Most commentary assumes one battery chemistry will eventually win. The more likely outcome is that different constraints will produce different winners for different applications.
Battery storage has been perpetually five years from mass deployment for most of the past two decades. The reasons were always the same: too expensive, too limited in duration, too dependent on materials with constrained supply chains, not yet bankable enough for institutional capital to flow at the required scale.
That picture is genuinely changing. Lithium-ion battery costs have fallen more than 90 percent since 2010. Lithium iron phosphate (LFP) chemistry, which uses no cobalt and minimal nickel, grew from roughly 20 percent of global lithium-ion battery production in 2020 to approximately 60 percent by 2025, according to Benchmark Mineral Intelligence. New chemistries that were laboratory curiosities five years ago are now receiving project finance, DOE loan guarantees, and billion-dollar manufacturing investments. The grid-scale storage market is no longer a pilot program. It is an industrial sector.
But the revolution is not uniform. A critical divergence is emerging, and understanding it matters enormously for anyone developing, financing, or investing in energy infrastructure: the chemistries that will dominate stationary grid storage are not the same chemistries that will power transportation. The physical laws governing energy density are sorting the market in ways that most commentary has not yet absorbed.
The Fundamental Fork: Weight Matters in a Car. It Barely Matters on the Ground.
Every battery stores energy, but batteries destined for different applications face radically different engineering constraints. In an electric vehicle, the battery must be light enough not to destroy the vehicle’s handling, compact enough to fit the available space, and energy-dense enough to deliver acceptable driving range. Those constraints are measured in watt-hours per kilogram. The physics are unforgiving: every kilogram of battery that is not contributing sufficient energy to range is dead weight that reduces the efficiency of the vehicle it is supposed to power.
Lithium-ion batteries in LFP chemistry currently achieve roughly 180 to 230 Wh/kg at the cell level. NMC (nickel-manganese-cobalt) chemistries reach 250 Wh/kg and above. Advanced cell designs, including CATL’s high-nickel formulations and semi-solid state approaches, are achieving 350 Wh/kg in commercial products. These numbers represent decades of optimization for exactly the constraints that vehicle applications impose.
A stationary grid storage system has none of those constraints. A battery sitting on a concrete pad next to a substation does not care how much it weighs. What it cares about is cost per kilowatt-hour of energy stored, cost per cycle over its operating life, safety, and duration of discharge. These are entirely different metrics, and they favor entirely different chemistries.
This divergence is not speculative. IDTechEx’s analysis of the sodium-ion market states it directly: for grid storage, energy density is less critical, and cost per kWh per cycle is the dominant factor. McKinsey’s Battery 2035 report, published in early 2026, projects that LFP will continue anchoring the mass-market EV and BESS markets while alternative chemistries are positioned as promising specifically for stationary storage where their lower energy density is not a disqualifying disadvantage. The IEA describes sodium-ion as a complement to lithium-ion rather than a replacement, with the greatest near-term potential in stationary storage and low-speed transport applications.
The Foundation: Why Lithium-Ion Has a Supply Chain Problem
Lithium-ion batteries dominate the current storage market because they won on cost and energy density. They also won because China industrialized their production faster and at greater scale than any other country. CATL and BYD together accounted for approximately 55 percent of global EV battery installations in 2025, according to SNE Research data, with CATL alone holding nearly 40 percent. China processes more than 60 percent of the world’s lithium, controls two-thirds of cobalt and lithium refining capacity, and processes over 90 percent of the world’s battery-grade graphite. The Democratic Republic of Congo supplies roughly 69 percent of global cobalt mining output, and Chinese companies control the majority of that supply through direct mine ownership and offtake agreements.
This concentration is the result of two decades of deliberate Chinese industrial policy: subsidizing domestic manufacturers, acquiring mining rights across Africa, Australia, and South America, and building refining infrastructure that other countries have been slow to replicate. Australia and Chile mine the majority of the world’s lithium, but much of it travels to China for processing before becoming battery-grade material. The US produced no natural graphite domestically in 2024. The security implications have driven a wave of Western industrial policy aimed at reshoring the battery supply chain, but building domestic refining and manufacturing capacity takes years and enormous capital investment. The transition is underway. It is not complete.
