As the world moves to reduce carbon emissions, solar and wind power will play an increasing role on electricity grids. But those renewable sources only generate electricity when it’s sunny or windy. So to ensure a reliable power grid—one that can deliver electricity 24/7—it’s crucial to have a means of storing electricity when supplies are abundant and delivering it later when they’re not. And sometimes large amounts of electricity will need to be stored not just for hours but for days or even longer.
Some methods of achieving “long-duration energy storage” are promising. For example, with pumped hydro energy storage, water is pumped from a lake to another, higher lake when there’s extra electricity and released back down through power-generating turbines when more electricity is needed. But that approach is limited by geography, and most potential sites in the United States have already been used. Lithium-ion batteries could provide grid-scale storage but only for about four hours. Longer than that and battery systems get prohibitively expensive.
A team of researchers from MIT and the Norwegian University of Science and Technology (NTNU) has been investigating a less familiar option based on an unlikely-sounding concept: liquid air. “Liquid air energy storage” (LAES) systems have been built, so the technology is technically feasible. Moreover, LAES systems are totally clean and can be sited nearly anywhere, storing vast amounts of electricity for days or longer and delivering it when it’s needed. But there haven’t been conclusive studies of its economic viability. Would the income over time warrant the initial investment and ongoing costs? With funding from the MIT Energy Initiative’s Future Energy Systems Center, the researchers developed a model that takes detailed information on LAES systems and calculates when and where those systems would be economically viable, assuming future scenarios in line with selected decarbonization targets as well as other conditions that may prevail on future energy grids.
They found that under some of the scenarios they modeled, LAES could be economically viable in certain locations. Sensitivity analyses showed that policies providing a subsidy on capital expenses could make LAES systems economically viable in many locations. Further calculations showed that the cost of storing a given amount of electricity with LAES would be lower than with more familiar systems such as pumped hydro and lithium-ion batteries. They conclude that LAES holds promise as a means of providing critically needed long-duration storage when future power grids are decarbonized and dominated by intermittent renewable sources of electricity.
The researchers—Shaylin A. Cetegen, a PhD candidate in the MIT Department of Chemical Engineering (ChemE); Professor Emeritus Truls Gundersen of the NTNU Department of Energy and Process Engineering; and MIT Professor Emeritus Paul I. Barton of ChemE—describe their model and their findings in a paper published in the journal Energy.
The LAES technology and its benefits
The LAES process consists of three steps: charging, storing, and discharging. When supply on the grid exceeds demand and prices are low, the LAES system is charged. Air is drawn in from the surroundings, cleaned and dried, and then cooled to the point that it liquefies. A large amount of electricity is consumed to cool and liquefy the air. The liquid air is then sent to highly insulated storage tanks, where it’s held at a very low temperature and atmospheric pressure. When the power grid needs added electricity to meet demand, the liquid air is first pumped to a higher pressure and then heated, and it turns back into a gas. This high-pressure, high-temperature, vapor-phase air expands in a turbine that generates electricity to be sent back to the grid.
According to Cetegen, a primary advantage of LAES is that it’s clean. “There are no contaminants involved,” she says. “It takes in and releases only ambient air and electricity, so it’s as clean as the electricity that’s used to run it.” In addition, an LAES system can be built largely from commercially available components and does not rely on expensive or rare materials. And the system can be sited almost anywhere, including near other industrial processes that produce waste heat or cold that can be used by the LAES system to increase its energy efficiency.
Economic viability
In considering the potential role of LAES on future power grids, the first question is, will LAES systems be attractive to investors? Answering that question requires calculating the technology’s net present value (NPV), which represents the sum of all discounted cash flows—including revenues, capital expenditures, operating costs, and other financial factors—over the project’s lifetime. (The study assumed a cashflow discount rate of 7%.)
To calculate the NPV, the researchers needed to determine how LAES systems will perform in future energy markets. In those markets, various sources of electricity are brought online to meet the current demand, typically following a process called “economic dispatch”: The lowest-cost source that’s available is always deployed next. Determining the NPV of liquid air storage therefore requires predicting how that technology will fare in future markets competing with other sources of electricity when demand exceeds supply—and also accounting for prices when supply exceeds demand, so excess electricity is available to recharge the LAES systems.
