Battery Storage

Not long ago, batteries on the grid were a laboratory curiosity. Today they are the fastest-growing power technology after solar. A battery energy storage system (BESS) soaks up electricity when it is cheap or plentiful and releases it within milliseconds when the grid needs it. Variable solar and wind now supply close to a fifth of global electricity, and batteries are the main tool for moving midday solar into the evening peak and for holding grid frequency steady as spinning thermal plants retire.

How it works

A battery cell stores energy electrochemically. In a lithium-ion battery, lithium ions move back and forth between a graphite anode and a metal-oxide or phosphate cathode through a liquid electrolyte, while electrons flow through the external circuit. Cells are built into modules and racks. A battery management system (BMS) watches voltage, temperature and state of charge for every cell group.

A grid-scale system adds bidirectional inverters (power conversion systems), transformers, HVAC or liquid cooling, fire detection and suppression, and an energy management system that decides when to charge and discharge. Every system has two ratings: power in MW (how fast it can deliver) and energy in MWh (for how long). A 100 MW / 400 MWh plant is a “four-hour battery”. That split between power and energy shapes both cost and use.

Home batteries use the same architecture at 5–20 kWh. They are usually paired with rooftop PV and installed behind the meter to raise self-consumption and provide backup. Our solar battery calculator simulates how much a given battery size adds to self-consumption and savings.

Main chemistries and variants

LFP (lithium iron phosphate)

LFP now dominates stationary storage worldwide. It uses iron and phosphate instead of nickel and cobalt, survives many more cycles, and gives off far less heat and oxygen when abused. Its lower energy density doesn’t matter in a shipping container. Chinese manufacturers (CATL, BYD, EVE, Hithium and others) supply most of the market.

NMC (nickel manganese cobalt)

NMC has higher energy density. It was common in early grid projects and still dominates premium electric vehicles, but in stationary storage it has mostly lost out to LFP on cost, cycle life and safety.

Sodium-ion

Sodium-ion batteries swap lithium for abundant sodium and can use aluminium current collectors on both electrodes. They hold less energy than LFP and their cycle life is still improving, but they work better in the cold and avoid lithium price risk. The first grid-scale sodium-ion projects came online in China in 2024.

Flow batteries

A flow battery stores energy in liquid electrolytes kept in external tanks and pumped through a cell stack. Power (stack size) and energy (tank volume) scale separately, which suits durations of 6–12 hours. Vanadium redox is the most mature type. The Dalian project in China (first phase 100 MW / 400 MWh, 2022) is among the largest. Efficiency is lower and upfront cost higher than lithium-ion, but the electrolyte lasts a very long time.

Typical values

Ranges compiled from IEA (2024), NREL ATB and manufacturer datasheets; individual products vary.

Grid services

Batteries make money by stacking several services:

• Energy arbitrage. They charge when prices are low or negative and discharge into evening peaks, which is what flattens the duck curve in California and Australia.
• Frequency response. Sub-second frequency response was the first profitable niche (UK Dynamic Containment, Germany’s FCR market, Australia’s FCAS). These markets fill up quickly as fleets grow.
• Capacity. Capacity markets and resource-adequacy programmes pay batteries to be available during system peaks. Four-hour batteries now cover a large share of California’s evening peak capacity.
• Network services. Batteries can defer grid upgrades and relieve congestion. With grid-forming inverters they also provide synthetic inertia and black start.

Efficiency, degradation and cycle life

Round-trip efficiency is energy discharged divided by energy charged. NREL’s ATB assumes 85% AC–AC for utility-scale lithium-ion. Well-designed LFP systems reach 87–90% at the point of interconnection, before auxiliary loads such as cooling, which can take a few more percentage points in hot climates.

Capacity fades in two ways. Calendar ageing comes from time spent at high state of charge and temperature. Cycle ageing comes from each charge and discharge, and gets worse with deep depth of discharge and high C-rate. Typical stationary LFP warranties guarantee 60–70% retained capacity after 15–20 years or after a fixed energy throughput. Operators often oversize at commissioning or add capacity later (“augmentation”) to keep delivering the contracted MWh.

Take a 10 kWh home LFP battery cycled once a day at 90% depth of discharge and 90% round-trip efficiency, fading linearly to 70% over 6,000 cycles. Over its life it delivers about 41 MWh. At an installed cost of EUR 6,000, the storage alone costs about EUR 0.15 per kWh delivered before financing. Compare that number with the gap between your import price and your export tariff.

