Why Molten Salt Won’t Be the Future of Industrial Heat Storage – CleanTechnica

---

Support CleanTechnica’s work through a Substack subscription or on Stripe.

---

---

Molten salt has long been positioned as the workhorse of high temperature thermal storage. Its story began with research in the 1980s and early deployment in Spanish parabolic trough plants in the 2000s. The technology was appealing on paper. A mixture of sodium and potassium nitrate has a high heat capacity, a density almost twice that of water, and can remain liquid over a wide temperature range. Two insulated steel tanks, one cold and one hot, allow operators to circulate the salt through solar receivers or electric heaters to charge, and then through heat exchangers to generate steam when discharge is required.

The design scales well. Crescent Dunes in Nevada and Noor III in Morocco both built tanks large enough to hold over a thousand megawatt hours of thermal energy. Gemasolar in Spain demonstrated continuous twenty four hour operation with fifteen hours of molten salt storage. That track record of real plants delivering dispatchable solar electricity gave molten salt its credibility and still makes it a favored reference point for project financiers. Yet behind the engineering drawings and case studies lie stubborn weaknesses that limit its role going forward.

Researching my recent piece on concentrated solar power failures Ivanpah and Heliogen reminded me how central molten salt once was to the concentrated solar story, and how its legacy still lingers even as the sector falters. Those projects leaned heavily on the promise that heat could be captured, stored, and dispatched at will, with molten salt tanks as the linchpin. That history inspired me to take a harder look at where molten salt fits today, whether as electricity storage, seasonal heat, or industrial process supply. What I found is that while it proved the concept at utility scale, the risks, costs, and complexity have left it overshadowed by simpler and more resilient options now emerging for industrial heat.

For electricity storage, molten salt and indeed any thermal storage solution cannot compete. The round trip efficiency penalty is fundamental. Turning electricity into heat through resistive elements is nearly 100% efficient, and storing that heat in insulated tanks is more than 90% efficient for daily cycles. The loss comes when heat must be converted back to electricity. Steam Rankine cycles running on molten salt rarely achieve more than 35% to 42% thermal efficiency. Even advanced concepts that replace steam turbines with supercritical carbon dioxide Brayton turbines cannot push much past 50% unless salts capable of 700° C or higher are used, and those salts corrode common alloys rapidly. And, of course, supercritical CO2 turbines have never worked commercially after 80 years of effort.

That leaves molten salt systems in the 40% to 45% round trip efficiency range at best for practical deployments. In comparison, lithium ion batteries routinely exceed 85%, and pumped hydro sits between 70% and 85%. When electricity prices fall to zero or negative, a 40% efficient storage can still make sense in theory, but in practice utilities and grid operators have chosen batteries and pumped hydro. Both have faster response times, fewer moving parts, and do not carry the unique risks of molten salt.

Those risks are worth unpacking. Molten salt freezes around 240° C, and to ensure it does not solidify in pipes or tanks it must be kept above 290° C at all times. That requires kilometers of trace heating cables, constant monitoring, and backup power in case the grid fails. A freeze event can render valves, pumps, and entire piping networks unusable until carefully reheated, often a process of days.

The tanks themselves are not trivial. A hot tank holding 20,000 tons of nitrate salt at 565° C imposes enormous stresses on welds, foundations, and insulation systems. Crescent Dunes infamously suffered leaks that shut it down for nearly a year, bankrupting the developer. Corrosion is another ongoing cost. At high temperature, nitrates attack carbon steel unless impurities are held below 0.1%. Stainless steels and nickel alloys are needed for hot piping and heat exchangers. These specialty materials add cost and demand expert welding and inspection. A molten salt plant is closer to a chemical processing facility than to a simple storage battery. It requires specialist operators and maintenance crews, not just electricians and mechanics.

On May 30, 2024, at a liquid nitriding facility in Chattanooga, Tennessee, a violent molten salt eruption occurred when a plug of salt trapped inside a roller was reheated in an 430° C bath while still holding water. The rapid steam expansion ruptured the casing and expelled molten oxidizing salt with such force that it engulfed a worker, who suffered fatal burns. Three others were treated for less severe injuries. Investigators later found that the company lacked essential process safety protocols, hazard analyses, and had not acted on lessons from earlier similar incidents within its parent organization. This tragedy underscores a grim reality of molten salt operations: when containment or procedures fail, the consequences can be deadly.

