Editorial Article

Stationary Energy Storage: The Battery Market Beyond Electric Vehicles

Updated September 11, 2026

Stationary Energy Storage: The Battery Market That Isn’t About Cars

For a decade, every battery story has been a car story. Electric vehicles absorb the overwhelming majority of cell supply, they set the chemistry roadmap, and they collect the policy attention. The next chapter will be written by batteries that never move.

Grid storage — the utility-scale, commercial and industrial, and residential systems that sit still and dispatch electricity — is now the fastest-growing power technology in the world. The IEA’s Global Energy Review 2026 counts 108 GW of new battery storage added in 2025, around 40% more than in 2024 and more than the historical peak for gas-fired capacity additions (about 107 GW, in 2002). Installed capacity is now eleven times its 2021 level. A second industry tally puts the year slightly higher at 112 GW/307 GWh, up 48% in power terms and the first year above 100 GW.

Pheonix Research sizes the global stationary energy storage systems (ESS) market at USD 64.54 billion in 2025, reaching USD 247.68 billion by 2033 at an 18.31% CAGR — a 3.84x expansion, or +283.8% in eight years. On those forecasts, storage is worth roughly 70% of the entire EV battery market in 2025, easing to about 67% by 2033. This is not a niche adjacent to the battery industry. It is the other half of it.

Why a stationary battery is a different product

The differences start with what the customer is buying. In a vehicle, the battery is a mass-and-volume problem: every kilogram of cell costs range. In a substation yard, mass is irrelevant and volume is nearly irrelevant. What matters is cost per cycle, calendar life, round-trip efficiency and — increasingly — how many hours the system can hold its rated output.

That reorders the chemistry hierarchy. The IEA notes that lithium-iron-phosphate (LFP) now accounts for around 90% of storage deployments, against well under half five years ago. LFP is less energy-dense than the nickel chemistries cars prefer, and that penalty — so costly on the road — costs nothing in a container.

It also reorders who captures the value. A grid-scale BESS is not a cell. It is cells assembled into racks, wrapped in power conversion equipment, a battery management system, thermal management and controls, connected to a substation and dispatched by software against market rules. Roughly half the project cost sits outside the cell. The decisive capabilities here are integration and grid access, which is why a company that never built a cell can lead the market — and why vehicle chemistries do not automatically win.

Duration is the other structural feature. Most projects still cluster around two hours; a growing share is built at four hours or more. The arithmetic of the past two years shows the drift: 307 GWh over 112 GW implies an average of about 2.74 hours in 2025, and the current-year pipeline — 459 GWh over 158 GW — implies about 2.91 hours. Long-duration storage of six hours or more is set to quadruple in 2026 to roughly 2 GW, most of it non-lithium and concentrated in China.

The market numbers

Pheonix’s forecasts place storage at the centre of a battery-and-power cluster compounding in the mid-to-high teens.

Market	2025 (USD bn)	2033 (USD bn)	CAGR
EV battery	91.70	369.50	19.03%
Stationary energy storage (ESS)	64.54	247.68	18.31%
Battery recycling	21.69	78.83	17.51%
Battery manufacturing equipment	19.41	68.25	17.02%
Battery electrolyte production	11.49	41.08	17.27%
EV charging infrastructure	40.22	147.28	17.61%
Nickel mining	93.70	324.07	16.78%
Lithium mining	1.40	5.62	18.97%

One ratio frames the whole story. Storage is equivalent to about 70.4% of the value of the EV battery market in 2025, easing to 67.0% by 2033 — a ratio of two market forecasts, not a cost breakdown. The direction is the point: storage is where surplus cell capacity gets monetised. When Chinese cell lines outrun vehicle demand, the grid is the buyer of last resort, and it clears at whatever price keeps a line running. That is the engine under this market’s volume — and the cap on its pricing.

The record year, region by region

The IEA puts China at around 60% of 2025 global battery additions, ahead of the United States and Europe, with widening momentum in Australia and parts of the Middle East. But the fastest-moving story of 2026 is Saudi Arabia.

