Long-Term Value of Grid Storage Is All About Capacity, Study Finds
The grid is heading in the direction of more renewables, with or without overarching policies to guide it. There’s general agreement that the ability to store electricity will become more valuable as this happens, but the exact value of energy storage in a dynamically evolving electrical system is hard to pin down.
A new study from current and former MIT energy system modelers attempts to quantify this. Rather than looking at the value of a single battery project, or the role of energy storage in a fully decarbonized grid, as previous studies have contemplated, the researchers tested the value of energy storage as the grid’s wind and solar penetration increases to 50 percent and beyond, and as energy storage deployment grows. These dynamics will play out in many parts of the grid over the next 15 or 20 years.
This approach, published in the journal Applied Energy, captures the dynamic interactions between renewables, storage, natural gas plants, and transmission networks. And it allows the authors to quantify which uses for storage produced the most benefit for that evolving system.
“It turns out that capacity avoidance or capacity deferral is the biggest source of value for energy storage in that long-run context,” said co-author Jesse Jenkins, who now teaches at Princeton University. “Storage, as an asset, allows you to make better use of other fixed assets in the system.”
That’s a shift from today’s grid, where batteries largely found a path to market through the quick-reacting service of frequency regulation. The need for that service quickly gets saturated as storage deployment expands; the long-term adoption of storage will rely more on the capacity role. Some developers are already finding ways to monetize that, but market rules often don’t allow full compensation for the thing that’s theoretically most valuable about storage technology.
Needs change as renewables grow
Energy storage displaces other capacity investments in three major ways, according to the study:
- Reducing variable renewable investments. Storage can shift generation that would otherwise be curtailed so that the system delivers more clean electricity production from a given amount of renewable capacity.
- Replacing thermal generators (namely, gas peaker plants) for peak-hour electricity delivery. Storage is well suited to knock off peakers that run rarely and for only a few hours at a time. This is starting to happen in select markets.
- Deferring transmission upgrades by holding power during congested periods and delivering it when the wires have more capacity.
To give a sense of the grid’s regional variety, the study modeled a “North” grid inspired by load profiles and renewables production in New England and New York, and a “South” grid resembling Texas.
The calculated system value of storage increases as renewable penetration rises but falls as storage penetration advances. (Image credit: Mallapragada et al.)
In the northern grid, at 40 percent wind and solar penetration, storage value gets a big boost from thermal capacity deferral — using batteries to offset fossil fuel plants that would otherwise need to cycle. That continues to play a role as renewables pile on, but once wind and solar hit 50 and 60 percent of the generation mix, the value of deferring new wind and solar investment skyrockets.
In the Texas-like South grid, transmission network deferral plays a more pronounced role; that reflects transmission constraints between the places wind and solar generate and the places where people consume it. Storage located at the distant renewable power plants can shift exports to times when the wires are not congested, delivering more clean power for a given amount of renewable and transmission capacity.
Across the board, the value of storage is highest during the initial phase of deployment — up to 4 percent of peak demand. The value tapers off as more storage hits the grid and fulfills the high-value jobs.
Decisions to build something involve cost as well as value. The study finds that, at today’s battery costs, two- and four-hour duration batteries don’t make financial sense until the North grid hits 50 percent wind and solar. At 60 percent wind and solar, those batteries are on solid financial footing in both North and South, but only up to 4 percent of peak demand.
To justify more storage investment, costs will need to fall. In a scenario where battery costs drop to about half of today’s levels (as estimated for 2050 capital costs), batteries already make sense in 40 percent wind and solar grids (up to 4 percent of peak demand), and their value shoots up as more renewables arrive.
Falling battery costs will improve the storage value proposition for grids with lower renewable penetration. (Image credit: Mallapragada et al.)
Getting paid is the hard part
Of course, this theoretical system value won’t count for much if storage developers can’t get paid for it.
“The real-world economic value of storage will depend on how the various forms of capacity substitution value are monetized and captured by and shared among various actors, including storage owners, [variable renewable energy] asset owners, thermal asset owners, network utilities, and electricity consumers,” the authors note.
Developers are already finding ways to make this happen.
The growing trend of co-locating storage with solar is often described as a way to qualify for the solar investment tax credit and save on construction costs. Viewed through the lens of this study, it’s a way to monetize the renewable capacity deferral value of storage and improve utilization of transmission capacity. Placing batteries at existing thermal plants also allows their owners to better utilize existing generation and transmission infrastructure.
The relatively new doctrine of “non-wires alternatives” has allowed battery projects to move forward in place of more expensive wires upgrades in places like New York and Arizona. But that remains a limited pathway for storage development.
Going forward, transmission solicitations could operate on a technology-agnostic basis, said lead author Dharik Mallapragada. The solicitation would ask for bids to solve a congestion problem and let storage compete against traditional transmission infrastructure projects.
“Storage benefits from cost and the time value of money,” he noted, compared to the years it takes to permit and construct new transmission lines.
The use of storage as a transmission asset is currently being debated in venues including the Federal Energy Regulatory Commission, said Jason Burwen, vice president for policy at the U.S. Energy Storage Association.
“Transmission and distribution planning have generally not been conducted with a strong ethic of competition or a sense that you can provide things other than conventional wires infrastructure,” Burwen said.
On the capacity side, regional markets have different rules for assessing the value of storage as a reliable capacity resource, given that it doesn’t run indefinitely the way gas plants can. The formula used to determine that value influences whether storage can compete. PJM’s 10-hour duration requirement dissuades batteries from competing, while other markets see four-hour batteries as perfectly capable of providing reliable capacity.
“The storage duration needed to compete with gas is a moving target,” Mallapragada said. “The capacity market, as I see it, has this perennial challenge that they have to continuously consider the capacity rating of these various resources.”
That rating should be updated regularly as renewables surge on the grid, altering competitive dynamics between wind, solar, batteries and gas, he added.
Much of the biggest battery development is happening in states where utilities are required to purchase resource adequacy. Their solicitations weigh the costs and benefits of batteries versus renewables and gas for delivering capacity at peak times, and award bankable, long-term contracts.
“It’s important to consider that the way things are paid for matters just as much as whether they’re paid for,” Burwen said.
A fixed utility contract for 10 or 20 years provides certainty for financing a battery project. Projected returns in wholesale markets with volatile rules for storage compensation make for a harder business case.