The rapid increase in many parts of the world of generating capacity by intermittent renewable energy sources, notably wind and solar, has led to a strong incentive to develop energy storage for electricity on a large scale. Due to the (desired or imposed) growing annual share of electrical energy originating from renewable technologies subject to naturally-fluctuating power flows (like solar PV and wind), characterised by relatively low load factors, the combined installed capacities of those technologies in the future are expected to be much larger than typical/conventional electrical peak power demand.*

• “The regrettable habit in some circles to blindly use the word 'power' as a synonym of 'electricity' must be avoided in the context of storage. 'Power' is charged into or discharged from a storage device, but it is 'energy' that is stored.” – Projected Costs of Generating Electricity 2020, International Energy Agency & Nuclear Energy Agency.

Distributed Backup Power Supply Outdoor Energy Storage Cabinet Self-Cooling-EN-215

The extent to which electricity storage can be developed will determine the extent to which those intermittent renewable sources can displace dispatchable sources, taking surplus power on occasions and bridging intermittency gaps. There are questions of scale – power and energy capacity – which are indicated below in particular cases. Also some stored energy usually needs to be available as electricity over days and weeks, though there is plenty of scope for short-term storage over minutes and hours. Cost-effectiveness is key so both value and cost must be clearly determined to compare different electrical storage technologies in a variety of applications and services.

Electricity cannot itself be stored on any scale, but it can be converted to other forms of energy which can be stored and later reconverted to electricity on demand. Storage systems for electricity include battery, flywheel, compressed air, and pumped hydro storage. Any systems are limited in the total amount of energy they can store. Their energy capacity is expressed in megawatt-hours (MWh), and the power, or maximum output at a given time, is expressed in megawatts of electric power (MW or MWe). Electricity storage systems may be designed to provide ancillary services to a transmission system including frequency control, and this is the chief role of grid-scale batteries today.

Of course, very effective storage of energy is achieved in fossil fuels and nuclear fuel, before electricity is generated from them. While the focus here is on storage after generation, particularly from intermittent renewable sources, any proper consideration of the question needs also to encompass nuclear fuel for power generation as a more economical option with relatively little materials requirement.

Pumped storage involves pumping water uphill to a reservoir from which it can be released on demand to generate hydroelectricity. The efficiency of the double process is about 70%. Pumped storage comprised 95% of the world’s large-scale electricity storage in mid-2016, and 72% of the storage capacity added in 2014. Pumped hydro has the advantage of being long-term if required. Battery storage, however, is being deployed widely. More than 6 GW of grid-scale battery storage was added in 2021, reaching close to 16 GW connected to electricity networks at the end of that year, according to the International Energy Agency (IEA). Building-scale power storage emerged in 2014 as a defining energy technology trend. This market has grown by 50% year-on-year, with lithium-ion batteries prominent but redox flow cell batteries show promise. Such storage may be to reduce demand on the grid, as back-up, or for price arbitrage. In 2015 battery storage costs were around $400/kWh of contained energy, and 1.6 GW was installed or planned. The cost dropped to $141/kWh in 2021 before rising to $151/kWh (in 2022 prices) according to Bloomberg NEF’s annual battery price survey.

Pumped storage projects and equipment have a long lifetime – nominally 50 years but potentially more, compared with batteries – 8 to 15 years. Pumped hydro storage is best suited for providing peak-load power for a system comprising mostly fossil fuel and/or nuclear generation. It is not so well-suited to filling in for intermittent, unscheduled and unpredictable generation.

A World Energy Council report in January 2016 projected a significant drop in cost for the majority of energy storage technologies as from 2015 to 2030. Battery technologies showed the greatest reduction in cost, followed by sensible thermal, latent thermal and supercapacitors. Battery technologies showed a reduction from a range of €100-700/MWh in 2015 to €50-190/MWh in 2030 – a reduction of over 70% in the upper cost limit in the next 15 years. Sodium sulfur, lead acid and lithium-ion technologies lead the way according to WEC. The report models storage related to both wind and solar plants, assessing the resultant levelised cost of storage (LCOS) in particular plants. It notes that the load factor and the average discharge time at rated power is an important determinant of the LCOS, with the cycle frequency becoming a secondary parameter. For solar-related storage the application case was daily storage, with six-hour discharge time at rated power. For wind-related storage the application case was for two-day storage with 24 hours discharge at rated power. In the former case the most competitive storage technology had LCOS of €50-200/MWh. In the latter case, levelised costs were higher and sensitive to the number of discharge cycles per year, and “few technologies appeared attractive."

