In a single year, the cost of battery storage fell by 40%. According to the BNEF Battery Storage System Cost Survey, the cost of stationary battery energy storage systems (BESS) stood at $165 per kWh in 2024, while the price of lithium-ion packs for all uses reached $115 per kWh. The International Energy Agency’s Electricity 2026 report, published in early 2026, cites an average global cost of approximately $213 per kWh for 2024 and focuses on grid flexibility challenges. This is the moment when an argument that has structured energy debate for forty years has just lost its technical foundation.

Intermittency has long been the decisive objection against solar and wind power. The sun doesn’t shine at night. The wind doesn’t blow on command. Without a solution to store energy produced at the wrong times, renewables could not ensure the supply security of a modern electrical grid. This argument has not disappeared, but it has fundamentally transformed: it is no longer an insurmountable physical constraint, but an economic challenge being resolved. The question that remains entirely open is strategic: to succeed in this transition, must the world accept a decade of industrial dependence on China?

The Essentials

  • The cost of battery storage fell by 40% in 2024: stationary storage systems reached $165/kWh according to BNEF, lithium-ion packs for all uses $115/kWh
  • Global storage capacity increased twelvefold between 2020 and 2024, exceeding 124 GW installed
  • In Texas, grid balancing service costs fell 74% in one year thanks to storage
  • 85% of the battery production chain remains concentrated in China, creating structural dependence for at least a decade

The New Cost Thresholds That Change the Equation

To understand why these price levels represent a break, we must start with recent history. In 2010, the average cost of lithium-ion storage was around $1,100 per kWh. Economic parity with peak gas plants, used precisely to respond to demand variations, required dropping below $250. This threshold was crossed around 2020. The decline that has occurred since is of a different order.

A 40% drop in a single year in 2024 exceeds the most optimistic projections that analysts were formulating three years earlier. BloombergNEF’s forecasts for 2030 oscillated between $60 and $80 per kWh depending on the year of publication — as early as 2019, BNEF already anticipated approximately $60/kWh for packs at that horizon. The price of $151/kWh observed in 2022 was actually an exceptional increase, not a forward-looking target. The IEA itself had banked on a more gradual trajectory. What the models had not fully integrated was the combined effect of large-scale industrialization of Chinese production chains, intense competition between manufacturers, and economies of scale linked to the explosion in demand driven by electric vehicles.

The result is a market being rewritten at a speed that energy planners are still struggling to incorporate into their scenarios. At the cost levels reached in 2024, building a storage system capable of shifting several hours of solar production to evening costs less, in many markets, than maintaining a gas plant in partial service to ensure this flexibility.

From 10 GW to 124 GW in Four Years: What This Multiplication Reveals

Global stationary storage capacity exceeded 124 gigawatts in 2024, compared to less than 11 gigawatts in 2020. A twelvefold multiplication in four years is not simply an impressive statistic: it is the signature of a technology that has crossed the threshold of industrial deployment.

Two types of actors explain this acceleration. On one side, utilities and grid operators investing in large-scale installations to manage flexibility at the system level. On the other, solar developers who integrate storage directly into their projects, creating hybrid power plants capable of delivering energy at programmed hours.

Texas illustrates what this shift produces concretely. The state, which has an isolated electrical grid managed by operator ERCOT, saw its ancillary services costs—that is, the costs paid to maintain instant balance between production and consumption—fall 74% in one year. These services were historically provided by thermal plants capable of ramping up or down quickly in output. Batteries now do this faster, with fewer losses, and at lower cost.

This case is not isolated. In South Australia, a pioneering state that now draws more than 70% of its electricity from renewables, batteries have helped stabilize a grid that many predicted would be unmanageable. In California, solar projects coupled with storage are winning competitive bidding at prices lower than new gas plants. I had documented this dynamic in a previous article: the coupling between production and storage transforms the very nature of what renewables can offer to a grid.

What Remains True in the Intermittency Argument

Saying that the intermittency argument has disappeared would be an overstatement. What disappears is its absolute version: “renewables cannot ensure grid security.” What remains is its economic and systemic version: at what scale, at what cost, with what constraints can storage actually fulfill this function?

Three limitations deserve to be named precisely. The first is seasonal. Batteries are effective at shifting a few hours of production, typically from daytime to evening for solar. They are much less effective at managing prolonged periods of low production, like a week of cloudy skies in winter in temperate countries. This challenge, distinct from daily intermittency, remains open and requires other solutions: long-distance interconnections, hydrogen, pumped hydro, or even nuclear depending on national contexts.

The second limitation is geographic. The cost savings documented in Texas or California don’t mechanically reproduce in markets where regulation, access to capital, or demand are structurally different. In many developing countries, the real obstacle to storage is not technological cost but financing capacity and investment conditions.

The third limitation is systemic. A grid with very high renewable penetration, say 80% or more, poses questions of frequency stability, system inertia, and cascade failure management that storage alone does not solve. These challenges are real, they are the subject of intense research, and some countries like the United Kingdom or Denmark are already managing them at high penetration levels, but they don’t automatically disappear with falling costs.

85% of the Battery Chain in China: A Dilemma With No Simple Answer

This is where optimism about the energy transition meets its most difficult constraint to formulate without oversimplifying. The cost decline that makes storage accessible globally is, for the most part, the product of a Chinese industrial and political decision: to invest massively, over two decades, in lithium-ion battery manufacturing.

