Despite years of trying to build a local supply chain, Europe had never imported that many batteries from China before.

Between 2022 and 2024, China accounted for 85.5% of the European Union’s battery imports from non-EU countries. In 2021-23, this number was 81.9% (Source: JRC, based on COMEXT data).

South Korea’s share fell from 8.5% to 5.7%, while Japan slipped from 2.6% to 2.4%. Together with China, the three countries represented 93.6% of EU battery imports.

Over those three years, the EU imported $76.5bn (€71.4bn) of battery cells from non-EU countries. $65bn (€61bn) came from China alone.

China also accounted for 115.9% of the EU’s net battery import needs during the same period. This number exceeds 100% because the EU also exports batteries. Even after subtracting EU exports to China, net imports from China were larger than the EU’s overall battery trade deficit.

Europe spent those years building battery cell factories, but the imports still went up.

I found 4 reasons why.

Reason #1: Europe built more than 200 GWh of cell capacity, but most come from Korean plants launched before its main battery policies.

Europe had 252 GWh of cell production capacity in 2025 (Source: SolarPower Europe). It sounds great, but there’s a high concentration.

The 3 Korean cell producers held 65% of it: LG Energy Solution in Poland, Samsung SDI, and SK On in Hungary.

LGES started construction of its Polish plant in October 2016, while Samsung SDI completed its Hungarian EV battery plant in May 2017. SK On announced its Hungarian plant in late 2017 and broke ground in March 2018.

In October 2017, the European Commission created the European Battery Alliance (EBA) to build up battery technology and capacity in the EU.

However, the first serious financial scheme to support the industry arrived 2 years later.

The European Commission approved the first battery IPCEI, its Important Project of Common European Interest scheme, in December 2019, with up to €3.2 billion of state aid. A second followed in 2021, taking approved state aid across both programs to €6.1 billion.

SK tied its Hungarian expansion to European EV demand and to long-term supply contracts with carmakers including Volkswagen and Mercedes-Benz.

It’s the same for LG Energy Solution and Samsung. They all came to Europe for their EV battery customers.

Meaning that only 88 GWh (35% of 252 GWh) of cell production capacity was built in 9 years of industrial push.

I don’t know about you, but I am not afraid to call it an enormous failure from our politicians.

Reason #2: European battery producers failed to turn billions of investment and announced gigafactories into reliable mass production.

Despite European politicians’ lack of realism, not everything should be thrown away.

Since Brussels launched the EBA in 2017, around €33 billion in investments has gone into battery factories in Europe (Source: European Commission, based on BloombergNEF).

A big part is coming from 1 company, Northvolt.

The Swedish company was seen as the European contender in the race against the Chinese and the Koreans. European governments and public lenders made Northvolt one of their biggest battery bets.

It secured around €14 billion in equity, debt and public funding before filing for bankruptcy in Sweden in March 2025.

The main reason was poor execution at its Skellefteå factory. They struggled for years to reach over 90% yield in one production line.

In addition, Northvolt wanted to do everything in the value chain: cathode, anode, recycling, and even sodium-ion production. It tried to compress into a few years the vertical integration that took CATL, LG Energy Solution, and BYD between 10 and 20 years.

The same ambition happened horizontally: factories were planned in Germany and Canada before the Swedish factory was even working.

Northvolt was not the only one to fail.

Morrow filed for bankruptcy in May this year. Morrow had a smaller factory in Norway with 1 GWh production capacity vs 16 GWh for Northvolt. It’s the consequences of poor execution as well. The Norwegian company struggled in the factory to reach a high level of yield (>90%).

FYI, Lyten, an American lithium-sulfur battery company, bought Northvolt’s former assets and was just selected as the preferred bidder for Morrow’s assets. I am not a big fan of its strategy, which risks accumulating too many technologies and chemistries, plus 2 factories, without any gigascale production experience.

You also have ACC in France, which is facing the same issues on the factory floor. Renault put pressure on Verkor to deliver after delays to the original schedule and asked for changes to its governance. Verkor has since announced a CEO change.

So, the European Commission wants to help them overcome the ramp-up phase.

It just launched the Battery Booster Facility. The Commission’s €1.5 billion Battery Booster Facility want to help these companies scale up production. Projects can get up to €500 million each, but only if they plan at least 10 GWh and make cells suitable for EVs.

To me, it’s just a patch, and there’s no real industrial planning behind it.

Reason #3: Europe built its battery industry around NMC while demand shifted toward LFP.

The Korean players, mentioned above, are all focused on nickel-based chemistries. Only recently, they just added LFP chemistry to their portfolio and only LGES plan to add it to their Polish plant in Europe.

Northvolt bet on NMC, same for Verkor and ACC. Morrow was one of the rare companies to build its strategy around LFP (and LMNO).

It reflects on the capacity in chemistry.

Only 15 GWh of cell production capacity in Europe is LFP, according to BMI. The rest is NMC or NCA (Samsung SDI mostly).

LFP accounted for nearly half of global EV battery demand in 2024 and more than 55% in 2025. It’s mostly a Chinese story but the European OEMs increasingly chose the chemistry for mass-market EVs.

LFP reached 10% of Europe's EV battery demand in 2025, and nearly all of it came from China: roughly 30% as cells and 70% already installed in imported vehicles (Source: IEA).

Korean manufacturers remain Europe’s largest producers, and their share of Europe's EV battery sales fell from nearly 80% in 2022 to 60% in 2024. One of the reasons is the growing LFP adoption.

Reason #4: Europe built cell factories mainly for EVs while battery storage created a fast-growing market dominated by LFP cells from China.

92% of the current European capacity is for the EV market.

One market is growing faster than the EV market: energy storage. The EU installed 27.1 GWh of battery storage in 2025, up 45% from 2024 (Source: SolarPower Europe). It’s still smaller than the EV market but the dynamic is quite strong.

This market needs a different chemistry mix.

LFP reached 90% market share of global stationary storage installations in 2025 (Source: IEA). The main reason is cost and long cycle.

China dominates LFP cell manufacturing, and so, European storage projects source almost all of their cells from Chinese suppliers.

My final thought…

Europe built battery factories and continues to do so.

But Europe’s problem is timing, incentives, experience, and market fit.

Much of today’s capacity came from Korean companies that arrived before Brussels launched its main battery support programs. 9 years have passed since the launch of the first initiative, and 7 years since the first financial support, and the needle has moved a bit.

The European Commission is failing in its role.

It launched several programs (IPCEI, IF24 Battery…) and provided at least €8-10 billion in support for the battery value chain. New companies came to Europe, including CATL and Envision AESC. But it is still far from enough.

There’s no real long-term planning for an industrial strategy.

Then, you have the European companies struggling to ramp up and going bankrupt, especially for the biggest one. The large majority of the factories in Europe were built for nickel-based EV cells, while LFP started to take some market share in the EV market and became the default chemistry for energy storage.

China filled the gap, and $29 billion of batteries came from there in 2025.

For almost a decade, European policy and capital have rewarded announced capacity and seen it as the finality.

Big mistake! It was just the beginning.

P.S. When the time is right, there are other ways I can support you:

1. Become a paid subscriber

Get access to the Monthly Briefing and deeper research on the battery industry. I do the digging, so you spend less time following the market and more time using the information.

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Unless the Bureau of Industry and Security (BIS) grants an exception, they must keep it in the U.S. and direct all monthly sales to U.S. buyers.

For the moment, the rule will remain in effect for one year, until August 27, 2027.

The goal is to keep the critical battery raw materials inside the country.

U.S. black mass exports reached 100,667 tonnes in 2025, up 48.7% from 2024, according to S&P Global Market Intelligence.

Black mass is the dark material produced by shredding lithium-ion battery scrap or end-of-life batteries. It’s the final product of the pre-treatment phase during the battery recycling process.

It contains material from the cathode and anode, including lithium, nickel, cobalt, manganese, and graphite, depending on the chemistry.

Those materials can be recovered and reused.

They are critical for the battery industry, but there’s one issue.

Recycling does not end with black mass

Black mass is an intermediate product that requires further processing and refining before it can be converted back into battery materials.

A simplified form of the recycling chain for NMC batteries would look like this:

battery scrap/end-of-life batteries → black mass → recovered battery-grade salts or compounds → pCAM (precursor cathode active material) → CAM (cathode active material) → cell.

Nickel, cobalt and manganese recovered from black mass are refined into battery-grade products and used to make pCAM. Producers then add lithium to make CAM.

LFP follows a different recovery route because it contains no nickel or cobalt.

Mechanical pre-treatment and downstream material recovery are distinct operations that require different equipment and know-how. They are often referred to as pre-treatment and treatment, respectively. The two stages differ significantly in terms of Capex but are equally important.

Even though it is a valuable source of metals, refining black mass into battery-ready raw materials at commercial scale is challenging.

Li-Cycle is an example of a company that wanted to do both.

Its Spokes facilities produced black mass from battery scrap and end-of-life batteries. The Rochester hub was supposed to recover metals (lithium, nickel, etc.) from the black mass.

But the company was forced to pause construction in October 2023 due to cost overruns after escalating construction costs pushed the project well above its previous budget.

The Department of Energy closed a $475 million loan facility for the project in November 2024. Li-Cycle later disclosed that it had drawn no funds because it had not met the conditions for the first advance.

Li-Cycle filed for creditor protection in Canada in May 2025. Its US subsidiaries have filed for Chapter 15 protection.

Glencore acquired Li-Cycle’s assets in August 2025. The business now operates under Glencore Battery Recycling.

The next gap is pCAM and CAM

Recycling still has loops to close.

The recovered lithium, nickel and cobalt must flow back into battery material production, and that is America’s weak point.

China produced 85% of the cathode active material (CAM) used in EV batteries in 2025, according to the International Energy Agency (IEA). South Korea is the largest alternative production base, with smaller volumes produced in Japan and Europe.

The U.S has built cell plants faster than cathode plants. Fastmarkets estimates that $43 billion of cell, CAM and pCAM projects in the U.S. and Canada have been cancelled, paused or formally delayed since January 2025.

This leaves American and European recyclers with a specific problem.

As cell production outgrows precursor CAM (pCAM) and CAM capacity, recyclers run out of domestic buyers.

A battery recycler can produce battery-grade lithium, nickel or cobalt. Without a pCAM or cathode producer nearby, it sells abroad. Some of that material will return to the U.S as CAM.

North America still has little operational pCAM and CAM capacity. Fastmarkets said in July 2026 that the region faces a ‘startling lack’ of capacity at both stages.

China has the opposite problem

Since 2021, China has banned imports of battery black mass.

That changed in August 2025, when China opened the door to lithium-ion black mass meeting its technical requirements. In addition, starting in 2026, tariffs on lithium-ion black mass drop from 6.5% to 3%.

The reason is simple: China has the downstream capacity.

But, Benchmark Mineral Intelligence estimates that the country had 1.5 million tonnes of excess black-mass refining capacity in 2025.

China’s Ministry of Ecology and Environment says imported black mass will help meet demand for nickel, cobalt and lithium.

Feedstock is still a real problem

U.S battery recyclers need feedstock, like any recyclers in the world.

However, most electric-car batteries are still on the road, and their retirement is not expected until years after they were bought.

The IEA evaluates a lag of roughly 15 years between the rise in EV battery demand and the arrival of comparable battery volumes at end of life. Until then, recyclers have production scrap, damaged cells and recalls to fill up their factories.

Recycling capacity has grown faster than the supply of end-of-life batteries and production scrap. Some plants therefore operate well below nameplate capacity.

More black mass in the United States would let recyclers use the capacity they have already built. It would not guarantee they make money selling material back to manufacturers.

Producing battery-grade raw materials allows recyclers to capture more value.

South Korea is part of the U.S. loop

I support building local supply chains for strategic products such as batteries and semiconductors.

But the US does not need a fully domestic battery supply chain, at least not in the short term. The current push by the government also favors producers over end-users, which makes little sense.

North American EV sales fell by 20% in the first six months of this year, after the tax credit expired in September 2025. Energy storage is driving the battery demand in the U.S at the moment.

The Korean cell producers are converting part of their EV battery production lines into ESS lines.

Building and pushing for a full supply chain from lithium refining to battery recycling is not their priority. It’s for a simple reason. South Korea has a large battery industry, especially for nickel-based chemistries.

However, it still relies on China for precursors and other upstream materials. Its domestic LFP supply chain also remains limited.

South Korea is also important for U.S. subsidies. Materials sourced from qualifying Korean suppliers can help U.S.-made battery cells meet the sourcing rules required for the $35/kWh Section 45X production credit.

For US battery recyclers, the sequence is short. They collect, transport, sort and pre-treat the feedstock to produce black mass, then recover the battery metals (lithium, nickel, cobalt) through a hydrometallurgical process.

Then they need buyers for the recovered materials. U.S. pCAM and CAM capacity remains limited, so there are still few domestic buyers.

South Korea is one destination. Korean producers turn them into pCAM and CAM, then ship the cathode material back to U.S. cell plants such as those operated by LG Energy Solution or SK On.

South Korea already supplies CAM to battery factories in the U.S. POSCO Future M, for example, sends cathode material to Ultium Cells in the United States.

The new restrictions on black mass exports only delay exports.

The U.S. wants to stop black mass from leaving

The rule should help US recyclers secure more material. The capital expenditures for processing black mass are very high, and in this business, the plants need to operate at a high level of utilization.

Korean recyclers in Europe already work this way.

SungEel HiTech is one example. The Korean recycler operates pre-treatment plants in Hungary and Poland, where batteries are shredded into black mass. Its hydrometallurgical refining capacity is concentrated in South Korea. But, SungEel said it now plans to build hydrometallurgical capacity in Europe as restrictions make shipping black mass out of Europe more difficult

That is what the US wants to avoid, though I doubt South Korea is what bothers them. The target is clearly China.

Washington treats several of these raw materials as critical inputs to batteries, semiconductors and AI.

China lifted its black mass import ban in 2025. Imported material now can feed Chinese recyclers, potentially raising plant utilisation and keeping the metals under Chinese control.

The U.S restriction applies to black mass. Once that material has been refined into separate battery-grade products, it no longer falls under the black-mass definition covered by the order.

The new rule only pushes the export one step further down the value chain. The US does not have the value chain needed to hold the recycled raw materials at home.

P.S. When the time is right, there are other ways I can support you:

1. Become a paid subscriber

Get access to the Monthly Briefing and deeper research on the battery industry. I do the digging, so you spend less time following the market and more time using the information.

I am currently running a Summer offer (20% off):

2. Battery market reports

I’ve published 2 reports so far: The Battery Starter Kit, to help you get up to speed on the battery industry, and the CATL Company Profile, to help you understand how CATL operates and why it leads the market.

You can find them here: Battery industry reports

Global EV sales reached 9.6 million vehicles in the first half of 2026, up 2% year-over-year (source: BMI)

Energy storage battery shipments rose by 71% over the same period, according to SNE Research.

Battery manufacturers have been focused on one market for most of the last decade, the EV passenger car. However, it is not a linear growth story.

I believe the battery is a strategic product, one that ends up embedded in more and more of what people use every day.

It started with phones, then laptops, and now it is moving on to EVs, e-bikes, micromobility, drones, defense, and, of course, energy storage.

Energy storage is becoming the second market

Markets outside China (all combined) shipped more storage batteries than China in the first half of 2026. In June, Saudi Arabia deployed more large-scale storage than China.

China is still the largest market for Chinese cell manufacturers. The demand outside of China, and in particular the Middle East, is growing rapidly and is a significant opportunity for cell manufacturers.

The same goes for North America, where AI data centers are driving demand for energy storage batteries.

The GM and LG Energy Solution plant at Spring Hill was built to supply GM's EVs. In March, the joint venture said some of that capacity would be converted to LFP cells for LG Energy Solution's energy storage division.

Meanwhile, GM has been diversifying its battery R&D away from EVs. In June, it partnered with Peak Energy on sodium-ion cells for utility-scale storage, with GM making the cells in Michigan and Peak Energy incorporating them into its systems.

LG Energy Solution is doing something similar in Windsor, Canada, which is LG’s EV battery plant, built in partnership with Stellantis. Now that Stellantis has agreed to sell its shares back to LGES, it appears that LG Energy Solution is interested in not only making EV batteries but also batteries for the energy storage market.

SK On and Samsung SDI are also preparing their LFP chemistry for this market.

China got there first

Energy storage provides opportunities for any battery cell makers, but it is hard to compete against the Chinese players.

The 10 largest cell manufacturers in the first half of 2026 were Chinese (if we count AESC as Chinese).

CATL’s energy storage division is set to grow faster than its EV division, and the company is diversifying its storage product offerings while also launching sodium-ion cells closer to commercialization.

Korean cell makers are competing in a market in which Chinese suppliers have secured a significant volume share and customer base thanks to LFP chemistry.

But, they are more or less protected in the U.S market.

LG Energy Solution’s second-quarter results saw a significant jump in US production tax credits, which were more than double the company’s reported operating income, leaving it with a large negative number for the quarter.

