Community Choice Aggregator Locks Down a 92 MW Battery: Who Controls Dispatch When the Grid Goes Private

EDP Renewables completed the Sandrini Energy Storage facility, a 92 megawatt / 368 megawatt-hour battery system in Kern County, California, co-located with a 300 MW solar farm.^[1] The Redwood Coast Energy Authority, a community choice aggregator serving Humboldt County about 600 miles north, holds an energy storage service agreement for 100% of the battery capacity and purchases 100 MW of the solar output as well.^[5] The project is designed to capture midday solar production and discharge it during evening peak demand, the hours California pays the most to cover.^[7] On its face, this looks like clean energy competence: a public agency buying a four-hour duration battery to smooth solar intermittency and support local grid reliability.

But the mechanics demand scrutiny. A community choice aggregator is a public agency, yet when it contracts for 100% of a private battery's capacity, it is buying dispatch rights, not ownership. EDP Renewables retains the hardware, the financial upside from any residual value, and the operational say. RCEA gets the energy it scheduled for. The public framing emphasizes grid reliability and carbon-free electricity; the deal structure embeds a private operator's return on capital, hardware degradation, and control over any surplus cycling opportunity that RCEA does not explicitly reserve. The contract terms are not public unless RCEA files them in a rate case or makes them available through California Public Records Act requests, and most ratepayers never learn they exist.

The honest questions: What price does RCEA pay per megawatt-hour dispatched? What happens to the battery after the contract term ends? If RCEA cycles it daily at the four-hour full-output rate, over how many years does the contract run, and what does battery degradation cost at the end? Does RCEA have the option to extend, or does the hardware revert to EDP to monetize in the wholesale market or sell to a different buyer? A 368 MWh system at full cycling could run 5,000 to 8,000 cycles over a 10-year life; that is real value. If the contract is structured as a lease with no buyout option, RCEA is essentially renting power while EDP captures the residual economic life of the cells. The public agency then has no claim on the asset it has been paying to degrade.

This is not an argument against RCEA's purchase. Buying storage is often cheaper and faster than building new peaking capacity, and a public agency signing a long-term offtake agreement de-risks a developer and can unlock financing that benefits everyone on the grid. But the template matters. If every community choice aggregator or municipal utility treats storage contracting as a black-box procurement, price, MWh, term, without requiring transparency on per-cycle cost, end-of-life disposition, and cycling caps, then the public sector is systematically overpaying for the service of dispatch while ceding the upside of battery degradation to private operators. The dollar value is substantial: a $5 million per year revenue flow ^[4] from a battery suggests a deployment cost in the $80, 120 million range (depending on the $/MWh capital cost); over a 15-year contract, that is $75, 180 million in cumulative payments. The public interest in knowing how much of that covers operations, how much de-risks a developer, and how much is surplus margin is self-evident.

California's energy storage procurement is booming because export-hostile rate design (NEM 3.0 and successor tariffs) has made rooftop solar economically marginal for most households, while utility-scale storage on solar sites remains viable under long-term contracts.^[6] That disparity is the policy win for incumbent utilities: residential storage and distributed solar stay expensive; bulk storage backed by ratepayer money becomes the grid's answer to intermittency. RCEA, a leader in renewable procurement, has built 100% carbon-free electricity procurement by contract because California's wholesale market is now deep enough in renewable supply to allow it.^[8] But the contract structure, private ownership, public dispatch rights, opaque pricing, is a template that scales. As storage deployment accelerates, every procurement of this type should require public disclosure of the per-kWh-cycled cost, the cycle cap or unlimited-event terms, and the residual value disposition at contract end. Public agencies should demand buyout options or performance-based extensions that preserve optionality if battery costs fall further.

The alternative is to build storage as a public asset. RCEA could have partnered with California's Clean Energy Access Program or sought grant funding (SGIP, LIOB, IRA section 1611 low-income backup power) to own the hardware directly, operating it for resilience and dispatch at cost. That trades upfront capital risk for permanent asset control and the ability to extend cycling if grid conditions change. Given that RCEA already operates as a load-serving entity, adding a balance sheet line for batteries owned by the agency is operationally and politically feasible. The private contract buys speed; public ownership buys sovereignty. RCEA's board should compare the cumulative 15-year cost of the EDP contract against the all-in financing cost of owning the same hardware, including the loss of dispatch control and residual value.