Following a two-year study by the California Public Utilities Commission, the state in 2010 passed legislation requiring 1325 MWe of electricity storage (excluding large-scale pumped storage) by 2024. In 2013 it brought forward the deadline to 2020, then having 35 MW total. The legislation specifies power, not storage capacity (MWh), suggesting that the main purpose is frequency control. The stated purpose of the legislation is to increase grid reliability by providing dispatchable power from an increasing proportion of solar and wind inputs, replace spinning reserve, provide frequency control and reduce peak capacity requirements (peak shaving). The storage systems can be connected with either transmission or distribution systems, or be behind the meter. The main focus is on battery energy storage systems (BESS). Energy arbitrage may enhance revenue, buying off-peak and selling for peak demand. Southern California Edison in 2014 announced plans for 260 MW of electricity storage to offset the closure of the 2150 MWe San Onofre nuclear plant. While 1.3 GW in the context of the state’s 50 GW demand will not provide much dispatchable power, it was a major incentive for the utilities.

Oregon followed California, and in 2015 set a requirement for larger utilities (PGE and PacifiCorp) to procure at least 5 MWh of storage by 2020, and PGE proposed 39 GW in several locations, costing $50 to $100 million. In June 2017 Massachusetts issued a target of 200 MWh storage by 2020. In November 2017 New York resolved to set a storage target for 2030.

In the USA, there is some 22 GW of pumped storage capacity and 550 gigawatt-hours of energy storage across the country, according to the Office of Energy Efficiency & Renewable Energy. In 2022, large-scale battery storage capacity in the USA reached 9.1 GW and 25 GWh. The Energy Information Administration projects this to reach 30.0 GW by the end of 2025.

Early in 2016 the UK’s National Grid got a strong response to a tender for 200 MW enhanced frequency response (EFR). It offered four-year contracts for capacity able to provide 100% active power output in a second or less of registering a frequency deviation. Some 888 MW of battery capacity was offered, 150 MW of interconnection, 100 MW of demand-side response and 50 MW of flywheel capacity. All but three involved battery storage. In August the winning bids were announced – the eight chosen tenders being from 10 MW to 49 MW (totalling 201 MW) and costing £66 million in total. The winning bids ranged from £7 to £12 per MW of EFR/h, with an average of £9.44/MW of EFR/h. Batteries are also expected to become the main choice for firm frequency response, slightly slower than EFR.

In the UK storage is treated as generation for licensing purposes, but on connection to a distribution network it has to comply with two different connection and charging methodologies, with one half connecting as demand and the other as generation. A single storage connection methodology is proposed, and the Department for Business, Energy & Industrial Strategy and energy regulator Ofgem are aiming to define ’electricity storage’ in legal and regulatory terms so as to expedite deployment. The Electricity Storage Network, an industry body, supports the move.

On demand response, the UK government said providers should have easier access to a range of markets so they can compete fairly with large generators, including the balancing market, ancillary services, and the capacity market. There is concern over whether storage and demand response providers should be able to access the same length capacity market contracts as new diesel generators. In this area the response needs to be over hours, and batteries are less economical.

In November 2016 the European Commission acknowledged energy storage as a key flexibility instrument required in the future. It proposed a new definition of electricity storage to include “deferring an amount of the electricity that was generated to the moment of use, either as final energy or converted into another energy carrier” such as gas. This brought power-to-gas (P2G) concepts within the regulatory definition of energy storage so that excess power from intermittent renewables can by electrolysis be turned into hydrogen which can be added to the normal gas distribution network (up to 20%, though much less allowed in most countries), or sold directly. Electrolysers could thus be providing ancillary grid services for which they are paid. The redefinition of P2G from simply a load to storage has implications for both electricity grids and reducing CO₂ arising from gas. P2G electrolysers can be seen as part of the grid, not simply end users.

ITM Power, which develops electrolysers for P2G systems, proposes to build a number of hydrogen refuelling stations for fuel cell cars in the UK, with these having some grid balancing function. In March 2017 it had four in operation, with hydrogen production timed to absorb excess power from the grid. The UK government wants 65 hydrogen refuelling stations by 2020. Each has 200 to 250 kW capacity, so a number of them are needed to be able to bid for enhanced frequency response (minimum 3 MW).

Polymer electrolyte membrane (PEM) electrolysers are now available at about €1 million per MW, with smaller footprint and more rapid response than alternatives, enabling grid balancing and energy storage. Some 4.7 TWh of renewable electricity was curtailed in Germany in 2015.

Hydrogen storage at scale and its long-range transmission is envisaged as being by conversion to ammonia, which in practical terms is more energy-dense.