China is set to drive demand in the commercial vehicle market

In June, China released a national plan targeting 40% new-energy vehicles in new commercial vehicle (mostly trucks) sales by 2030. The plan backs it with charging, battery swapping stations, and dedicated freight corridors.

Commercial vehicle sales are unlikely to reach the levels of the passenger car market, but because of the larger battery packs, the number of cells needed will still be substantial.

China has a goal and the infrastructure to support it, and it is following the same playbook that it used for the EV market.

Passenger cars will continue to dominate cell sales, but energy storage and commercial vehicles show that battery demand is also growing beyond the passenger-car market.

The Battery Chronicle Briefing #4 (June and H1 2026 data analysis) covers:

• The 33.5 GWh of energy storage capacity commissioned globally in June, led by Saudi Arabia

• More than 60 GWh of agreements announced at ees Europe

• Tesla’s energy storage deployment in Q2

• How GM, LG Energy Solution, and Ford are adapting North American battery plants to weaker EV demand

• H1 global EV sales and the widening gap between Europe, China, and North America

• China’s battery production, domestic EV installations, energy storage sales, and exports

• Global EV battery installations and energy storage battery shipments by manufacturer

• CATL’s sodium-ion rollout, direct cell sales, and battery-swapping expansion

• China’s 60-day supplier payment pledge

• Beijing’s target for new-energy heavy trucks

• The Jianxiawo permits that pulled lithium prices back down

• June price movements across cathodes, battery salts, electrolytes, anodes, and separators

• Europe’s Battery Booster Facility and CATL’s permitting delay in Hungary

• Battery distress cases involving Ascend Elements, Northvolt Heide, and Morrow

• Solid-state developments at QuantumScape, Factorial, and Dongfeng

• Q2 and H1 results from LG Energy Solution, SK On, Samsung SDI, and CATL

• Japan’s decision to replace its global battery capacity target with a sales target

• Tight supply for higher-grade LFP cathodes while lower-end capacity remains oversupplied

• June supply-chain developments in China, the DRC, South Africa, Korea, and Malaysia

Download the full Battery Chronicle Briefing #4 report below ⬇️

Read more

Its cells accounted for an estimated 6.7 GWh of the 20.4 GWh installed in passenger EVs sold that year, a 33% market share (Source: EV Sales, José Pontes).

CATL was in 6th place with 1.14 MWh or 5.6% market share.

In the first half of 2026, the ranking looked very different.

Panasonic ranked 6th with 22.7 GWh (3.7%) of a 608 GWh market, while CATL led with 40% market share (source: SNE Research).

NB: The 2016 ranking covered passenger plug-in cars only, while SNE’s 2026 data also include HEVs, buses and trucks. José Pontes of the EV Sales blog estimated that including buses would have placed BYD first and CATL third in 2016. The comparison is imperfect, but Panasonic’s decline is still evident.

China’s EV subsidy policy offers an obvious explanation.

China is now by far the world’s largest EV market. More than 13 million BEVs and PHEVs were sold there in 2025, accounting for about 60% of global electric car sales.

From late 2016 to June 2019, EVs could receive Chinese subsidies only if their batteries came from suppliers on a list approved by China’s Ministry of Industry and Information Technology (MIIT). Panasonic, LG Chem, SK Innovation and Samsung SDI never made the list.

Panasonic was effectively locked out of China’s subsidized EV market.

But that policy alone does not explain why Panasonic fell behind.

LG Energy Solution (spin-off from LG Chem) faced the same situation. It ranked 3rd with 8.6% market share in H1 2026. LG Energy Solution has a broader product range and a wider geographic footprint than Panasonic.

The more revealing number comes from June 2016.

Deutsche Bank counted 86 disclosed EV and energy storage battery contracts at Panasonic, including 41 underway. LG Chem had 40, and Samsung SDI around 39.

Of course, the number of contracts doesn’t always mean larger volumes.

So, what happened since then?

How Panasonic built its lead

Panasonic entered the EV era with 2 lithium-ion battery businesses that had spent 15 years competing with each other.

The first was Matsushita Battery Industrial, spun out of the parent company in 1979.

It developed a lithium-ion cell in 1994 and began mass-producing thin lithium-polymer cells in 1999. In 2006, it started making a high-capacity cylindrical cell with a nickel-based cathode.

The second business was Sanyo, founded in 1947 by Toshio Iue.

Iue had helped start Matsushita in 1918 alongside his sister and her husband, but left in 1946 and later founded a rival company.

Sanyo began lithium-ion production in 1994, the same year as Matsushita.

By 2008, Sanyo was the world’s largest producer of consumer lithium-ion cells, and Panasonic ranked 5th.

Japanese business publication Toyo Keizai estimated their combined share at around 40%.

Panasonic bought 50.19% of Sanyo in December 2009 for ¥403.8bn (about $4.5bn) and acquired the rest in 2011.

Why Tesla was worth it

In July 2009, Panasonic signed its first contract to supply lithium-ion cells for Tesla’s battery packs.

The initial term ran to the end of 2010 (Source: Tesla SEC filing). Tesla was 6 years old and was selling only one model.

The partnership deepened twice over the next 2 years.

In January 2010, Tesla and Panasonic announced that they were developing next-generation 18650 cells together. In November, Panasonic paid $30m for about 1.5% of Tesla. A year later, Tesla committed to buying enough cells for more than 80,000 vehicles over 4 years.

Panasonic produced them at Suminoe in Osaka, Japan, and reactivated a second Osaka plant at Kaizuka around 2014 as demand grew.

Then, the Japanese company moved part of its production inside Tesla’s Nevada factory.

Panasonic Energy North America was established in 2014, and in 2017, cell production began at Tesla’s own Gigafactory near Reno, with 2170 cylindrical cells.

Panasonic has been producing cylindrical nickel-based cells since 2006.

The Tesla program extended an existing specialization rather than pushing it into the prismatic or pouch formats its rivals were using.

I believe it was a pragmatic approach at the time. Cylindrical cells were standard and cheap to produce.

Deutsche Bank estimated in June 2016 that Panasonic’s Tesla-related automotive battery business had an operating margin of around 10%. Its non-Tesla automotive battery business ran at a low-single-digit margin.

Panasonic relied too much on Tesla

The Nevada plant is located within Tesla’s factory, and Panasonic manufactures cells there for Tesla products.

The dependence extended beyond Nevada. By June 2024, Panasonic said 99% of the automotive batteries produced at Suminoe and Kaizuka were shipped to North America.

That dependence became a liability.

At the end of January 2020, Tesla said it had added LG Chem (now LG Energy Solution) and CATL as battery suppliers.

Tesla had started producing Model 3s in Shanghai and later adopted CATL’s LFP cells for lower-cost versions.

Then, at its 2020 Battery Day, Tesla unveiled the 4680, a new cylindrical cell format measuring 46 mm in diameter and 80 mm in height.

The 4680 was larger than the standard 2170 cylindrical cell, giving Panasonic a natural opportunity to develop the new format.

Panasonic took the opportunity. At first, it moved quickly.

On 29 October 2020, CFO Hirokazu Umeda said the company had started working on the cell immediately after Battery Day and was preparing a prototype line.

In October 2021, Panasonic showed its first 4680 prototype.

By June 2022, prototype development was done. The pilot line had started running at the end of May, and Panasonic had begun sending samples to customers. At its Wakayama factory in Japan, the building was being renovated, and the production equipment was being built.

The company planned to start mass production there during the fiscal year ending March 2024.

NB: When I refer to a fiscal year in this article, I mean Japan’s fiscal calendar, which runs from April to March.

But the date slipped.

In May 2023, Panasonic pushed the start of production back to between April and September 2024, saying it wanted to improve the cell’s performance and make it more competitive.

In September 2024, Panasonic said the preparations at the Wakayama factory were finished. Samples had gone to automakers, but production still depended on their final approval.

Tesla was also struggling with the format, particularly the dry-electrode process, but still moved faster than Panasonic.

It began delivering Model Ys with Tesla-made 4680 cells and structural battery packs in the second quarter of 2022. In December 2023, Reuters estimated that production at the Texas plant was enough for about 24,000 Cybertrucks a year, roughly a tenth of what Tesla’s targets needed.

On the Q4 2023 earnings call the next month, Tesla’s vice president of supply chain, Karn Budhiraj, said 4680 production was running ahead of the Cybertruck ramp up.

Production increased through 2024.

Tesla produced over 50% more 4680 cells in the second quarter than in the first and began testing its first Cybertruck fitted with in-house dry-cathode 4680 cells. It announced its 100 millionth cell in September.

By January 2026, Tesla reported 40 GWh of installed annual 4680 capacity at the Austin plant. The company said it was making dry-coated anodes and cathodes there and had started building 4680 packs for some Model Ys.

LG Energy Solution was also moving into Tesla’s 4680 supply chain.

Korean outlet ETNews reported in 2024 that Tesla had placed an order for LGES 4680 cells, with production planned at its Ochang plant. In March 2025, Korea JoongAng Daily reported that LGES was supplying 4680 cells to Tesla. LGES has since expanded the wider 46-series program, with an order backlog of more than 440 GWh at the end of April 2026.

Panasonic was still waiting.

According to Nikkei, Panasonic told investors in July 2025 that final customer feedback was close and that full production would start by the end of March 2026. But in May 2026, the newspaper reported that the deadline had passed and Panasonic still had no confirmed order from a key customer.

Panasonic had spent more than 5 years developing the cell and had refurbished the Wakayama factory to produce it.

Over those same years, Tesla worked through its own production problems and built its own 4680 production capacity.

Panasonic narrowed the market it could serve

The 4680 delay was one problem.

However, Panasonic had already decided to cut the share of the battery market it controlled directly.

In April 2020, Panasonic moved the automotive prismatic battery business it had acquired with Sanyo into Prime Planet Energy & Solutions, a joint venture with Toyota. Toyota took 51%, and Panasonic kept 49%.

PPES ceased to be a Panasonic subsidiary. Toyota appointed 3 of PPES’s 5 directors, including the president.

Panasonic’s directly controlled automotive battery business became centered on cylindrical cells, with North America as its main market.

The market increasingly shifted toward products Panasonic no longer controlled directly.

In 2025, lithium iron phosphate (LFP) accounted for more than 55% of EV batteries deployed worldwide, almost all of them in prismatic cells. China represented 60% of global deployment (Source: IEA 2026).

Tesla first used LFP in some standard-range models in China, then expanded it to other markets, while retaining nickel-based cells in longer-range vehicles. Panasonic competes with LG Energy Solution and Tesla’s own 4680 line.

Panasonic Energy has no directly controlled LFP product for that part of the market.

Panasonic is rebuilding from a smaller base

Panasonic has started adding customers beyond Tesla.

It signed a multi-year supply agreement with Lucid in 2022, and its 2170 cells power the Lucid Air and Gravity. In November 2025, it added Zoox, Amazon's robotaxi subsidiary, with deliveries due to start in early 2026.

Its largest new supply programs are in Japan.

Panasonic Energy plans to start supplying Mazda in 2027. The production capacity allocated to the partnership is expected to reach 10 GWh a year by 2030.

Panasonic will also supply Subaru from 2027. Capacity for that program is planned to reach 20 GWh a year by 2030, including 4 GWh at Suminoe and 16 GWh at the new Oizumi factory.

All four agreements concern cylindrical lithium-ion cells. They reduce Panasonic’s dependence on Tesla.

Panasonic is also moving some of its capacity beyond cars.

Panasonic has already converted an EV battery production line at its Osaka factory to make lithium-ion cells for data centers, with shipments starting in April 2026. It also plans to produce supercapacitors at the site. At its Kansas factory, Panasonic plans to introduce a production line for data-center applications, with mass production scheduled for the fiscal year ending March 2029.

Panasonic plans to continue using nickel-based chemistry and has said it does not intend to produce LFP cells.

China’s subsidy policy was one factor in Panasonic’s decline. In addition, the Chinese market increasingly favored prismatic cells while Panasonic remained focused on cylindrical cells.

LG Energy Solution faced the same exclusion and diversified its business outside China. It kept its pouch business, expanded in cylindrical cells, and agreed with GM to develop prismatic cells.

Panasonic tied most of its growth in cylindrical automotive batteries to Tesla.

The relationship delivered volume and margins, but also tied years of investment to Gigafactory Nevada.. It reinforced Panasonic’s focus on cylindrical nickel-based cells.

But Tesla then qualified LG Energy Solution and CATL as suppliers, adopted LFP for standard-range vehicles, and built its own 4680 line.

Panasonic is still one of the most experienced cell manufacturers in the industry, and its recent contracts show automakers still want its cells. It started widening its customer base after the market had already moved to other suppliers and other chemistries.

In the second quarter of 2026, Panasonic’s automotive battery business made ¥14.6bn (about $90m) in adjusted operating profit on ¥141.7bn (about $871m) of sales, a 10.3% margin. LG Energy Solution reported ₩113.3bn (about $79m) in operating profit, a 1.5% margin, while Samsung SDI’s battery business made ₩159.3bn (about $111m), a 4.5% margin.

NB: Panasonic reports its automotive battery business, LG Energy Solution reports at company level, and Samsung SDI’s battery division includes applications beyond EV batteries. US production credits also affected all 3 results.

Even with those differences, Panasonic reported the highest margin of the 3 companies in Q2 2026.

Panasonic’s narrow focus has cost it market share, but it has not stopped the company from making money. It remains focused on cylindrical nickel-based cells, a product it knows how to manufacture profitably.

Panasonic still has demand from automakers and is now targeting data centers as well. Its weakness is the lack of alternatives if demand shifts away from its preferred format or chemistry.

For now, Panasonic’s specialization still makes money.

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China is putting the tax back on lithium-ion batteries.

From 1 September 2026, cells and packs will carry a 2% consumption tax, rising to 4% in September 2027. Sodium-ion, solid-state battery and fuel-cell products stay exempt through the end of 2028.

Lithium-ion is the biggest of several categories losing the break, along with mercury-free primary, nickel-metal-hydride, lithium primary and all-vanadium flow batteries.

The finance ministry, customs, and the tax administration set out the policy on 16 July.

The exemption is not automatic.

A sodium-ion solid-state battery or fuel-cell product gets it only if it meets its national standard and has a test report from a state-accredited lab. Without a national standard, it does not qualify.

Lithium-ion batteries' break date is 1 February 2015, when China imposed a 4% consumption tax on batteries and coatings to promote energy conservation and environmental protection.

It exempted 7 battery categories, including lithium-ion.

Lead-acid got only a deferral, then paid the 4% from 2016. Lithium-ion kept its exemption for more than 11 years.

The new split reads as Beijing treating lithium-ion as mature enough to pay, while it gives the newer ones more time.

China produced 1,068.9 GWh of EV and energy storage batteries in the first half of 2026, up 53.3% from a year earlier, according to the China Automotive Battery Innovation Alliance (CABIA).

The low end still runs in oversupply, with a price war Beijing has spent the past year trying to cool, even as some advanced cell lines run tight. Taxing the mature end of the industry fits that campaign.

The number starts small

Sina Auto estimated the effect at 400 to 1,200 yuan (about $60 to $180) per battery-electric car at the 2% rate, depending on battery size and price.

On a 150,000-yuan car, that is 0.3% to 0.8% of the price. The rate doubles in 2027.

At 2%, it is unlikely to decide many purchases on its own.

The tax gives Beijing steady money from an industry big enough to pay it, and it ends lithium-ion’s long exemption.

Who actually pays

The producer or importer pays the tax when the battery is sold, imported, or transferred into a non-battery product.

The tax applies once across the production chain.

A pack maker can deduct the tax already paid on purchased cells. If it makes the cells itself, no tax is due when those cells move into the pack.

The final tax point depends on where the pack goes. A supplier pays when it sells the pack to a carmaker. If the same taxpayer makes the pack and installs it in a vehicle, the tax is due when the pack is installed in the vehicle.

The pressure will not fall evenly.

Each producer’s exposure depends on its domestic sales, export share, deductions and customer contracts. Larger suppliers may have more leverage to pass the tax through, while smaller producers may have to absorb more of it.

The export rebate is the bigger lever

The policy keeps the existing consumption-tax refund and exemption for qualifying exports, leaving domestic sales and imports to bear most of the new tax.

A separate move squeezes exports.

China cut the battery export VAT rebate from 9% to 6% on 1 April 2026, and drops it to zero on 1 January 2027.

Against the rate before April, that takes away 9 points of rebate.

Both moves reduce tax support for established battery products, including lithium-ion: one principally on domestic sales and the other on exports.

China still exported 181.3 GWh of EV and energy-storage batteries in the first half of 2026, up 42.5% from a year earlier, according to CABIA. The first cut, in April, barely moved the total.

The exports keep going, despite the rebate reduction.

What the exemption is paying for

Qualifying sodium-ion, solid-state and fuel-cell products pay nothing, while lithium-ion pays 2% from September 2026 and 4% from 2027.

Sodium-ion has the clearest near-term path into energy storage and cheaper cars.

CATL says its Naxtra sodium-ion battery will reach full mass production by the end of 2026, and HiNa says it operates a GWh-scale cell line with products already selling in volume.

Solid-state battery is the longer bet, aimed at higher-end cars first.

