Batteries store and release energy electrochemically. The requirements for battery storage are high energy density, high power, long life (charge-discharge cycles), high round-trip efficiency, safety, and competitive cost. Other variables are discharge duration and charge rate. Various compromises are made among these criteria, underlining the limitations of battery energy storage systems (BESS) compared with dispatchable generation sources. The question of energy return on energy invested (EROI) also arises, which acutely relates to how long a battery is in service and how its round-trip efficiency holds up over that period.

Batteries require a power conversion system (PCS) including inverter to link into a normal AC system. This adds about 15% to the basic battery cost.

Various megawatt-scale projects have proved that batteries are well-suited to smoothing the variability of power from wind and solar systems over minutes and even hours, for short-duration integration of these renewables into a grid. They also showed that batteries can respond more quickly and accurately than conventional resources such as spinning reserves and peaking plants. As a result, large battery arrays are becoming the stabilization technology of choice for short-duration renewables integration. This is a function of power, not primarily energy storage. The demand for it is much lower than for energy storage – the California ISO estimated its peak frequency regulation demand for 2022 at just over 2000 MW from all sources.

Some battery installations replace spinning reserve for short-duration back-up, so operate as virtual synchronous machines using grid forming inverters.

Smart grids Much discussion of battery storage is in connection with smart grids. A smart grid is a power grid which optimizes power supply by using information on both supply and demand. It does this with networked control functions of devices with communication capabilities such as smart meters.

Lithium-ion batteries in 2015 accounted for 51% of newly-announced energy storage system (ESS) capacity and 86% of deployed ESS power capacity. An estimated 1,653 MW of new ESS capacity was announced around the world in 2015, with just over one-third coming from North America. Lithium-ion batteries are the most popular technology for distributed energy storage systems (Navigant Research). Lithium-ion batteries have a 95% round trip direct current efficiency, falling to 85% when the current is converted to alternating current for the grid. They have a 2000-4000 cycle and 10-20 year lifespan, depending on use.

In the World Energy Outlook 2022, the IEA identifed lithium-ion batteries as the fastest growing storage technology in the world. In its Net Zero Emissions by 2050 Scenario (NZE), battery storage capacity is projected to reach 778 GW by 2030 and 3860 GW by 2050, from 27 GW in 2021.

At household level, behind the meter*, battery storage is being promoted. There is obvious compatibility between solar PV and batteries, due to them being DC. In Germany, where solar PV has an average 10.7% capacity factor, 41% of new solar PV installations in 2015 were equipped with back-up battery storage, compared with 14% in 2014. In 2020 that figure reached 70%, with Germany’s residential storage market representing around 2.3 GWh of installed capacity. This increase, in both household and grid-connected PV systems, is encouraged by the KfW Development Bank, which arranges low-interest government loans and payback assistance covering up to 25% of the required investment outlays. KfW requires that sufficient PV electricity be used for onsite consumption and storage so that no more than half of the output reaches the transmission network. In this way, it is claimed that 1.7 to 2.5 times the usual solar capacity can be tolerated by the grid without overloading.

* Household and small business PV is not part of the distribution system but is essentially domestic to the premises, with much generated power used there and some possibly exported to the system through the meter which originally measured power drawn from the grid to be charged for.

Over one-third of the 1.5 GW ‘battery storage’ in 2015 was lithium-ion batteries, and 22% was sodium-sulfur batteries. The International Renewable Energy Agency (IRENA) estimates that the world needs 150 GW of battery storage to meet IRENA's desired target of 45% of power generated from renewable sources by 2030. In the UK about 2 GW is required for rapid frequency control in a 45 GWe system, and National Grid spends £160 to £170 million per year on this. In Germany, installed utility-scale battery storage increased from about 225 MW in 2017 to 750 MW in 2021.

A large BESS is a 40 MW/20 MWh Toshiba lithium-ion system at the Tohoku Electric Power Company’s Nishi-Sendai substation in Japan, commissioned early in 2015, and San Diego Gas & Electric has a 30 MW/120 MWh lithium-ion BESS in Escondido, California. Also STEAG Energy Services has started a 90 MW lithium-ion storage program in Germany (see below), and Edison is setting up a 100 MW facility in Long Beach, California.

In South Australia a Tesla 100 MW/129 MWh lithium-ion system was installed next to Neoen’s 309 MWe Hornsdale wind farm near Jamestown – the Hornsdale Power Reserve (HPR). About 70 MW of the capacity is contracted to the state government to provide grid stability and system security, including frequency control ancillary services (FCAS) through Tesla's Autobidder platform in timeframes of six seconds to five minutes. The other 30 MW of capacity has three hours of storage, and is used as load shifting by Neoen for the adjacent wind farm. It has proved capable of very rapid response for FCAS, supplying up to 8 MW for about 4 seconds before slower contracted FCAS cut in when frequency dropped below 49.8 Hz. In 2020 the project was expanded by 50 MW/64.5 MWh for A$79 million so that it now provides about half the virtual inertia required in the state for FCAS.

