IN DEPTH | A wind-powered LAES system would already be a cheaper back-up for variable renewables than a gas peaker plant, and could be the game-changer the energy industry needs
To wean the world off fossil fuels, we need to ensure that variable renewable energy can be stored and used to meet electricity demand at any given moment.
The most established methods of energy storage — pumped hydro, batteries and green hydrogen — all have their drawbacks, being expensive or geographically constrained.
But a breakthrough low-cost, build-anywhere solution may have been found, thanks to a privately-funded UK-based company that has been quietly developing its unique technology for the past 14 years.
Highview Power’s liquid-air energy storage (LAES) technology — which has been proven in the field at a 5MW/15MWh grid-connected pilot project near Manchester — is able to store huge amounts of power for months at a time in any location, and at a far cheaper price than any other energy-storage system.
“For a 100MW system, we are already touching [a levelized cost of storage (LCOS) of] $100 per MWh today,” chief executive Javier Cavada tells Recharge. “In ten years from now, I can see that being $50/MWh. That’s very doable.”
By comparison, a new pumped-hydro plant would have an LCOS of $152-198 per MWh, with a comparable lithium-ion system costing $285-581/MWh, according to analyst Lazard.
With a new gas-peaker plant having a levelized cost of energy of $156-210/MWh, and wind power at $30-60/MWh (according to Lazard), it may already cheaper to balance the grid using wind-powered liquid-air storage than fossil-fuel technology. And if the LAES system is “charged” using wind power that would otherwise be curtailed, the wholesale price of that power would be close to zero.
And renewables backed up by LAES could soon be cheaper than new dispatchable coal-fired power plants, which currently cost $60-140/MWh (according to Lazard).
Highview’s technology is highly modular, meaning that a project’s power (MW) and storage capacity (MWh) can easily be scaled up by simply adding larger turbines or more storage tanks — with no technical or economic limit on either.
“The turbine is one of the most expensive components of the system. But if you change a 50MW turbine for a 100MW turbine, you don’t get double the cost,” Cavada explains. “A turbine of 200MW is double the cost of a 50MW turbine, but it’s four times the capacity.”
He points out that a 50MW system today would have an LCOS of $140/MWh, whereas a 100MW plant would be close to $100/MWh. “The larger the system, the lower the cost,” Cavada says. “It’s totally exponential.”
Multiple LAES plants are already in the pipeline, with the first projects of around 50MW/250MWh due to be completed in the UK next year — developed by Highview in a joint venture with solar EPC company TSK.
“In 2022, we will be building 20 [liquid-air storage] plants of 100MW each,” says Cavada. “We will be the biggest energy-storage company on the planet, that’s for sure.”
How it works and what it can do
Highview’s technology is surprisingly straightforward. Air is cooled down to -196°C, shrinking its volume by a factor of 700, and stored in low-pressure vacuum-insulated steel tanks — the kind that houses liquefied natural gas (LNG). When this cryogenically frozen air is exposed to ambient temperatures, it turns back into a gas and rapidly expands, with the rush of air from this 700-fold expansion directly driving an electricity-generating turbine.
The round-trip efficiency of the system — ie, the amount of energy that goes in, compared to the amount that comes out — is 60%, although this can be increased to 100% by using waste heat or waste cold from neighbouring facilities, says Cavada.
“[When you get heat from] industrial processes — a [nearby] steel foundry or a power plant — you can actually go to 70% [round-trip efficiency]. And if you get a lot of heat you can get to about 75%,” explains Cavada. “But if you get cold on top of that, for instance from an LNG [liquefied natural gas] terminal — you are wasting cold everywhere there — you can go to 90 or 100, and more than 100 because it’s not really round-trip because you are getting the cold and heat from somewhere.”
The insulation of the commoditised steel tanks is so good that only about 0.1% of the stored liquid air is lost each day, although the exact amount depends on the shape and surface area of the tank. This cold “boil off” is not wasted, as it is fed back into the system’s high-grade cold store.
In fact, all the “super-reliable and low-cost” equipment used in the Highview system is off-the-shelf and has been used in other industries for decades, giving Cavada confidence that the company’s plants will be able to operate for more than 30 years.
The first of these, in the UK, “are all at existing power plants that are going to be decommissioned — coal plants and thermal plants that are going to be [shut down] in the coming two or three years”, says Cavada.
“We are coming in with storage capabilities able to give all the services of thermal plants [including reactive power and voltage control], but the input of power into the storage will come hopefully from more and more wind. We get the power from the grid and we expect that the grid will enable more renewables.”
One of the main business models supporting the LAES plants is known as “arbitrage” — charging the system using cheap electricity (generally when the supply of wind and solar is greater than electricity demand) and selling it back to the grid when wholesale market prices are high (ie, when demand is higher than supply).
“That’s one of the revenues, arbitrage, [but] more than 50% of the revenues are totally contracted. So in a way we are replacing decommissioned thermal power generation with energy storage.”
While the initial string of LAES plants will be used to balance the grid, they could also be built at wind or solar farms to make those renewables projects dispatchable, or near-dispatchable.
This would be most efficient for island projects, or perhaps those in places with little grid interconnection.
“We are looking at projects on islands, I cannot say the names, where you can connect directly to wind and solar [farms],” says Cavada. “Then you can really make a wind or solar farm dispatchable. So instead of eight hours of sun, you’re having 14 [or more] hours of sun.
“So we can eliminate curtailment of wind obviously, and we are enabling solar to work 24/7.”
Cavada says Highview’s competition is the fossil-fuel industry — gas-peaker plants — rather than comparable up-and-coming medium-term storage technologies, such as Siemens Gamesa’s hot-rock thermal system.
“We don’t see ourselves competing with other energy storage [technologies] because today we are so much ahead,” says Cavada. “We are proven. We are ready with a very, very good efficiency, with super-good scaleability.”
He adds that Siemens Gamesa’s technology is still at the “experimental” stage (it is now being tested at a commercial pilot project in Hamburg) and has much lower efficiencies.
Siemens Gamesa chief technology officer Antonio de la Torre recently told Recharge that his company’s ETES (electric thermal energy storage) system currently has a round-trip efficiency of 45-50%, with an aim to reach 70% within 15-20 years.
“We are much cheaper, and we are going to stay much cheaper,” says Cavada.
“But I tell you that we are only scratching the surface in all the energy storage that needs to be deployed. Let’s push for all the energy-storage technologies because we need all of them to be in the market because there’s so much power to be replaced with renewables. [Highview is] not going to be able to win all the projects needed because we won’t have capacity to [build them all].”