At least 32 utilities are aiming to be carbon-free or achieve net-zero emissions by 2050. This is the third of a four-part series exploring the storage technologies that could get them there.
In 1991, generation and transmission cooperative PowerSouth — then known as the Alabama Electric Cooperative — started operating a 110 MW compressed air energy storage (CAES) plant in McIntosh, Alabama.
The project was the first of its kind in the U.S., and had a 26-hour duration. It essentially served as a peaker plant, to smooth demand between the low weekday loads and high weekend peaks that came from having a predominantly residential load, according to Bobby Bailie, business development director for energy storage at Siemens Energy. Bailie used to work for Dresser-Rand, the company that built the equipment at the McIntosh plant, which was acquired by Siemens in 2015.
Nearly three decades later, the McIntosh plant is still the only operational utility-scale CAES plant in the U.S. But more recently, utilities and developers have taken a renewed interest in the technology for a completely different reason: the ability to store large amounts of renewable energy for long periods of time.
"What's driving the renewal is the excess renewable capabilities, and the demand for storing those renewables for longer periods of time," said Rob Webster, chief strategy officer at Magnum Development. "We all know the sun doesn't always shine, the wind doesn't always blow, yet electric demand is there — and these bulk storage facilities give the ability, for the first time, to really have truly dispatchable renewable energy."
"You'll see that with anything new that's coming out generically in the energy storage space, duration is going to be what everybody is trying to achieve."
Business Development Director for Energy Storage, Siemens Energy
At its most basic level, CAES technology involves taking air, compressing it during times of surplus power, and storing it in pressurized form either underground or in above-ground containers — although large-scale facilities are predominantly underground because of cost effectiveness, according to Bailie. That air can then be heated and expanded to drive a turbine and generate power when electricity is needed.
Existing plants tend to be designed in the 24 hour-plus duration range, Bailie said, and have a wide operating range. But in principle, a CAES plant could have hundreds of hours of storage, since it boils down to the volume of the cavern — an attractive proposition to an industry that is looking to transition to intermittent renewables.
"Let's say you start to push 60%, 70% [clean energy] targets — you start to have a huge need for storage, and there are just limited long-duration storage options," Bailie said. "You'll see that with anything new that's coming out generically in the energy storage space, duration is going to be what everybody is trying to achieve."
Another somewhat similar — but also very different — technology that is elbowing its way into the storage space is liquid air energy storage, a process that involves turning air to liquid form by cooling it down, storing it in insulated containers, and then re-warming it to expand and drive a turbine, creating power, as required. The technology is employed in a facility in Greater Manchester, England, and the company that owns it, Highview Power, is in the process of developing a similar project in northern Vermont.
There is quite a bit of commonality between the technologies, said Todd Tolliver, senior manager of storage technologies at ICF, in terms of using equipment to literally squish air into a smaller space, or liquid form, and storing it until needed. But their applications can be quite different. Compressed air projects, whether stored under or above ground, tend to be plant-scale, and provide anything from MWhs to GWhs of storage capabilities, Tolliver said. Liquid air facilities, on the other hand, are more scalable, and can be deployed in the space between commercial and industrial applications and utility-scale projects.
'There's a lot of unknowns' about compressed air
CAES is a relatively old technology, with a plant installed in Huntorf, Germany in 1978. But the technology has faced some limitations. Compressed air projects have historically been associated with underground salt caverns, which are only found in certain locations. And then there's the issue of cost. In a 2018 report filed with the California Energy Commission, for instance, Pacific Gas & Electric (PG&E) outlined its efforts to look into the viability of underground compressed air storage, in light of increasing renewables on its system and the "need to continue investigating promising technologies that could provide operational flexibility for power grid scheduling."
The project, which was based in King Island, California, and provided with $25 million in funding from the U.S. Department of Energy, as well as another $25 million from California energy agencies, demonstrated that using an abandoned natural gas reservoir to store high-pressure compressed air is technically feasible, according to the report. But after issuing a solicitation to develop and operate the facility, the utility found that the best offer it received could not compete economically with other storage technologies.
"There's a lot of unknowns about it — even though that McIntosh facility has been around forever, there's only one of them and they haven't built a second. That to me tells us something," said Glenn McGrath, leader of the electricity statistics, uranium statistics and product innovation team at the U.S. Energy Information Administration.
But now, some say there are signs that CAES could be poised for a comeback.
The Los Angeles Department of Water and Power (LADWP), for instance, is evaluating proposals for CAES deployments, including at the Intermountain Power Project, said James Barner, assistant director of LADWP's Clean Grid LA Strategy Division. The utility has its eye on two types of compressed air technologies — one that uses a small amount of natural gas along with compressing the air into a large underground cavern like a salt dome, which could be a good fit for the Intermountain project, and another that doesn't use any fuel but tends to be a little less efficient, which LADWP is evaluating for other parts of its system.
Webster, whose company Magnum controls the salt dome adjacent to the Intermountain project under a long-term lease, is eyeing multiple potential customers — including the Intermountain Power Agency and most of the major western utilities — about the possibility of deploying a CAES facility in Utah.
"We, at this point, haven't nailed down any of those and are still in the development phase," said Webster. "The cavern, the geology is ready to go, the technology is ready to go, and we can deploy that quite quickly."
