Solar is taking over California's grid, and the state has to eliminate carbon emissions from power plants by 2045. Those trends suggest the grid will benefit from energy storage that covers a longer period of time than the lithium-ion batteries getting installed today.
Exactly how much, though, is a matter of debate, because there's little recent track record for procuring long duration storage, and many of the potential technologies have limited experience in the field. Earlier this year, California regulators floated an interim need for nearly 1 gigawatt of long duration storage by 2026.
But the state could need much more: up to 11 gigawatts by 2030, and 45 to 55 gigawatts by 2045, according to a new analysis prepared for the California Energy Storage Alliance, an industry group. CESA tapped sister organization Strategen Consulting to model the future of the grid with more temporal granularity than the official state process, and with more detailed cost assumptions for the emerging suite of technologies that purport to store electricity cost-effectively for five, 10 and 100 hours.
“We need long duration storage sooner than we think,” CESA policy manager Jin Noh told GTM. “The resource buildout rate is so significant that we just have to start steadily procuring now to get to our 2045 goal.”
But doing so will generate savings for ratepayers compared to a portfolio that overlooks the need for long duration resources, Noh added.
See GTM's previous coverage on this topic: So what exactly is long duration energy storage?
Different model, different outcome
California's grid regulator, the California Public Utilities Commission, conducts a long term planning process using the RESOLVE model, which is geared toward investment planning for highly renewable systems. But that model does not simulate an entire calendar year; instead, it uses a “smart sampling” of 37 independent days to create an aggregate account of potential wind, solar, hydro and load conditions.
That framework, though, does not track the kind of back-to-back extreme conditions that may constrain the grid, like a prolonged heatwave, or days on end of low solar production.
“Finding these representative days and averaging them out, you miss some of the outlier events that really drive what investment is needed,” Noh said.
To address that, the study uses the GridPath model, which allows sequential modeling of each hour of each year. Doing so captures energy time shifting dynamics over longer periods of time, the authors note. That approach is more computationally intensive, so CESA only modeled the needed additions for 2030 and 2045. The analysis did not include local transmission constraints, Noh noted.
The CESA study also dug into a spectrum of long duration technologies to create generalizable cost assumptions for five-hour, 10-hour and 100-hour storage devices. Energy storage cost assumptions are another topic of frequent debate: choose unflattering assumptions, and a model will minimize the role for storage. But long duration has little public record to go on in terms of cost structure.
With the full year, hour by hour model and the more detailed technology profiles, the modelers applied the parameters of California's transition to carbon-free energy to see what portfolio made sense.
Way more long duration
Currently, lithium-ion batteries account for almost all storage capacity built in the U.S., with typical storage capacities up to the four-hour range being cost effective. Strategen's study anticipates long duration storage will eventually challenge that dominant market position, as California's grid proceeds toward its clean energy goals.
The basic Strategen model picks lithium-ion as the go-to firm capacity resource through the 2020s, but long duration dominates the buildout between 2030 and 2045.
The base case calls for long duration storage installations of 45 gigawatts by 2045, with roughly 10 gigawatts of lithium-ion on the system, too. Scenarios with more stringent carbon targets lead to greater deployment of long duration storage — up to 55 gigawatts. Planning for periods of low solar irradiance bumps the long duration storage component to 49 gigawatts.
The base case envisions lithium-ion leading storage installations in the next decade, with long duration taking over after 2030 as solar deployment accelerates. In the “No LDES” case, the long duration storage selected refers to pumped hydro, the maximum duration resource included in CPUC's assumptions. (Image credit: Strategen Consulting)
In its press release, CESA called the 55 gigawatt figure “staggering,” noting it is 150 times bigger than all the storage California has installed since 2010.
Achieving the base case buildout, though, would save $1.5 billion annually by 2045, the authors calculated, largely from reduced capacity costs. The long duration would capture solar that would otherwise be curtailed, and deliver it when needed for less money than alternative capacity sources.
You guessed it: Some policies will have to change
One major challenge to long duration developers in California is that there isn't really a reason to develop long duration energy storage right now. The state's resource adecuacy program, which aspires to and often succeeds at ensuring sufficient power capacity, compensates energy storage for how much power it can deliver over four hours.
“Under this rule, any storage resource that can dispatch at maximum capacity for greater than four hours would receive no additional capacity credits for that increased dispatch capability, and any LSEs that were to contract such a resource would not be able to realize any additional benefits towards their capacity obligations,” the study notes.
So far, long duration development has either stalled in the search for a customer, as in the case of a longrunning pumped hydro development near Joshua Tree National Park, or had to wait for someone to specifically ask for this type of technology. A group of Community Choice Aggregators did just that this fall, soliciting proposals for storage with durations eight-hour or longer for delivery by 2026.
Changing the four-hour rule to compensate for energy delivered over longer periods of time would be a good place to start, Noh said. The study also recommends integrating California's resource adecuacy planning with its long term resource mix modeling.
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