Costs

In real terms, battery prices have fallen around 90% since 2010. The BloombergNEF 2024 battery price survey found an average lithium-ion pack price of $115/kWh, down 20% on the year and the biggest drop since 2017. Cheap LFP cells, falling lithium prices and manufacturing overcapacity in China drove the fall. Packs for stationary storage cost slightly more than the overall average, around $125/kWh. BNEF’s separate system survey put the global average turnkey cost of a four-hour grid system near $165/kWh in 2024. Chinese projects came in considerably cheaper, US and European ones more expensive.

The levelized cost of storage (LCOS) adds financing, O&M, efficiency losses and charging energy. Lazard’s LCOE+ 2024 puts unsubsidised LCOS for four-hour utility-scale systems roughly in the low hundreds of dollars per MWh (on the order of $120–300/MWh, depending on configuration and market). Residential systems stay several times higher per MWh because of installation and small-scale hardware costs. In sunny markets, hybrid solar-plus-storage PPAs now compete with new gas peakers. Model a project with the LCOE calculator.

Global deployment

According to the IEA and BNEF, annual grid-scale battery additions grew from a few gigawatts in 2020 to roughly 40 GW in 2023, and rose again in 2024. China, the United States and Europe account for most of the volume. California and Texas lead in the US; the UK, Germany and Italy lead in Europe. Global stationary battery fleets should overtake pumped hydro storage in power capacity in the second half of this decade. Pumped hydro will still hold most of the stored energy (GWh) for years, because a typical plant runs for 6–20 hours.

Land, water and materials

Batteries are compact. A 100 MW / 400 MWh LFP plant fits on a few hectares, and a home unit takes up part of a wall. Operating water use is negligible. Materials are the main concern. Lithium-ion cells need lithium (Australia, Chile, Argentina and China supply most of the raw material, and China refines the majority) and graphite (mostly Chinese). NMC also needs nickel (Indonesia now dominates) and cobalt (around 70% from the Democratic Republic of Congo, where labour and artisanal mining problems are documented). The move to LFP and sodium-ion takes cobalt and nickel out of most stationary batteries.

Recycling capacity is growing in China and Europe, and the EU Battery Regulation sets targets for recycled content and collection. Hydrometallurgical processes can recover over 90% of lithium, nickel and cobalt, although LFP contains less valuable metal, which makes recycling it harder to pay for.

Lifecycle CO2 emissions

A battery generates no electricity, so its lifecycle emissions are its manufacturing emissions spread over the energy it delivers, plus its losses multiplied by the emissions of the charging source. Studies (e.g. IVL Swedish Environmental Research Institute 2019, and later LCA reviews) put cell and pack manufacturing at roughly 50–150 kg CO2e per kWh of capacity, highest for cells made with coal-heavy power. Over several thousand full cycles, that works out to roughly 10–50 g CO2e per kWh delivered. Round-trip losses of 10–15% add the same share of the charging electricity’s carbon intensity. A battery charged from solar therefore stays far below gas-fired generation, while one charged from coal carries coal’s emissions plus the losses.

Safety and environmental impacts

The main hazard is thermal runaway. An internal short circuit, overcharging or outside heat sets off exothermic reactions that spread from cell to cell and release flammable and toxic gases, including hydrogen fluoride. In January 2025 a fire at Vistra’s Moss Landing facility in California, an indoor installation of NMC-based modules, burned for days and forced local evacuations. Earlier incidents at the same site (2021–2022), in Arizona (2019) and in South Korea (2017–2019) shaped today’s standards. Current practice favours LFP, outdoor containers spaced apart, cell-level gas detection, deflagration venting, and testing under UL 9540A and NFPA 855. EPRI’s incident database shows global failure rates per GWh deployed falling by about 97% from 2018 to 2023, while installations multiplied.

Other impacts include noise from cooling fans and inverters, end-of-life waste where recycling isn’t organised, and upstream mining impacts on water and communities.

Outlook

In power systems with a lot of solar, batteries are turning into the default source of flexibility and are pushing gas peakers out of arbitrage and capacity roles. As costs fall, expect durations to stretch from 2–4 hours toward 4–8 hours. Sodium-ion should spread in cost-sensitive and cold-climate uses, and home batteries and electric vehicles will increasingly be aggregated into virtual power plants and vehicle-to-grid schemes. Multi-day and seasonal balancing is a different problem, where long-duration storage, pumped hydro and green hydrogen remain the more plausible options. Compare the economics with the pumped hydro storage calculator or read the broader hydropower overview.