Battery Chemistry Now Sets Storage Cost, Safety, and Scale

? chibueze-amanchukwu describes batteries as connective tissue between electricity generation, transport, and industry. Solar and wind are intermittent, electric vehicles need a compact means of carrying energy, and industrial systems attempting to move away from fossil fuels need a way to use electricity when it is available rather than only when it is generated. Batteries can serve each of those settings—if their cost is low enough.

That condition has changed dramatically. Amanchukwu traces lithium-ion batteries from their commercialization by Sony in 1991, when he puts their cost at nearly $10,000 per kilowatt-hour, to roughly $100 per kilowatt-hour today. Some quoted prices, he notes, are as low as $50 per kilowatt-hour, although he cautions that the actual price is not always clear. The broad result is a roughly 99% decline.

He attributes the decline to better materials design, improved manufacturing, and large-scale investment in battery production, particularly in China. Lower prices did not simply make existing electronics cheaper. They made cost-sensitive applications more plausible, including electric vehicles and grid-scale storage.

Amanchukwu points to an exponential rise in U.S. lithium-ion deployment, reaching roughly 40 gigawatts of installed capacity in 2025. China, he says, is closer to hundreds of gigawatts. The buildout is not evenly distributed within the United States. California and Texas stand out because they combine large populations with substantial solar and wind resources; Illinois has battery projects, but at a much smaller scale.

Other storage technologies remain important but more constrained by location or conversion losses. Hydroelectric storage is still the dominant storage method available today, he says, but needs suitable water and elevation. Compressed-air storage requires accessible caverns. Thermal storage can be scalable and useful for supplying heat to chemical processes, but converting stored heat back into electricity introduces conversion limitations.

Batteries differ because they are modular. Systems can be assembled from cells rather than requiring a dam, cavern, or specialized thermal installation. Amanchukwu cites the early Tesla Model S, which used roughly 7,000 commercially available cylindrical cells. The same principle extends outward: enough cells can be combined into systems for much larger loads.

That modularity is electrical as well as physical.Cells can be connected in series to raise voltage and combined in larger arrays to add capacity. A nine-volt battery, he explains, can be understood as three cells connected in series. Manufacturers still make packaging tradeoffs. Cylindrical cells can leave unused space in a vehicle pack, while pouch or prismatic cells can better fit a particular geometry. But cylindrical cells benefited from established scale and could be used across models. Amanchukwu describes Tesla as accepting some pack-level energy-density loss in exchange for flexibility and manufacturing scale.

? chibueze-amanchukwu frames a rechargeable battery as a system for repeatedly moving ions between two electrode materials. In a lithium-ion battery, charging moves lithium ions from the cathode, through the electrolyte and separator, into the anode. Discharging reverses that movement: lithium leaves the anode and returns to the cathode while the device uses the resulting electrical energy.

At minimum, a battery contains an anode, a cathode, and an electrolyte. Most also have a separator: a porous polymer barrier that keeps the two electrodes from touching while allowing ions to pass through. Direct contact makes the battery electrically useless and can create an internal short.

The electrolyte is the transport medium. Amanchukwu uses seawater as the intuitive example: sodium chloride dissolved in water allows sodium ions to move. Lithium-ion cells follow the same general principle but use lithium salts dissolved in engineered organic solvents because water is not stable at the voltages at which these batteries operate.

Those formulations are part of the commercial technology. He identifies ethylene carbonate as one electrolyte component; because it is solid at room temperature, it is mixed with another compound that remains liquid. Manufacturers may add small, often proprietary quantities of other compounds to improve cold-weather operation or battery lifetime. Some of the incremental gains consumers see from one battery generation to the next, he argues, come through electrolyte engineering.

The standard lithium-ion anode is graphite. Its layered carbon structure leaves spaces for lithium ions to enter and exit. Graphite can be mined or made synthetically, including by carbonizing plastics at high temperatures. Lithium titanate, or LTO, is another anode option. It can charge quickly and support long life, but is expensive in part because it relies on titanium.

The cathode is often where commercial differences become clearest. It is generally a lithium-containing transition-metal oxide or related host structure. Its composition shapes voltage, cost, energy density, thermal behavior, and the applications for which a cell is suited.

Voltage follows from the thermodynamics of the reaction rather than being chosen arbitrarily. Given the free-energy change for the reactions occurring in a battery, Amanchukwu says, one can calculate the maximum voltage that chemistry can provide. An LFP cell typically operates around 3.4 to 3.5 volts, while a conventional AA battery is labeled around 1.5 volts.

Capacity ratings alone do not establish practical value. A 10,000 milliamp-hour power bank may simply be larger or heavier than another power bank with the same rating. A useful comparison accounts for capacity relative to mass or volume, then combines that with voltage to establish energy density.

