From Science Magazine
1.25.24
Robert Kunzig
How giant water batteries could make green power reliable
Pumped storage hydropower plants can bank energy for times when wind and solar power fall short.
The Nant de Drance pumped storage hydropower plant in Switzerland can store surplus energy from wind, solar, and other clean sources by pumping water from a lower reservoir to an upper one, 425 meters higher. When electricity runs short, the water can be unleashed though turbines, generating up to 900 megawatts of electricity for 20 hours. Credit: Fabrice Coffrini/AFP via Getty Images.
The machines that turn Tennessee’s Raccoon Mountain into one of the world’s largest energy storage devices—in effect, a battery that can power a medium-size city—are hidden in a cathedral-size cavern deep inside the mountain. But what enables the mountain to store all that energy is plain in an aerial photo. The summit plateau is occupied by a large lake that hangs high above the Tennessee River, so close it looks like it might fall in.
Almost half a century ago, the Tennessee Valley Authority (TVA), the region’s federally owned electric utility, built the lake and blasted out the cavern as well as a 329-meter-tall shaft that links the two. “It was quite an effort to drill down into this mountain, because of the amount of rock that’s here,” senior manager Holli Hess says dryly. The cavern holds a candy-colored powerhouse, filled with cherry-red electrical ducts and vents and beams in a pale grape. Four giant cylinders, painted bright green and yellow, are the key machines: Each one houses a turbine that becomes a pump when it spins the other way, and a generator that is also an electric motor.
At night, when demand for electricity is low but TVA’s nuclear reactors are still humming, TVA banks the excess, storing it as gravitational potential energy in the summit lake. The pumps draw water from the Tennessee and shoot it straight up the 10-meter-wide shaft at a rate that would fill an Olympic pool in less than 6 seconds. During the day, when demand for electricity peaks, water drains back down the shaft and spins the turbines, generating 1700 megawatts of electricity—the output of a large power plant, enough to power 1 million homes. The lake stores enough water and thus enough energy to do that for 20 hours.
Pumped storage hydropower, as this technology is called, is not new. Some 40 U.S. plants and hundreds around the world are in operation. Most, like Raccoon Mountain, have been pumping for decades.
But the climate crisis is sparking a fresh surge of interest. Shifting the electric grid away from coal and gas will require not only a lot more solar panels and wind turbines, but also a lot more capacity to store their intermittent output—to keep electricity reliable when the Sun doesn’t shine and winds are calm. Giant versions of the lithium-ion batteries in electric vehicles are also being deployed on the grid, but they’re too expensive to do the job alone. Dozens of new technologies, including different battery designs, are at various points on the road from lab bench to commercialization.
Pumped storage, however, has already arrived; it supplies more than 90% of existing grid storage. China, the world leader in renewable energy, also leads in pumped storage, with 66 new plants under construction, according to Global Energy Monitor. When the giant Fengning plant near Beijing switches on its final two turbines this year, it will become the world’s largest, both in terms of power, with 12 turbines that can generate 3600 megawatts, and energy storage, with nearly 40,000 megawatt-hours in its upper reservoir.
In the Alps, where pumped storage was invented in the late 19th century, Switzerland opened a plant in 2022 called Nant de Drance that can deliver 900 megawatts for as long as 20 hours. Austria, too, has ambitious plans. Down in Australia, one of two new plants already under construction will be the new record holder for energy, storing enough to supply 3 million people for 1 week. Called Snowy 2.0, it’s scheduled to open by 2029.
“When people talk about batteries—these are little things,” says Andrew Blakers of Australian National University, a solar-cell pioneer who has become an influential pumped storage evangelist. “And little Australia, where the population is smaller than California, has a single pumped-hydro system under construction that will be bigger than all the utility batteries in the whole world combined.” It’s not that Australia is particularly blessed by geography, Blakers says. From satellite data he and his team have compiled a global atlas showing about 1 million sites across all the continents that would be technically suitable for pumped storage.
The underground powerhouse at the Tennessee Valley Authority’s Raccoon Mountain plant contains four reversible turbines (green cylinders) that are powerful enough to pump water straight up a 329-meter-tall shaft—and to generate up to 1700 megawatts of electricity when the water comes down. Credit:Tennessee Valley Authority.