GAC aims for cars in 2026, SAIC for mass delivery in 2027, and CATL and BYD talk of small batches or demos around 2027.

CATL chairman Robin Zeng rates the current solid-state battery technical roadmap at level 4 out of 9, with level 9 representing mass-production readiness. He also says the chance of reaching million-vehicle deployment by 2030 is very small.

The exemption runs until 31 December 2028. That gives the newer technologies 28 months without the tax after lithium-ion starts paying it.

Sodium-ion may be able to use that time. Solid-state is unlikely to be ready at scale.

The current rules end the break in 2029, though Beijing can change them before then.

P.S. When the time is right, there is another way I can support you:

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On December 18, 2024, CATL brought financial lessors, insurers and carmakers to Xiamen, China, to expand its passenger-car battery-swapping business under the Choco-Swap name.

CATL launched the same basic model under the EVOGO brand in 2022.

The 2024 event broadened it into a cross-brand system involving standardized batteries, more carmakers, leasing, financing, and insurance.

It had signed subscription deals with 30 companies covering 107,500 packs.

China Development Bank Leasing and CMB Financial Leasing agreed to finance cars sold without their batteries.

In a battery-swap system, the driver buys the car without a battery and rents a pack instead. When it runs low, they pull into a station and trade it for a charged one in minutes.

In the traditional model, A cell maker is usually paid once, when the battery leaves the factory.

That day, CATL set up a business to keep earning from it afterward.

The battery bank

For passenger cars, CATL built 2 standard pack formats, the #20 and the #25.

Each is a fixed size across the models that use it. A driver pulls into a Choco-Swap station, a robot swaps the empty block for a full one, and the car leaves in about 100 seconds.

Qiji, the name of its battery swapping network for heavy trucks, does the same.

By June 30, 2026, the Choco-Swap passenger network had reached 2,000 stations across 180 cities, up from 1,020 six months earlier (Source: CnEVPost).

The driver rents the pack rather than buying it, and the battery remains a financed asset under the leasing structure.

CATL says drivers can rent the battery, buy it outright, or use a buyback service.

For example, GAC's Aion UT Super costs about $6,900 without the battery, then about $70 a month to rent the pack (Source: Gasgoo, November 2025).

The driver avoids owning a battery that loses value over time. The monthly rent still has to cover that depreciation.

This is why the lessors and insurers came to Xiamen.

Someone has to finance a battery the driver does not own, and price a part that wears out.

CATL says it tracks every swap pack down to the cell, using historical and real-time data to monitor degradation. That data provides a better basis for estimating the battery’s remaining life and residual value, which are central to financing it as a separate asset.

The standard pack does more than enable swapping.

Changan, Chery, GAC and the rest have to build their cars around CATL’s dimensions and swap mechanism.

Every compatible model sends more drivers to the stations, and every new station makes the format worth adopting for the next carmaker.

If that network reaches enough density, CATL’s pack starts to function as infrastructure.

Changing the supplier would then mean redesigning the vehicle and giving up the swap network.

The energy business

At its Super Tech Day on April 21, 2026, CATL added charging to its battery-swap network.

Every Choco-Swap and Qiji station will carry a Shenxing supercharger, and CATL says its latest Shenxing battery charges from 10% to 98% in 6 minutes and 27 seconds.

It wants 4,000 combined stations by the end of 2026 and more than 100,000 replenishment points by 2028, with Changan, Chery, GAC, Seres, SAIC-GM-Wuling and BAIC.

The new #26 block uses an 800V architecture and has a capacity of 75 kWh, extending the standard to larger cars.

That widens who pays.

Without chargers, a swap station serves only drivers with a compatible swap car. Adding superchargers lets the same site serve any electric vehicle that pulls in.

One grid connection now carries 2 revenue streams.

CATL says the charging gear costs a fifth as much as a standalone system because charging and swapping share the substation and power modules.

A cell sale pays once, at the gate.

The swap system generates recurring revenue from battery rent, battery swaps, and electricity.

How much reaches CATL, rather than its station and finance partners, is the difference between owning that recurring-revenue business and supplying its hardware.

The whole life of the pack

CATL also runs businesses around batteries already on the road.

NING Service, its aftermarket brand, ran about 1,200 service shops and 11 experience centers by the end of 2025, selling inspections, repairs and health checks.

CATL also owns the recycling subsidiary Brunp.

In 2025, it processed 210,000 tonnes of spent batteries and recovered 24,000 tonnes of lithium salts (Source: CATL 2025 annual report).

CATL now operates across manufacturing, replenishment, aftermarket service, and recycling.

In the traditional cell-sale model, most revenue is concentrated at manufacturing.

Neither rival has shown a profitable national network

NIO and Gogoro have run battery swapping longer, and neither has shown a profitable national network.

NIO is a Chinese premium electric-car manufacturer that has built the world’s largest passenger-car battery-swap network. Drivers can buy a NIO without the battery, rent the pack through its battery-as-a-service plan, and swap it at NIO stations.

The model is close to Choco-Swap, except NIO built the network to support its own cars, while CATL wants several carmakers to use the same pack format.

NIO ended 2025 with 3,676 stations and passed 100 million swaps in February 2026. It lost about $2.1 billion for the year and does not report the swap network’s profit separately.

Its CFO put break-even at 60 to 70 swaps a day.

On May 1, 2026, NIO set a record of 170,585 swaps across 3,839 stations, about 44 each.

Shanghai is the exception: 183 stations there ran more than 9,000 swaps a day and neared profitability, 7 years after NIO opened its first station.

A “quiet” station leaves 2 assets underused: the site and the spare packs inside it, while financing and depreciation continue.

Gogoro applies the same basic model to electric scooters.

The Taiwanese company sells vehicles that use standardized removable batteries, while subscribers exchange depleted packs at a dense network of cabinets.

Gogoro has run its network since 2015 and ended 2025 with 665,000 subscribers.

Battery swapping is now its biggest revenue line at USD 149 million, ahead of USD 132.5 million from hardware. It still lost USD 80.8 million, with its energy arm only nearing profit (Source: Gogoro FY2025 results).

The bet

By the end of 2025, CATL said Choco-Swap had reached profitability in Chongqing.

CATL also has what NIO and Gogoro lack: a profitable battery business to back its network. It made about $10 billion in 2025, while NIO lost about $2.1 billion.

CATL can carry a long infrastructure ramp with far less pressure on its core business.

CATL does not need to finance every station itself.

In June 2026, it launched Swaptopus, a European truck-swapping venture with Octopus Energy, with the first UK hubs planned for 2027.

Swaptopus says the wider European rollout could attract more than £30 billion in private investment, giving CATL a route to expand without carrying the full infrastructure cost itself.

CATL wants more of the money generated after the battery sale.

The network does not have to rely on swap fees alone. Removing the battery lowers the car’s upfront price and can expand demand for CATL cells. Standard packs also make CATL harder to replace once carmakers and stations adopt the format.

The swap-and-charging network can increase CATL’s cell sales now and give it a share of downstream battery revenue later.

P.S. When the time is right, there is another way I can support you:

I’ve published 2 reports so far: The Battery Starter Kit, to help you get up to speed on the battery industry, and the CATL Company Profile, to help you understand how CATL operates and why it leads the market.

You can find them here: Battery industry reports

• GB 38031-2025 covers the traction battery, the cell, and the pack.

• GB 18384-2025 covers the whole electric vehicle (EV).

Both replace the 2020 versions.

The battery standard is the one that changes the mandatory test conditions for cells, packs, and systems.

What the thermal-propagation test now requires

Under GB 38031-2025’s thermal-propagation test, a pack, system, or tested vehicle fails if it catches fire or explodes after a target cell is driven into thermal runaway.

A thermal-event alarm must follow within 5 minutes.

The revised method also includes internal heating as a means of triggering thermal runaway, in addition to external heating and nail penetration.

The internal-heating method uses a prepared test cell with an embedded heating pad, so it is a trigger method rather than a simulation of a real internal short circuit.

The smoke rule differs by test level:

• For a pack or system, the manufacturer must provide technical documentation demonstrating that smoke released before the thermal-event alarm and during the following 5 minutes does not pose a danger in the passenger compartment.

• For a vehicle-level test, no smoke may enter the passenger compartment before the alarm or during the following 5 minutes.

The standard’s smoke requirement is limited to that defined window.

Appendix C requires at least 2 hours of observation and does not end the test until all monitored points are at or below 60°C.

The old battery rule was weaker.

GB 38031-2020 required a thermal-event warning at least 5 minutes before thermal propagation could endanger the passenger compartment.

But GB 18384-2020 already required a conspicuous audible or visual warning to the driver when the REESS, the vehicle’s rechargeable energy-storage system, was about to undergo a thermal-runaway safety event.

GB 18384-2025 clarifies the connection: when the battery sends the GB 38031 thermal-event signal, the vehicle must alert the driver with both light and sound.

The other two battery tests

Two other additions target fast charging and underbody damage.

Fast-charge durability.

The requirement applies to cells that charge from 20% to 80% state of charge (SOC) in 15 minutes or less, except cells that can only charge from an on-board energy source.

That equates to a 2.4C average over that SOC window.

The cell completes 300 partial fast-charge cycles with prescribed rest intervals, then undergoes an external short-circuit test. It must not catch fire or explode.

Bottom impact.

The test applies to an underfloor battery pack or system, or its corresponding whole vehicle. N-category vehicles, meaning goods vehicles such as vans and trucks, are exempt if the pack or system has at least 200 mm of ground clearance at full load.

A 10 kg impactor with a 30 mm #45-steel hemispherical head strikes three manufacturer-defined risk points on the underside of the battery, covering the front, middle, and rear. Each impact carries 150 J.

After a 2-hour observation period, the test object must show no visible leakage, no housing crack, no fire or explosion, and retain the required insulation resistance.

CATARC, the China Automotive Technology and Research Center, says the test was developed from accident data on underbody impacts and road obstacles.

Not every car is on the same deadline

GB 38031’s own implementation clause is explicit:

• New vehicle models applying for approval must comply from July 1, 2026.

• Models already approved for sale move on to the requirement from July 1, 2027.

• GB 18384 uses the same structure.

The transition rules apply to vehicle model approvals. They do not require carmakers to modify or recall vehicles already sold or registered. Recalls remain governed by separate vehicle-defect rules.

Who moved first

CATL said it was the first company to pass.

On April 29, 2025, CATL said that CATARC’s New Energy Vehicle Testing Center had issued two GB 38031-2025 reports on April 27 for its Qilin battery.

One covered a cell, and one covered a pack.

On May 10, CATL said CATARC had issued reports for five products the previous day and that its mass-produced brands across passenger and commercial vehicles had passed the tests.

On May 27, 2025, BYD said its Blade Battery and Flash-Charge Blade Battery had passed all test items under GB 38031-2025 and received certification from CATARC Automotive Test Center.

By the end of June, Chinese business and technology outlet Huxiu had counted 16 OEMs that had publicly announced compliance with GB 38031-2025.

Huxiu also noted four carmakers publicly claiming performance above the standard.

What the concentration data shows, and doesn’t

In May 2026, the top 10 battery makers accounted for 93.8% of China’s domestic EV battery installations, with CATL at 46.14% and BYD at 16.56%. (Source: CABIA)

37 battery companies supplied batteries installed in vehicles through May 2026, compared with 52 across full-year 2025 and 72 in 2020.

The market had already concentrated well before July 2026, so these figures do not prove that the standard caused it. The rule is likely to favor companies with more mature cell, pack, and battery management system engineering.

What the vehicle standard adds

GB 18384-2025 includes several vehicle-level revisions.

Three matter most for battery safety:

• A driver-accessible physical device that can cut propulsion-system power with one action when the vehicle is stationary and neither charging nor discharging.

• A vehicle-level bottom-protection test requires a towed vehicle to pass over a fixed 150 mm solid #45-steel hemispherical barrier at 35 km/h, with 30 mm overlap. The barrier is positioned at a vulnerable point within ±150 mm of the REESS centreline.

  After the test, the REESS and high-voltage connectors must still meet IPXXB protection requirements. There must be no electrolyte leakage within 30 minutes, no fire or explosion within 2 hours, and the vehicle must retain the required insulation resistance.

• A revised driver warning linked directly to the battery’s GB 38031 thermal-event signal.

Clause 5.4 establishes the link between them: the traction battery in the car must comply with GB 38031.

The battery standard sets the floor for the cell and the pack. The vehicle standard covers how the car protects its occupants.

The standard raises performance in defined abuse tests. But it does not claim that every collision, external fire, multi-cell event, or untested failure mode can no longer produce a battery fire.

What the standard achieves, and what it doesn’t yet

Direct global rankings are a poor fit because the rules use different triggers and test sequences.

FMVSS 305a, a US federal vehicle-safety standard, becomes mandatory for U.S. light vehicles on September 1, 2027. It requires no fire or explosion from impact through one hour after its specified crash-test sequence, and no electrolyte leakage, rupture, venting, fire, or explosion in specified vehicle-control tests.

Separately, FMVSS 305a directly requires a thermal-event warning to the driver within 3 minutes of onset, using audible and visual signals that remain active for at least 5 minutes.

The UNECE R100 rule, a UN vehicle regulation, employs a different thermal propagation test structure. None is the same test as China’s.

New battery-pack programs now face a higher validation burden. A cell or pack supplier must support compliance with the battery requirements of GB 38031.

The OEM must demonstrate compliance with the vehicle-level requirements in GB 18384, including the warning, physical cut-off, and underbody tests.

But the battery pack, BMS, and vehicle controls now have to be validated together.

This raises the bar for suppliers seeking new EV business. Companies with weaker pack engineering or incomplete testing may need to redesign, work with a stronger partner, or lose future contracts.

China has raised the safety bar for thermal propagation. That is good news for the industry.

If EVs are to keep growing, safety cannot be an afterthought.

P.S. When the time is right, there is another way I can support you:

I’ve published 2 reports so far: The Battery Starter Kit, to help you get up to speed on the battery industry, and the CATL Company Profile, to help you understand how CATL operates and why it leads the market.

You can find them here: Battery industry reports

Once again, in May, the biggest battery investments went to energy storage, and some of the capacity was originally built for EVs.

Ford committed $2 billion to repurpose a paused EV battery plant in Kentucky to manufacture battery energy storage.

The plant is designed to produce at least 20 GWh per year, with first customer deliveries planned for late 2027. The demand signal came early: a five-year framework with EDF Power Solutions.

The market context was clear.

North American EV sales fell 25% year on year in the first five months of 2026, while Ford was resetting its EV programs and building an energy storage business.

The pattern appeared elsewhere, in different forms.

SK On took full ownership of the Tennessee plant after dissolving its Ford joint venture and is preparing it for energy storage alongside automotive cells.

Panasonic, after a 44.6% decline in operating profit, committed ¥350 billion (~$2.3B) to data-center backup power cells. Kureha reset its PVDF binder plan after EV-related demand fell short of its assumptions.

The buyers on the other side sign real contracts.

In the UAE, Sungrow signed a 7.5 GWh supply agreement for Masdar's round-the-clock project in Abu Dhabi.

In Australia, the Smoky Creek and Guthrie’s Gap projects in Queensland reached financial close after Rio Tinto agreed to buy 90% of their solar output and battery-storage capacity for 20 years to help supply its Gladstone aluminum operations.

The repricing has started, too.

Battery-grade lithium carbonate reached a 2.5-year high, up about 70% this year, and the increase is moving through the rest of the materials chain.

Energy storage is becoming a real second outlet for capacity planned for EVs. The market is growing faster, and all the players are betting big on ESS, especially Chinese players.

The Battery Chronicle Briefing #3 (May analysis) covers:

• Ford’s $2B Kentucky conversion and framework agreement

• SK On’s exit from the Ford JV and the Tennessee plant repurposing

• Panasonic’s data-center energy storage pivot

• International GWh-scale energy storage deals: Abu Dhabi, Queensland, Chile

• China’s capacity expansion against MIIT overcapacity warnings

• China’s May production vs EV installations and exports

• Gotion’s sodium-ion family and the 261 Wh/kg claim

• The lithium price surge and the materials chain repricing

• Nickel and cobalt supply shocks

• Semcorp’s new separator plant and SKIET’s China exit

• Korea’s LFP cathode pivot (L&F, POSCO Future M)

• Recycling: Korea’s used-battery bill, SungEel’s LFP pilot, Moment Energy’s Series B

• Japan’s OCCTO auction and the 6-hour duration floor

• Kureha’s PVDF reset and Sumitomo’s Ambatovy exit

• Morrow’s bankruptcy

• Battery projects in Indonesia and Saudi Arabia

• Tesla’s Grünheide cell expansion

• May global EV sales by region and Chinese brands’ European growth across all powertrains

Download the full Battery Chronicle Briefing #3 report below ⬇️

Read more

China’s battery makers have put a number on how fast they will pay SME suppliers.

On June 29 2026, two battery industry bodies announced a payment initiative.

It calls for materials and components to be accepted within 7 working days in principle, and for small and medium-sized (SME) suppliers to be paid within 60 calendar days of delivery or acceptance.

