store excess generation for use at a different time, such as when power demand peaks.
Though utilities now have energy storage technologies available to them, utilities are still trying to figure out the economics of storage—how this technology fits with the way that utilities have invested in the grid and recovered those costs. Pockets of the grid in North America have become laboratories experimenting with different approaches. California regulators in 2013 passed rules requiring the state’s three largest electric utilities to add 1.3 GW of energy storage to the California grid, in increments, through 2020. The utilities commission left it up to the companies to determine how they would integrate energy storage, but the regulator set broad goals, such as reducing peak demand and making the grid more efficient.
The deregulated Texas market presents different challenges. Oncor, operator of the largest transmission and distribution network in the state, in 2014 proposed installing batteries as a way of helping the electric grid operate more efficiently. But the plan has stalled. Under state law, transmission and distribution companies like Oncor can’t own electricity generation, and utilities that generate power can’t own transmission and distribution infrastructure. Without a change in the law, Oncor can’t operate batteries on its network because that would be considered owning generation.
Some guidance on energy storage policy could come from Canada. The Independent Electricity System Operator, the regional transmission organization overseeing Ontario, last year awarded 10-year contracts for nine different energy storage projects intended to test whether they can improve the grid’s reliability. With a contract, energy storage becomes a service supporting grid reliability, Roberts explains. Reducing the need for maintenance and extending the lifetime of utility infrastructure offers something of value that utilities can price.
Charlotte-based Duke Energy (NYSE: [[ticker:DUK]]), the nation’s largest electric utility, is testing storage at various company sites throughout the U.S. In Texas, Duke has used batteries to store energy produced at its Notrees Windpower farm since 2013. Last year, Duke committed $1 million for research at the Battery Innovation Center in Indiana. There, researchers are studying how batteries can help renewable sources, such as wind and solar, integrate with the grid. Those research objectives are the goals of a new North Carolina hybrid-battery system at a substation connected to a solar installation west of Charlotte. Duke says patented algorithms in this system determine how energy is stored and discharged. The goal is to smooth out fluctuations in solar power availability caused by clouds or other weather conditions.
Utilities and regulators are watching the approaches in different regions to see how the technologies and the economics work, says Ivan Urlaub, executive director of the North Carolina Sustainable Energy Association. The electricity market in North Carolina, like much of the Southeast, is regulated. In regulated markets where utilities own and operate the assets from generation to transmission and distribution, these large players also face most of the risk. “The risk is going to be fully borne by someone, or many someones—by the utility, by the ratepayer, maybe the government,” Urlaub says.
Urlaub expects that regulation will lag the technological advances in energy storage. Rather than finding answers within the traditional regulatory process, he supports a more flexible, collaborative discussion that brings energy storage stakeholders together for open dialogue. He hopes this approach would be faster. Absent clearer direction from regulators, he says, utilities may feel it’s too risky to do much more with energy storage than experiment.
“The utility’s got to get pretty quickly to an answer how they’re going to deploy their own capital and provide [energy storage], or nothing’s going to happen,” Urlaub says.
