Sometimes the greatest clean energy innovations happen in your own backyard.
That’s a wishful statement for most people in this country, but I live in Oakland, California, so it comes true with delightful regularity. Thus, I commuted 10 minutes on a recent Monday morning to see the unveiling of an energy storage project that the industry would do well to emulate elsewhere.
The Oakland Clean Energy Initiative hits several grid edge high notes.
It’s shutting down an urban peaker that burns jet fuel next to bustling residential and commercial areas, replacing it with a battery peaker. It’s also a non-wires alternative, offsetting a much more expensive and invasive wire-based upgrade. Lastly, it’s a proof of concept that California’s local power purchasers, known as community-choice aggregators (CCAs), could offer considerably more upside for storage deployment than previously thought.
Here are the key lessons from this new project structure that could translate beyond the shores of Oakland’s Jack London Square.
CCAs will drive significant storage development
For better or worse, California structured its energy storage rollout so that large projects flow through utility procurement. The state gave each investor-owned utility a target, and they had to meet it. But CCAs are breaking open a new market that does not depend on the lengthy cycle of utility procurement.
Case in point, East Bay Community Energy, which covers Oakland and the rest of Alameda County, across the bay from San Francisco, just launched last fall. Besides the 20-megawatt/80-megawatt-hour system slated for downtown Oakland, it contracted with EDP Renewables North America for a 100-megawatt solar plant in the Central Valley paired with 30 megawatts/120 megawatt-hours of storage.
Before its one-year anniversary, the group signed contracts that exceeded its obligation under the state energy storage mandate by a factor of four or five, CEO Nick Chaset told me.
That’s a striking departure from the status quo approach of procuring to meet a target. East Bay Community Energy is not alone in this storage enthusiasm.
Silicon Valley Clean Energy and Monterey Bay Community Power signed a joint deal with Recurrent Energy in October for a 150-megawatt solar plant combined with a battery system rated at 45 megawatts/180 megawatt-hours. They also signed a deal with EDF Renewables North America for 128 megawatts of solar capacity coupled with a 40-megawatt/160-megawatt-hour battery plant.
"CCAs represent a non-trivial opportunity for solar and storage developers doing business in California," said Ravi Manghani, energy storage director at Wood Mackenzie Power & Renewables.
The upside could be considerably better than "non-trivial," as the addressable market of CCA customers has grown astonishingly vast in the last few years. Industry group CalCCA counts 19 different CCAs covering almost the entire coastal territory of California. They serve a combined 4,073,600 customer accounts, and many more counties are mulling whether to go the CCA route.
In just a few years, CCAs have pulled retail customers away from utilities across a vast swath of California. Image credit: CalCCA
The CCAs' charters include varying degrees of commitment to locally sited and clean energy investments. Both goals lend themselves to storage when it comes time to ensure dispatchable capacity; nobody is eager to build new fossil-fuel-burning resources in their neighborhood.
“CCAs, just based on the philosophy of their existence, are likely to go beyond state mandates,” said WoodMac's Manghani. “By definition, they have to be progressive.”
If developers get comfortable with young offtakers with short credit histories, this could create a massive new customer base. The fact that the local decision-making process moves faster than working with massive utility bureaucracies only sweetens the deal.
Keep an eye on Vistra
Independent power producer and retailer Vistra is not starved for attention. A nearly $11 billion market cap and operating fleet of 41 gigawatts speak for themselves. I would argue, though, that Vistra has quietly built itself into a pivotal player in the storage developer ecosystem.
The Texas-based company hasn’t spent much time in the storage conference spotlight, and its involvement in the sector is quite a recent development, starting with a solar-paired project announced in 2018. Since then, though, Vistra won the biggest battery contract ever for PG&E’s Moss Landing colossus and followed up with the Jack London system, much smaller but still among the larger projects being built nationwide.
What distinguishes this company from the other storage developers angling to replace gas peakers is that Vistra owns the gas peakers. Its subsidiary Dynegy controlled Moss Landing, where batteries will fill a decommissioned turbine hall, as well as the Jack London peaker with its giant vat of jet fuel.
These forays into storage development, then, reveal Vistra as selectively cannibalizing its old business, a refreshingly forward-looking approach for an incumbent that could instead continue making money from its previously capitalized plants.
Stepping into storage gives Vistra experience with a new business ahead of peers like Calpine or NRG, and positions a favorable narrative. The representatives onsite for the signing ceremony were celebrated as harbingers of the newer, cleaner era, instead of detested as the profiteers burning jet fuel in a dense urban environment.
It should be noted that rarely used peaker plants are easy candidates for swap-outs like this. Closing massive coal, gas or nuclear plants with robust workforces triggers thorny political and economic questions for the communities that host them (see New Mexico's legislative compromise to close its remaining coal plants).
In contrast, the economic impact of closing the Oakland peaker never came up at the signing ceremony.
I'm not aware of any movement from Calpine in this direction, although a few of its California peakers have come under pressure from storage; the Moss Landing procurement, where Vistra won big, was created to avoid paying Calpine to keep three gas plants open.
That said, Calpine’s private-equity backer, Energy Capital Partners, just acquired industrial storage developer Convergent. The two will remain separate, but the shared corporate parent could start conversations between them about peaker replacement.
Apples and oranges, peakers and batteries
The foregoing discussion assumes an awareness on the part of my savvy readers that the efficacy of storage as a peaking resource remains a theory in need of further empirical proof.
At this point, we know that storage can dispatch instantly to help meet peak demand, but the mechanics of how much is needed and where can get complicated real quick. Oakland offers a case study of how to translate an existing peaker into a new battery.
By nameplate capacity, the transition looks like a massive downgrade. Oakland will lose a 165-megawatt power source in the heart of its load pocket in exchange for a 20-megawatt resource.
That doesn’t tell the full story, of course.
For six months of 2018, the facility produced absolutely nothing. Those would be months when a battery could generate revenue in the wholesale markets, instead of sitting idle. Several of the months when the plant did generate, it produced negligible amounts, like 4 megawatt-hours in December or 13 megawatt-hours in November. The battery can easily handle that duty.
The real question is how a battery will fare in those summer months when the peaker produced thousands of megawatt-hours. Will those needs come spread over enough time that the battery can fill them with just 20 megawatts of instantaneous capacity? Do they allow time for the battery to recharge, preferably without spending a bundle on highly priced peak power? Will enough other resources come online to assist, such that this single plant needn’t shoulder the entire burden itself?
Those are the details that need clarification to build confidence in a vision of battery-dominated local capacity.