Even in the United States, where no large pumped hydro facility has been constructed since the 1990s, the federal government is providing encouragement. A 2022 study by the National Renewable Energy Laboratory (NREL), a Department of Energy (DOE) lab, identified more than 14,000 potential sites for “closed-loop” plants, where both reservoirs are placed off-river to minimize environmental impacts. The 2022 Inflation Reduction Act has made generous tax credits available to pumped storage, as it does for renewables. TVA has begun what’s likely to be a decadelong process to build another facility like Raccoon Mountain.
The Federal Energy Regulatory Commission (FERC) has issued dozens of preliminary permits, mostly in the mountainous West, to utilities and developers that want to stake claims to potential pumped storage sites. Three developers have completed the costly multiyear process to receive a FERC license, meaning their projects are shovel-ready. But none has begun construction, and it’s far from clear the United States will share in the global boom.
The impact of these massive projects on the land and environment is one reason. But the bigger problem is that pumped storage is an enormous long-term investment—more than $2 billion for a large plant, according to a recent NREL estimate—and in the U.S. electricity market, the returns on that investment are uncertain. “Bankers and investors and utilities are thinking, ‘I know there’s a great value here, but can I quantify it?’” says Patrick Balducci, an economist at DOE’s Argonne National Laboratory. “‘Is this just going to reduce emissions and improve reliability and benefit everyone throughout the region—and I never get paid for it?’”
When TVA built Raccoon Mountain in the 1970s, the case for pumped storage was simpler. At the time the agency was also building nuclear reactors, which are designed to run 24/7. Raccoon Mountain could pump at night when electricity was cheap and regenerate during the day when it was expensive. The economic benefit of such “energy arbitrage” was clear and drove the construction of many other pumped storage plants.
Today, with the growth of wind and solar power, the rationale has shifted. Grid operators increasingly need storage to meet their central challenge: balancing electricity supply against fluctuating demand every minute, day, and season. They do that now mostly by adjusting power generation at fossil fuel plants, which can be turned on and off as needed. Wind and solar aren’t “dispatchable” that way; indeed their capricious ebbs and flows aggravate the balancing problem. But stored energy can help match renewable power to demand and allow coal and gas plants to be retired.
For now, lithium-ion batteries are filling the need. In places such as California they’re starting to replace the gas “peaker” plants that utilities turn on to meet the demand peak that arrives in the late afternoon, just as solar power begins to dip. For that purpose—a few hundred megawatts of extra power for a few hours—a lithium battery plant is much cheaper, easier, and quicker to build than a pumped storage plant, says NREL senior research fellow Paul Denholm.
But a few hours of energy storage won’t cut it on a fully decarbonized grid. Winter, especially, will tax renewable power, Denholm says. As people switch from gas heat to electric heat pumps, winter demand for electricity can begin to rival the summer peak caused by air conditioning. But whereas a summer peak usually subsides within a few hours as nightfall brings relief, a winter peak triggered by a cold snap can persist for much longer.
“In the end, the storage requirement is driven not by the summer afternoon air conditioning peak,” Blakers says. “It’s driven by a wet, windless week in winter. Try and do that with batteries.” As you add more and more of them, each module as expensive as the last, the cost eventually becomes prohibitive.
Jeremy Twitchell and his colleagues at DOE’s Pacific Northwest National Laboratory modeled how California would fare if it were to rely solely on expanding solar and wind power to meet its goal of a carbon-free grid by 2045. A nearly fivefold expansion would be enough to meet demand on an annual basis, they found, but it would lead to huge temporary excesses and shortfalls, including deficits as big as 30 gigawatts, the output of 15 Hoover Dams. The average shortfall would last nearly 15 hours.
“What that points to is that long-duration energy storage is an absolute necessity in a decarbonized grid,” Twitchell says.
Blakers did pioneering work on solar cells and helped accelerate the turn to renewables. But he felt countries wouldn’t fully embrace green energy until they were convinced the grid will remain reliable. In 2015 he dropped his photovoltaic work to devote himself to the one technology he says is up to the task and available right now. “That’s pumped hydro. Everything else is arm waving.”