The salt dome is several miles across and about a mile thick, making it the perfect bulk energy storage medium, according to Webster. And while there are hundreds of salt domes throughout the U.S., their dome is somewhat unusual, both because of its size and because it's adjacent to pre-existing infrastructure that can be repurposed, Webster said.
There are many reasons for the renewed interest in CAES, according to Joe Spease, CEO of WindSoHy — for instance, recent research advances that have shown pressurized air can be stored in depleted gas wells. In addition, wind power has grown cheaper in the last few years and could be an ideal companion to pair with a CAES project, Spease said.
Advances in hydrogen technology could also boost CAES since it burns at a far higher temperature than natural gas. And on the regulatory side, the Federal Energy Regulatory Commission's Order 841 "was a game changer," which allows for a more level playing field for energy storage in the marketplace, Spease noted.
Some utilities appear to be taking a closer look at compressed air storage. Siemens has been having discussions with multiple utilities and developers in North America and in Europe who are interested in the technology, according to Bailie. For companies with aggressive renewable targets, the most prominent long-duration storage options are essentially CAES and pumped hydro, Bailie said. But while both technologies have geographical limitations, pumped hydro has the added burden of having more "visibility" and environmental hurdles, including the ecological impacts of constructing dams on rivers.
"If you're going to the McIntosh plant, for example, it's nothing special as far as the physical footprint of the plant. If anything, you stand over a wellhead and just are told, trust us, there's a big huge hole in the salt below you where they store air, but it's not visible," Bailie said.
Another benefit with CAES is that its cost levels out as you scale up, since expanding a CAES plant requires simply making a bigger cavern, said Bailie. And while some think of both pumped hydro and CAES as old school, "this energy transformation is bringing those to the forefront… [these] two are really what the grid is going to need in the future."
Liquid air: small footprint, high density
Liquid air energy storage isn't an old technology — but it's based on engineering concepts that have been used for the last 40 or 50 years in the oil and gas sectors, said Javier Cavada, CEO of Highview Power.
According to Highview, one 50 MW/250 MWh plant can store enough power to generate electricity for 100,000 homes.
Cavada took over his role at Highview after seeing the enormous demand in the market for large-scale storage with many hours of duration, as well as the simplicity of the technology, which makes it easy to deploy and scale. Highview has patented the technology that it uses, but intends to license it out to developers to build projects. Last December, the company announced plans to build its Vermont facility — a minimum 50 MW project with the ability to provide more than eight hours of storage — as a solution to transmission challenges in the region.
"[I]n California, our electric system needs some amount of power generation in local or more heavily populated areas, where land can be expensive. So you want to bring solutions that can fit in those physical spaces."
Executive Director, California Energy Storage Alliance
The main benefits of the technology are the attractive costs, flexibility and high energy density, which means it requires a small footprint to put in a large number of MWh, Salvatore Minopoli, vice president of Highview Power, said at the Energy Storage Association's (ESA) annual conference and expo in August, adding that the optimum scale for a project is anything over 25 MW, and anything over four hours.
Those attributes could make liquid air competitive, especially in urban areas, said Alex Morris, executive director of the California Energy Storage Alliance.
"A good example is how in California, our electric system needs some amount of power generation in local or more heavily populated areas, where land can be expensive. So you want to bring solutions that can fit in those physical spaces."
In fact, LADWP is interested in liquid air storage solutions, said Ashkan Nassiri, the utility's manager of strategic initiatives. LADWP is particularly interested in the technology because adding more duration to it doesn't require a linear increase in costs — increasing the system's duration simply requires adding in low-cost tanks, which brings capital costs down.
"If you're going to do the same thing, for example, with lithium-ion batteries, the more duration you need, the more batteries you need to add — and that battery basically is the same cost as the first part of the battery that you got. So there's no economy of scale," Nassiri added.
'The challenge is correctly estimating costs'
Another commonality between CAES and liquid air storage technologies is they are both trying to carve out a niche that distinguishes them from lithium-ion batteries. For both, the key draw is duration.
"Lithium has a big role, [it] has a very big list of projects that need to happen — but that's not going to make the whole transition alone," Cavada said, adding that while lithium-ion batteries are the best technology for small-scale, shorter-duration projects, it isn't viable to continue stacking up batteries to scale up.
With liquid air, the biggest challenge is getting a good understanding of the operating costs for a plant, in terms of preventative maintenance and potential overhauls, Tolliver said. Because there aren't a lot of parallels to other technologies out there, "the challenge is correctly estimating costs to make sure that it continues to make money."
But renewables are going to continue coming on to the grid, and will become the new baseload for the market — and that is going to create volatility, Minopoli said at the ESA conference.
"And the answer to that is long-duration storage," Minopoli added.
Bailie anticipates receiving an order for a large CAES project at some point in the next two years, after which the market will accelerate and start to deploy one or two every year. There are stages to this, Bailie acknowledged — first, more renewables need to come on to the grid and utilities have to start getting more serious about storage.
But "my belief is if… you have the access to a salt cavern and you have renewables on your grid, you're best suited to put in a CAES plant. Why wouldn't you at that point?"