Utility PG&E finalized its contract with a battery project slated to displace a jet-fuel-burning power plant in downtown Oakland, California.
The Oakland Clean Energy Initiative models a pathway for removing decades-old power plants in dense urban settings while keeping the lights on with new lithium-ion batteries. But the project’s collaborative business model also makes it potentially groundbreaking for energy storage development, by formalizing the use of the battery for discrete grid services on behalf of two different clients.
PG&E, which is working to emerge from bankruptcy by the end of June, has experience building batteries and contracting with third parties for the use of their batteries. Battery owners often contract services to an offtaker while playing in merchant markets themselves. But the Oakland project marks a new foray into an owner sharing a front-of-meter battery plant with multiple customers.
Independent power producer Vistra Energy, which owns the 165-megawatt jet-fueled plant in question, signed a deal with PG&E to build a 36.25-megawatt/145-megawatt-hour battery at the existing site in Jack London Square. The facility will provide “local area reliability service,” helping the utility with its job of transmitting power to residents in Oakland. Doing so avoids a far costlier investment, like running new wires over the hills from the Moraga substation.
But those consumers now buy their power from a community-choice aggregator called East Bay Community Energy, a locally administered group dedicated to rapidly scaling up clean energy. EBCE contracted with Vistra last year to use the same battery as a capacity source to fulfill its resource adequacy requirements, which provide power to ride out extreme peak events. The battery originally was going to deliver 20 megawatts/80 megawatt-hours, but the planned capacity has expanded since then.
The double-dipping addresses a structural challenge facing the rise of storage technology on the grid: Batteries can do all sorts of useful things, but it’s often hard to find one customer that needs all of those capabilities. A world that constrained batteries to single uses for single customers would result in redundancy and inefficiency compared to a system where multiple stakeholders use the same equipment for different purposes.
"This is a prime example of collaboration as innovation — recognizing energy storage's value to both parties may be the only way either party can capture that value," said Daniel Finn-Foley, energy storage director at Wood Mackenzie. "Providing either resource adequacy to EBCE or a non-wires solution to PG&E may not have been bankable, but by contracting with both entities, both problems get solved and the system is fully recognized for its value."
The regulatory backdrop here is in some sense specific to California. The state allowed local populations to form community-choice aggregators, giving them control over power purchasing and pricing for customers but leaving it to the utilities to manage the power delivery. EBCE pulled away PG&E customers in the East Bay, and that came with an obligation to provide for their peak power needs.
Most states lack this sort of arrangement. But it’s quite common to see storage contracts that cannot account for the full value of the asset due to legal limitations on what certain energy companies can do. This typically happens in markets where regulated utilities manage the wires and private investors engage in market competition to supply generation, as in Texas and many states in the Northeast.
For instance, a wires utility could use a battery to avoid a costly transmission expansion, but not if it puts them into the generation business. Conversely, a generator could use the battery to deliver capacity at a valuable grid node where gas plant development would not be feasible, but it has no role to play in the transmission and distribution of power. These firm distinctions predate the rise of grid batteries, which defy easy categorization due to their wide-ranging technical capabilities.
Vistra’s Oakland battery still needs approval from the California Public Utilities Commission. After that, it’s supposed to be up and running by January 2022. If all that happens and it operates in a way that satisfies its clients, the project will prove that a more collaborative world is possible.
That doesn’t mean this model could work everywhere, given the variations in market rules from state to state. But where it does work, it promises better project economics through cost-sharing among more stakeholders, and more efficient use of grid infrastructure, all while replacing polluting plants with non-emitting boxes of batteries.