Sodium-Ion: The Grid Storage Challenger
Sodium-ion batteries have attracted intense interest because sodium is roughly a thousand times more abundant than lithium, is distributed globally, and produces batteries that perform exceptionally well in cold temperatures. They contain no cobalt and no nickel, eliminating two of the most geopolitically sensitive materials in the lithium-ion supply chain.
The commercial story is accelerating. CATL launched its first-generation sodium-ion cell in 2021 at 160 Wh/kg energy density. By April 2025, the company’s Naxtra sodium-ion series reached 175 Wh/kg with an operating range from -40 to 70 degrees Celsius. In February 2026, CATL and Changan unveiled what the company described as the world’s first mass-production passenger vehicle equipped with sodium-ion batteries. BYD commissioned its first sodium-ion mass-production line in Xining, Qinghai, in July 2025. US startup Peak Energy deployed the first grid-scale sodium-ion installation in the United States in Colorado in 2025, and has contracted to provide 4.75 GWh of sodium-ion storage to Texas-based Jupiter Power for deployment between 2027 and 2030.
The energy density gap relative to lithium-ion is real but context-dependent. The IEA puts the latest sodium-ion cells at up to 175 Wh/kg, compared to roughly 205 Wh/kg for LFP and 255 Wh/kg for NMC. For long-range electric vehicles, that gap matters. For a battery sitting on the ground next to a wind farm, it is largely irrelevant. CATL Chairman Robin Zeng has publicly projected that sodium-ion could eventually displace 30 to 40 percent of the existing battery market, describing the two chemistries as a ‘dual-star’ development path in which lithium-ion and sodium-ion coexist serving different applications rather than competing head-on. That is an executive forecast from a manufacturer with obvious commercial interest in sodium-ion adoption, not an industry consensus, but it reflects the seriousness with which the world’s largest battery company is treating the technology.
Vanadium Redox Flow: The Long-Duration Answer With Its Own Supply Chain
Vanadium redox flow batteries (VRFBs) store energy in liquid electrolytes containing dissolved vanadium ions, pumped through electrochemical cells during charging and discharging. Energy capacity is physically separate from power capacity: more electrolyte in larger external tanks means more energy stored, without rebuilding the power conversion equipment. This decoupling makes VRFBs well suited to durations of four hours and above, where lithium-ion economics deteriorate and grid operators need multi-hour storage to smooth renewable generation.
VRFBs are a stationary technology. No serious commercial transportation pathway currently exists for vanadium flow batteries: the liquid electrolyte storage tanks, pumping systems, and overall system architecture are suited to fixed installations, not mobile applications. They are a grid asset, and should be evaluated on those terms: long operational lifespan of 20 to 25 years versus 10 to 15 for lithium-ion, minimal capacity degradation over thousands of cycles, and essentially no fire risk from thermal runaway.
The commercial scale milestone is already on the books. China’s Huaneng Group completed the main construction of a 200 MW / 1 GWh VRFB system paired with a 1 GW solar farm in Jimusar, Xinjiang in mid-2025, with a total investment of approximately $520 million. It is the largest vanadium flow battery installation ever built. The challenge for VRFBs outside China is vanadium supply: production is concentrated in China, Russia, and South Africa, and vanadium prices are volatile, having nearly doubled the capital cost of some VRFB projects during the 2018 price spike. The VRFB market is growing rapidly but remains largely a Chinese-led story for now, with US and European project finance for this technology still dependent on government credit support.
Iron-Air: The Most Audacious Bet in Long-Duration Storage
Iron-air batteries store energy through the reversible oxidation of iron in a water-based electrolyte. Iron is the fourth most abundant element in the Earth’s crust, and the raw material supply chain for iron-air storage is among the least geopolitically exposed of any major battery chemistry currently under commercial development. Like vanadium flow, iron-air is a stationary technology: its 100-hour discharge design and relatively slow charge and discharge rates make it unsuitable for transportation applications, but well suited to providing the multi-day storage the grid needs to cover extended renewable generation gaps.