His own country’s leadership is convinced. Australia, the world’s leading coal exporter and still dependent on the stuff itself, has committed to getting 82% of its electricity from renewables by 2030, more than doubling renewable capacity in just 7 years. To enable that expansion, the government is also investing heavily in pumped storage. More heavily than it had hoped, in fact: The gargantuan Snowy 2.0 project in New South Wales has been beset by delays and cost overruns.
The site, in a national park, already has two large hydroelectric reservoirs at different elevations that just needed to be connected by tunnels. But that connection is 27 kilometers long—which increases the risk of geologic surprises. Sure enough, one of Snowy’s three tunnel-boring machines spent almost all of 2023 stuck in soft rock less than 200 meters from its starting point. In the summer, the government announced that the project’s cost had ballooned to AU$12 billion.
A massive penstock carries water between the two reservoirs at Nant de Drance. Credit: Fabrice Coffrini/AFP via Getty Images.
Nevertheless, Snowy 2.0 will store 350,000 megawatt-hours—nine times Fengning’s capacity—which means each kilowatt-hour it delivers will be far cheaper than batteries could provide, Blakers says. Yet his atlas shows that Australia has many sites more technically ideal than Snowy 2.0.
The ideal is a site that maximizes the vertical distance between the two reservoirs—the “head”—while minimizing the horizontal distance. “Everything just gets better as you go for larger head, because the pressure of water is bigger,” Blakers says. Double the head and you can double the power capacity and the energy stored—or shrink the reservoirs, tunnels, and turbines.
In Queensland, Australia’s largest coal-producing state, the government created a special organization, Queensland Hydro, to build pumped storage. Last year, it announced it would commit AU$14.2 billion to construct a 2000-megawatt, 24-hour plant above Lake Borumba, 1 hour north of Brisbane, and another AU$273 million to investigate Pioneer-Burdekin, a second site farther to the north that had emerged as a favorite from Blakers’s atlas.
“It is an extraordinary site, it really is,” says Chris Evans, the Queensland Hydro executive in charge of development. With nearly 700 meters of head and only 3.5 kilometers of horizontal distance between the intended reservoirs, Pioneer-Burdekin could generate 5000 megawatts for 24 hours, making it the world’s most powerful. Together with Borumba, it could meet Queensland’s typical demand on a rainy winter day and night. A decision on whether to proceed with the project is due later this year.
But the Queensland government, which operates 8000 megawatts of coal-fired power plants, is already committed to pumped storage as a cornerstone of its energy transition. The public ownership “is a real benefit about the electricity system, particularly in Queensland,” Evans says. “It’s enabling a smoother transition.”
“Most pumped storage projects being built today are by these quasi-government setups,” said Ushakhar Jha. Rye Development, the hydropower developer for which Jha is chief engineer, has been working for nearly a decade to get a project built privately. It holds one of the three outstanding FERC licenses, for a 400-megawatt project at Swan Lake in southern Oregon, and it’s close to getting a license for a 1200-megawatt project near Goldendale, Washington, on the Columbia River Gorge. California, Oregon, and Washington state have all enacted grid-decarbonization deadlines. Rye smells a coming regional market.
In October 2023, I visited the Goldendale site with Jha and Michael Rooney, the firm’s head of project development. On a blustery, overcast morning, we climbed up a gravel road through sagebrush steppe to Juniper Point, overlooking the Columbia River, to see where Rye plans to place an upper reservoir. Strong gusts drove the wind turbines high above us into a stately spin. All along this ridge and far across the river into the wheat fields of Oregon, the land was dotted with hundreds of white turbines. Far below us, the Bonneville Power Administration’s John Day Dam interrupted the river.
Rooney and Jha explained why the site looked just about perfect to them. The landowner and local officials are eager to develop it. The lower reservoir, like the upper one about 600 meters across, would be built on the waste site of a derelict aluminum smelter. No new transmission towers would be required; a single 500-kilovolt line, attached to towers already built for the dam and the wind turbines, would connect the storage plant across the Columbia to the John Day substation, a gateway to utilities from Los Angeles to Seattle.
