Lithium-ion batteries remain at the centre of the global energy storage conversation. Most large-scale battery projects around the world use lithium-ion batteries as the technology of choice for storing excess energy generated on the grid. Lithium-ion batteries have benefited from the enormous scale-up of production capacity for the electric vehicle industry (presently accounting for around 4x the annual demand of the stationary storage market), which lead to significant performance improvements and cost declines over the past decade.

But as the energy transition matures, new battery chemistries including Long Duration Energy Storage solutions, or LDES, that can cover prolonged periods of high demand and supply droughts are getting closer attention.

LDES demand and Lithium-ion batteries

Lithium-ion batteries include a subset of different chemistries that are optimised for various applications. Lithium Iron Phosphate (LFP) batteries dominate the stationary storage market. They account for more than 80 percent of new utility-scale battery storage commitments with typical storage capacities of up to eight hours. Some Nickel Manganese Cobalt (NMC) batteries, a subset of lithium-ion, are used for high-density storage for shorter durations, but are more commonly found in electric vehicles and consumer electronics. The same can be said of Lithium Nickel Cobalt Aluminum Oxide (NCA) batteries, more commonly found in long-range electric vehicles. As the demand for LDES continues to increase because of higher variable renewable energy penetration levels, alternate battery chemistry technologies are gaining traction that could complement LFP batteries. Whilst some of these chemistries are new and still supported by intensive R&D efforts, others - such as vanadium flow batteries - are chemistries that were commercialised several decades ago but until recently have not seen sufficient demand to achieve the scale needed to drive down costs. LDES is commonly seen as energy storage that has the capacity to dispatch energy for eight hours or more. The first generation of utility-scale battery projects currently in operation were deployed with a generation capacity of one to two hours, whilst four hours is increasingly the norm for projects being built today. While shorter duration batteries manage daily peaks and smooth the intermittency of renewables, LDES time shifts solar from day to night, and steps in when it hasn’t been sunny or windy for several days. All forms of energy storage allow grid operators to extract more value from their existing infrastructure, taking some pressure off grids to build more transmission.

Demand for energy storage to firm up renewable energy generation is unquestionable. The Australian Energy Market Operator’s Draft 2026 Integrated System Plan notes 6.6 GW of renewable generation and battery storage projects achieved full output in the two years to June 2025, which was double year-on-year. AEMO’s modelling also pegs the total storage capacity required by 2030 at 27 GW, with 33 GW needed if Australia is to achieve its Net Zero target by 2050¹. These targets include a mix of shallow (0-4 hrs), medium (4-12 hrs), and deep (weeks to months) storage. The same story can be seen in other parts of the world. The International Energy Agency notes in its most recent World Energy Outlook that global battery storage additions reached 77 GW in 2024, adding that battery prices fell by 20 per cent in 2024. This was “the largest annual drop since 2017,” and “largely driven by major price declines in lithium, nickel, cobalt and graphite”. The IEA further notes that global installed battery capacity needs to rise to 2,900 GW to meet Net Zero by 2050². This all bodes well for strong, ongoing demand for lithium-ion batteries and lithium-ion chemistry will continue to have a place in the utility-scale battery industry.  The demand for LDES has put Eku Energy’s interest in long duration storage projects such as our 100 MW / 800 MWh Griffith BESS which will have an eight-hour duration storage capacity. But grids in Australia and around the world are looking towards new battery chemistries with even longer capacity as electrification and more renewable energy needs to be stored on the grid.

Some of these chemistries can potentially deliver large-scale projects at a lower cost and offer additional safety benefits. Let’s take a look at some of the leading contenders.

Sodium-ion

These batteries use cheap, abundant salt (sodium). While still in the pilot and early commercial phases, sodium-ion is the "chemical cousin" of lithium, as both elements belong to the Alkali Metal group of the periodic table. Because of their close relationship, sodium-ion batteries can often be built with the same equipment and factories currently used for LFP batteries, which means there’s no need to restart a ‘Gigafactory’ phenomenon that powered the emergence of lithium-ion batteries. Manufacturers will primarily source sodium from soda ash and industrial sodium. Soda ash, also known as sodium carbonate, can be sourced naturally from mining trona ore. Soda ash can also be sourced synthetically. Industrial sodium, also known as sodium chloride, comes from processes such as evaporating ponds of seawater brine, water desalination, or rock salt mining. The abundance of sodium-ion (table salt) means there is also potential to produce these batteries at a significantly lower cost than LFP batteries without the same extraction and supply chain risks of lithium. LFP batteries also have challenges with transport because discharging to zero can damage them. This means they need to be shipped with a charge of about 30 per cent, which is a potential but highly unlikely fire risk in the case of an accident. Sodium-ion batteries can be shipped with a state of charge of zero. Some formulations of sodium-ion batteries also maintain their capacity much better than lithium-ion in hot or cold climates making it more adaptable for extreme weather conditions and potentially lowering auxiliary power consumption and servicing costs for thermal management. Sodium-ion batteries do have a lower energy density than their lithium cousins, which means they need more space to generate the same power. A sodium-ion configuration in a standard shipping container generates roughly 2.3-3.0 MWh, versus 5.4-6.4 MWh from an LFP pack. Wood Mackenzie says sodium-ion batteries are on “a slightly faster downward trajectory” than lithium-ion batteries but are not expected to reach price parity “until around 2035”³.

Vanadium

Unlike lithium-ion batteries, where the capacity and power are bundled together, a vanadium redox flow battery decouples these two outputs, which holds potential benefits. In a lithium-ion battery, the amount of energy stored is related to the amount of solid active material. Lithium ions move between positive and negative electrodes (usually graphite and a transition metal oxide), while charging and discharging. In a vanadium redox flow battery, the energy stored is related to a liquid electrolyte, which is often contained in external tanks. This electrolyte is then pumped through a flow battery ‘stack,’ where energy can be stored by changing their oxidative state. If you need more capacity, you can increase the size of the tanks, if you need more power, you can add more stacks. This makes vanadium batteries an increasingly attractive option for longer duration energy developers, as the marginal cost of augmenting the system to add extra hours of storage is significantly lower than with traditional battery chemistries. Australia is uniquely positioned here, holding some of the world’s largest vanadium deposits.

Iron-Air

These batteries utilise iron, water and air. Iron-air technology operates on a fundamental chemical process known as “reversible rusting”. While lithium-ion batteries are sealed units, iron-air systems “breathe”. During discharge, the battery absorbs oxygen from the air, which reacts with an iron anode to form rust and release energy. To recharge, an electrical current is applied to convert the rust back into metallic iron, causing the battery to “breathe out” oxygen. Iron-air systems are designed for multi-day storage, capable of continuously dispatching energy for up to 100 hours. This makes them an ideal solution for bridging renewables droughts. From a cost perspective, iron-air technology is highly competitive. Iron ore is much more common and lower cost than minerals like lithium or cobalt, which means these systems can potentially be produced cheaper than lithium-ion batteries. Additionally, the water-based, non-flammable electrolyte makes these systems safe for large-scale grid deployment. Like sodium-ion, iron-air batteries have a lower energy density than lithium-ion, meaning they require a larger physical footprint. However, multi-day reliability could make them a critical partner for a fully renewable grid.

The foreseeable future is lithium, with partners

Lithium-ion batteries remain the bedrock of our current project fleet. But the energy transition is quickening. By exploring a mix of battery chemistries and picking the most suitable solution for our projects, we are ensuring that grids have maximum optionality for the retirement of coal-fired power stations.

‍