Now that Duke Energy DUK -0.52% Corp. has successfully tested its wind-integrated energy storage project in Texas, what does that mean for the future of the technology?
The “Notrees Energy Storage Project” is not what the average person might envision — a battery that soaks up the grid’s electrons at night and then releases that electricity during the day if the wind is not blowing. While that’s the long term objective, the battery’s main function right now is to feed the electrical network with the energy it would need if a power surge occurs that would cause the grid to overload and the lights to go out.
“When we detect frequency changes, we will respond before the grid operator even knows that there has been problem,” says Jeff Gates, with Duke’s Notrees, in an interview with Public Utilities Fortnightly. The grid operator is the Electric Reliability Council of Texas, or ERCOT, which contracts with Duke to deliver electrons as needed — just as it would a traditional coal-or natural gas-fired generator. The project has been commercial since December 2012.
Simply, each time an industrial outlet or a residential customer uses electricity, the system operator is tasked with matching the demand with the existing supplies. And when something tips that balance, the “frequency” can fluctuate and machines will automatically shut down. That’s how cascading blackouts are started.
When the network gets out of kilter, the lead acid batteries used by Duke can almost instantaneously respond. “Storage is good at being fast and accurate at small deviations in frequency,” says Gates, who adds that the cost to both business and residential consumers is less than if generators were used to fill that void. That’s because the battery is enabling ERCOT to use less electricity.
To be sure, the cost of the actual storage technologies is high, especially if consumers want to siphon electrons from the grid, harness them and then release them during the day. For the time being, Gates says that such usage is for “rich people,” although that could change over time. That’s because more than half of all states have renewable portfolio standards that, ideally, are inviting the creation of newer and better energy storage devices.
In the case of California, it is requiring its incumbent utilities to provide 1,325 megawatts of energy storage capacity by 2020. Southern California Edison , PG&E PCG -0.36% Corp. and Sempra Energy SRE -0.27% are participating.
“I hope that the combined demand for electric vehicles in California and elsewhere, along with the CPUC’s energy storage procurement program will facilitate improvements in the performance and cost of storage technology,” says Michael Peevey, chair of the California Public Utilities Commission, in an interview with this writer to appear in the November edition of Public Utilities Fortnightly.
Peevey adds that the requirements could change if costs are more than expected. Currently, storage devices produce electricity at a price three times greater than that of a traditional electric generator. And if the technology is to become commercialized, the federal government will need to partner with the private sector. That’s the case with Duke, which is sharing equally the $44 million price tag of its 24 megawatt/hour energy storage project with Uncle Sam.
It’s also the same with Edison International’s Southern California Edison, which is splitting the cost of $50 million lithium-ion battery project that is 100 miles north of Los Angles. It just started a two-year demonstration called the Tehachapi Energy Storage Project, which will produce at 32 megawatts/hour.
Generally, “All you are seeing now is demonstration projects,” says Jay Whitacre, engineering professor at Carnegie Mellon University in Pittsburgh, in the Fortnightly discussion. “It’s too hard to make money at it.”
To get that point, he adds that energy storage needs to serve multiple functions. In other words, stabilizing the grid to maintain frequency is a start. But the technology will have to develop to the point where renewables can be stored and then released — all to keep electricity flowing for long periods of time.
Otherwise, utilities are not going to spend $1 billion testing the waters. When they build power generation, power companies are looking out at least 20 years. To that end, energy storage is no different – something that will take more than 10 years to create positive returns, says Whitacre, also the founder and chief of technology at Aquion Energy, an energy storage company.
He goes on to explain that for energy storage to be cost competitive, it would need to be able to deliver electricity at about 10 cents per kilowatt-hour over the lifetime of the system. That would put it on par with “pumped storage,” which costs between 3 cents to 8 cents per kWh.