Finally, the project wouldn’t require a single new road: The wind turbines and the smelter already have access roads. “This is a dream for hydro engineers like us, finding a site where you’re only thinking about the specific core infrastructure,” Jha said. The reservoirs would be barely 2 kilometers apart, with a head of 670 meters—close to ideal.
There’s one major problem for the project: The original occupants of the land don’t want it. The reservation of the Yakama Nation begins about 25 kilometers to the north, but Juniper Point, like most of central Washington, is on land the Native Americans were forced to cede to the U.S. in an 1855 treaty. The treaty reserved for them the right to continue fishing, hunting, and gathering food on the ceded land—and to the Yakamas, this part of the ridge above the gorge is sacred. Called Pushpum, it figures in their creation stories. Their ancestors gathered roots and shoots here, and some Yakamas still follow those traditions. Just last spring, Yakama fisheries biologist Elaine Harvey told me, her family celebrated her 8-year-old daughter’s formal initiation to food gathering in a ceremony at the Rock Creek Longhouse. The little girl fed the foods she had gathered on Pushpum to the whole assembly.
Harvey and I were parked directly under a high-voltage transmission tower, on the north bank of the river, looking at the John Day Dam through a windshield wet with rain. A wooden fishing platform that her family still uses jutted into the river. This riverbank had been the site of her family village until the U.S. Army Corps of Engineers ordered it evacuated in 1957, when the Dalles Dam was completed 35 kilometers downstream. That dam drowned Celilo Falls, a fishing and trading hub that had been inhabited for 11,000 years. Roaring falls disappeared and were silenced under a lake.
To Harvey, the Goldendale pumped storage project is of a piece with that trauma. “They’re going to build a 30-foot-diameter tunnel through the mountain, and that’s our sacred mountain,” she said. She and other tribal representatives stress they’re not opposed to renewable energy—just to projects that damage their cultural heritage. “We’re just trying to protect what we can, and people don’t get it,” she says.
FERC’s draft environmental impact statement, released in March 2023, recommends licensing the Goldendale project. But it acknowledges that the plan would destroy five presettlement archaeological sites, interfere with Yakama food gathering, and change the visual feel of the place. It’s not clear that those harms can be remedied. “We’re not going to settle for mitigation,” says Yakama Nation Tribal Council member Jeremy Takala. “We already know there is no way.” The Columbia Riverkeeper, the Sierra Club, and other environmental groups are backing the tribe.
With its need for manhandling mountains, pumped storage inevitably risks exciting local opposition. But in general, that’s not the biggest barrier to new facilities being built in the U.S. The market is.
Many utilities are interested in pumped storage, Balducci says, but the models they use to plan investments don’t capture all the benefits it provides to the grid—let alone to the environment. He and his colleagues analyzed the Goldendale project and found that it would improve the overall stability of the Western grid and be “a key enabler” of the expansion of solar and wind energy needed to meet zero-carbon electricity targets. The problem is, although the grid will surely need more long-duration storage in coming decades, it doesn’t need more yet, making utilities reluctant to commit.
“The market is incentivizing what the current grid needs,” Denholm says. “Right now we need 4-hour storage. The market is not incentivizing what we might need 5 years from now.” New pumped storage plants take longer than that to license and build, cost billions, and can last a century—a virtue, but also a commitment that takes nerve in a rapidly changing market.
It’s possible utilities will be spared that choice by long-duration storage technologies that are still being developed. Pumped storage might be superseded by flow batteries, which use liquid electrolytes in large tanks, or by novel battery chemistries such as iron-air, or by thermal storage in molten salt or hot rocks. Some of these schemes may turn out to be cheaper and more flexible. A few even rely, as pumped storage does, on gravity.
The Yakama Nation favors one of those. The tribe is in conversation with a company called ARES, for “advanced rail energy storage,” which this year plans to put its technology to a major test in an abandoned gravel quarry in Pahrump, Nevada. An electric motor-generator will haul a 340-ton concrete mass up a 50-meter-tall hill on a railcar; the energy released when the car rolls back down will generate 5 megawatts. The system doesn’t require water or tunneling and so might be easier to site and have less permanent impact than pumped storage. It’s “getting the advantages of pump storage without the disadvantages,” says Russ Weed, chief development officer of ARES.