That is also where claims can be made to look better than a practical device will perform. A developer may calculate energy density using only active materials, excluding other cell components or the larger device. Amanchukwu’s practical question is straightforward: what mass is in the denominator?

? chibueze-amanchukwu uses coulombic efficiency to explain why lithium-ion batteries can survive repeated use. The metric measures the fraction of charge recovered after charging. If 100 lithium ions leave the cathode during charging and only 99 return during discharge, the efficiency is 99%. A small loss in every cycle compounds quickly over hundreds or thousands of cycles.

He puts the coulombic efficiency of a contemporary lithium-ion battery at about 99.98% per cycle.

That level of reversibility is why, he says, a phone battery can be charged and discharged around 1,000 times while retaining more than 80% of its capacity. Pairing a lithium-ion cell with an LTO anode can extend the cycle count to roughly 10,000 cycles.

The structural explanation is that lithium ions move between host materials rather than repeatedly destroying and rebuilding them. Amanchukwu calls lithium-ion a “rocking chair battery”: lithium moves back and forth between the electrodes. Limited structural change allows that process to be repeated. Excessive expansion makes reversibility much harder to sustain.

Silicon illustrates both the appeal and constraint of trying to improve on graphite. Amanchukwu says silicon can offer roughly 10 times graphite’s capacity. Graphite stores one lithium for every six carbon atoms, while silicon can accommodate about four lithium atoms per silicon atom. But silicon undergoes a conversion reaction as it lithiates: chemical bonds break and form, the material can expand by as much as 400%, and cycle life suffers.

Commercial devices use compromise rather than a complete replacement of graphite. He says phones may incorporate around 5% silicon by weight into graphite anodes, gaining some energy density without taking on the full degradation problem of a pure-silicon anode.

The same tradeoff logic applies across battery development. Energy density measures how much energy can be stored per unit of mass or volume. Power density measures how quickly that energy can be extracted. C-rate describes charging and discharge speed: 1C means a full charge or discharge in one hour, while C/4 means four hours. Cycle life measures repeated use, while energy efficiency asks how much energy comes back out compared with what went in.

No chemistry optimizes every metric simultaneously. A claim about a battery’s energy density remains incomplete without a measurement basis, useful charging rate, repeated-cycle performance, and safety conditions.

? chibueze-amanchukwu puts the cathode at roughly half the cost of a lithium-ion battery. That is why NMC, NCA, and LFP are commercial categories as much as chemical ones.

He puts manufacturing at roughly 24% of cell cost and the anode at about 12%, with the electrolyte accounting for less. About 80% of cell manufacturing occurs in China, he says. That concentration shapes adoption: chemistries produced at scale in China can proliferate outside the country through supply-chain and price advantages.

Nickel-containing chemistries such as NMC and NCA have historically been prominent in passenger electric vehicles, particularly in the United States and Europe, where energy density and performance have been important priorities. LFP was a small share of the market in 2021 but has grown substantially through 2025 in the data Amanchukwu presents. It is particularly prominent in vans and lorries, stationary storage, China, and an increasing share of emerging economies and the Global South.

Cost is one reason. LFP is cheaper than nickel manganese cobalt alternatives, he says. The other is safety. In stationary storage, where systems can deploy hundreds of megawatts of batteries, a safety incident has consequences well beyond a single vehicle or device.

Nickel and cobalt contribute materially to cathode cost, which is why efforts to reduce or eliminate them are often framed around critical minerals. A battery is not one commodity; it is a system of materials whose prices, availability, manufacturing requirements, safety properties, and performance characteristics interact.

The fire risk is central to this selection. Amanchukwu describes conventional lithium-ion cells as containing the three elements of a fire triangle inside the cell: oxygen, fuel, and heat. In lithium cobalt oxide and nickel manganese cobalt cells, oxygen can be released from the cathode at high temperatures. The organic electrolyte is volatile and flammable, providing fuel. Heat can arise from an abuse condition: a crash, puncture, external fire, or internal short allowing anode and cathode to contact.

A slide shown during the presentation depicts an NCM cell being pierced by a nail. The contact between electrodes triggers a violent reaction and rapid temperature increase. The separator exists to prevent that contact under normal operation.

The difficulty of response, in his account, is that the battery can supply its own oxygen, flammable solvent, and heat. Amanchukwu says firefighters’ best advice can be to let a lithium-ion battery burn. He cites Moss Landing in California, which he describes as the world’s largest grid-scale battery installation and says caught fire again in the prior year. He also says communities around the United States have adopted moratoriums limiting grid-battery deployment, with New York accounting for more than half of the country’s lithium-ion moratoriums.