It also advocates all-cash payment to SME suppliers, while seeking to reduce the use of commercial acceptance bills and electronic payment vouchers. (source: Xinhua)

The two bodies are the China Automotive Power Battery Industry Innovation Alliance (CABIA) and the China Energy Storage Alliance (CNESA).

11 battery companies responded, including CATL, CALB, EVE Energy, Sunwoda, and BYD’s battery arm.

The Ministry of Industry and Information Technology (MIIT) backed the move the same day. (source: CnEVPost)

Why Beijing moved against late payment

China’s revised SME-payment regulation, effective since June 1, 2025, requires large enterprises to pay SMEs within 60 days of delivery.

Where payment is conditional on acceptance, the 60-day period starts when the buyer accepts the goods.

Contracts may set another reasonable term consistent with industry norms and trading practice. The battery initiative adds sector-specific guidance on acceptance, payment instruments and cash settlement. (source: State Council regulation)

The initiative comes amid wider government pressure to curb destructive competition.

The 2025 figures show strong demand and weak margins.

China produced 1,755.6 GWh of EV and storage batteries in 2025, up 60.1% year-on-year. Total battery sales reached 1,700.5 GWh. Of that, storage-battery sales reached 499.6 GWh, up 101.3%. (source: CABIA)

Global pack prices continued to fall as China’s battery volumes rose.

BloombergNEF estimated that LFP battery packs averaged $81/kWh across end-use segments in 2025, and stationary storage battery packs averaged about $70/kWh, down 45% from 2024.

A November 2025 study by the China Chemical and Physical Power Industry Association found that only 16.7% of LFP producers were profitable. Its cost index used audited January-to-September data from seven leading producers. (source: Sina Finance)

By late 2025, suppliers were pushing back. Chinese media reported that Hunan Yuneng had sought a 3,000 yuan-per-ton increase in LFP processing fees from January 2026, while AnDa was reported to be considering the same. Longpan and Wanrun were still negotiating with customers.

The industry association had published a cost index and a collaborative-action proposal aimed at rebuilding pricing discipline after a period of below-cost competition. (source: Securities Times)

The higher fees were an attempt to restore margins after years of losses and aggressive pricing.

How the discount gets financed

A price cut has to be paid for somewhere.

Price cuts reduce what the buyer pays. Longer payment terms reduce how quickly the buyer must fund those purchases.

The first hits supplier margins. The second pushes working-capital pressure onto supplier balance sheets.

When a dominant buyer stretches its terms, the supplier carries the working-capital gap unless it discounts or finances the receivable. In that case, the finance provider advances cash, which the buyer repays at maturity.

At 200 days, the buyer has effectively been using supplier credit or supply chain finance for more than 6 months.

This is why the initiative seeks to reduce commercial acceptance bills and electronic payment vouchers.

The regulation explicitly states that commercial bills and electronic receivables certificates must not be imposed on SMEs or used to disguise extended payment. (source: State Council regulation)

The 60-day rule loses force if a buyer uses a non-cash instrument on day 60 and the supplier must wait or pay to convert it to cash.

What months of receivables do to a supplier

The pressure lands on the companies least able to take it.

At the end of 2025, CATL reported RMB37.223 billion in supplier finance payables, including electronic debt certificates and reverse factoring. Suppliers had already received RMB30.728 billion from finance providers, equal to about 83% of the total.

CATL says its obligation under the certificates is unconditional and irrevocable. It pays the equivalent amount on the payment date. Suppliers can transfer or finance the certificates before maturity.

The annual report does not disclose the maturity dates or when each supplier received cash.

LFP cathode suppliers’ FY2025 results diverged sharply.

Wanrun New Energy’s LFP gross margin rose from 0.08% in 2024 to 4.09% in 2025, while LFP sales volume rose 64.3% to 375,068 tonnes. It still reported an attributable net loss of 458 million yuan, around $64 million. (source: Wanrun FY2025 annual report)

Dynanonic reported an attributable FY2025 loss of 821 million yuan, while AnDa Technology lost 257 million yuan. Hunan Yuneng reported 1.277 billion yuan in attributable net profit, or roughly $179 million. (source: company FY2025 annual reports)

A loss-making supplier has less cash to absorb long receivables and keep funding process development and R&D. Money that could fund equipment, engineers, or new material work remains tied up in receivables.

MIIT said that high R&D requirements and long payment cycles were tightening upstream suppliers’ cash positions and weakening their ability to invest in technology. (source: Xinhua)

Price pressure and slower payment leave less money for new materials and process improvements.

BYD’s payment record

BYD offers a documented example.

Bloomberg calculated its payment period at 275 days in 2023, up from 198 days in 2021. This is an accounting measure and not the cash wait for every supplier.

BYD uses DiLink, its supply-chain-finance platform, in supplier payments. BYD and its member companies issue DiLink electronic debt certificates to suppliers. Suppliers can hold a certificate of maturity, transfer it, or finance it earlier.

The last publicly disclosed cumulative DiLink issuance figure was more than RMB400 billion in May 2023, about $55 billion at the time. (source: Bloomberg)

One supplier’s filing spelled out the terms.

In a June 2026 Shenzhen Stock Exchange response, Shanghai Willtai, which controls 51% of Zijiang New Material, disclosed BYD-group terms for its subsidiary: invoice receipt, month-end plus 30 days, then an eight-month DiLink instrument.

The filing said Zijiang continued to record BYD-group balances settled through DiLink as receivables. Those receivables were aged beyond 6 months but within one year. Its receivables from other major customers remained within 6 months. (source: Shanghai Willtai filing)

In November 2024, a screenshot of an email circulating online, attributed to BYD executive He Zhiqi, asked suppliers for a 10% price cut starting in January 2025. Reuters could not independently verify the document. BYD said annual price-reduction targets were non-mandatory and negotiable. (source: Reuters)

These terms show why payment instruments sit at the center of the new initiative.

FinDreams Battery, BYD’s battery arm, is among the 11 companies that responded.

The 11 firms have their own reason to pay

CATL called the commitment a supply-chain matter. It said high-quality growth depends on a healthy supply chain and that protecting suppliers is part of its responsibility.

Cell makers have a commercial interest in keeping key suppliers financially healthy.

Cell makers depend on suppliers for material and manufacturing improvements. Longer payment cycles tie up cash in receivables and leave less for product development and equipment.

Faster payment gives viable suppliers more room to invest through the price war. As weaker competitors exit, the remaining suppliers could gain pricing power.

The automakers already ran this test

The carmakers tried this a year ago.

In June 2025, 17 automakers, including BYD, pledged the same 60-day term. (source: CnEVPost).

By February 2026, CAAM said its survey found an average supplier payment period of about 54 days, with most of the 17 automakers below 60 days.

CAAM also identified different starting points, including acceptance, reconciliation, invoice receipt, and vehicle validation. Those choices can extend the time between delivery and cash.

Battery makers now face the same scrutiny.

The measure now is cash reaching SME suppliers within 60 days of delivery or acceptance.

A cathode or anode supplier with cash keeps improving its materials and processes, and those gains pass on to cell makers, carmakers, and ultimately the people who buy the cars and storage systems.

P.S. Whenever you’re ready, here are three ways I can help:

1. Battery industry reports

I’ve published two so far: The Battery Starter Kit, to help you get up to speed on the battery industry, and the CATL Company Profile, to help you understand how CATL operates and why it leads the market.

You can find them here: Battery industry reports

Last month, I spent 3 days at the China International Battery Fair (CIBF) in Shenzhen, from May 13 to 15.

It was my first CIBF. You only realize how big the exhibition is when you walk through it.

Organizers reported nearly 3,200 exhibitors across 14 halls and more than 280,000 square meters. They also reported cumulative visitor traffic of more than 400,000 person-visits over the 3 days.

Before the exhibition opened, Wang Zeshen, secretary-general of the China Industrial Association of Power Sources, called on the industry to move away from price wars and focus on value.

China shipped 1.889 TWh of lithium-ion batteries in 2025, equal to 82.8% of global shipments. It also sold 16.49 million new-energy vehicles, mainly BEVs and PHEVs.

But overcapacity has become more structural. Older and lower-specification capacity remains abundant, while advanced large-format storage cells are tighter.

Three big themes stood out across the exhibition floor.

Large-format energy-storage cells dominated the main halls. Sodium-ion cells had moved into larger and more practical formats. Solid-state batteries were everywhere, although companies made more cautious claims.

I also did not see a single booth from LG Energy Solution, Samsung SDI, Panasonic, or SK On.

Energy storage cells: 587/588Ah took the center of the floor

At CIBF, 587 Ah and 588 Ah were the main large-format cell sizes for energy storage.

CATL and Hithium had already begun mass production and delivery of 587 Ah cells. CORNEX, REPT, Sunwoda, and CALB showed 588Ah cells.

The 280Ah format was no longer the main focus. Companies still showed 314 Ah cells, but the next generation had moved beyond 500 Ah.

CORNEX paired its 588Ah cell with a module-free CTP 3.0 pack. Each pack has 104 cells and stores 195.68kWh. Its M6 system uses these packs in a standard 20-foot container, with a capacity of 6.25 MWh.

Larger cells reduce the number of cells, electrical connections, and pack parts inside a storage system. They also allow suppliers to increase container capacity without changing the container size.

Still, no single cell size had become the standard.

REPT showed 314Ah, 392Ah, and 588Ah cells. The 392Ah cell sits between the older 314Ah format and the new generation above 500Ah.

Pylontech showed a 601Ah cell. It claimed 426Wh/L, more than 12,000 cycles, and 96.5% energy efficiency.

EVE displayed its LF628K cell with its Mr. Giant 1.0, 5MWh system. The company said it had produced more than 1 million cells on this platform and received orders totaling 25 GWh.

Sunwoda showed 588Ah and 684Ah cells. It said production of its 684Ah stacked cell had passed 2 million units by the end of March.

BYD showed the largest cell I saw: a 2,710Ah energy-storage Blade cell with roughly 9kWh of capacity.

The figures were similar across many stands. Several suppliers quoted more than 12,000 cycles, cell energy efficiency above 96%, and volumetric energy density of roughly 420Wh/L.

LFP dominated the large-format lithium-ion cells on display. Sodium-ion and semi-solid cells were also present, but in separate product lines.

Companies were targeting similar container capacities while using different cell designs to get there.

587 Ah and 588 Ah were the main reference sizes. They were widely used, but I saw no single dominant format across exhibitors.

Blade cells: BYD took a different route

BYD showed something much larger.

Its 2,710Ah energy-storage Blade cell is far bigger than the 500Ah to 600Ah cells shown by most other suppliers. BYD uses it in its Haohan storage system. The company says the smallest system can reach 14.5 MWh. It also says the platform can fit 10 MWh within the footprint of a 20-foot container.

BYD also displayed 320 Ah and 335 Ah storage cells.

The Blade name now covers two different products. One is the large energy-storage cell. The other is BYD’s second-generation Blade Battery for EVs, designed for fast charging.

They displayed it for the Denza Z9 GT.

The car stood beside BYD’s new FLASH Charging Technology station. I was impressed by the quality of the car.

German OEMs will find it harder to rely on the idea that premium quality is a German advantage.

(The rest of the article covers solid-state and semi-solid batteries, sodium-ion, LMFP, and new demand areas, with more photos of cells and battery packs)

Read more

In March 2020, GM unveiled Ultium as a common battery and EV platform for its next-generation vehicles. It used large-format pouch cells and a nickel-rich chemistry, designed to serve almost every vehicle segment.

In 2021, it raised its EV and autonomous-vehicle investment to $35 billion through 2025 (Source: GM).

Its EVs use nickel-rich NCMA and LFP. LMR is next for EVs, while sodium-ion is for stationary storage.

Two weeks ago, I wrote an article on the BYD story and its LFP bet. They picked lithium iron phosphate (LFP) around 2002 and spent 18 years improving that chemistry until it won out.

GM’s LFP plan has already changed.

The plan that kept changing

Ultium is built around large-format pouch cells through its partnership with LG Energy Solution.

In February 2024, it appointed Kurt Kelty as its first Vice President of Batteries, a newly created role.

Kelty had led Tesla’s battery development team for 11 years and had begun working on lithium-ion batteries at Panasonic in 1993.

Kelty said GM was moving to a multi-chemistry, multi-form-factor, and multi-supplier approach.

In July 2025, they announced that the Spring Hill plant will make LFP cells for EVs by late 2027.

But, Ultium Cells had redirected the immediate output of the retooled facility to LFP cells for LG Energy Solution’s stationary-storage business.

In June 2026, Kelty told Reuters that LFP might not remain part of GM’s future EV portfolio, even though the new Chevrolet Bolt already uses imported CATL LFP cells.

The workhorse GM has yet to mass-produce

GM now calls lithium manganese-rich its future high-volume EV chemistry.

Kelty describes LMR as the “workhorse” and says “that’s where we’re going to be using the big volume” (Source: Reuters).

The case is real on paper.

GM has worked on LMR since 2015. LG Energy Solution holds more than 200 LMR-related patents. GM estimates that its LMR prismatic cell will deliver 33% higher energy density than LFP at a comparable cost.

GM’s May 2025 plan targeted commercial production in 2028 and aimed to make GM the first automaker to deploy LMR cells in EVs.

In June 2026, Kelty said LMR development remained on schedule, without reconfirming the 2028 date.

LMR has historically faced short life and voltage fade. According to GM, its new cell has addressed those issues through coatings, dopants, particle engineering, and process changes.

The proof will come in mass production.

Until then, LMR is a development target for 2028.

LMFP is a clear example. For years, it was presented as offering 15 to 20% higher energy density than LFP at a comparable cost.

Manufacturing problems have so far kept it from meeting those expectations.

China is moving sodium-ion into commercial deployment

In June, GM partnered with Peak Energy, a startup developing sodium-ion battery systems for grid-scale storage.

GM will develop sodium-ion cells in its Michigan laboratories and keep the manufacturing rights.

Peak Energy will use the cells in its storage systems. GM plans to prototype the cells by the end of 2026 and target commercialization in 2028.

But, no supply chain exists in the West.

China is already leading sodium-ion battery development and production.

CATL and Changan unveiled a sodium-ion passenger car in February, with a market launch scheduled for mid-2026. CATL says Naxtra will enter full-scale mass production by the end of the year.

CATL has also signed a 3-year agreement to supply 60 GWh of sodium-ion batteries to HyperStrong for stationary storage. CATL says it has resolved key mass-production constraints, including hard-carbon processing and moisture control.

China already has a strong supply chain, ready to mass-produce and scale quickly.

Peak Energy is earlier in its own cell development. Its co-founder, Cameron Dales, says the technology is roughly where LFP was 10 years ago.

As of 2025, Peak Energy imported sodium-ion cells from China and assembled them into storage systems in the United States.

The lane GM already has

In the US, GM sells EVs using 2 mature chemistries.

Its larger EV portfolio uses nickel-rich NCMA cells. The Chevrolet Bolt, GM’s lowest-priced US EV, uses imported LFP cells from CATL.

The improvement path is proven.

BYD adopted LFP in 2002 and launched Blade Battery in 2020. Its long-cell, cell-to-pack design improved pack-level space utilization and made LFP more competitive in passenger cars.

LFP is mature, but its materials, cell design, pack architecture, fast-charging capability, and manufacturing cost can still be improved.

GM should maintain NCMA where energy density matters and establish a stable domestic LFP supply for lower-cost EVs.

LMR remains a 2028 development target. Sodium-ion is a stationary-storage program.

GM has several chemistry options. 11 months after GM said Spring Hill would make LFP cells for EVs, Ultium Cells allocated its first planned LFP production to stationary storage.

Kelty says LFP might not earn a place in future GM EVs.

It would be a mistake.

They should stick to NCMA for high performance and LFP for volume, at least until the end of the decade.

Betting its EV volume segments on unproven chemistry is too risky.

P.S. Whenever you’re ready, here are three ways I can help:

1. Battery industry reports

I’ve published two so far: The Battery Starter Kit, to help you get up to speed on the battery industry, and the CATL Company Profile, to help you understand how CATL operates and why it leads the market.

You can find them here: Battery industry reports

On 9 June 2026, the European Commission established the Battery Booster Facility. It will lend up to €1.5 billion to cell makers building in Europe, drawn from EU Emissions Trading System (ETS) revenue through the Innovation Fund.

For the first time, the money is an interest-free loan instead of a grant.

Brussels identified the right problem.

The Commission describes ramp-up as the hardest phase: low yields, high material costs, validation, fine-tuning, and scrap. Then it makes 10 GWh of nameplate capacity the price of entry.

That minimum rewards the same scale-first bet that helped sink Northvolt.

What €1.5 billion actually buys

The loan terms are more restrictive than the €1.5 billion suggests.

A project can borrow the lower of 60% of eligible costs or €500 million per final recipient, at no interest. The loan structure is designed to encourage companies to adopt sound capital management and to attract private capital alongside public funds.

Few projects can even apply.