Power and energy could be increased in steps, by adding more rails, motor-generators, and cars. The Yakamas think an old landfill on their reservation could be a good site for a 500-megawatt system, and have applied for DOE grants to study it. “This isn’t just a Yakama Nation solution, this is a state of Washington solution,” says Ray Wiseman, head of Yakama Power, the tribe’s utility.
The upper reservoir at Raccoon Mountain is some 300 meters above the lower reservoir on the Tennessee River (left). The powerhouse inside the mountain has been humming for 45 years. Credit: Tracey Trumbull.
Another gravity-based energy storage scheme does use water—but stands pumped storage on its head. Quidnet Energy has adapted oil and gas drilling techniques to create “modular geomechanical storage.” Energy is stored by pumping water from a surface pond under pressure into the pore spaces of underground rocks at depths of between 300 and 600 meters; electricity is generated by uncapping the well and letting the water gush to the surface and spin a turbine. The energy is stored not in the water itself, but in the elastic deformation of the rock the water is forced into.
Quidnet says it has conducted successful field tests in several states and has begun work on its first commercial effort: a 10-megawatt-hour storage module for the San Antonio, Texas, municipal utility. It should be online in 2025, CEO Joe Zhou says. Unlike pumped hydro, geomechanical storage doesn’t carry the cost of tunneling, dam building, or getting a FERC license. And the technique exploits existing oil-and-gas technology. “We ourselves are repurposed oil and gas people,” Zhou says.
If anyone should be able to repurpose pumped storage for the era of renewables and get a new plant built, it’s TVA. As a federal agency, it doesn’t need a FERC permit. As a self-financing, vertically integrated utility responsible for delivering power to 10 million people in the Tennessee Valley, it can capture the benefits of pumped storage regardless of whether the market knows how to price them. But it does have to complete an environmental impact statement.
One morning last fall, at a site TVA is now considering in Pisgah, Alabama, project manager Scottie Lee Barrentine was studying black-and-white pictures of the construction of Raccoon Mountain. He was trying to learn more about how his predecessors had managed the challenge. “Nobody’s around anymore,” he says. Pisgah sits on top of a long ridge called Sand Mountain, about 80 kilometers downriver from Raccoon Mountain, and Barrentine’s field headquarters was an empty wedding venue next to the potential location of an upper reservoir. The terrace offered an expansive view north across the Tennessee River. Like Raccoon Mountain, the Pisgah project would draw water from a TVA reservoir on the river itself.
TVA values Raccoon so much, a senior executive once told me, it might one day consider building two or three new pumped storage plants. Barrentine is hoping to deliver at least one, but it will take a decade if it happens at all. The decision won’t be made until 2025, after the environmental impact statement. The plant would then take at least 8 years to design and build.
The environmental review is intended to reveal any reason not to build. Drill crews are looking for anything that might make tunneling hazardous. Biologists are combing the site for endangered species such as bats. Archaeologist Sarah Stephens and a team of 11 are digging shovel holes every 30 meters, 20,000 holes in all, looking for “anything from grandma’s trinket to Native American arrowheads.” There is no doubt, she says, that the Muscogee (Creek), Cherokee, and other Native Americans occupied this site at least occasionally for millennia. But they were mostly driven from the area in the 1830s, west to Oklahoma along the Trail of Tears.
Across the river from the wedding venue, the cooling towers of TVA’s Bellefonte nuclear power plant rose on the far bank. No steam was billowing from them. TVA never quite finished the plant back in the past century; it had overestimated how fast demand for electricity would grow. It was a cautionary message for pumped storage hydropower: Projects that seem foresightful today may prove to be myopic—or too far ahead of their time.
TVA did, however, complete the high-voltage transmission line connecting the nuclear plant to a transmission artery south of the river. That line crosses the possible pumped storage site at Pisgah, and it may yet come in handy, Barrentine says. “I hope it will be energized one day.”
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