Grid-Scale Storage

Pumped-storage hydropower is still the most widely deployed grid-scale storage technology today. Total installed capacity stood at around 160 GW in 2021. Global capability was around 8 500 GWh in 2020, accounting for over 90% of total global electricity storage. The world’s largest capacity is found in the United States. The majority of plants in operation today are used to provide daily balancing. 

Grid-scale batteries are catching up, however. Although currently far smaller than pumped-storage hydropower capacity today, grid-scale batteries are projected to account for the majority of storage growth worldwide. Batteries are typically employed for sub-hourly, hourly and daily balancing. Total installed grid-scale battery storage capacity stood at close to 16 GW at the end of 2021, most of which was added over the course of the previous five years. For the second year in a row, installations increased strongly in 2021, rising by 60% compared with 2020 as more than 6 GW of storage capacity was added in 2021. The United States, China and Europe led the market, each registering gigawatt-scale additions.  

The grid-scale battery technology mix in 2021 remained largely unchanged from 2020. Lithium-ion battery storage continued to be the most widely used, making up the majority of all new capacity installed. 

The rapid scaling up of energy storage systems will be critical to address the hour‐to‐hour variability of wind and solar PV electricity generation on the grid, especially as their share of generation increases rapidly in the Net Zero Scenario. Meeting rising flexibility needs while decarbonising electricity generation is a central challenge for the power sector, so all sources of flexibility need to be tapped, including grid reinforcements, demand‐side response, grid-scale batteries and pumped-storage hydropower.  

Grid-scale battery storage in particular needs to grow significantly. In the Net Zero Scenario, installed grid-scale battery storage capacity expands 44-fold between 2021 and 2030 to 680 GW. Nearly 140 GW of capacity is added in 2030 alone, up from 6 GW in 2021. To get on track with the Net Zero Scenario, annual additions have to pick up significantly, to an average of over 80 GW per year over the 2022-2030 period. 

Based on cost and energy density considerations, lithium iron phosphate batteries, a subset of lithium-ion batteries, are still the preferred choice for grid-scale storage. More energy-dense chemistries for lithium-ion batteries, such as nickel cobalt aluminium (NCA) and nickel manganese cobalt (NMC), are popular for home energy storage and other applications where space is limited. 

Besides lithium-ion batteries, flow batteries could emerge as a breakthrough technology for stationary storage as they do not show performance degradation for 25-30 years and are capable of being sized according to energy storage needs with limited investment. In July 2022 the world’s largest vanadium redox flow battery was commissioned in China, with a capacity of 100 MW and a storage volume of 400 MWh. 

While the past decade has witnessed substantial reductions in the price of lithium-ion batteries, it is now becoming evident that further cost reductions rely not just on technological innovation, but also on the rate of increase of battery mineral prices. The leading source of lithium demand is the lithium-ion battery industry. Lithium is the backbone of lithium-ion batteries of all kinds, including lithium-iron phosphate, NCA and NMC batteries. Supply of lithium therefore remains one of the most crucial elements in shaping the future decarbonisation of light passenger transport and energy storage. 

Ranging from mined spodumene to high-purity lithium carbonate and hydroxide, the price of every component of the lithium value chain has been surging since the start of 2021. 

Moreover, the impacts of Russia’s invasion of Ukraine are also apparent in the battery metals market. Both cathode (nickel and cobalt) and anode (graphite) materials are affected by this. Russia is the largest producer of battery-grade Class 1 nickel, accounting for 20% of the world’s mined supply. It is also the second and fourth largest producer of cobalt and graphite respectively. 

Global investment in battery energy storage reached almost USD 10 billion in 2021. It is led by grid-scale deployment, which represented more than 70% of total spending in 2021 and by lithium-ion batteries, which took more than 90% of total deployment in 2020 and 2021. After solid growth in 2021, battery energy storage investment is expected to hit a record high and approach USD 20 billion in 2022, based on the existing pipeline of projects and new capacity targets set by governments.  

By far the most significant investment in new pumped-storage hydropower capacity is currently being undertaken in China: Since 2015, 80% of all final investment decisions for new capacity have been taken there, and close to 50 GW of capacity is currently under construction, far exceeding additions in other regions. 