The Kingdom connected the world’s largest battery storage system in December 2025 — 7.8 GWh across three sites at Najran, Khamis Mushait and Madaya, each 2.6 GWh and connected at 380 kV, owned by Saudi Electricity Company with Sungrow supplying the equipment. Sungrow manufactured more than 1,500 PowerTitan 2.0 units in 58 days.
In August 2026 the Saudi Power Procurement Company signed four 500 MW, four-hour (2,000 MWh) storage service agreements for 2 GW/8 GWh, worth more than USD 1.16 billion, under 15-year contracts — three to an ACWA Power-led consortium, one to Engie. A second tender for 3 GW/12 GWh opened in April 2026. The national target is 48 GWh by 2030.
In July 2026, Saudi Arabia led global utility-scale installations: 2.5 GW/12.5 GWh of the 9.1 GW/33.4 GWh added worldwide, ahead of China’s 3.7 GW/10 GWh.

India is the other market to watch: from 0.5 GW/0.9 GWh installed in 2025 to roughly 1.8 GW/5.4 GWh expected in 2026 as government-auctioned projects come online, on a path that industry forecasts place sixth-largest globally by 2036.

The pattern across all three is the same. Storage is no longer procured as a sustainability accessory bolted onto a solar farm. It is procured as capacity — contracted, priced and paid for on availability.

What it costs, and why the price is political

Battery storage has become the cheapest battery segment in the world. Industry price surveys put lithium-ion pack prices at a record low of about USD 108/kWh in late 2025, with stationary-storage packs nearer USD 70/kWh — below electric-vehicle packs, because a stationary system tolerates cheaper, denser, slightly heavier LFP cells with no range penalty. The global average turnkey price for a BESS landed near USD 117/kWh for 2025, down about 31% year on year.

Ember’s benchmark, excluding China and the United States, puts all-in capex for a four-hour-plus utility-scale project at about USD 125/kWh — roughly USD 75/kWh for equipment shipped from China and USD 50/kWh to install and connect — with a levelised cost of storage near USD 65/MWh.

Then the regional spread opens up, and it is not a technology gap:

China: four-hour turnkey systems land around USD 90–130/kWh, with the most aggressive equipment bids in the low USD 50s.
Europe: roughly USD 160–200/kWh on an equipment-plus-EPC basis, with broader cost boundaries nearer USD 275/kWh.
United States: above USD 230/kWh on analyst benchmarks, with NREL’s fuller cost accounting nearer USD 330/kWh for a four-hour utility system.

That is a two-to-three-times spread driven by tariffs, labour, fire engineering, permitting and grid codes. Duration economics matter too: an hour-long system carries roughly a 35% per-kWh premium over a four-hour reference, while an eight-hour system trades at a small discount, because power costs amortise across more energy. And since roughly half the stack is not cells at all, integration quality moves the number as much as cell price does.

The United States: records inside a hostile policy frame

The US added a record 6.7 GW/20.2 GWh of storage in the second quarter of 2026, more than double the prior quarter, including 17.9 GWh of utility-scale projects and seven individual sites of 1,000 MWh or more. Just over half of new utility-scale capacity was standalone rather than solar-paired. First-half additions reached nearly 10.3 GW/31 GWh, up 23% year on year, and cumulative US capacity has almost doubled in 18 months, from 88 GWh to 165 GWh. The 2026 forecast was revised up to 71 GWh, from 59 GWh in 2025.

That happened at the same time as the policy environment tightened sharply:

Foreign-entity-of-concern (FEOC) rules introduced via the One Big Beautiful Bill Act took effect from 2026. If a project incorporates “material assistance” from a prohibited foreign entity, it is disqualified from the clean electricity production and investment credits. Treasury’s interim guidance (IRS Notice 2026-15) set out safe harbours and a material-assistance cost ratio, but left identification of prohibited entities partly unresolved.
The credit gap is enormous. A project using domestically produced batteries that meets the FEOC test can claim a 30% investment tax credit plus a 10% domestic-content adder — roughly 40% — against 0% for a project using Chinese cells. The credits begin phasing down after 2033.
Tariffs move unpredictably. After the Supreme Court struck down the use of emergency powers for tariffs in February 2026, a 10% global tariff was announced on 24 February and raised to 15% by early March.

The paradox is genuine: the deployments are real, and the returns now depend on supply-chain provenance rather than on generation economics. Storage is being deployed fastest in states that did not vote for the administration imposing the rules — 74% of second-quarter additions came from states won in 2024.

China: from mandate to market

China has been the volume engine, and in 2026 it changed how storage gets paid. In January, the NDRC and National Energy Administration issued Document No. 114, extending capacity pricing to grid-side standalone storage for the first time nationally, with levels set as a proportion of local coal capacity prices. By early April, roughly 20 provinces had revised or drafted their mechanisms.

