The capital cost for long-duration (4 hours or more) utility-scale battery energy storage systems (BESS) in markets outside China and the U.S. reached roughly $125/kWh by October 2025, according to a recent report by Ember.

This cost reflects a split of around $75 for core equipment and about $50 for installation, engineering, and grid connection.

Such reductions translate into a levelized cost of storage (LCOS) of $65/MWh for large, contracted projects. This figure represents the cost of moving one megawatt-hour of electricity from one time to another. However, this LCOS excludes the cost of charging electricity, thereby isolating the true cost of storage infrastructure.

Why Prices Are Falling So Quickly

Core equipment prices fell by about 40% in 2024 compared with 2023. Provisional data and tender results suggest another significant drop in 2025.

BloombergNEF’s 2024 global benchmark for core BESS equipment was around $165/kWh, but this figure averages higher-cost markets such as the U.S. and a wider supplier base. The $75/kWh cited for 2025 reflects large-scale procurement of Chinese equipment in lower-tariff markets late in the year. The implied 55% fall between the two, therefore, is not representative of global conditions.

The global manufacturing landscape has also expanded rapidly, and 2024 saw a large oversupply, roughly three times annual demand. This market imbalance has forced suppliers to compete aggressively. Non-equipment costs such as civil works and grid connection have also edged down, but their contribution to the overall reduction in project capex is much smaller than the impact of falling battery and enclosure prices.

Longer lifetimes, higher round-trip efficiency, and improved degradation rates have reduced the per-unit cost of stored energy. Modern utility storage systems routinely achieve about 90% efficiency and can operate for 20 years at one cycle per day. Many now deliver between 10,000 and 12,000 cycles over their lifetimes. Earlier generations typically operated at around 80–85% efficiency and were designed for a lifespan of closer to 10 years, so these improvements alone have shaved tens of dollars per MWh off LCOS.

Manufacturers and developers have streamlined project assembly through modular plug-and-play designs. As a result, installation risk is lower, and soft costs are more predictable. Over the past decade, total installed costs fell by around 20% per year, while annual deployment grew by roughly 80%.

Improved safety performance, especially lower fire risk and the shift from purely merchant projects to contracted auction-based revenues, has further reduced perceived project risk and helped cut financing costs.

What Falling Costs Mean for Solar Power

One of the clearest implications of low-cost storage is its impact on solar electricity. The report estimates that storing half of a solar project’s daily output at an LCOS of $65/MWh would add roughly $33 to the cost of each MWh of solar energy. When added to the 2024 global average solar power cost of about $43/MWh, the resulting dispatchable solar cost is around $76/MWh, according to the report.

In practical terms, storing about 50% of daytime generation allows solar output to be shifted into evening and night-time hours, aligning production much more closely with typical demand profiles without needing to cover every hour of the year.

In regions with ultra-low-cost desert solar, oversizing PV capacity and storing a larger share of output can be even more attractive, pushing the effective cost of dispatchable solar well below competing fossil options.

This figure represents electricity available on demand, not just during daylight hours. The report emphasises that dispatchable solar is not the same as baseload solar. A true baseload supply would require additional overbuild and larger storage volumes. Still, the finding is powerful. Dispatchable solar in this price range increasingly competes with new gas generation, particularly in countries reliant on expensive LNG imports.

As a result, solar plus storage is poised to meet a substantial portion of incremental global electricity demand, transforming solar from a “cheap daytime” resource into an affordable, anytime source of power.

Battery-backed solar energy systems need just 17 kWh of storage to flatten a 5 kW solar generation profile into a steady 1 kWh of output over 24 hours, according to Ember.

Auctions and Contract Structures Shape Costs

Ember highlights how project financing conditions influence LCOS just as much as hardware pricing. Competitive auctions with fixed-revenue contracts allow developers to secure low-cost debt and equity. Discount rates fall to 5-7%, which is essential to reaching the $65/MWh LCOS benchmark.

Analysis shows that even if the discount rate is raised to around 11% and utilisation rises to roughly one full cycle per day (96% utilization) with slightly higher efficiency, the LCOS for a $125/kWh project still sits near $65/MWh, underlining how robust the economics are at today’s capex levels.