Spain published its Energy Storage Strategy in February 2021, targeting the deployment of 20 GW of behind-the-meter and grid-scale storage by 2030. In July 2021 China announced plans to install over 30 GW of energy storage by 2025 (excluding pumped-storage hydropower), an eightfold increase on its installed capacity as of 2021. 

Regulatory barriers specific to electricity storage systems are starting to be addressed, including the issue of double-charging, where energy storage systems are charged twice for using the grid – once when charging and again when discharging. The United Kingdom, for example, abolished double-charging of the grid cost-recovery component for storage facilities in January 2020. 

In Germany, the deployment of storage is encouraged through so-called innovation auctions, which reward the pairing of renewables with storage: in 2021 and 2022 all successful bids, together representing over 1 GW of installed capacity, were projects combining solar PV with battery storage.  

In the United States several states have set dedicated targets for storage. In January 2022 the governor of New York committed to doubling the state’s energy storage target, aiming for the deployment of at least 6 GW of storage by 2030. Furthermore, the Inflation Reduction Act passed in August 2022 includes an investment tax credit for stand-alone storage, which is expected to boost the competitiveness of new grid-scale storage projects.

Governments should consider pumped-storage hydropower and grid-scale batteries as an integral part of their long-term strategic energy plans, aligned with wind and solar PV capacity as well as grid capacity expansion plans. Flexibility should be at the core of policy design: the first step needs to be a whole-system assessment of flexibility requirements that compares the case for different types of grid-scale storage with other options such as demand response, power plant retrofits, smart grid measures and other technologies that raise overall flexibility.  

In liberalised electricity markets, long lead times, permitting risks and a lack of long-term revenue stability have stalled pumped-storage hydropower development, with most development occurring in vertically integrated markets, such as in China. Dedicated support mechanisms, such as capacity auctions for storage, could help promote deployment by providing long-term revenue stability for pumped-storage hydropower and battery storage plants. 

Regulatory frameworks should continue to be updated to level the playing field for different flexibility options, which would help to build a stronger economic case for energy storage in many markets. One example would be ending the double charging of taxes or certain grid fees. 

Transmission and distribution investment deferral (using storage to improve the utilisation of, and manage bottlenecks in, the power grid) is another potential high-value application for storage, since it can reduce the need for costly grid upgrades. To capture the greatest benefit, storage should be considered, along with other non-wire alternatives, in the transmission and distribution planning process. A key issue is ownership: in many markets, storage is considered a generation asset and system operators (transmission as well as distribution) are not allowed to own storage assets. One solution is to allow them to procure storage services from third parties. However, regulatory frameworks need to be updated carefully to minimise the risk of storage assets receiving regulated payments and undercutting the competitive power market.

Business cases for grid-scale storage can be complex, and may not be viable under legacy market and regulatory conditions. 

In liberalised electricity markets, measures to increase incentives for the deployment of flexibility that is able to rapidly respond to fluctuations in supply and demand could help improve the business case for grid-scale storage. These include decreasing the settlement period and bringing market gate closure closer to real time, as well as updating market rules and specifications to make it easier for storage to provide ancillary services. The business case for storage improves greatly with value stacking, i.e. allowing it to maximise revenue by bidding into different markets. 

Battery recycling has the potential to be a significant source of secondary supply of the critical minerals needed for future battery demand. Targeted policies, including minimum recycled content requirements, tradeable recycling credits and virgin material taxes all have potential to incentivise recycling and drive growth of secondary supplies. International co-ordination will be crucial because of the global nature of the battery and critical minerals markets.

Batteries that no longer meet the standards for usage in an electric vehicle (EV) typically maintain up to 80% of their total usable capacity. With EV numbers increasing rapidly, this amounts to terawatt hours of unused energy storage capacity. Repurposing used EV batteries could generate significant value and benefit the grid-scale energy storage market.   

Initial trials with second-life batteries have already begun. However, a number of technological and regulatory challenges remain for second-life applications to grow at scale. Chief among them is their ability to compete on price given the rapidly falling cost of new systems, although recent surges in the cost of battery minerals could improve the viability of recycling and reuse. Retired batteries need to undergo costly refurbishing processes to be used in new applications, and a lack of standardisation and streamlining of measuring the state of health of used batteries (e.g. storage condition, remaining capacity) further complicates the economics. Clear guidance on repackaging, certification, standardisation and warranty liability of used EV batteries would be needed to overcome these challenges.