The design detail matters more than the headline. Capacity payments now turn on a “capacity coefficient” — a system’s continuous full-power duration divided by a local reference duration, capped at 1 — with reference durations running from four hours in Hebei to ten in Hubei. Duration is now the thing the market pays for. In provinces such as Gansu, Yunnan and Jilin, capacity revenue’s share of total generator revenue rose by roughly 10 percentage points to above 15%, against 6–7% in coastal provinces. In parallel, market-based time-of-use pricing is reshaping industrial and commercial storage economics.

China is converting storage from a compliance attachment into a market asset — while continuing to ship most of the world’s hardware.

Who sells it: a Chinese-integrated market

Integrator market-share data reported in mid-2026 makes the structure plain: Chinese system integrators captured 76% of the global BESS market in 2025, and eight of the top ten integrators are now headquartered in China. Tesla and Sungrow held the top two positions for a third consecutive year; BYD rose five places to third. The combined share of the top three fell from 36% to 30% — a reflection of rapid market growth and the rise of mid-tier vendors rather than weakness at the top.

In Europe, Chinese vendors occupy all three leading positions (Sungrow first, with BYD and Huawei behind), with Bulgaria, Romania, Belgium, Spain, the Netherlands and Greece forming a second tier of growth markets. In Asia-Pacific, China accounts for roughly 85% of the market; Australia remains the region’s most accessible market for non-Chinese integrators because of its technical standards and lender preferences, while Southeast Asia is the new frontier.

Half-year shipment tallies put global ESS shipments at 303.40 GWh in the first half of 2026, up 83.45% year on year, with emerging markets outside China, the US and Europe exceeding 20% of system shipments — a share that could reach around 25% for the full year.

Pheonix’s own structural read is that this is a fragmented market with about ten tier-one players, high capital intensity, rising investment and recent M&A activity — with high geopolitical exposure and high overall risk. The competitive fault line is not price; it is bankability. Suppliers are increasingly being assessed on safety record, vertical integration, supply-chain resilience and financial strength, not on the headline cost of a container.

What can’t be built: transformers, switchgear and queues

The binding constraint on this market is not cells. It is the equipment and permission needed to connect them.

Around 2,300 GW of generation and storage sits in US interconnection queues — more than the country’s entire installed capacity — with waits of four to seven years in the densest data-centre markets.
Large power transformers average roughly 128 weeks and generator step-up transformers 144 weeks on mid-2025 utility surveys, with some high-voltage classes moving from about a year’s lead time in 2020 to multiple years. Demand for step-up units is up 274% since 2019 while prices for power transformers have risen 77%. Medium-voltage switchgear has effectively sold out through 2028.
Wood Mackenzie and American Clean Power’s September 2025 supply-chain study modelled deficits across most transformer classes, and Reuters reported in July 2026 that data centres could reach 40% of the US electrical equipment market.

Pheonix lists power electronics supply bottlenecks among the market’s core restraints, alongside FEOC restrictions, rising levelised cost of storage and critical-material supply risk. The equipment squeeze explains an apparent contradiction in the data: storage is being built behind the meter precisely because it lets an operator reduce the size of the grid connection it is waiting on, and energise years earlier. The bottleneck is also the demand driver.

Safety, insurance and the compliance file

Thermal runaway remains the defining peril of a stationary lithium-ion battery — a single cell can cascade into a fire that reignites over days. Two consequences now shape project economics.

First, codes have tightened. The 2026 edition of NFPA 855, the US installation standard, makes a Hazard Mitigation Analysis the default requirement for most installations, strengthens explosion control, adds thermal runaway propagation prevention provisions and requires large-scale fire testing alongside UL 9540A evidence. A system can carry a whole-product certification and still fall short on siting or suppression.

Second, underwriting has followed. Insurers treat the compliance file — hazard analysis, UL 9540A data, spacing, gas detection, suppression design, emergency-response plans — as central to whether an account is written at all, and products-completed-operations cover matters because latent cell defects surface years after commissioning. Pheonix flags certification, safety and compliance risks as a distinct threat to this market, and rates regulatory complexity high. In storage, engineering documentation is a financing instrument.

Long-duration and the substitution question

Pheonix rates substitution risk as high for stationary storage — an unusual call, and a deliberate one. Unlike the electrolyte layer, where liquid chemistry is effectively irreplaceable through 2033, storage is defined by the service it performs rather than the chemistry that performs it. That leaves room for sodium-ion systems competing on cost, for vanadium and iron flow batteries in longer-duration roles, and for iron-air designs targeting multi-day storage — none of which the incumbent lithium supply chain controls.