Form Energy, the leading commercial developer, has raised more than $1.2 billion from investors including T. Rowe Price, GE Vernova, and Breakthrough Energy Ventures, and received up to $150 million in DOE manufacturing support. Its West Virginia factory completed construction in 2024. The first commercial installation, a 1.5 MW / 150 MWh project with Minnesota utility Great River Energy, came online in 2025. Xcel Energy has contracted 30 GWh of Form Energy iron-air batteries to serve a Google data center in Minnesota, with most of that capacity scheduled for phased deployment over future years rather than already operating in service. PacifiCorp’s 2025 Integrated Resource Plan includes up to 3,073 MW of iron-air storage by 2045. These are utility-scale commitments signed by regulated utilities with real capital behind them, not demonstration projects.
The bankability challenge for iron-air, as for any first-of-a-kind technology, is the absence of a multi-year commercial operating track record. Technology performance insurance, offered by specialty insurers able to evaluate new technologies and provide performance coverage, is one mechanism that bridges this gap for institutional lenders. The DOE’s Loan Programs Office has also stepped into the financing gap directly, with conditional commitments to Eos Energy Enterprises (up to $398.6 million for its zinc-based Eos Z3 battery), to Hydrostor (a $1.76 billion guarantee for advanced compressed-air energy storage in California), and to a growing pipeline of storage manufacturers. Zinc-based systems like the Eos Z3 represent another emerging stationary-storage pathway attracting meaningful federal support, occupying a middle ground between lithium-ion and long-duration chemistries.
What Is Actually Getting Financed
The breakdown of which battery technologies are attracting capital today separates clearly along the stationary-versus-mobile line.
In transportation, lithium-ion is not being displaced. It is being refined. LFP has captured the majority of the global battery market because it eliminated cobalt dependence while maintaining adequate energy density for most vehicle applications. Solid-state lithium designs represent the next frontier for transportation: they promise higher energy density, faster charging, and reduced fire risk. CATL, Toyota, and QuantumScape are all investing heavily in solid-state manufacturing. These are lithium-ion evolutions, not lithium-ion replacements. Sodium-ion will capture transport niches in two-wheelers, short-range vehicles, and cold-climate applications. Vanadium flow and iron-air will not participate in mainstream transportation in any scenario current technology supports.
In stationary grid storage, the market is diverging by duration. For two-to-four-hour storage, LFP lithium-ion is the bankable standard, with dozens of projects closing every month using conventional project finance. For four-to-twelve-hour storage, sodium-ion for stationary applications is entering the market with major Chinese manufacturers behind it, and VRFBs are bankable in China and increasingly viable in the West with government support. For twelve hours and beyond, iron-air and compressed air are receiving DOE loan support and utility commitments, with the commercial operating track record currently being accumulated and expected to unlock broader institutional lending within two to three years.
The Supply Chain Is the Strategy
The strategic lesson from surveying these chemistries is that battery technology selection is inseparable from supply chain analysis, and supply chain analysis is inseparable from the specific application. For transportation, the challenge is reducing lithium-ion’s dependence on Chinese refining and cobalt from the DRC while maintaining the energy density that vehicles require. For stationary storage, the challenge is building alternatives to lithium-ion that use geographically distributed, abundant materials, because the weight penalty those materials carry simply does not matter when the battery never moves.
The battery industry is not converging on a single winning chemistry. It is diverging into specialized solutions for specialized constraints. The technologies most likely to attract the broadest institutional capital are those that combine adequate technical performance for their specific application with supply chains that lenders and investors can underwrite without requiring aggressive geopolitical risk assumptions. Understanding that divergence, and the financing structures that make each segment bankable, is the starting point for anyone trying to build, finance, or invest in energy storage at scale. That is the kind of infrastructure finance logic explored throughout Financing the World We Trade In.