The Hoover Dam has been harnessing the Colorado River to generate power since 1936. The Los Angeles Department of Water and Power wants to modernize it with a $3 billion pumped storage project.
Source: Associated Press
Driven by advances in lithium-ion batteries and mounting policy support, electrochemical energy storage has emerged as a powerful new resource to manage increasing volumes of intermittent solar and wind energy on the U.S. electric grid. But batteries still have a long way to go to equal pumped hydroelectric storage.
With an installed capacity of nearly 22.7 GW, pumped hydro maintains a 96% share of energy storage in the United States, according to S&P Global Market Intelligence data. Undeterred by a two-decadelong development drought, during which only 370 MW of new pumped storage capacity came online, technology proponents believe pumped storage is poised for another major push.
"It's sort of like the unsung hero of the system in that people forget how much benefit these projects have been providing," Jeff Leahey, deputy executive director at the National Hydropower Association, or NHA, said in an interview. "As more wind and solar in California and other parts of the West come online... people have started to recognize the benefit that pumped storage can bring."
Effectively giant water batteries, hydroelectric storage facilities typically rely on off-peak power to pump water to an upper reservoir and then release water to a lower reservoir to generate power during periods of higher demand. While lithium-ion batteries often discharge energy for one to five hours, depending on application, pumped hydro commonly provides six to 10 hours of storage, according to NHA.
Developers clearly believe there is an appetite for additional bulk energy storage. S&P Global Market Intelligence data identifies almost 25 GW of planned new pumped storage in the U.S., the majority of which is in the West. Leahey estimates 15 GW to 20 GW under active development through applications with the Federal Energy Regulatory Commission sets "a good framework" for how much pumped storage could come online in the next 20 years.
But that is only realistic if policies do not discriminate against the technology in favor of batteries, if markets do not undervalue pumped hydro, and if the permitting and licensing process is not too drawn out, he said, adding that such obstacles are currently widespread.
'Bridge to the future'
One of the boldest proposals is a modernization project. The Los Angeles Department of Water and Power is in the very early stages of roughly $3 billion vision to add pumped storage to one of America's most iconic power plants, the Hoover Dam. With a nameplate capacity of about 2,080 MW, the federal government-owned project operated with a capacity factor of less than 20% in 2017. By adding new pipeline and pumping systems, LADWP hopes to recycle water from below the dam back into Lake Mead, boosting the hydro project's capacity factor to about 35%.
LADWP, one of several dozen entities that purchase power from Hoover Dam, views the proposal as "a bridge to the future," said Reiko Kerr, the utility's senior assistant general manager. "From a concept, I don't think you could come up with a better solution to meet the overgeneration challenge in the western states. ... We have not seen any showstoppers."
While the California ISO has experienced increasingly frequent periods of oversupply and curtailment of solar generation on its grid, Kerr says LADWP has avoided such conditions because of its existing Castaic pumped storage plant. "It is really the crown jewel. It is why we are not having curtailments."
With its solar resources growing, however, LADWP is looking to again to pumped storage, even as the utility invests in batteries for its shorter-duration storage needs.
Given that more than half of installed pumped storage capacity comes from facilities that are at least four decades old, such modernization projects could be a big opportunity. CMS Energy Corp. subsidiary Consumers Energy, for instance, has added 150 MW since 2015 to its existing Ludington Pumped Storage Facility in Michigan and plans to add another 150 MW. In South Carolina, Duke Energy Corp. has started work to boost the capacity of its Bad Creek Pumped Storage Project as well.
The fate of many new pumped storage proposals remains uncertain, as two projects granted FERC licenses in recent years are experiencing.
FERC issued a license for the 1,300-MW Eagle Mountain Pumped Storage Hydroelectric Project in June 2014. To be built on the site of an inactive mine near Joshua Tree National Park in Southern California, developer Eagle Crest Energy Co initially had to start construction by June 19, 2016. FERC later set a new deadline of June 19, 2018.
Eagle Crest missed that deadline, prompting the National Parks Conservation Association in June to ask FERC to terminate the license. (FERC Docket No. P-13123)
A proposal from U.S. Rep. Paul Cook, R-Calif., H.R. 5817, would give Eagle Crest until June 19, 2024, to start construction. The bill, introduced in May, is still before the House Energy and Commerce Committee. The proposal allows FERC, at the company's request, to extend the construction start date for up to three consecutive two-year periods from the 2018 deadline.
An Eagle Crest representative did not return requests for comment about where the project stands. The U.S. Bureau of Land Management in early August said Eagle Crest can run across federal lands a 16-mile, 500-kV transmission line and water pipeline associated with the project.
A last-minute proposal introduced in August in the California legislature, Senate Bill 2787, sought to help Eagle Crest's quest for a contract by ordering the California ISO to complete a process by the end of 2019 for the procurement of up to 2,000 MW of long-duration energy storage.
In Aug. 27 testimony on the bill, Kerry Hattevik, the western U.S. government affairs director for NextEra Energy Resources LLC, a development partner in the project, the state would need long-duration energy storage to meet its climate policy objectives.
Lawmakers did not vote on the bill before the session ended Aug. 31.
Absaroka Energy LLC, the company behind the planned 400-MW Gordon Butte Pumped Storage project near Martinsdale, Mont., slated 2018 to secure a contract for its proposal. FERC issued a license for the project in December 2016. Should Absaroka get a contract this year, it could jump-start a four-year construction period to bring the project online in 2022 and mark the end of a years-long effort to bring the project to fruition.
Pumped storage projects have to contend with a complex and sometimes difficult licensing and permitting process that can take years and involve multiple local, state and federal agencies.
Absaroka got through the FERC licensing process the Gordon Butte project in a fairly speedy three and a half years. That is partly due to the company picking the right site for the project. The project will be built in private land, has a water resource on site and has local public support, said Absaroka President and CEO Carl Borgquist. Absaroka also took and "early and often" public and stakeholder engagement approach.
Borgquist said pumped storage is the "Swiss Army Knife" for transmission grid support, providing many ancillary services to grid operator. Use of pumped storage and batteries will only continue to grow as more intermittent renewable generation and distributed generation comes online.
Still, for all the uncertainty about the future of new proposals, existing pumped storage facilities benefit the power system, said Mark Gabriel, administrator of the Western Area Power Administration. The 200-MW Mount Elbert project in Colorado, for instance, creates a "solid backbone" so the grid operates better and allows WAPA to balance its system, he said. To Gabriel, pumped storage is a tremendous value in providing a safe, reliable way of capturing an increasing amount of intermittent solar and wind resources.
"It's the best storage you can get," he said.