A project has to produce battery cells for electric vehicles within the European Economic Area (EEA). The site must already be in the ramp-up phase when the call opens. The project must also be the first full commercial-scale EV cell production project globally for the final recipient and its related parent companies, subsidiaries, and entities under common control. Then the size requirement: at least 10 GWh of nameplate capacity.

The schedule is tight.

The call opens in Q3 2026 and runs about six weeks, and the Commission wants the first awards signed and the first payments made before the end of 2026.

This follows earlier moves: a €1 billion Innovation Fund battery call in December 2024, a €200 million InvestEU top-up, a Battery Booster Strategy in December 2025, and a public consultation in March 2026 (Source: European Commission).

Europe wants its own cells, and it is now willing to lend directly to get them.

The failures behind the loans

The Battery Booster exists because the first European cell makers kept failing at the same step.

Northvolt filed for bankruptcy in 2025. Northvolt’s collapse had several causes, but ramp-up was the failure point that turned the business model into a cash drain.

Morrow Batteries, operator of Europe’s first gigawatt-scale lithium iron phosphate (LFP) factory, filed on 6 May 2026.

ACC (Automotive Cells Company), backed by Stellantis, Mercedes-Benz, and TotalEnergies, has started production in France while its German and Italian projects have been shelved after being on hold since 2024 (Source: Reuters).

Each one stalled at ramp-up. Capital alone was not enough.

Every one of them raised money and signed real customers. The equipment arrived. The trouble started when the lines could not turn out qualified cells fast enough. Funding got harder, and customers lost patience. The plant costs more to run than it could earn.

ACC shows the deeper gap.

Its German and Italian plants are shelved, and the French plant is working through a ramp-up that ACC says is running longer and costing more than planned. It’s now getting support from external Chinese engineers.

Europe has capital. It lacks enough proven manufacturing know-how at scale and patience.

The 10 GWh rule is the problem

The 10 GWh minimum favors companies that scale first.

The money goes to projects already in ramp-up, so it is not pushing a newcomer to build 10 GWh from scratch. Eligibility is based on the site’s planned nameplate capacity. A site designed for at least 10 GWh of capacity can qualify, though actual production remains uncertain.

A company that wants to prove a 1 or 2 GWh line first stays under the minimum.

The Battery Booster is meant to solve ramp-up risk, but its first filter is still capacity ambition.

That filter favors the exact bet that just failed. Northvolt scaled the nameplate before the line worked. Yield decides survival, and only a running line proves yield.

A cell line is a process system.

Coating, drying, calendering, formation, and inspection all have to hold together, and scrap runs 15% to 30% in the early years (Source: Fraunhofer FFB). You can easily find some players at 50% scrap in their first year. The economics depend on how fast a single line ramps up to high yield.

The gigawatt-hour figure in the press release means nothing.

A European entrant should prove a 1-2 GWh line first: ramp speed, scrap, yield, and customer-qualified cells that sell at a margin. Once that line works, you replicate it to reach multi-GWh capacity.

Replication copies a process that already runs. Scaling a line you have not validated copies the defects at ten times the cost.

Who the short window is built for

The six-week window is the only time to apply.

It still tells you who the booster is built for: factories already far enough through planning, financing, installation, and qualification to file a mature application almost at once.

The short list is narrower than it first looks.

The eligibility language points toward first-commercial-scale ramp-up projects and screens out incumbent Asian makers already producing globally.

PowerCo has started cells at Salzgitter and plans up to 20 GWh in the first stage (Source: Volkswagen Group).

ACC is already producing cells at its French plant.

Verkor is trying to bring its 16 GWh Dunkirk plant into series production, while Renault has publicly challenged it on cost, delay, and governance (Source: Marianne).

Those are the names to watch, subject to the Commission’s final call.

€1.5 billion may look like major support, but let’s be honest: for the battery industry, it is almost nothing.

Against the cost of a local supply chain, €1.5 billion is small.

A single 10 GWh plant, the booster’s own minimum, costs €1 to €2 billion to build. A full chain also needs refining, cathode, anode, electrolyte, separator, and recycling. Building all of it runs into the tens of billions.

I feel European politicians are living in a fantasy world. There is a lot of talk about sovereignty, but little real action.

Yes, we have policies and funding tools, such as the Net Zero Industry Act and the future Industrial Accelerator Act. But the loopholes are massive. Companies can still qualify as “Made in Europe” without real production in Europe.

Most public support is still grant-based. There is too little tied to actual output and real local content.

Since I entered the industry in 2020, I have not seen Europe build a real system to establish a local battery supply chain.

It is a shame, but it also reflects the quality of European policymaking. There is still no serious long-term plan.

Only regulation, regulation, and more regulation.

P.S. Whenever you’re ready, here are three ways I can help:

1. Battery industry reports

I’ve published two so far: The Battery Starter Kit, to help you get up to speed on the battery industry, and the CATL Company Profile, to help you understand how CATL operates and why it leads the market.

You can find them here: Battery industry reports

In 1995, a 29-year-old chemist named Wang Chuanfu borrowed 2.5 million RMB (about $300,000) and hired 20 people in Shenzhen.

In 2025, his company passed Tesla as the world’s top battery energy storage system (BESS) integrator by shipped capacity (Source: BMI).

You probably know the company by now. It's BYD.

Western battery startups raised more than $20 billion over the past decade. I counted at least 14 of them going under in the last 15 months.

PS: Morrow is not in the list, as I wrote the article before they declared bankruptcy.

The difference between BYD and them was patience.

BYD treated every big decision as a ten-year bet. Western companies gave themselves five years, and five years was never enough.

A factory without robots

Japanese giants like Sanyo and Panasonic dominated the battery industry in 1995.

Their automated factory lines cost tens of millions of RMB each. BYD could not afford even one of the machines.

So Wang broke the line into small manual steps.

He gave each worker a cheap metal jig, a tool that locks a part in the exact right spot. With one in hand, workers could repeat the same motions cheaply enough to replace parts of the automation. And instead of building fully enclosed clean rooms, BYD built sealed “clean boxes” in which workers handled sensitive parts through glove openings (Source: INSEAD Knowledge).

The numbers were brutal.

Wang says his lines cost one-fifteenth as much as the Japanese equivalent. For lithium cells, BYD spent $1.30 per cell, compared with Sanyo’s $4.90 (Source: 36Kr).

That gave BYD a production-cost advantage big enough to undercut rivals and still make profits.

Then, the 1997 Asian Financial Crisis crashed battery prices by 20-40%. The crash squeezed Japanese makers of low-margin nickel-cadmium (NiCd) cells, and the cheapest producer took the share they had given up.

Over the next three years, BYD claimed about 40% of global NiCd sales (Source: 36Kr).

Motorola signed with them in 2000. Nokia followed.

By 2002, BYD was listed in Hong Kong as China’s top rechargeable battery maker, second worldwide in NiCd and fourth in lithium-ion (Source: BYD 2002 listing prospectus).

The acquisition investors hated

In January 2003, Wang paid 269.5 million RMB (about $33 million) for 77% of Qinchuan Auto, a struggling carmaker in Xi’an (Source: BYD 2003 interim report).

BYD’s stock fell 19.7% on the next trading day (Source: Sina Finance). One fund manager threatened to dump the shares “until it dies.”

The critics had a point on paper, since Qinchuan built shoddy little hatchbacks. But Qinchuan held the passenger-car production qualification BYD needed (Source: HKEX filing, January 2003).

The strategic logic was simple: put BYD’s batteries inside vehicles.

The gamble paid off first in gasoline cars. BYD learned by tearing down rival models and building its own molds and engines.

The F3, which looked a lot like the Toyota Corolla, launched in 2005 and became one of China’s best-selling domestic-brand sedans.

That cheap gasoline car paid for everything that came next.

Twenty years on the unfashionable chemistry

Wang picked his chemistry around 2002, according to his battery chief (Source: Sun Huajun, via 21st Century Business Herald).

His team had three routes on the table.

Two stored more energy: lithium cobalt oxide (LCO), the chemistry in phone batteries, and lithium manganese oxide (LMO).

Wang chose lithium iron phosphate (LFP), the route with the weakest commercial case for passenger-car range at the time.

Cobalt and nickel are relatively scarce in China. Wang has long argued against replacing dependence on imported oil with dependence on scarce metals.

LFP had other strengths.

It costs less, since the recipe skips both. The cells also last longer and handle heat better than many nickel-manganese-cobalt (NMC) designs, and BYD rates them at more than 3,000 charge cycles.

The bet drew its most famous backer before the product existed.

In September 2008, Warren Buffett’s MidAmerican bought 225 million BYD shares at HK$8 (about $1) each, a $230 million endorsement.

Three months later, BYD launched the F3DM, the first mass-produced plug-in hybrid, running its own LFP cells at 149,800 RMB (about $21,500).

Then the bet nearly broke BYD.

China’s 2017 subsidy reform paid more for energy density, a rule that favored NMC. CATL, which used NMC for cars and LFP for buses, passed BYD that year and never fell behind again. Chinese coverage began treating BYD as the No. 2 EV battery player.

BYD even gave in for a while. From 2017 it put NMC in its higher-range passenger BEVs to chase range and the bigger subsidy.

But it never dropped the chemistry.

LFP stayed in BYD's buses and commercial vehicles, and at a 2018 meeting in Qinghai the team agreed to hold the line (Source: Sun Huajun, via 21st Century Business Herald).

The Blade battery

In March 2020, BYD fixed LFP’s weakness with mechanical engineering instead of chemistry.

A normal pack wastes space. Carmakers group cells into modules and frame the modules into the casing, so only about 40% of the volume holds actual battery.

So, BYD launched the Blade Battery.

BYD stretched its LFP cell into a blade format about a meter long and skipped the module layer. The blades lie side by side and form the pack’s structure themselves. Space utilization passed 60%, and the first Han sedan reached 605 kilometers of range on China’s official test cycle.

To prove the safety, BYD ran the nail penetration test on camera.

The test drives a steel nail through a charged cell to force an internal short circuit, the fault that starts most battery fires. The NMC cell shot past 500°C and burst into flames. The Blade’s surface stayed between 30°C and 60°C with no fire or smoke (Source: BYD launch demonstration, March 2020).

Carmakers no longer had to choose between NMC’s range and LFP’s safety, because the Blade gave them both.

By 2025, LFP dominated China’s battery installations, and rivals that had mocked the chemistry were ordering it.

The Blade also let Wang close a loop he had opened in 2003. In March 2022, BYD became the first major automaker to stop building pure gasoline cars.

The bet is still growing.

In March 2026, BYD launched a second-generation Blade and kept it on LFP, pulling more out of the same chemistry with faster charging.

BYD says the new pack charges from 10% to 70% in five minutes on its 1,000-volt platform and delivers a driving range of 1,000 kilometers.

CATL is chasing the same goal with its own next-generation cells.

One cell, three markets

The same battery playbook now feeds three businesses.

Cars came first. Grid storage followed. BYD opened its power research institute in 2008 and built its first energy storage station in Shenzhen the next year (Source: China Energy News).

Its first container-sized systems reached the United States in 2011, and BYD pushed hard into overseas storage markets years before the home market was ready.

That work gave BYD more than a decade of operating experience in demanding storage jobs. By 2025, it had shipped more than 60 GWh of BESS capacity, compared with Tesla’s 46.7 GWh (Source: BMI).

The third business sells cells to rivals.

BYD split its battery unit into a company called FinDreams in 2019 and opened it to outside buyers. Xiaomi became the largest external customer, accounting for 17.9% of shipments outside China.

Among third-party brands, XPeng followed at 6.6%. Toyota uses FinDreams batteries in some Chinese EVs, including the FAW Toyota bZ3.

It has not all gone smoothly.

In late 2025, BYD recalled almost 90,000 hybrids due to battery pack consistency issues that could reduce power output (Source: State Administration for Market Regulation).

The China price war cut net profit 19% to 32.6 billion RMB (about $4.7 billion) (Source: BYD 2025 annual report). Wang told shareholders in December 2025 that BYD’s technological lead had narrowed, and that the company needed another round of technology releases to rebuild the gap.

Even after thirty years, none of it comes easy.

The part Western companies skip

BYD built its business one step at a time.

The battery business came first and made money. That money paid for the car gamble. The cars then became a steady buyer for the LFP bet, and that bet took eighteen years to pay off.

It also owns most of the chain.

BYD mines and refines some of its own lithium, makes its own cathode material, cells, packs, and power chips, and puts them in its own cars. So when lithium prices spiked or chips ran short, it kept building while rivals stalled, and when costs fell, it can cut prices faster than anyone buying from outside.

Several battery makers are now developing blade cells. BYD set the reference point here.

Western startups did it in reverse.

They raised billions on a single battery bet and built big factories before they could make good cells. Demand kept rising, and they went under anyway.

BYD was slow, and it made mistakes.

An engineering fix on the Blade saved the LFP bet. What it never did was give up on LFP for good.

The Western companies trying to copy China want the same result in a single product cycle. You cannot get there that fast.

P.S. Whenever you’re ready, here are three ways I can help:

1. Battery industry reports

I’ve published two so far: The Battery Starter Kit, to help you get up to speed on the battery industry, and the CATL Company Profile, to help you understand how CATL operates and why it leads the market.

You can find them here: Battery industry reports

This article is brought to you in partnership with Hymson

In May 2026, Morrow Batteries filed for bankruptcy. It was Norway’s first lithium iron phosphate (LFP) cell maker. Northvolt, the larger Swedish cell maker, had already collapsed.

Both went down while global battery demand kept rising.

Together, largely through Northvolt, they attracted billions in financing and signed customers. The most expensive part came after the equipment arrived, when the lines had to start making cells.

Energy and labor explain part of Europe’s battery cost gap.

They miss the part that did the most damage. The bigger bill often comes before a factory can ship cells that a customer will accept. It builds after the equipment is installed, while the line still has to move from acceptance tests to qualified output.

In many European projects, the equipment suppliers and the cell maker never share enough responsibility for the ramp-up production.

Europe also keeps score on the wrong number. It measures factories by announced capacity, when the better number is qualified output: cells that pass validation and can be sold.

The gap between those two numbers is where much of the European money has vanished.

The number Europe argues about, and the one it ignores

Start with the number everyone quotes.

BloombergNEF put 2025 pack prices at $84 per kWh in China and $131 in Europe, a 56% spread. The blame lands on energy bills and wages. Equipment adds to it: Porsche Consulting and VDMA estimate European machinery can cost up to 50% more once CE marking, safety rules, and documentation are included.

The headline gap is not a fair comparison.

Part of it is chemistry.

China produces mostly LFP, while Europe still relies on nickel-rich chemistries such as nickel manganese cobalt (NMC) and nickel cobalt aluminum (NCA), which use higher-value metals. The regional spread measures what the cells are made of as much as how well they are made.

Roland Berger adds a second distortion. Chinese overcapacity near 100% has pushed LFP toward marginal cost, as low as €30 per kWh, so oversupply widens the headline gap on its own.

Strip both out, and a real gap remains.

Roland Berger’s late-2025 model puts Europe’s cell-cost disadvantage at €9-€11 per kWh, about 15-20%. Higher capital and energy costs explain part of it. Fraunhofer plays down labor and points to production know-how.

Then the same model carries a line most readers skip.

A new 20 GWh European entrant pays around €1.5 billion more in ramp-up costs than an established Asian player building the same plant. Spread across the factory’s first production cycle, that figure can match the entire steady-state gap. The steady-state gap shows up in the model.

The ramp-up cost hides in delays and low yield.

What a slow ramp-up actually costs

Morrow shows the shape of the cost.

The company started in 2020 in Arendal with one 1 GWh line, Europe’s first LFP gigafactory, against an ambition of 42 GWh. By the May 2026 bankruptcy, cumulative funding exposure had passed NOK 5.1 billion, around $480 million.

The timeline tells the rest.

Morrow declared commercial start in January 2026. In March, it brought in Korea’s JR Energy Solution to help with electrode production. Electrodes determine much of the yield, and reaching outside for them late in the ramp-up showed that the line was still unstable. Deliveries to Proventia began in April, and the bankruptcy filing came in May. It was too late.

Along the way, work permit delays for Japanese and Korean technicians cost NOK 100 million and took 4 months. Acting chief executive Jon Fold von Bülow said there are no shortcuts to building stable and competitive battery production.

Scrap makes the cost visible.

Fraunhofer FFB and PEM at RWTH Aachen put normal scrap in cell production at 15% to 30% in the first years, and at around 10% after five years. In their model of a 40 GWh plant, each percentage point of scrap costs about €30,000 per day, or nearly €10 million per year. At 30% scrap, the plant loses about €900,000 a day.

During a slow ramp-up production, the factory keeps spending while too many cells fail inspection. Materials get consumed, labor gets paid, energy gets used, and depreciation runs. Little of that cost reaches the cells that a customer can buy.

Some scrap can be avoided before the line starts.

Design of Experiments (DOE) is an early testing that finds the right process settings before mass production. Process problems in mixing, coating, and drying are a leading cause of ramp-up scrap, and DOE can cut them (Source: Fraunhofer). Most makers still do too little of it, so the line sorts the problems out during the ramp-up, which takes longer.

The scrap that still comes off the line needs a plan. Two things decide how much of it comes back: rework and recycling.