A chart displayed in the presentation makes the chemistry distinction visible. As temperature rises, the plotted self-heating rates for LCO and NCM rise sharply, while the LFP curve remains comparatively low and flat. Amanchukwu attributes the difference to how tightly oxygen is held in the cathode: in LFP, oxygen is covalently bound to phosphorus and is much less prone to leave the material and feed combustion.

Fuel and heat may still be present, but the oxygen component of the fire triangle is substantially constrained. That distinction can affect local manufacturing permission as well as product design. Amanchukwu points to Gotion’s facility south of Chicago, which, he says, is permitted under its community agreement to manufacture LFP batteries but would need to return to the community for permission if it chose to make NMC cells.

? chibueze-amanchukwu presents lithium-ion as state of the art, but not as a chemistry that can necessarily meet every future storage demand. One constraint is materials. Grid-scale renewable integration could require battery materials at a scale far beyond recent mining levels.

He presents an estimate of roughly 870 kilotons of lithium for one terawatt-hour of storage. The slide shown during the presentation says global lithium mining totaled only about 130 kilotons in 2022. In his spoken explanation, Amanchukwu instead cites about 180 kilotons mined worldwide in 2023. The source therefore gives two different recent reference figures, but its point is clear: one terawatt-hour of storage based on lithium would require mining far beyond either cited annual amount, before accounting for other uses of lithium or demand for nickel and cobalt.

The resulting research agenda is not a race toward one universal successor. Different next-generation chemistries pursue different goals: material abundance, lower cost, higher energy density, safer operation, or a better fit for a particular application.

Sodium-ion offers abundance, not a free replacement

Sodium-ion batteries aim to replace lithium with sodium, which Amanchukwu describes as highly earth-abundant and potentially lower in material cost. A sodium-ion cell substitutes hard carbon for graphite at the anode, sodium salts in the electrolyte, and sodium-containing cathodes. Some cathodes use Prussian-white structures containing sodium, iron, nitrogen, and carbon.

The substitution does not eliminate every constraint. Sodium-ion batteries currently cost more, he says, and can retain similar safety problems when they use the same flammable liquid electrolytes. Cathodes containing releasable oxygen can still present the fire-triangle problem. Their energy density is lower than lithium-ion’s, meaning a sodium-ion cell must be larger to store the same amount of energy. Many designs also remain reliant on nickel and manganese, retaining part of lithium-ion’s supply-chain challenge.

The appeal is therefore not superior performance on every measure. It is a possible route to lower-cost storage based on more abundant materials where a larger physical footprint is acceptable.

Solid-state designs hinge on lithium-metal stability

Solid-state batteries replace the flammable liquid electrolyte with a solid electrolyte. Removing the liquid is a safety proposition because it eliminates the volatile organic material that serves as fuel in conventional cells. But Amanchukwu argues that much of the excitement is really about energy density.

Simply replacing liquid with solid would not create that gain. He says a solid electrolyte weighs more than the liquid it replaces, so a direct substitution would reduce energy density. The anticipated advantage is tied to enabling a lithium-metal anode rather than graphite. In his comparison, graphite stores one lithium for every six carbon atoms; lithium metal is presented as the route to a much more energy-dense design.

The obstacle is that lithium metal is highly reactive. It can penetrate the solid electrolyte and short the battery. Amanchukwu also identifies low current densities and operating pressures above 100 bar as practical constraints for many solid-state designs. The challenge is not only finding a solid that transports ions; it is maintaining a stable cell while preventing lithium-metal penetration.

Carbon and salt is an effort to remove solvents and transition metals

Amanchukwu’s group is developing what it calls a carbon-and-salt battery. Its stated aim is to eliminate solvents and transition metals while using earth-abundant elements. The design uses carbon composite materials for both anode and cathode, alongside a low-melting molten-salt electrolyte rather than a solvent-based electrolyte.

The intended result is a battery that is intrinsically safer, energy-dense, and easier to recycle. Amanchukwu says the work has received support from the Department of Energy and Breakthrough Energy, and that his group has filed patents. The group is continuing fundamental work to determine whether the chemistry can be made rechargeable and whether it can scale.

Flow batteries trade compactness for separable power and energy

Flow batteries take a different approach for grid applications. Instead of storing all energy inside sealed cells, they store charge in liquid electrolyte tanks and pump those liquids through electrodes. This separates energy capacity from power capacity: increasing tank size adds stored energy, while increasing electrode area adds power capability.

That architecture can suit stationary systems, where physical footprint is less constraining than it is in a vehicle. But Amanchukwu emphasizes the drawbacks. Flow batteries have low energy density, and their pumps and related equipment make them operate more like chemical plants than self-contained battery packs. Pumps can fail, the systems require attention, and organic compounds in their electrolytes can face stability and degradation challenges.