For their study, the MIT and NTNU researchers designed a model that starts with a description of an LAES system, including details such as the sizes of the units where the air is liquefied and the power is recovered, and also capital expenses based on estimates reported in the literature. The model then draws on state-of-the-art pricing data that’s released every year by the National Renewable Energy Laboratory (NREL) and is widely used by energy modelers worldwide. The NREL dataset forecasts prices, construction and retirement of specific types of electricity generation and storage facilities, and more, assuming eight decarbonization scenarios for 18 regions of the United States out to 2050.
The new model then tracks buying and selling in energy markets for every hour of every day in a year, repeating the same schedule for five-year intervals. Based on the NREL dataset and details of the LAES system—plus constraints such as the system’s physical storage capacity and how often it can switch between charging and discharging—the model calculates how much money LAES operators would make selling power to the grid when it’s needed and how much they would spend buying electricity when it’s available to recharge their LAES system. In line with the NREL dataset, the model generates results for 18 U.S. regions and eight decarbonization scenarios including 100% decarbonization by 2035 and 95% decarbonization by 2050, and other assumptions about future energy grids including high demand growth plus high and low costs for renewable energy and for natural gas.
Cetegen describes some of their results: “Assuming a 100-megawatt (MW) system—a standard sort of size—we saw economic viability pop up under the decarbonization scenario calling for 100% decarbonization by 2035.” So positive NPVs (indicating economic viability) occurred only under the most aggressive—therefore the least realistic—scenario, and they occurred in only a few southern states, including Texas and Florida, likely because of how those energy markets are structured and operate.
The researchers also tested the sensitivity of NPVs to different storage capacities, that is, how long the system could continuously deliver power to the grid. They calculated the NPVs of a 100-MW system that could provide electricity supply for one day, one week, and one month. “That analysis showed that under aggressive decarbonization, weekly storage is more economically viable than monthly storage, because [in the latter case] we’re paying for more storage capacity than we need,” explains Cetegen.
Improving the NPV of the LAES system
The researchers next analyzed two possible ways to improve the NPV of liquid air storage: by increasing the system’s energy efficiency and by providing financial incentives. Their analyses showed that increasing the energy efficiency even up to the theoretical limit of the process would not change the economic viability of LAES under the most realistic decarbonization scenarios. On the other hand, a major improvement resulted when they assumed policies providing subsidies on capital expenditures on new installations. Indeed, assuming subsidies of between 40% and 60% made the NPVs for a 100-MW system become positive under all the realistic scenarios.
Thus, their analysis showed that financial incentives could be far more effective than technical improvements in making LAES economically viable. While engineers may find that outcome disappointing, Cetegen notes that from a broader perspective, it’s good news. “You could spend your whole life trying to optimize the efficiency of this process, and it wouldn’t translate to securing the investment needed to scale the technology,” she says. “Policies can take a long time to implement as well. But theoretically you could do it overnight. So if storage is needed [on a future decarbonized grid], then this is one way to encourage adoption of LAES right away.”
Cost comparison with other energy storage technologies
Calculating the economic viability of a storage technology is highly dependent on the assumptions used. As a result, a different measure—the “levelized cost of storage” (LCOS)—is typically used to compare the costs of different storage technologies. In simple terms, the LCOS is the cost of storing each unit of energy over the lifetime of a project, not accounting for any income that results.
On that measure, the LAES technology excels. The researchers’ model yielded an LCOS for liquid air storage of about $60 per megawatt-hour, regardless of the decarbonization scenario. That LCOS is about a third that of lithium-ion battery storage and half that of pumped hydro. Cetegen cites another interesting finding: The LCOS of their assumed LAES system varied depending on where it’s being used. The standard practice of reporting a single LCOS for a given energy storage technology may not provide the full picture.
Cetegen has adapted the model and is now calculating the NPV and LCOS for energy storage using lithium-ion batteries. But she’s already encouraged by the LCOS of liquid air storage. “While LAES systems may not be economically viable from an investment perspective today, that doesn’t mean they won’t be implemented in the future,” she concludes. “With limited options for grid-scale storage expansion and the growing need for storage technologies to ensure energy security, if we can’t find economically viable alternatives, we’ll likely have to turn to least-cost solutions to meet storage needs. This is why the story of liquid air storage is far from over. We believe our findings justify the continued exploration of LAES as a key energy storage solution for the future.”