The evidence is already arriving. Form Energy has signed a 30 GWh iron-air agreement with Xcel Energy and Google — the largest announced energy storage project in the world by energy capacity, at 300 MW over 100 hours — plus a 12 GWh supply deal with data-centre developer Crusoe from 2027, and reports more than 75 GWh of projects under agreement. It raised USD 750 million in August 2026 and is scaling its West Virginia plant toward 500 MW of annual output. Round-trip efficiency is materially worse than lithium’s; the company’s case is that cheap iron and hundred-hour duration matter more in the segments lithium serves worst.

The reasonable expectation through 2033 is not displacement but division of labour: lithium-ion holds the mass market for one-to-four-hour duty, and non-lithium chemistries take the long-duration and cost-floor segments.

What to watch to 2033

Duration, not just capacity. Watch average hours per project and China’s capacity coefficient design — both are signals that the market is being paid for energy rather than power.
US tax-credit provenance. Whether FEOC-compliant domestic supply arrives fast enough before the credits phase down after 2033 is the single biggest variable in Western demand.
Interconnection reform. FERC Order 2023 and the transformer build-out determine whether projects can be delivered, not whether they are wanted.
The data-centre pipeline converting. Behind-the-meter and co-located storage deals moving from announcement to energisation is the clearest read on the next demand step.
Long-duration commercial reality. Iron-air, sodium-ion and flow projects need utilisation data, not just agreements.

Sources and further reading

Pheonix Research market intelligence:

Primary and industry sources:

IEA, Global Energy Review 2026 — battery storage technology chapter; and IEA commentary, “Battery storage is scaling up and taking on a larger system role,” 29 May 2026.
Solar Energy Industries Association and Benchmark Mineral Intelligence, US Energy Storage Market Outlook, Q1 and Q3 2026 editions.
Saudi Power Procurement Company, award of four 500 MW/2,000 MWh storage service agreements, August 2026; Saudi Electricity Company project completion, December 2025 (reported by Energy-Storage.News and pv magazine).
NDRC and National Energy Administration, Notice on Improving Generation-Side Capacity Pricing Mechanisms (Document No. 114), January 2026; RMI, 2026 China Power Market Outlook: 10 Key Trends for Market Players, July 2026.
Regulation (EU) 2023/1542 (Batteries Regulation); European Commission energy storage policy pages and the June 2026 tripartite agreement on energy storage.
IRS Notice 2026-15 on material assistance, prohibited foreign entities and interim safe harbours under IRC Sections 45Y, 48E and 45X.
Ember, “How cheap is battery storage?”, December 2025.
Wood Mackenzie with American Clean Power, Making the Connection: Meeting the Electric T&D Supply Chain Challenge, September 2025; Reuters, “US power companies scramble to secure equipment as data center demand strains supply,” 9 July 2026.
NFPA 855 (2026 edition) and UL 9540/9540A standards, as summarised in specialty insurance market guidance, 2026.
Form Energy corporate disclosures on Xcel Energy/Google and Crusoe agreements, 2026.
Energy-Storage.News, Canary Media and pv magazine reporting on global deployment, integrator market share and tariff/FEOC policy, 2026.

Frequently Asked Questions

How big is the stationary energy storage market?

Pheonix Research values the global stationary energy storage systems (ESS) market at USD 64.54 billion in 2025 and forecasts USD 247.68 billion by 2033, an 18.31% CAGR over the 2026–2033 forecast period.

How much battery storage was installed worldwide in 2025?

The IEA counts 108 GW of new battery storage capacity in 2025, about 40% more than 2024 and more than the historical peak for gas-fired additions. A second industry tally puts 2025 at 112 GW/307 GWh, with 158 GW/459 GWh expected for 2026.

Why is storage growing so fast in the United States if tax rules tightened?

Because demand is driven by grid connection queues and electricity price volatility rather than by credits alone. US storage hit a record 6.7 GW/20.2 GWh in the second quarter of 2026, with cumulative capacity nearly doubling in 18 months to 165 GWh — even as FEOC rules disqualify Chinese-cell projects from the investment tax credit and tariffs fluctuate.

Which companies lead the energy storage market?

Chinese integrators held 76% of the global BESS market in 2025, with eight of the top ten headquartered in China. Tesla and Sungrow have held the top two positions for three consecutive years, with BYD third, and Chinese vendors hold all three leading positions in Europe.