Markets relying on merchant revenues face higher uncertainty and are often financed at discount rates of 10 to 15%. This raises LCOS significantly. Some countries are also using capital expenditure subsidies to reduce bid prices. India, for example, provided a subsidy of just over $20/kWh, which helped push auction bids into record-low territory.

Regional Variations

Markets with strict testing requirements or high import duties often see core equipment costs closer to $100/kWh. Others with more flexible standards and lower duties benefit from the global benchmark price of around $75/kWh. In some markets, such as India, local manufacturing of power conversion and energy management systems has become competitive with Chinese suppliers, which partly offsets higher costs stemming from tariffs or localisation rules.

Connection costs can range from about $30/kWh to nearly $100/kWh, depending on location and network operator rules. Co-located solar and storage projects often avoid some of these charges, improving their economics. The indicative $50/kWh allowance for EPC and grid connection generally assumes that land is either provided by a utility under the tender or acquired at low cost.

In sites with expensive land or complex connection requirements, these costs can be substantially higher. Where batteries are installed behind the meter or directly at existing solar plants, grid connection fees can become almost negligible, further enhancing project returns.

Examples from recent auctions in Saudi Arabia, India, and Italy all point to capital costs in the range of $120/kWh.

Around 80% of projected global electricity demand growth over the next decade will occur in regions with excellent solar resources, which aligns closely with the economics of solar plus storage. For many of these countries, combining cheap daytime solar with low-cost storage now represents a more affordable and faster path to meeting demand than building new gas-fired capacity, especially where liquefied natural gas imports are expensive.

The Shift Beyond Lithium

Lithium-iron phosphate technology remains dominant for grid-scale storage. Most systems integrate 5 to 6/MWh enclosures equipped with power conversion and energy management systems. These enclosures account for roughly 90% of the core equipment cost. In typical utility-scale projects, 5–6 MWh of cells are packed into a standard 20-foot containerised enclosure, which simplifies logistics, factory assembly, and site installation.

Round-trip efficiency is typically around 90%, and annual degradation stays below 2%. After 20 years of operation, systems retain around two-thirds of their original capacity. Four-hour storage durations are becoming the standard for utility projects because many components scale with power rather than energy, making longer durations increasingly cost-effective.

For four-hour systems in particular, several major components are sized to the project’s power rating rather than energy, making them around 10–15% cheaper per kWh than shorter-duration projects; beyond four hours, the incremental savings from longer durations become progressively smaller.

There are also early signs of a transition toward sodium-ion batteries. These remove the need for lithium, nickel, and cobalt and could provide greater long-term supply chain flexibility. Today’s dominance of LFP chemistry already eliminates nickel and cobalt from most grid-scale systems; a broader shift toward sodium-ion would also remove lithium, effectively taking all commonly defined critical minerals out of the battery bill of materials.

At the same time, oversizing of installed capacity relative to usable capacity is becoming standard practice, enabling suppliers to offer 20- to 25-year performance guarantees with cycle counts of 10,000–12,000 or more.

Sodium-ion batteries are increasingly seen as an alternative because they are built similarly to lithium-ion cells, using sodium instead of lithium. The shared architecture allows manufacturers to adapt existing production knowledge and facilities.

System-Level Risks

Tariffs and local content requirements can inflate equipment costs. Grid connection fees can also swing overall project costs by tens of dollars per kWh. Merchant revenue exposure also increases financing costs and, in turn, LCOS. Project-specific utilisation patterns and degradation rates also mean that some systems deliver better economics than others.

Moreover, the LCOS figures discussed for energy shifting do not account for additional value streams such as frequency control, voltage support, or black-start services; when these ancillary revenues are stacked on top of energy arbitrage, the effective cost of moving a megawatt-hour of electricity can fall well below the headline $65/MWh.

Even so, navigating permitting constraints, network upgrade requirements, and evolving market rules remains critical to ensuring that the falling cost of hardware translates into real-world project delivery at scale.