Rework fixes problems early, at the electrode stage, and before the cell is finished, so the material can go back into the line. Once a cell is fully built, it usually cannot be reworked.

Recycling deals with the rest. Scrapped material still contains metals like nickel, cobalt, and lithium, and recovering them helps recoup some of the money lost during the ramp-up. It does not bring everything back. The labor and energy already spent are gone. Still, recycling scrap during the ramp-up helps a cell maker manage cash in the early months, when scrap is high and sales are low.

Delay adds a second bill.

Fraunhofer estimates the average loss of profit from a delayed start of production at about €1.1 million per day for the same 40 GWh plant. Reported start-of-production delays run from three to nine months, with an average of seven months.

Morrow blamed the market and a cooling investment climate. But its own list named industrialization delays, the ramp-up problem in plainer words. The line never reached stable yield, so the cash ran out.

Small delays became cash burn, and a line that cannot reach yield bleeds money long before it ships at scale.

The gap that opens after the equipment arrives

Northvolt shows the problem clearly.

Northvolt Ett in Skellefteå had an initial nameplate of 16 GWh. Internal figures reviewed by Dagens Industri put output at 79.8 MWh in the first nine months of 2023, about 0.5% of that target. BMW noticed. In June 2024, it canceled a €2 billion contract after Northvolt fell behind on deliveries and could not produce enough high-quality cells.

The equipment had arrived. The factory still had to turn it into a stable production system.

Norran, a Swedish media, later reported a difficult handover with one of Northvolt’s Asian equipment suppliers. Some lines were shipped to Sweden without factory testing after pandemic restrictions blocked routine checks, and Northvolt took the equipment rather than wait. Supplier engineers helped install and support it on-site. The problems persisted, and the delay lasted at least 10 months.

Peter Carlsson, the former chief executive, later called the decision a big mistake.

That shortcut made sense on a schedule. On the shop floor, it pushed unresolved work into Sweden.

A battery line is a process system.

Coating, drying, calendering, slitting, assembly, formation, aging, and inspection must all work together. A small deviation early in the line shows up later as yield loss or rejected cells.

That makes the supplier relationship matter from the start, before installation, through design checks, process-window definition, operator training, and shared access to the data that explains yield loss.

Reuters found Northvolt still missing internal targets in late 2024, with machine faults and inexperienced staff behind the shortfall. Northvolt disputed parts of the account and said some serial-production equipment ran well. Both can be true.

Some machines worked, some parts of the line improved, and the factory still could not turn out enough shippable cells fast enough.

Buying machines is the easy part.

Building the production system around them is where Europe continues to lose time. The Porsche Consulting and VDMA study notes that Asian makers hold more than 90% of global cell manufacturing capacity, supported by long relationships with their equipment suppliers.

Europe bought the hardware and often missed the relationship behind it.

Why the buying model slows the ramp-up

The contract can leave the hardest part with no clear owner.

Most equipment deals move through two acceptance steps. The factory acceptance test (FAT) is conducted at the supplier’s site, and the site acceptance test (SAT) is conducted at the buyer’s site. In many contracts, FAT and SAT close the formal handover before the line has reached stable qualified output.

A line can pass both tests and still be far from stable production.

There is a way to lower that risk before the line leaves the supplier.

A standard FAT checks that the machines run. A longer one runs them to make good cells at a real production rate, like a mini ramp-up before shipment. A workable bar for that mini ramp-up phase is Overall Equipment Effectiveness (OEE) above 70%, a measure of how much good output a line makes. The buyer can write that into the contract and hold the line at the supplier’s site until it clears the bar.

This costs more up front.

The supplier needs space, materials, and people to run the line longer. The buyer pays for that time. In return, more problems surface before delivery, not after, when they are slower and dearer to fix. It is the same logic as the rest of the ramp-up: spend earlier where the work is cheaper, or spend more later once the line is in the buyer’s plant.

The supplier knows the machines. The cell maker owns the product, the quality targets, and the customer qualification. Yield problems fall between those two worlds, and nobody fully owns them.

Procurement habits make the split worse.

The Porsche Consulting and VDMA study describes how early European factories bought turnkey lines from a single Asian supplier, struggled with ramp-up, then moved to buying machines piece by piece. European tenders also run 12 to 27 months before the planned start of production, long enough for the original line concept to age.

Both routes leave the same hole: too little shared responsibility for yield.

That is where the China comparison bites.

Established Asian players have deeper supplier relationships and more ramp-up experience. In practice, the supplier focuses on process definition, data sharing, training, and yield improvement.

In Europe, the relationship often stays transactional. Buy the line first, solve the ramp-up later.

That delay is expensive.

What buying the ramp-up looks like

A good equipment supplier earns its keep after delivery.

The hard work is the ramp-up, getting an installed line to reach high yield, above 90%.

Roland Berger and Porsche Consulting both describe the same shift, in which supplier value extends into ramp-up and line operations. At Battery Show Europe in 2025 and CIBF in 2026, integrators presented turnkey lines with ramp-up support and digital monitoring attached.

In practice, the supplier stays close before and after installation.

Engineers check the cell design against the line’s actual tolerances, test the process window before the line is called ready, and continue working with the cell maker’s process team through the ramp-up rather than leaving after acceptance. Once the line runs, equipment data keeps flowing back to the people who built the machines.

Hymson is bringing this model to Europe.

Hymson is a Chinese laser and automation supplier with lithium battery equipment across electrode manufacturing, CT inspection, cell assembly, baking, and module and pack production.

Its method relies on two steps before mass production: Design of Experiments (DOE), which tests the process window, and Design to Manufacturing (DTM), which ensures the cell design can run through the line without creating problems later.

Hymson says one pre-production validation surfaced 30+ DTM tasks, six of them unresolved defects that it estimates would have added more than six months of commissioning and over €3 million in equipment changes.

After delivery, the support continues on the floor. An expert team helps find bottlenecks, lift line efficiency, and trains the operators through the ramp-up. It also backs the line with a graded spare-parts service and remote monitoring.

A battery line should not first meet its process limits during mass production. The model works when the supplier and cell maker define the process window together, share the data behind yield loss, train the operators, and stay involved until the line reaches high yield.

Why the better model is hard to buy

Procurement is where the model breaks down.

A machine has a price. Ramp-up support has a moving boundary. It can cover process engineers before FAT, DOE work before shipment, shared data access, spare parts, operator training, remote monitoring, and support through the ramp-up.

That makes the comparison uncomfortable. The cheaper machine bid is visible on day one. Weak ramp-up support only shows up later, when scrap rises, commissioning drags, the start of production slips, or the customer refuses to qualify the cells.

So the old handoff survives.

Buy the equipment, sign FAT, install the line, sign SAT, and leave most of the ramp-up with the cell maker. The sequence is easy to manage on paper and a poor fit for battery manufacturing.

The alternative is to define the working relationship before the line is built. Spell out which data gets shared, which engineers stay involved, how the process window gets tested, and who leads corrective action when yield stalls. That is harder to score than a machine price. It is also closer to the real cost.

A cheap machine bid can become an expensive ramp-up.

Someone has to own the ramp-up

Ramp-up is the part of Europe’s cost gap that stays hidden. It lives inside delays, low yield, scrap, and missed qualification. The factory may have the equipment. It still needs a production system that can make cells customers accept.

European projects did not fail for one reason, but most paths led to the same place. High scrap broke the numbers, and it came from management choices made early.

Announced capacity is the wrong scoreboard. Qualified output is the number that decides the gap.

China shows the other model. Cell makers and equipment suppliers work the ramp-up together, check manufacturability before production, keep supplier engineers close through the ramp-up, and hold support in place once the line runs.

That closeness helped shorten the path from installed equipment to high yield.

Europe has to build that collaboration from the start, with shared data and shared responsibility for yield. The handover matters less than the yield curve. Public money can support that shift by paying for supplier involvement during ramp-up, rather than treating equipment delivery as the milestone.

Buyers can stop comparing machine bids as if the cheapest line makes the cheapest factory.

Europe cannot subsidize past the cost its own contracts keep creating. China’s lead comes from cheaper inputs and from the way its cell makers and equipment suppliers build the line together.

The gap starts to narrow when someone takes ownership of the ramp-up.

PS: To learn more about Hymson, visit their website below or stop by booth 1-B30 at Battery Show Europe next week.

Hymson website

I will be there too, meeting people and walking the booths. If you are going, reply to this email and we can set up a meet-up.

P.S. Whenever you’re ready, here are three ways I can help:

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I help companies answer battery-industry questions through a market lens: demand, technology adoption, competitive moves, customer segments, and value chain shifts.

If you’re working through a strategic question, reply to this email with a short note on what you’re trying to figure out.

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Reply to this email with the question, the context, and what decision you’re trying to make. If it is a fit, I’ll send the next step.

On May 28, Li Lecheng, the minister who runs China’s Ministry of Industry and Information Technology (MIIT), chaired a meeting most of the industry will skim past.

A task force met for the second time and set the year’s priorities. The agenda reads like a routine update, but the timing gives it away.

One month earlier, on April 27, five departments launched a joint enforcement campaign against illegal battery recycling.

The May 28 meeting deepened a campaign that was already running. A year before, the same task force met for the first time and spent its energy on writing rules.

This time, the message was about enforcement.

The seven changes that matter

Six government departments issued the Interim Measures as Order No. 73 on the last day of 2025.

Since April 1, those measures have turned a decade of voluntary guidance into binding law, built around 7 practical changes:

• Car-battery integrated scrapping: A scrapped electric vehicle has to be turned in with its battery, and a car that arrives without its pack counts as an incomplete vehicle. Battery-swap models fall under a separate framework, with specific rules still being developed.

• A digital identity card for every pack: Each battery gets a unique, dynamic ID, built on a code printed on the cell, module, and pack. The ID links every stage of the battery's life into one record, from production through swapping, repair, and final recycling. Forging or destroying that code is itself an offense.

• A national traceability platform: MIIT runs a system that tracks each pack across its life, and every company in the chain has to report movements to it on fixed deadlines.

• Extended producer responsibility: Carmakers and battery makers must build recovery outlets matched to their sales, take back used packs, and carry the final recovery duty. They also have to design batteries that come apart.

• A closed recovery channel: Used batteries can move only to licensed recyclers or to maker-run collection points, and selling them to anyone else can lead to a fine.

• Closing unsafe second-life channels: The measures, together with parallel enforcement actions, shut down backdoor routes for salvaged cells, including unsafe repackaging into e-bikes. Any product made from used cells must meet the quality and safety standards of its target market.

• Rules with fines attached: Companies that break the battery coding, tracking, or recovery rules can be fined up to 50,000 yuan ($7,000).

  Selling batteries outside the approved channel can cost companies 10,000 to 30,000 yuan (roughly $1,400 to $4,200).

  A recycler punished under the rules cannot apply for the MIIT whitelist for two years. If it is already on the list, it can be removed.

Together, the rules build a closed recovery system. Now China has to prove it can make companies follow it.

China’s two recycling systems

To see why China switched from drafting to policing, look at the two recycling economies the country has run side by side.

One is licensed. White-list recyclers hold permits, run pollution controls, report every pack into a national database, and carry the cost of all of it.

The other is informal: thousands of small collectors and backyard workshops that carry none of that cost.

The capacity numbers show it. China’s 156 approved recyclers hold nominal capacity above 4 million tonnes a year, yet run below 20% of it (Source: China Industry News).

The formal system exists, but the feedstock has not arrived yet.

That arrangement held while the volumes stayed small, and they will not stay small.

How the illegal market works

The gray market is bigger than most people think.

China has roughly 200,000 battery-recycling-related companies, depending on the database cut-off. The 156 whitelist companies represent less than 0.1% of that registered universe.

In one CCTV-reported case, a Wuhan whitelist recycler said around 80% of the scrapped NEVs it bought arrived without batteries.

A single pack resells for several thousand yuan, sometimes more than 10,000 (roughly $400 to $1,400). A workshop strips a pack for under 1,500 yuan (about $210) and pays no tax invoice. With none of the environmental cost on top, it bids 20% to 30% above the white-list price. A compliant plant spends more than 3,000 yuan a tonne (about $420) to do the same work inside pollution controls (Source: CCTV).

The highest bidder usually gets the battery, and the cost shows up elsewhere.

Investigators have found dismantling yards next to homes, with swollen and damaged cells piled in the open.

Some are repackaged as new e-bike batteries and sold anyway. The law now bans that channel. China recorded 21,000 electric-bike fires in 2023, according to Xinhua.

That is the channel the enforcement campaign is trying to shut down.

Why the missing batteries now matter

China recovered more than 400,000 tonnes of waste EV batteries in 2025, up 32.9% from the year before (Source: Xinhua).

According to industry estimates cited by 21st Century Business Herald, less than 25% of retired packs flow to whitelist recyclers. Around 75% is handled by small workshops and companies outside the formal list.

The number of retired batteries keeps rising. MIIT expects annual retired EV battery volume to exceed 1 million tonnes by 2030.

At today’s volumes, a 75% leakage rate is painful but manageable. At larger scale, it becomes a fire-safety problem and a raw-materials problem.

Why the rules now have penalties

For 7 years, the rules only encouraged compliance. Order No. 73 makes them binding and attaches penalties. Two provisions make enforcement possible.

The first is the integrated scrapping of the car and battery. A scrapped car without its pack is now incomplete, which closes the loophole the informal sector used. Before, a pack could leave a dismantling yard and reappear in a workshop with no paper trail.

The second is the digital identity card. Each pack now carries a code reported across every stage, from the factory through the vehicle, retirement, and the black mass it becomes. It records the battery’s chemistry and end-of-life history.

The logic is similar to the European Battery Passport.

A missing pack now leaves a visible hole in the regulator’s database.

Rules small workshops cannot meet

The measures came with a second, quieter tool.

Revised technical standards have raised the bar for whitelist qualification.

Qualifying recyclers must achieve recovery rates of at least 98% for nickel, cobalt, and manganese, with lithium recovery targets moving toward or exceeding 90% under updated guidance. Leading operators already surpass these levels.

It must also be based in a designated industrial park, hold certified quality systems, and spend part of its revenue on research.

A backyard operator fails before the paperwork starts. The new penalties make that gap enforceable, which earlier guidance did not.

The standard is already within reach for the biggest recyclers. For small workshops, it is a wall.

Who enforces what

Put those two provisions together, and the April 27 campaign has something real to enforce.

The notice, signed by five departments, splits enforcement by violation type.

MIIT checks traceability uploads and battery handoffs. The environment ministry goes after illegal dismantling and illegal discharge. Transport authorities watch battery movement and repair shops selling packs through the back door. The Ministry of Commerce targets scrap dismantlers issuing false recovery certificates. Market regulators hunt salvaged cells inside e-bikes and scooters.

The campaign has owners, targets, and a deadline. Enforcement runs through May, with exposed cases due by June 30. Three years ago, a crackdown would have had nothing to trace.

Now every missing pack maps to a record.

Where the batteries go now

The informal channel works only when enforcement is weak. Once inspections start, paying more for used batteries becomes dangerous. More packs then start moving toward licensed recyclers.

Large recyclers gain feedstock they could not secure before, at prices they could not match. Their black mass also gets cleaner because the input stream gets cleaner.

China’s recycling market was worth 48 billion yuan, about $6.7 billion, in 2024 and could pass 100 billion yuan, about $14 billion, by 2030, according to Xinhua. Formalization decides which operators capture that growth, and there are not many of them.

China uses a lot of LFP batteries (80% market share in the EV market). So its recycling market is not only about nickel and cobalt. Many retired packs will carry less value per tonne. That favors recyclers with steady feedstock and low processing costs.

CATL’s recycling arm, Brunp, has a recycling capacity of nearly 270,000 tonnes a year and reports nickel, cobalt, and manganese recovery rates of 99.6%, among the highest publicly reported in the industry.

GEM and Huayou are also among China's largest battery recycling and materials players.

As informal volume gets squeezed into the licensed channel, it lands with a small group of integrated companies that already control much of China’s secondary battery metal.

The same campaign that cleans the market pushes more volume toward those companies.

The companies that helped write the rules

The rulebook favors scale.

Brunp has helped shape many of China’s lithium-battery recycling technical standards. The recovery thresholds for whitelist entry sit close to what Brunp already achieves.

That matters.

A standard set near the leader’s capability is easy for the leader to pass. It is impossible for a workshop to meet. So when the sweep pushes informal volume into the licensed channel, it favors companies that already operate at the standards the new system requires.

Who wins

The campaign ends on June 30 with a list of exposed cases.

That list will show the intent. A few fines mean routine enforcement. Closed workshops and revoked licenses mean a market-clearing.

Either way, the surviving volume moves toward the companies built for the new rules. At that scale, China’s secondary lithium, nickel, and cobalt will move through a short list of integrated recyclers. Those companies also feed the cathode supply chain.

China spent years trying to stop battery metal from leaking into backyard workshops.

Now it is pushing more of that metal toward companies already tied to cell and cathode production.

That does not guarantee pricing power. But it changes the balance.

