Utility-scale adoption of battery-based energy storage is expected to accelerate over the next decade, in large part due to a similarly strong market for larger solar arrays, according to independent and U.S. government researchers. This growth in new installations will provide multiple services, such as load-balancing and emissions reductions for utilities and their customers, as the nation moves toward ambitious greenhouse gas reduction goals to create a carbon-free power sector by 2035.

Two recent forecasts project a rapid trajectory for battery-based storage adoption. Wood Mackenzie’s Global Energy Storage Outlook for the second half of 2021, released in October, estimated the total energy storage market doubled over last year alone, and forecast that the 56 gigawatt-hours in 2021 would increase 17 times by 2030.

The United States is expected to maintain its leadership role in these deployments, totaling 40% of the global market driven largely by front-of-the-meter applications—that is, battery systems deployed by utilities or power developers rather than utility customers to serve their own energy needs.

The U.S. Energy Information Administration (EIA) is similarly bullish in its August 2021 “Battery Storage in the United States: An Update on Market Trends,” which estimates 10 gigawatts (GW) of large-scale battery storage will be added to the U.S. grid between 2021 and 2023—10 times the capacity online at the end of 2019.

To explain the difference in the two reports’ figures, “gigawatts” describes capacity—the amount of electricity that would be added to the grid if all the batteries were switched on at once. “Gigawatt-hours” describes production over time, similar to the way electricity use is allocated on a monthly utility bill.

This shift will be a big one. According to the EIA, as of the end of 2020, 62% of battery storage capacity was built for standalone operation, and only 30% was located with generation from renewable resources. However, the EIA expects the majority of planned battery plants over the next three years to be co-located with generation, particularly utility-scale solar. If all projects planned to become operational between 2021 and 2023 actually come online, the share of U.S. battery storage co-located with generation would jump up to 60%.

Another interesting insight from the EIA report is that battery-based storage is becoming more widespread and reaching into regions where it had not been prevalent before. At the end of 2019, more than 60% of large-scale battery capacity was located in California or within the PJM interconnection, which stretches from Illinois to the mid-Atlantic. This was largely due to market rules in those areas being favorable to the technology. Moving forward over the next two years, more than a third of planned capacity is expected to be installed in states outside those regions.

The growth in pairing solar and storage is supported by findings of a January report from the National Renewable Energy Laboratory (NREL). Unlike wind turbines, solar photovoltaic (PV) systems generate electricity on a predictable daily cycle that lines up well with batteries’ storage and discharge schedules. The report, “Grid Operational Impacts of Widespread Storage Deployment,” is the latest in a series produced through the lab’s Storage Futures Study project. It uses advanced modeling technologies to assess potential hourly operations of high-capacity diurnal storage up to 12 hours.

Researchers found that storage adds the most value—and deployment increases most significantly—when it’s allowed to provide multiple grid services, including ancillary offerings such as load and frequency balancing, at higher solar PV penetration. And these benefits could accrue over just the next decade.

“We find significant market potential for diurnal energy storage across a variety of modeled scenarios, mostly occurring by 2030,” said Will Frazier, NREL energy analyst and the report’s lead author. “To realize cost-optimal storage deployment, the power system will need to allow storage to provide capacity and energy time-shifting grid services.”

The researchers modeled several variables, including battery cost and grid services storage, and found that even at the highest cost, national battery capacity would reach 125 GW by 2050.

This compares to today’s 23 GW, almost all of which is supplied by pumped hydroelectric systems. Whether battery systems are allowed to bid into capacity markets will have the biggest impact on future deployment. Providing energy time-shifting services—storing up energy during low-demand periods for use during peak demand—will also drive adoption.

Finally, the report reinforces the symbiotic relationship between solar and storage. Increased PV capacity reduces the length of peak demand periods, cutting the capacity needs for storage. Shorter storage-demand periods mean utilities can turn to less-expensive, shorter-duration batteries, putting them at a cost advantage over other options, such as natural gas generators. Increased PV penetration can also lead to energy price spikes, which increases storage’s value as an energy time-shifting provider.