For district heating and seasonal thermal storage, molten salt is a poor fit. City heating networks operate at 80° to 150° C. Molten salt must be kept nearly double that to avoid freezing, making it inefficient for low grade heat. Seasonal storage requires holding energy for months with minimal loss. Salt tanks, even with thick insulation, lose a few degrees per day. Over weeks and months that adds up. Borehole thermal energy storage, aquifer thermal energy storage, and large water pits have been proven at hundreds of megawatt hours and even gigawatt hour scale in, the Netherlands, Denmark and Germany. These systems store water at 80° to 100 °C, lose only a small fraction of energy over an entire season, and cost a fraction of a steel salt tank. Molten salt cannot compete where the job is to hold low temperature heat for months. It is simply the wrong tool.

The one segment where molten salt retains diminishing relevance is industrial heat above 200° C. Many industries require continuous supplies of steam or direct heat in the 300° to 550° C range. Paper and pulp mills, refineries, and chemical manufacturers all fit this profile. A two tank molten salt system can deliver steady steam or superheated air on demand, charging with surplus electricity and discharging into process lines. There are even startups like Kyoto in Norway that are rebranding salt storage as modular heat cubes for factories, with salts engineered to stay liquid down to 131° C to reduce freeze risk and allow cheaper tank materials. The economics at this scale appear attractive. At large capacity, molten salt systems can come in below $35 per kWh of thermal storage, beating electrochemical batteries by an order of magnitude. For an industrial operator trying to shift from fossil gas to renewables for process heat, the bankability of molten salt is a selling point.

Yet even here, molten salt is not the obvious winner. Competing technologies are simpler and carry lower failure risks. Refractory bricks heated electrically to 1000° C can store heat with less than 1% loss per day, and deliver it back as superheated air or steam. Companies like Rondo and Antora are building these brick and carbon block batteries now. Their systems use cheap, abundant materials, standard fans and ducts, and can cycle indefinitely without concern about freezing or corrosion. Electrified Thermal is heating stacks of iron and carbon blocks. Lumenion is embedding heating elements into steel cores. These are familiar industrial materials, handled by boiler makers and steel fabricators everywhere. When a fan fails or a block cracks, the system can keep running while repairs are made. There are no specialty pumps, no nitrate chemistry to monitor, no heat tracing across every pipe. The costs are dropping rapidly, with some brick based systems already below $20 per kWh of thermal capacity. That undercuts molten salt while eliminating its unique risks.

Phase change materials promise even higher energy density, using the latent heat of melting metals or salts to store several times more energy per cubic meter than molten salt. Thermochemical storage, using reversible reactions like calcium hydroxide to calcium oxide, can hold energy indefinitely without thermal loss and release it on demand. Both are less mature than molten salt, but both are progressing quickly. Steam accumulators, while low in energy density, already provide reliable short term buffering in factories worldwide. The pattern is clear. Every industrial heat storage option except molten salt either has fewer ways to fail, requires less specialist expertise, or delivers higher performance at lower cost once scaled.

The only reasons molten salt is still considered are its history and the comfort that comes with familiarity. Financiers and insurers know it has worked before, even if at high maintenance cost. Engineers know how to design to its failure modes, even if the fixes are expensive. In contrast, refractory brick batteries and sand based storage are new to investors, even if they are technically less risky. That lag between technical advantage and financial bankability is temporary. As the first wave of solid storage projects accumulates operating hours and public data, the perception of risk will collapse. When that happens, molten salt will be left as a legacy technology, remembered as a bridge but not adopted for the long term.

The economics, the physics, and the engineering all point away from molten salt. It is too inefficient for electricity, too hot for district heating, too lossy for seasonal storage, and too complex compared to solid alternatives for industrial heat. Its tanks are monuments to a transitional phase in thermal storage. The future of storing high temperature heat belongs to simpler, cheaper, lower risk approaches. The inevitable shift will not be away from thermal storage, but away from molten salt.