2017 could go down as the year regulated utilities took the lead in energy storage.
Several of the most notable energy storage projects this year were done by or for regulated utilities. And that momentum will likely carry into 2018 as well, Tim Gretjak, an analyst at Lux Research, told Utility Dive.
In some cases, it is easier for a regulated utility to make the economic case for energy storage, Gretjak said. It is hard for developers of energy storage projects to compete in energy markets where the rules do not value the flexibility that storage can provide, he added.
The trend could be bolstered by the fact that utilities across the country are beginning to include energy storage in their resource planning processes. In Oregon, for instance, Portland General Electric’s integrated resource plan proposes five storage projects. In New Mexico, the Public Regulation Commission amended the state’s 2017 IRP rules to include energy storage.
The most talked about
High on the list of notable projects of the year is Tucson Electric Power’s (TEP) solar plus storage facility. The project is being built by NextEra Energy and features a 100 MW solar array and a 30 MW, 120 MWh energy storage system. It’s most notable feature, however, is its power purchase agreement.
TEP reported that the all-in cost for the solar-plus-storage project was “significantly less than $0.045/kWh over 20 years.” TEP said the solar portion of the project, at under 3¢/kWh, was “the lowest price recorded in the U.S.” That puts the remaining storage portion of the project at about 1.5¢/kWh.
The project marked the lowest price announced for a solar-plus-storage project to date, far outstripping the nearest contender, a 11¢/kWh PPA between Kauai Island Electric Cooperative and AES Corp. for a 28 MW solar array with a 20 MW, 100 MWh battery system on Kauai, Hawaii.
The TEP project drew the scrutiny of industry analysts who examined the outlines of the project — the contract details are confidential — in an effort to understand how the utility and the developer could make the project viable at such a low price.
Carmine Tilghman, TEP’s energy supply director, provided some hints. “Storage provides the ability to simulate ‘load’ by allowing us to charge during the day and minimize the ‘duck curve’ issues, but [batteries] still have significant limitations to both peak shaving,” he said.
In a subsequent article, Jesse Jenkins, a PhD candidate at the Institute for Data, Systems and Society at the MIT Energy Initiative, said that if the value of available subsidies is backed out, the pricing on the project is closer to 9¢/kWh, but that “is still impressive.”
And Ravi Manghani, director for energy storage at GTM Research, said the ability of the developer to capture the 30% investment tax credit for both the solar and storage portions of the project is “paramount” and makes the economics of developing a combined facility more attractive than developing separate projects.
The tax credit not only offsets 30% of the cost of the storage project, the developer also benefits because the combined interconnection and installation costs are arguably lower with co-installation.
The deferral play
Another of the year’s most notable projects also is in Arizona, but is being developed by Arizona Public Service. It is a much smaller project, 2 MW, 8 MWh, but is notable because it is being undertaken without a statutory or regulatory mandate.
APS is building the project as an alternative to building about 20 miles of new transmission lines to serve the small community of Punkin Center about 90 miles northeast of Phoenix.
APS has not disclosed the cost of either the storage project or the transmission lines, but estimates the batteries will enable it to defer investment in a new transmission line for up to six years. And during that time, the batteries will also deliver additional value by providing frequency regulation and bolstering grid reliability.
T&D deferral is a growing trend, especially among regulated utilities, Manghani told Utility Dive, but such efforts are also very specific, particularly when any individual project can require regulatory approval.
Another T&D deferral project recently surfaced in Massachusetts where National Grid has plans to install a 48 MWh energy storage system on the island of Nantucket. The storage project will help back up a new diesel generator on Nantucket and defer investment in a new subsea cable to the island.
In North Carolina, Duke Energy in April won regulatory approval to build a 10 kW solar installation with a Fluidic 95 kWh zinc-air battery in the Great Smoky Mountains of Haywood County. The energy storage system will power a remote communications tower in the national park that is currently served by an overhead transmission line.
Duke says the microgrid project, which would cost less than $1 million, is less expensive than upgrading and maintaining the existing four-mile 12.47-kV distribution feeder that travels over rugged mountain terrain and is due for upgrades this year.
The project demonstrates the “practicality” of energy storage, Gretjak said.
Duke also plans to invest $30 million in two battery storage systems in North Carolina, which the company says will be the first large storage projects built by its regulated utility. “Battery technology has matured, and we are ready to take the next step. We can go to regulators and say this makes economic sense, Duke spokesman Randy Wheeless told Utility Dive at the time.
Energy storage once again made market inroads this year, as it did last year, by responding to emergencies. Last year, energy storage’s value was on display when it was called on to respond to the Aliso Canyon gas leaks that threatened gas supplies to power plants critical to reliability in Southern California. Following a call by state regulators, developers stepped up to quickly build several large storage projects to support grid reliability in the region. One of those project, Powin Energy’s 2 MW, 8 MWh battery system in Irvine, came online in January.
In March, Tesla CEO Elon Musk tweeted that he could solve blackouts that have been plaguing South Australia by installing a battery storage system in 100 days or it would be free. Tesla made good on Musk’s promise this week, nearing completion of a $50 million, 100 MW, 129 MWh storage system at Neoen’s 315 MW Hornsdale wind farm. The storage system, which would be the largest in the world, is expected to come online Dec. 1.
The Tesla project could soon be overshadowed by a massive 100 MW, 500 MWh storage system that is expected to “be the cornerstone of a new smart energy grid” in Hubei Province, China. The vanadium flow battery project is being built by Hubei Pingfan Vanadium Energy Storage Technology Co., a subsidiary of Hubei Pingfan, a mining and industrial metals and minerals company that has about 1 million tonnes of vanadium in its reserves.
The China project may not have much overlap with U.S. projects because the energy markets in the two countries are so different, but China’s push could demonstrate the value of flow batteries and might aid the economies of scale for the technology.
Another trend that has taken shape this year is the pairing of energy storage with traditional generation sources. In April, Southern California Edison and General Electric completed what they said is the world's first battery-gas turbine hybrid system. The system, being installed in Norwalk, Calif., combines a 10 MW, 4.3 MWh battery system with a 50 MW gas turbine. Pairing the technologies enables a faster response time and can offset the need to ramp up the gas turbine to meet short demand peaks, thereby cutting fuel consumption and emissions. GE says the system can cut greenhouse gas emissions by as much as 60%.
GE is not the only company pairing storage with generation. In July, Wartsila acquired Greensmith Energy Management Systems as a means of expanding its integration of storage and generation. Also in July, Scottish power generator Aggreko agreed to pay $52 million to acquire Younicos, the German-U.S. provider of battery technology and energy storage solutions.
“I think that is going to be a trend,” Lux Research's Gretjak told Utility Dive. But he warned that the trend will include combining storage and generation in several different combinations “to see which makes sense.”
“Combining gas generation and energy storage is sort of like wearing a belt and suspenders,” Gretjak said, but it makes sense in areas [such as California] where there are strong emissions requirements.