There are several types of lithium-ion battery, some with high energy density and fast charging to suit motor vehicles (EVs), others such as lithium iron phosphate (LiFePO₄, abbreviated as LFP), are heavier, less energy-dense and with longer cycle life. Concepts for long-duration storage include repurposing used EV batteries – second-life batteries. 

Sodium-sulfur (NaS) batteries have been used for 25 years and are well established, though expensive. They also need to operate at about 300°C, which means some electricity consumption when idle. PG&E’s 2 MW/14 MWh Vaca-Dixon NaS BESS system cost about $11 million ($5500/kW, compared with about $200/kW which PG&E estimated to be break-even cost in 2015). Service life is about 4500 cycles. Round-trip efficiency in an 18-month trial was 75%. A 9.0 MW/20 MWh NaS unit was built as part of a hybrid system by Hitachi for EWE at Varel in Lower Saxony, North Germany and commissioned in 2018. (A 7.5 MW/2.5 MWh lithium-ion battery is the quick-response part of the system, the whole plant costing €24 million.) A 5.8 MWh NaS system was commissioned for BASF at Antwerp in 2021.

Redox flow cell batteries (RFBs) developed in the 1970s have two liquid electrolytes separated by a membrane to give positive and negative half-cells, each with an electrode, usually carbon. The voltage differential is between 0.5 and 1.6 volts in aqueous systems. They are charged and discharged by a reversible reduction-oxidation reaction across the membrane. During the charging process, ions are oxidised at the positive electrode (electron release) and reduced at the negative electrode (electron uptake). This means that the electrons move from the active material (electrolyte) of the positive electrode to the active material of the negative electrode. When discharging, the process reverses and energy is released. The active materials are redox pairs, i.e. chemical compounds that can absorb and release electrons.

Vanadium redox flow batteries (VRFB or V-flow) use the multiple oxidation states of vanadium to store and release charge. They suit large stationary applications, with long life (approx. 15,000 cycles, or 'infinite'), full discharge, and low cost per kWh compared with lithium-ion when cycled daily or more frequently. V-flow batteries become more cost-effective the longer the storage duration – often about four hours – and the larger the power and energy needs. The crossover economic scale is said to be about 400 kWh capacity, beyond which they are more economic than lithium-ion. Also they operate at ambient temperature, so are less prone to fires than lithium-ion. On cost and scale, VRFBs have major grid and industry applications – up to GWh projects rather than MWh ones.

With RFBs energy and power can be scaled separately. The power determines the cell size or the number of cells, and the energy is determined by the amount of the energy storage medium. Modules are up to 250 kW and may be assembled up to 100 MW. This allows redox flow batteries to be better adapted to particular requirements than other technologies. In theory, there is no limit to the amount of energy, and often the specific investment costs decrease with an increase in the energy/power ratio, as the energy storage medium usually has comparatively low costs.

A model 'peaker' plant in China has 100 MWe solar PV with a 100 MW/500 MWh VRFB.

A general finding from the PG&E trial was that if batteries are to be used for energy arbitrage, they should be co-located with the wind or solar farms – often remote from the main load centre. However, if they are to be used for frequency regulation, they are better located close to the urban or industrial load centres. Since the frequency control revenue stream is much better than arbitrage, utilities will normally prefer downtown rather than remote locations for assets they own.

Lithium-ion battery costs have dropped by two-thirds between 2000 and 2015, to about $700/kWh, driven by the vehicle market and a further halving of cost is predicted to 2025.

According to Bloomberg NEF’s annual battery price survey, prices dropped to $141/kWh in 2021 before rising to $151/kWh (in 2022 prices). Power conversion system (PCS) costs have not dropped at the same rate, and in 2015 added about 15% to battery cost for non-vehicle applications. In 2020 PCS costs were $73/kWh.

Lithium-ion batteries may be categorized by the chemistry of their cathodes. The different combination of minerals gives rise to significantly different battery characteristics:

• Lithium nickel cobalt aluminium oxide (NCA) battery – specific energy range (200-250 Wh/kg), high specific power, lifetime 1000 to 1500 full cycles. Favoured in some premium EVs (e.g. Tesla), but more expensive than other chemistries.
• Lithium nickel manganese cobalt oxide (NMC) battery – specific energy range (140-200 Wh/kg), lifetime 1000-2000 full cycles. Most common battery used in electric and plug-in hybrid electric vehicles. Lower energy density than NCA, but longer lifetimes.
• Lithium iron phosphate (LFP) battery – specific energy range (90-140 Wh/kg), lifetime 2000 full cycles. Low specific energy a limitation for use in long-range EVs. Could be favoured for stationary energy storage applications, or vehicles where size and weight of battery are less important. Reported to be less prone to thermal runaway and fires.
• Lithium manganese oxide (LMO) battery – specific energy range (100-140 Wh/kg), lifetime 1000-1500 cycles. Cobalt-free chemistry seen as an advantage. Used in electric bikes and some commercial vehicles.