak Power focus on facilities with more than 1 MW of load (Peak Power’s overview). The battery-service line above shows that 15% share. A demand charge this high makes Oahu one of the stronger cases for a business battery, even without a market to sell into.

Hawaiian Electric’s grid services portfolio is in flux. OATI’s agreement was extended into 2026 but remains short of its contracted capacity, and Swell’s agreements were terminated in January 2025 (Hawaiian Electric’s 2026 CER filing; see our OATI profile). Hawaiian Electric expects commercial projects to take a larger share of BYOD Plus in 2026 (CER goals report).

The future of VPP to grow at scale will depend on multiple assets in unison at any given site: building controls, chilled water and water heaters, EV charging and batteries, dispatched together. For businesses in Hawaii, the next steps are time-of-use business rates that reward shifting, a Fast DR redesign that passes its cost test, and a grid services contract that replaces the lost aggregator capacity.

Compare: the Hawaiian Electric residential deep dive for BYOD Plus at home, and the Austin Energy C&I deep dive for a utility inside a wholesale market.