The Pinal Central Solar Energy Center in Arizona includes 10 MW of lithium-ion batteries.
Source: Salt River Project
More than twice the size of the largest battery system currently operating in the United States, the AES Alamitos Energy Battery Storage Array in Long Beach, Calif., signals much bigger things soon to come for electrochemical energy storage on U.S. power grids.
This first 100-MW/400-MWh phase of the system, on which owner AES Corp. recently broke ground, is underpinned by a 20-year contract with Southern California Edison Co. starting in December 2020. Relying on lithium-ion batteries, the system could eventually triple in size with its permit to expand to 300 MW.
That will dwarf the largest operational battery installation in the U.S., LS Power Group's 40-MW Vista Energy Storage in San Diego County, according to S&P Global Market Intelligence data.
"We need to step it up with the amount of batteries we have in California," Ken Zagzebski, president of AES' U.S. strategic business unit, said in an interview. Though only 136 MW of batteries were connected to the state's primary power grid as of early June, according to California ISO data, an energy storage procurement mandate of 1,325 MW is beginning to bear its first big fruits.
The AES storage project is part of a modernization and replacement of the company's nearly 2,000-MW Alamitos plant, portions of which are more than 60 years old, and includes the nearly 700-MW natural gas-fired Alamitos Repowering project.
Among contracted U.S. battery storage projects, the Alamitos array is surpassed by Vistra Energy Corp.'s 300-MW/1,200 MWh Vistra Moss Landing Energy Storage system, near Santa Cruz, Calif., which has a 20-year agreement for the entire installation with Pacific Gas and Electric Co., or PG&E. Co-located at another major combined-cycle gas plant, Vistra's Moss Landing CC, the project is also scheduled to start operations in December 2020.
Planned to come online at the same time and in the same place is the PG&E Corp. subsidiary's 182.5-MW Tesla Moss Landing Battery Energy Storage Project (Elkhorn), an approved utility-owned project to be supplied by Tesla Inc. Other major utility-scale battery projects, some coupled with solar farms, are planned around the country, including in Arizona, Colorado, Florida, Hawaii, Nevada, New York and Utah.
While the PG&E projects could see delays, or even cancellations, related to the utility's ongoing Chapter 11 bankruptcy and restructuring process, batteries could ultimately satisfy "a substantial portion of U.S. peak capacity needs," the U.S. Department of Energy's National Renewable Energy Laboratory, or NREL, concluded in a new report, "The Potential for Battery Energy Storage to Provide Peaking Capacity in the United States." Assuming current conditions and demand patterns on the U.S. grid, the analysis identified a practical energy storage peak power potential of about 70,000 MW. That includes approximately 28,000 MW from four-hour battery storage arrays, 8,000 MW from six-hour storage systems and 34,000 MW from eight-hour storage projects.
'50 GW or beyond nationally'
Those base-case results do not account for the expanded need for energy storage that comes with larger volumes of variable wind and solar power. A second scenario, under which solar photovoltaic, or PV, power plants provide 10% of U.S. demand for electricity, would increase the potential for four-hour storage systems to "50 GW or beyond nationally," the report found.
A key factor in how successful batteries and other energy storage technologies emerge in the marketplace is their cost compared with traditional sources of peak power like gas and hydropower, NREL said. Recent power purchase agreements for energy storage paired with solar farms already undercut conventional gas-fired peakers in some areas of the United States, according to a recent S&P Global Market Intelligence analysis.
There appears to be a consensus that, leveraging the expanding base of lithium-ion battery manufacturing capacity, costs are poised for double-digit drops in coming years. Another recent NREL report, "Cost Projections for Utility-Scale Battery Storage," based on more than two dozen studies on lithium-ion batteries — the dominant technology used in new energy storage projects — projected that the capital cost of installations would decline 10% to 52% by 2025, 21% to 67% by 2030 and 31% to 80% by 2050.
But falling capital costs alone will not secure a break-even point with traditional peakers, according to scientists at the national laboratory. Other factors include the shorter lifetimes and greater flexibility of batteries versus combustion turbines, as well as changes in the value of storage as solar volumes rise, they said. Another factor is federal tax subsidies. Currently, batteries charging on solar power can qualify for declining federal investment tax credits. U.S. lawmakers recently punted on extending and expanding tax incentives for energy storage.
With an estimated 150 GW of the 261 GW of operating U.S. peaking capacity on track to retire in the next 20 years, NREL nevertheless sees enormous potential for energy storage to replace traditional peakers.