Today, according to IEA data, 85% of the battery production chain, from lithium extraction to cell assembly, is concentrated in China or depends on Chinese components. CATL, the world’s leading manufacturer, alone holds more than 35% of the global battery market for stationary storage. BYD, EVE Energy, and several other Chinese manufacturers occupy the following positions.

This concentration creates a dilemma that neither Europe, nor the United States, nor Japan has really resolved. Accelerating the energy transition by deploying storage now means consolidating industrial dependence on China for at least a decade. Waiting for alternative chains to become operational means slowing decarbonization, with real climate costs.

Attempts to build alternatives do exist. The American Inflation Reduction Act mobilized several tens of billions of dollars to develop a domestic battery industry, with preliminary results: several gigafactories are under construction, including projects led by Panasonic, Samsung SDI, and American actors like Eos Energy. Europe launched the European Battery Alliance, which enabled the emergence of Northvolt in Sweden, even though the latter faced serious financial difficulties in 2024. But industrial timelines are incompressible: building a competitive supply chain against Chinese advantage takes between ten and fifteen years according to the most solid estimates.

American trade policy has added a layer of complexity. Tariffs imposed on Chinese batteries and components under successive administrations have limited imports, but without the local industry yet being able to bridge the cost differential. The result, for now, is a more expensive transition in the United States than it could be with Chinese batteries, which precisely slows the deployment that these policies are supposed to protect.

This is not an indefinitely untenable position, but it is a real tension that rhetoric about energy sovereignty tends to underestimate. The race for AI illustrates a similar dilemma: energy demand is exploding, and technological and geopolitical choices are colliding uncomfortably.

What Regulators Are Beginning to Learn

The good news is that several electrical systems show that it is possible to manage growing penetration of storage without systemic catastrophe, and sometimes with unexpected benefits.

South Australia is the most cited example because it preceded the others. Tesla’s “big battery” at Hornsdale, inaugurated in 2017, was then a bold wager. It responded to a grid failure in less than 140 milliseconds, where reserve gas plants took several minutes. Since then, the battery fleet in South Australia has been multiplied by twenty, and the state regularly exports renewable electricity to its neighbors.

What is learned in these experiments is grid regulation. Electricity markets were designed for dispatchable thermal plants. The rules for remunerating balancing services, the conditions for market access, the technical requirements for battery participation, all of this had to be rewritten. Australian, Californian, British, and Texan regulators have accumulated expertise that other countries are only beginning to acquire.

The challenge for the coming decade is not only technological or industrial. It is a regulatory and governance challenge: how to design electricity markets that allow storage to deploy its true economic value? How to distribute the costs of the transition between producers, consumers, and the state? How to integrate industrial sovereignty objectives without blocking a technological deployment whose climate benefits are immediate?

These questions have no universal answer. They are already being resolved differently in California, Germany, and China, with results that other systems are watching carefully.

The Argument Has Changed Nature, the Debate Remains Open

The decline in storage costs doesn’t resolve the energy transition. It transforms its terms. What was a physically difficult-to-overcome constraint has become a political and industrial choice: how quickly to deploy, with what dependence accepted, with what market rules, with what level of managed systemic risk.

This is less comfortable terrain than the intermittency argument, because it no longer allows outright rejection of the problem. Decision-makers who opposed the transition by invoking technical impossibility have lost their main argument. Those who support it must now answer more precise questions: how to manage dependence on China? How to finance storage in low-income economies? How to regulate increasingly complex grids?

These questions are harder to evade than intermittency was. They also have the advantage of being the real ones.

Sources

  1. IEA, Electricity 2026 — Flexibility, January 2026: https://www.iea.org/reports/electricity-2026/flexibility
  2. BloombergNEF, Energy Storage Market Outlook (cited without URL, paid report)
  3. ERCOT, Ancillary Services Cost Reports, 2023-2024 (cited without URL, public data available on the ERCOT website)
  4. IEA, Global EV Outlook 2024: https://www.iea.org/reports/global-ev-outlook-2024
  5. Australian Energy Market Operator (AEMO), South Australia Renewable Energy Report, 2024 (cited without URL)
  6. BNEF, Battery Storage System Cost Survey 2024: https://www.energy-storage.news/behind-the-numbers-bnef-finds-40-year-on-year-drop-in-bess-costs/
  7. BNEF, Lithium-Ion Battery Pack Prices 2024: https://about.bnef.com/insights/commodities/lithium-ion-battery-pack-prices-see-largest-drop-since-2017-falling-to-115-per-kilowatt-hour-bloombergnef/
  8. BNEF, Lithium-Ion Battery Pack Prices 2022: https://about.bnef.com/insights/commodities/lithium-ion-battery-pack-prices-rise-for-first-time-to-an-average-of-151-kwh/
  9. CATL, 2024 Annual Report: https://en.tmtpost.com/post/7516919
  10. IEA, Global battery markets are growing strongly — and so are the supply risks, February 2026: https://www.iea.org/commentaries/global-battery-markets-are-growing-strongly-and-so-are-the-supply-risks
  11. ElectraNet / Government of South Australia: https://www.energymining.sa.gov.au/consumers/energy-grid-and-supply/our-electricity-supply-and-market