The companies that control compliant recovery will sit closer to China’s next stream of battery metals. As retired packs scale, recovered lithium, nickel, and cobalt become more valuable. Control over that flow becomes part of the supply chain.

P.S. Whenever you’re ready, here are three ways I can help:

1. Battery industry reports

I’ve published two so far: The Battery Starter Kit, to help you get up to speed on the battery industry, and the CATL Company Profile, to help you understand how CATL operates and why it leads the market.

You can find them here: Battery industry reports

China’s battery makers now allocate more of their production to the energy storage market than ever.

In April, most of China’s battery output never went into a domestic EV. Energy storage has become a main line of the business.

Most people read record Chinese battery output as a sign of strong car demand. It helps more to watch where the cells go.

China produced 183.9 GWh of EV and ESS batteries combined in April. But, only 62.4 GWh of that went into vehicles at home. So just 34% of April output ended up in cars.

The rest does not all go to energy storage. Some cells are exported, others wait in inventory, and some cover the gap between making a battery and installing it.

Cells produced in April get fitted into cars and projects later. Energy storage still takes the largest visible share. Sales of energy storage batteries grew 75.5% from a year earlier, almost three times as fast as car battery sales.

The orders are landing.

In China, April energy storage cell tenders exceeded 28 GWh in volume. CATL led, with CORNEX taking a significant share ahead of EVE.

Prices for energy storage cells have risen this year.

A rebound in lithium prices and the early-April cut to China’s battery export tax rebate both pushed in that direction.

New capacity keeps arriving, and most of it is for energy storage.

Envision’s Yichang Phase II adds 60 GWh of energy storage battery production capacity. CORNEX is building a 70 GWh plant at Xiangyang for about RMB 22 billion ($3.2B).

Energy storage has moved from a side market to a main business for China’s cell makers.

The Q1 2026 results already show a split. One maker posted a record quarter.

All three Korean cell makers lost money. The most vertically integrated player in the market saw profit fall by more than half. Energy storage volume is rising for almost everyone.

That is how I read April in the latest Battery Chronicle Briefing.

The free read covers one signal. The briefing covers the month.

The Battery Chronicle Briefing (April analysis) covers:

• Q1 2026 results for CATL, LG Energy Solution, Samsung SDI, SK On, EVE, CALB, Gotion, Sunwoda, and BYD.

• China’s April battery production against EV installations

• April energy storage tender pricing and what moved it

• China’s energy-storage-heavy capacity wave (Envision, CORNEX, CALB)

• Tesla’s ESS results in Q1 2026

• April battery exports and the export tax rebate cut

• CATL Tech Day: Shenxing Gen 3, Qilin, Naxtra sodium-ion, and the Choco-Swap network

• CATL’s 60 GWh sodium-ion offtake with HyperStrong

• Korean cathode and materials recovery financial results (L&F, EcoPro BM, POSCO Future M)

• Solid-state progress (EVE, Farasis, Gotion, QuantumScape)

• Japan, ASEAN, and India qualification and localization signals

• Recycling distress: Ascend Elements’ Chapter 11 and Redwood’s layoffs

Download the full Battery Chronicle Briefing #2 report below ⬇️

Read more

Ford signed a 5-year framework under which EDF, the French utility, can buy up to 20 GWh of grid batteries for North America.

Meanwhile, Volkswagen connected a small 40 MWh battery in Salzgitter, Germany.

Ford’s deal is 500 times bigger on paper, but the smaller Volkswagen project says more about where the profit is made.

The factory builds the battery once.

Running it is where the real money begins: trading electricity, providing grid services, managing warranty risk, and updating software.

The 20 GWh headline is the trap

Ford and Volkswagen announced their grid storage moves around the same time.

In May 2026, Ford Energy signed a 5-year framework with EDF Power Solutions under which EDF can buy up to 20 GWh of grid batteries, limited to 4 GWh each year. Deliveries will start in 2028.

By contrast, Volkswagen’s Elli plugged a 20 MW, 40 MWh battery into the German grid on 9 March 2026.

Look only at the GWh and Ford looks bigger.

That is the trap.

Shipping a container is one sale. Running a battery is a series of decisions stretched across years, each one shaped by electricity prices, weather, grid rules, safety limits, and customer commitments. The operator learns something new with every dispatch.

That learning adds up.

Anyone can count GWh. Who controls the battery after installation keeps the profit.

Ford has the contract

Ford found a second customer for batteries its EV plan no longer needed.

Ford announced the energy storage pivot in December 2025 and formally introduced Ford Energy in May 2026.

The company committed $2 billion over 2 years to convert Kentucky’s battery factory capacity originally built for an electric car market that grew slower than planned.

Ford Energy’s DC Block is a 20-foot shipping container packed with 5.45 MWh of grid batteries. The cells inside are large 512 Ah LFP batteries. EDF can buy up to 4 GWh a year under the deal. The LFP technology underneath relies on licensing from CATL, China’s largest battery maker.

Ford solved the hardware problem.

Ford’s timing is not random. The US installed 18.9 GW of battery storage in 2025, according to American Clean Power and Wood Mackenzie. The Energy Information Administration projects another 24 GW of utility-scale capacity for 2026.

The market is large enough to absorb factory-scale supply, with utilities and data centers leading domestic demand.

Data centers add weight to the domestic angle. The International Energy Agency expects global data-center electricity demand to more than double to 945 TWh by 2030. Those buyers want capacity and speed the grid cannot match.

Once the container leaves Kentucky, EDF owns every operating decision and every dollar of operating profit.

Morgan Stanley estimates that a 20 GWh annual Ford Energy business could earn $500 million to $600 million of run-rate EBIT (operating profit) by 2028. Hardware can be a real business at that scale.

The deal lets Ford enter grid storage without becoming a power trader.

That bridge is helpful but the destination is somewhere else.

Volkswagen is testing the asset layer

Volkswagen built Salzgitter small on purpose. Scale comes later.

Volkswagen started trading power on EPEX SPOT, Europe's wholesale power market, in July 2023. The Salzgitter battery arrived nearly 3 years later.

The operating stack is the proof point.

Elli’s PowerCenter uses 13 containers, runs inside a virtual power plant, connects directly to wholesale markets, and trades across multiple revenue streams with its own algorithms.

A grid battery has more than one way to earn money.

The simplest is buying low and selling high. Beyond that, the battery can sell frequency response, take balancing contracts, earn capacity payments, or sign flexibility deals with customers. The tough part is picking which market to serve in each hour without wearing out the battery.

Elli is starting with that operating question.

Volkswagen wants to know how much money the battery can earn before wear cuts the profit. One 2024 study found degradation cut yearly net profit by 13% to 24% in the arbitrage cases modeled.

Germany is a useful place to learn this business. Day-ahead price spreads widened from around €30/MWh in 2019 to around €130/MWh in 2024, per Modo Energy. Wider spreads make storage worth more. They also make every dispatch decision more complex.

At today’s scale, Salzgitter project is tiny.

The real value is what Elli learns. The company tests how far a carmaker can go in grid storage.

If Elli proves Volkswagen can operate this battery profitably, the company gets a playbook it can scale. If it fails, it becomes an expensive lesson.

Either way, Volkswagen went after the deeper problem first.

Tesla shows why the asset layer matters

Tesla made grid storage profitable by tying the battery to software, dispatch, customer operations, and market trading.

Tesla has built stationary storage since 2015 and remains the Western benchmark for a full-stack battery business.

Tesla deployed 46.7 GWh of storage in 2025, up 48.7% year over year. Energy revenue reached $12.77 billion, up 26.6%.

Tesla’s Energy Generation and Storage segment reached a 29.8% gross margin in 2025, versus 17.8% for total automotive.

The profit comes from many layers.

• Tesla makes Megapacks at its Lathrop, California factory at 40 GWh of yearly capacity. A second US Megafactory in Brookshire, Texas, near Houston, will add 50 GWh of Megapack 3 capacity.

• Tesla’s Autobidder software runs the operating stack for third-party battery operators.

Tesla’s long-term supply deals give it buying power newer entrants cannot match.

Volkswagen’s small test points at this stack. The 40 MWh battery looks tiny, but it aims at the right problem.

The container matters but the business is bigger than the container.

Volume and control are different strategies

3 companies. 3 different starting points.

Ford will ship more GWh, while Volkswagen tests the part of storage that decides who keeps the long-term profit.

Ford’s path can grow faster because it starts from a factory and a signed contract. The Volkswagen path moves slower. Operations and trading take longer to learn.

VW also faces a PowerCo problem. European EV demand keeps growing, and VW’s car brands will need more cells. Growing the storage business would fight for the same supply.

The uncomfortable conclusion

This is the test for every OEM storage announcement now.

Is the company just putting cells into containers, or building an operating business around the battery?

The first keeps factories busy but the second creates a storage business.

In grid storage, the second one matters more.

The next 15 years are the business.

P.S. Whenever you’re ready, here are three ways I can help:

1. Battery industry reports

I’ve published two so far: The Battery Starter Kit, to help you get up to speed on the battery industry, and the CATL Company Profile, to help you understand how CATL operates and why it leads the market.

You can find them here: Battery industry reports

This article is brought to you in partnership with SES AI

For years, Pentagon battery contracts were mostly judged through cost per kWh and energy density.

The cheapest qualified cell usually won at equal performance.

The Fiscal Year 2026 National Defense Authorization Act, signed on December 18, 2025, added a new filter: country of origin.

Section 842 stops the Department of Defense from buying advanced batteries “owned, sourced, refined, or produced” by a foreign entity of concern.

Meaning no Chinese products or materials.

The phase-in begins January 1, 2028, for new acquisitions. It expands to standard batteries on January 1, 2029. Existing programs roll over by January 30, 2031.

Drones come first.

What “NDAA-compliant” actually requires

A compliant cell can’t be “owned, sourced, refined, or produced” by a Foreign Entity of Concern (FEOC). That means companies in or controlled by China, Russia, Iran, or North Korea.

In batteries, the main exposure is China.

The rule reaches all four key materials in the cell: cathode, anode, electrolyte, and separator.

Each has to come from a non-Chinese company outside China, from raw powder through final cell assembly.

The Battery Management System (BMS) is also in scope. Hardware and firmware both count.

The exception clause requires 95% of a battery’s cost to come from non-FEOC sources.

There’s no central registry. “NDAA-compliant” is self-certified. A supplier that overstates faces False Claims Act exposure.

For a drone maker, the test is simple. If the cell can’t be documented to the four-material level outside China, the drone can’t win a federal contract.

Different drones need different cells

The market breaks into five rough categories: ultra-energy, energy, balanced, power, and ultra-power.

Each category shows a trade-off behind a different application.

A first-person view (FPV) attack drone usually belongs on the power side. It discharges hard for 15 to 20 minutes, hits a target, and the pack is gone. Weight, discharge rate, availability, and cost beat cycle life.

A reconnaissance drone has a different job. If it is watching a border or a combat area, flight time becomes more important. A logistics drone needs a more balanced design. A speed-only cell cuts range, and an endurance-only cell stalls.

At the far end, ultra-energy cells serve missions where endurance is everything. For example, the Airbus AALTO Zephyr stayed in the stratosphere for 67 days.

On cell format, cylindrical cells dominate mature war-fighting drones because they are cheap and ship in volume.

Pouch cells go into next-generation drones designed around the cell.

It’s the same market name but very different segments.

Order momentum is real, but compliance is uneven

The drone market is now large enough for specialty cell makers to chase.

Amprius shows there is demand.In 2025, the company announced a repeat $35 million purchase order for SiCore cells from a UAS manufacturer, after an earlier $15 million order from the same buyer.

Its sourcing position is more complicated.

In its 2025 annual report, Amprius said Berzelius, a Chinese corporation, developed the material system behind its SiCore batteries. The company also said it sources battery materials mostly from China and relies on Chinese and South Korean contract manufacturers for cell production.

It can create a diligence problem for defense buyers, as they are not yet NDAA-compliant.

KULR is in a different position.

Pack integrators like KULR can win defense drone programs, but they still depend on third-party cells whose origin has to be proven.

Enovix is positioning itself closer to the compliant-cell side. In May 2026, it launched its MX1-B01 drone cell at 360 Wh/kg, described it as NDAA-compliant, and confirmed production in South Korea. Shipments will only start in 2027.

Drones are a small market, but Defense procurement will decide who survives.

The window suppliers are racing into

Buyers need cells that can ship before the rules start biting.

A non-Chinese final assembly line is not enough. The cell still needs cathode, anode, electrolyte, separator, BMS hardware, and firmware that can be documented outside FEOC control.

That is where the market gets tight.

U.S. greenfield builds solve location, but not timing. A new factory line funded by the Defense Production Act Title III or Department of Energy programs can take 3-4 years before the first shipment.

Factories in Korea, Japan, Taiwan, and Europe are in a better position because some are already running.

But they still need non-FEOC material inputs. A Korean or Japanese cell can still run into problems if the anode, separator, electrolyte, software, or licensed technology points back to a restricted supplier.

SES AI is staying ahead of this through its battery factory in Chungju, Korea.

The site was already outside FEOC jurisdictions, and the conversion took only 6-9 months instead of years.

SES finished converting the Chungju plant in April 2026. The factory had been built for EV cells, but those programs wound down by the end of 2025 as Western automakers pulled back on premium chemistry.

The factory shell carried over. So did the dry rooms and formation equipment. Cell size dropped from a 100 amp-hour pouch to a 10 amp-hour pouch. The anode shifted from lithium metal to silicon anode.

From recent customer-exclusive tours, SES says the supply chain is NDAA-compliant. The cathode comes from Korean suppliers. Korean and U.S. suppliers split the silicon-carbon anode. SES makes the electrolyte in Boston and ships it to Korea. Separators come from Japan.

The line is ramping toward 1 million drone cells per year, starting at 500,000. Shipments started back in April 2026.

That is the advantage of using an existing Korean line.

SES AI hosts customer tours of the converted line. I could not attend in person, but I was able to secure an exclusive online factory video for you.

The largest cell makers passed on drones

The biggest cell makers haven’t built drone cells in real volume.

CATL, BYD, LG Energy Solution, Samsung SDI, SK On, and Panasonic put their capital into EVs and stationary storage.

Those markets run in the 100+ GWh per year (now 1000+ for EVs).

The aviation battery market, including drone cells, is small. That doesn’t justify a dedicated gigafactory for them.

The second problem is chemistry/materials.

A drone cell needs higher energy per kilogram (300+ Wh/kg) and greater continuous discharge than an EV cell. It can tolerate a shorter cycle life.

An EV line designed doesn’t fit that profile.

That leaves room for specialty cell suppliers.

A smaller cell maker with the right chemistry and supply chain can beat the biggest names, because none of them ever built capacity for this market.

What Ukraine actually buys

Ukraine is the clearest live case for drone battery demand.

FPV drone production rose from roughly 3,000 units in 2022 to 4-5 million in 2025, according to ChinaTalk and Ukraine Arms Monitor.

Pack assembly has grown inside the country. Pawell Power produces up to 10,000 battery units per month, per Mezha.ua.

The weak point is the cell.

Many packs still use imported cells, mostly from China.

Local pack assembly helps, but it gives Ukraine no control over the active materials, the separator, the electrolyte, the battery management system, or the software around the pack.

Molicel’s P45B 21700 cylindrical cell has become a reference point. The Taiwan-built cell was designed for power tools and e-bikes.

Drone pack builders use it because it delivers 45 amps continuously without becoming too heavy for small aircraft.

Where European and American players still have room

Drone batteries are a small market. That is where Western specialty suppliers have a real opening.

In passenger EVs and grid storage, cost decides the winner. Buyers in those markets can still source from China, especially LFP cells.

Defense drones run on different rules.

That matters because U.S. federal buyers face tighter sourcing rules.

A drone company may not be allowed to use a Chinese cell, even if the cell is cheaper and technically capable. The compliant cell wins because it is the only cell the buyer can use.

That opens the door for NDAA-compliant companies like SES AI.

These companies sell into defense procurement, where documentation outranks price.

The market is small enough for Western suppliers without matching Chinese volume. The customer either pays the premium or cannot bid.

The rule decides the purchase.

Washington and Seoul started writing the same rule

The U.S. and South Korea signed a Letter of Intent on May 15, 2026 to work toward a common battery standard for small drones.

Drone batteries are moving out of normal electronics sourcing and into defense procurement, where buyers care about documented components and restricted suppliers.

The next thing to watch is the FCC Conditional Approval process under Public Notice DA 26-22, issued on January 7, 2026.

Applicants now have to document the country of origin for every component to qualify for exemptions from the Covered List.

Watch the first FCC approvals. If they go to drones using Korean or U.S. cells, the rule is already changing who gets contracts. If approvals slow because companies cannot prove where their parts came from, drone makers will have to fix the supply chain before the 2027 deadline.

The next test comes on January 1, 2028, when Section 842 starts phasing in for new Department of Defense acquisitions.

The rule also reaches beyond drones.

DoD storage systems and government vehicle battery contracts could face the same sourcing logic if their batteries fall within the covered procurement scope.

Price still matters, but in Defense procurement, price only matters after the battery clears the rule.

PS: if you are interested in knowing more about SES AI batteries, you can download their product portfolio below (you need to scroll to the bottom of the page):

SES AI batteries drone

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Data centers are becoming serious battery buyers.

“AI needs more electricity, so data centers will need more batteries.”

That view is too simple.

It mixes two battery applications that share almost nothing in real operation.

A UPS (Uninterruptible Power Supply) battery next to the servers protects against short grid disturbances. A behind-the-meter BESS at the site boundary exists to help the project secure grid connection and manage load within the limits the utility will accept.

These two batteries run on different duty cycles, safety requirements, warranties, and suppliers.

Treating them as one market hides who is buying, what they need, and when they need it.

Grid access is the bottleneck

Hyperscalers can spend hundreds of billions on compute, but transformers and interconnection studies still set the schedule.

Google, Microsoft, Amazon, Meta, and Oracle move faster on real estate and equipment than utilities can move on grid hardware and connection work.

Reuters reported in May 2026 that Big Tech AI infrastructure spending will exceed $700 billion in 2026, up from $410 billion in 2025. The capital is flowing faster than the grid can absorb it.

A hyperscale data center can be built in roughly 18 to 24 months. In parts of the U.S., grid connection can take three to seven years.

U.S. grid operator PJM forecasts 55 GW of new large-load growth by 2030 and 100 GW by 2037.

ERCOT’s large-load queue reached 233 GW by December 2025, up more than 260% year over year, with more than 70% linked to data centers. By late March 2026 that queue had grown to roughly 410 GW, with about 87% tied to data centers.

The queue overstates real near-term demand, but the trajectory shows how aggressively data center load is entering utility planning.

Utilities cannot move at hyperscaler speed. Behind-the-meter (BTM) batteries now show up in interconnection applications because they let the site show lower peak demand and more flexible load behavior.

In some cases, utilities may accept earlier, phased, or conditional energization when the battery is tied to enforceable terms covering operating envelope, controls, metering, and curtailment rights.

The battery does not remove the need for grid upgrades but it reduces pressure on the connection while those upgrades happen.

Investment bank Jefferies estimates the hyperscaler behind-the-meter BESS market at 20 GW through 2035.

Aligned Data Centers paired a 31 MW / 62 MWh system with Calibrant Energy in the Pacific Northwest. Calibrant sized the battery so the site could interconnect years earlier than a standard utility upgrade would allow. The project starts with the site and the need for power on a schedule that matches already-financed compute.

A utility storage project starts with grid needs and market revenue.

Hyperscalers buy batteries for schedule and interconnection

A utility buyer follows regulated planning and procurement cycles. A hyperscaler starts with a practical question: can this facility receive enough power soon enough to go live and avoid stranded investment?

Cell price still matters, but it is one factor among several.

The system has to fit how the site runs and help meet interconnection requirements. The battery needs to shape load or limit peaks in a way utilities will accept.

A battery that energizes a site earlier closes the gap between capex and revenue.

Warranty terms and degradation under the real duty cycle dominate the specification, alongside compatibility with on-site electrical gear. Outage risk and schedule certainty drive the spec more than raw energy capacity.

A lower-priced cell that cannot meet these integration or performance requirements will lose to a system that gets the compute revenue flowing earlier.

Hyperscalers and data center developers are starting to use batteries to lock in power and pull schedules forward.

Batteries now serve more than backup

Microsoft deployed lithium-ion UPS batteries with Eaton's EnergyAware technology in its Dublin data center, where they participate in EirGrid's DS3 frequency response market through aggregation.

Google’s Saint-Ghislain site operates a 2.75 MW / 5.5 MWh Fluence system that provides both site backup and Belgian grid frequency services.

Both batteries keep their primary protection role during grid disturbances. They also deliver grid services during normal operation. The asset earns money between outages instead of sitting idle.

Interconnection approval increasingly depends on whether the site can show credible load management.

Developers specify and deploy batteries because they can shape site demand profiles in ways utilities find acceptable for earlier or more flexible connections.

Two distinct battery layers

Data center battery demand splits into at least two layers with different technical requirements.

• Power-layer batteries sit close to critical power equipment. Buyers judge them on response speed, recharge time, power capability, safety certification, and UPS integration. Their typical duty cycle runs through long periods of standby with occasional short, high-power events. They bridge disturbances until backup generation starts.

• Energy-layer batteries live behind the meter or further out. Buyers weigh them on duration, degradation under frequent cycling, peak-management capacity, and flexible load behavior for interconnection. These batteries can earn revenue from ancillary services between outage events.

Long-duration storage is its own category. It addresses multi-hour or multi-day gaps and follows different technical and commercial rules. But, it does not replace the lithium-ion systems placed near electrical rooms.

Meta has a PPA tied to a 300 MW solar plus 300 MW / 1,200 MWh BESS project in Arizona. The asset is an outer-layer energy product with its own ownership and contract structure.

Google, Xcel Energy, and Form Energy’s iron-air deals show longer-duration approaches for renewable firming.

Buyers contract these projects on different terms than the batteries that sit next to the UPS or behind the site meter.

LFP remains the default

LFP is the standard choice for most stationary BESS applications around data centers. It costs less than NMC and offers longer cycle life.

BloombergNEF reported 2025 stationary lithium-ion pack prices at $70/kWh, down 45% year over year.

In January 2025, a fire at Vistra’s Moss Landing 300 system in California damaged about 55% of the site’s roughly 100,000 lithium-ion batteries.

The Phase 1 system used LG JH4 NMC cells. It was one of the first large-scale BESS installations and was designed before the first edition of NFPA 855 became a common reference point for stationary battery fire safety. Active flames were visible through January 17, with smoldering and residual heat persisting until January 22.

The incident added pressure on code authorities and project developers to revisit indoor layouts, chemistry choices, thermal runaway containment, and emergency response. That scrutiny matters even more near critical loads.

NMC is not finished, but for many stationary projects near sensitive equipment, LFP is now the easier default because it combines lower cost with better thermal stability.

Sodium-ion could fit short, high-power duty cycles in the UPS power layer. Until suppliers clear certification and prove production that buyers will finance, the layer stays with established UPS chemistries and proven lithium-ion systems.

Specification control beats cell price

In data center battery deals, whoever writes the spec captures more margin than the cheapest cell supplier.

Near the critical load, critical-power vendors like Vertiv, Eaton, Schneider Electric, and ABB are already inside the electrical design.

When the battery must meet UPS performance or backup requirements, these vendors define the specification before pure cell suppliers come in.

At the BTM or grid-connection layer the buyer group is wider. BESS integrators, developers, hyperscaler energy teams, or utilities lead the deal.

Competition shifts toward full-system providers that can deliver integration, project execution, financing, and ongoing support across backup and flexibility duties.

A cell supplier without systems capability or specification influence risks becoming a parts vendor with thin margin.

Suppliers that can offer financeable, integrated systems with clear performance on load shaping and interconnection compliance hold a stronger position.

Chinese and Korean suppliers face different constraints

Chinese suppliers already cover much of the stationary storage chain, from cell production through to commissioned project handover, with their own integrators in between.

Their domestic experience with integrated power projects fits data center site-power planning. In the United States, suppliers balance speed and cost against tariffs and FEOC content rules under the investment tax credit.

This opens a window for Korean suppliers.

Samsung SDI has flagged data centers as a major growth area for U.S. ESS and is positioning converted lines to serve this need with compliant supply.

The company expects U.S. data-center ESS demand to rise from about 9 GWh in 2025 to more than 40 GWh by 2030. That forecast explains why Korean players are trying to turn U.S. EV capacity into ESS capacity.

Buyers still weigh delivery speed, integration with site systems, warranty performance under expected cycling, and sourcing compliance.

Policy and fire risk tighten the spec

In the U.S, policy risk remains.

FEOC rules increasingly matter because energy storage projects can lose tax-credit eligibility if key components rely on prohibited foreign entity material assistance.

Fire-code scrutiny tightened after Moss Landing, with more attention on testing, installation design, thermal runaway containment, and emergency response near critical loads.

Execution risk includes limited skilled labor and EPC capacity for high-power battery integration.

Operators position batteries as the flexible layer alongside other on-site firm sources such as nuclear restarts or SMRs.

The projects that energize on schedule treat the battery as part of the site power architecture.

Uncertainty about how much of the headline queue will actually energize also favors batteries, because they support phased or conditional energization.

Gas turbine delivery times have been pushed into the 2030s. Batteries can be deployed faster, depending on permitting and integration.

For a hyperscaler, the battery's value usually begins with one number: how many months earlier the site can energize.

A system that supports earlier approval or shows acceptable load behavior to the utility reduces the cost of delay.

The winning systems get the site to power faster and still meet backup duty.

Response speed, cycling degradation, ownership model, and integration all decide which ones do.

Specification and ownership set the terms

Battery economics depend on who writes the spec and who owns the asset.

A hyperscaler that owns the project sets terms directly. Critical-power vendors get to shape the spec when UPS integration is on the table.

When the focus shifts to interconnection or financed energy delivery, utilities or PPA counterparties take over the terms.

Direct ownership, third-party developer structures, PPA terms, and co-location arrangements all create different expectations on cycling, warranties, degradation, and integration work.

Procurement documents reveal market direction more clearly than aggregate forecasts. Watch the terms on discharge rate, duration, duty cycle, sourcing, and warranty alignment with actual use.

They show which layer of the data center battery market is moving first, and which suppliers can take it.

P.S. Whenever you’re ready, here are three ways I can help:

1. Battery industry reports

I’ve published two so far: The Battery Starter Kit, to help you get up to speed on the battery industry, and the CATL Company Profile, to help you understand how CATL operates and why it leads the market.

You can find them here: Battery industry reports

2. Consulting projects

I help companies answer battery-industry questions through a market lens: demand, technology adoption, competitive moves, customer segments, and value chain shifts.

If you’re working through a strategic question, reply to this email with a short note on what you’re trying to figure out.

3. 1:1 paid call

If you have a specific battery market question, I offer paid 1:1 calls when there is a clear topic to work through.

Reply to this email with the question, the context, and what decision you’re trying to make. If it is a fit, I’ll send the next step.

The EU Battery Regulation has a chemistry problem.

LFP is covered, but the issue is what the regulation values.

Lithium iron phosphate batteries still fall under the regulation’s lithium rules, collection duties, Extended Producer Responsibility, due diligence requirements, and battery passport system.

The problem is narrower than that, and more awkward.

The recycled-content part of the law was built around cobalt, lithium, nickel, and lead. That works cleanly for a nickel-rich market. It works less for the market now forming in Europe, where LFP is moving into lower-cost EVs and battery storage.

The law still reaches LFP. But it does not value LFP in the same way it values nickel- and cobalt-based chemistries.

That is where the trouble starts.

What the regulation counts

Regulation (EU) 2023/1542 puts recycled-content targets on four materials: cobalt, lithium, nickel, and lead.

From 18 August 2031, covered batteries must contain:

• 16% recycled cobalt

• 6% recycled lithium

• 6% recycled nickel

• 85% recycled lead

From 18 August 2036, those targets rise to:

• 26% recycled cobalt

• 12% recycled lithium

• 15% recycled nickel

• 85% recycled lead

The 2031 targets apply to EV batteries, SLI batteries, and industrial batteries above 2 kWh, except industrial batteries with exclusively external storage.

LMT batteries enter later, with documentation from 2033 and minimum recycled-content thresholds from 2036.

Recyclers also face recovery targets.

By the end of 2027, they must recover 90% of cobalt, copper, nickel, and lead, and 50% of lithium.

By the end of 2031, those targets will rise to 95% for cobalt, copper, nickel, and lead, and 80% for lithium.

The battery passport arrives earlier.

From 18 February 2027, EV batteries, LMT batteries, and industrial batteries above 2 kWh must carry a digital battery passport. Recycled-content data will sit inside that system.

It is a law with a very clear material hierarchy.

Cobalt, nickel, lithium, and lead sit at the center. Iron, phosphate, manganese, and graphite do not.

That choice made more sense when Europe’s battery market looked more nickel-heavy.

It looks less safe now.

The market moved

Europe is not replacing every nickel-rich battery with an LFP battery.

Premium EVs and long-range models will still need NMC and NCA.

Those chemistries offer higher energy density, and automakers will continue using them where range and performance justify the cost.

But the market is splitting.

LFP is becoming the chemistry for cheaper EVs, standard-range models, and stationary storage. It is cheaper, durable, and avoids nickel and cobalt in the cathode.

That shift is no longer theoretical.

CATL’s Debrecen plant in Hungary has been reported as expected to start production around late 2025 or early 2026.

Stellantis and CATL are moving ahead with an LFP plant in Zaragoza, with planned capacity of up to 50 GWh.

Volkswagen’s PowerCo is building a chemistry-flexible battery plant in Valencia, designed to produce cells using chemistries including LFP and NMC.

LG Energy Solution has agreed to supply LFP cells to Renault’s Ampere business from late 2025 through 2030.

The exact chemistry mix will vary by plant and customer. But the direction is plain enough.

Europe’s future battery market will not be a single-chemistry market but segmented.

LFP will take more of the cost-sensitive market. Nickel-rich chemistries will hold the premium end. Battery storage will lean heavily toward LFP.

The regulation was not written for that mix.

LFP is covered, but not rewarded in the same way

An LFP battery still has to comply with the Battery Regulation.

It still faces the lithium recycled-content target. It still falls under collection and treatment rules. It still has to fit into the passport system. Producers still carry responsibility for end-of-life costs.

None of that solves the recycler’s problem.

A nickel-rich battery gives recyclers several valuable metals to recover. Nickel and cobalt help pay for collection, processing, refining, and compliance. Lithium adds more value.

An LFP battery has a thinner revenue stack. It contains lithium, iron, phosphate, graphite, copper, aluminum, and other materials, but the cathode has no nickel or cobalt.

That leaves recyclers with less high-value material to sell.

Lithium can be recovered from LFP. Iron phosphate may also find a route back into new cathode material. Direct recycling could improve the numbers if it reaches commercial scale.

Europe is not there yet.

Until it is, LFP recycling will need one of three things: higher gate fees, lower processing costs, or stronger demand for recovered iron phosphate.

The law can require recovery.

It can make producers pay, but it cannot make bad unit economics disappear.

Graphite is the blind spot

Graphite is still the standard anode material in most lithium-ion batteries. By mass, it is one of the larger active-material streams in the cell.

Natural graphite sits inside the Battery Regulation’s due diligence framework. Article 8 excludes it from the recycled-content targets, and Annex XII provides no recovery rate for it.

That is a strange place to leave it.

Europe has very little domestic anode capacity.

The graphite supply chain is still heavily concentrated in China. Yet the regulation treats graphite differently from cobalt, nickel, and lithium because it carries less value per tonne.

That logic is weak.

A material can be cheap and still be hard to secure.

Graphite should be part of the 2028 review, and Europe needs a recovery plan for it.

August 2026 matters more than it sounds

The next important date is 18 August 2026.

By then, the Commission must adopt the delegated act that sets the method for calculating and verifying recycled content.

That method will decide how strict the chain of custody becomes.

If Brussels allows broad mass-balance accounting, compliance becomes easier. Producers can meet the rule with less direct connection between the recycled material and the battery placed on the market.

That would lower the cost. It would also weaken the link between the regulation and new recycling capacity in Europe.

If Brussels requires tighter physical traceability, the rule becomes harder to meet. More material would need to move through verified recycling and refining routes.

That helps the industrial-policy case. It also adds cost to European cell makers already competing with cheaper Asian supply chains.

This is the real 2026 decision.

The 2031 targets set the destination. The August 2026 methodology decides how companies are allowed to get there.

The law needs to follow the fleet

The Battery Regulation still does useful work. It forces producers to plan for the end of life. It creates traceability. It sets recovery targets. It gives Europe a common rulebook for circular batteries.

But the chemistry mix has moved faster than the law.

The 2028 review should start with the material list. Cobalt, nickel, lithium, and lead made sense as the center of the system when Europe expected a more nickel-heavy fleet. That is no longer the only fleet being built.

Graphite needs a proper recovery plan. Manganese deserves another look. If LFP continues to gain market share, Brussels will also have to decide whether iron and phosphate can remain outside the recovery logic.

The regulation covers LFP.

It just rewards a nickel-and-cobalt battery market more than the one Europe is now building.

That gap is manageable today. By the 2030s, it may not be.

P.S. Whenever you’re ready, here are three ways I can help:

1. Battery industry reports

I’ve published two so far: The Battery Starter Kit, to help you get up to speed on the battery industry, and the CATL Company Profile, to help you understand how CATL operates and why it leads the market.

You can find them here: Battery industry reports

2. Consulting projects

I help companies answer battery-industry questions through a market lens: demand, technology adoption, competitive moves, customer segments, and value chain shifts.

If you’re working through a strategic question, reply to this email with a short note on what you’re trying to figure out.

3. 1:1 paid call

If you have a specific battery market question, I offer paid 1:1 calls when there is a clear topic to work through.

Reply to this email with the question, the context, and what decision you’re trying to make. If it is a fit, I’ll send the next step.