Billions of dollars are flowing into battery storage, a technology critical to the clean energy transition. Whether to help balance grids, improve the economics of renewables projects or, ultimately, provide long-term capacity when the wind doesn’t blow, enormous investment will be needed in battery storage on the road to net zero.
However, supply chain constraints and the availability of vital commodities are reversing price falls that have helped propel the growth of the most popular technology, the lithium-ion (Li-ion) batteries found in phones, computers and electric vehicles (EVs). Rising prices risk slowing the sector’s growth.
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By GlobalData
“The good news is that we have seen record deployment in 2021… despite the very real impact of Covid-19 disruptions to supply chains,” says Michael Taylor, a senior analyst at the International Renewable Energy Agency (IRENA). The industry has weathered increasing lithium costs and shortages of key components such as semiconductors.
“But we have seen projects delayed or even cancelled,” he adds.
“In well-established energy storage markets, like the US, higher costs have resulted in some developers looking to renegotiate contract prices with offtakers,” says Helen Kou, an energy storage associate at the research company BloombergNEF (BNEF) in San Francisco. “These renegotiations can take time and can delay project commissioning.”
“In emerging energy storage markets, higher costs result in batteries being less competitive or less attractive than other generation resources,” she says. “Markets that might have started deploying more batteries in 2022 may delay deployments until prices fall.”
According to research from Energy Monitor’s parent company, GlobalData, 20.84GW of battery storage was installed by the end of 2021. It forecasts this figure rising to 92.22GW by 2026, by which point the market will be worth $10.84bn.
Similarly, BNEF forecasts that total energy storage (excluding pumped hydro) will reach a total capacity of 365GW/912GWh in 2030, compared with 27GW/56GWh at the end of 2021. In 2030, it anticipates that 58GW/178GWh will be installed, five times greater than the 10GW/22GWh installed in 2021, which was a record year. Almost all of the grid-scale battery storage projects in recent years have used Li-ion technology.
Battery storage uses
A big part of the value of battery storage technology lies in its versatility, says Richard Braakenburg, head of equity investments at SUSI Partners, an active investor in the space. “The key advantage that storage has is that it is the Swiss army knife of the electricity markets,” he says.
“Battery storage is increasingly being used to solve problems caused by policy or regulatory inertia,” says Taylor at IRENA, whether that is transmission issues in Australia or congested grids in some US markets. “Because costs have come down so much, it is working itself into niche applications.”
According to BNEF figures, half of battery projects by output are expected to be deployed for 'energy shifting' in 2022, rising to two-thirds later in the decade. This is where large-scale batteries are used to temporarily store power generated by renewables to be sold when power prices are higher or to smooth output.
The use of battery storage in this way is changing the economics of renewable energy generation, particularly of solar systems. Research by the Lawrence Berkeley National Lab in the US finds that, at the end of 2021, some 42% of solar plants seeking permits for connection to the grid in the US, totalling 285GW of capacity, were paired with storage systems. Of all the large-scale solar capacity in the development queue in California, 95% is paired with storage, the research found.
Battery storage is particularly valuable in ‘island’ electricity grids, says Tom Edwards, an analyst at UK-based consultancy Cornwall Insight, whether that be physical islands such as the UK or grids that are isolated from wider distribution networks, such as those in California, Texas or Iberia, which are less able to share resources than those connected to much larger systems.
For this reason, Edwards says, the UK is likely to need relatively large investment in battery storage. Its modelling suggests the UK power system will need to invest £20bn in energy battery storage, or 18% of its planned total investment in energy technologies, if it is to meet its 2030 renewables targets. These targets will rely on battery storage providing around 10% of grid capacity by that date.
A declining proportion of batteries are being deployed to provide ancillary services, regulating the frequency and voltage of power grids. These services can offer a valuable source of revenue for a limited amount of energy storage capacity.
Meanwhile, the deployment of relatively small-scale batteries by businesses and households, either for backup power and/or in conjunction with renewables will decline but remain a significant source of new capacity, BNEF expects. It forecasts this segment of the market dropping from more than a third to around a fifth of deployments.
However, cost pressures are reversing what has been a continuous and significant decline in battery system costs. A recent report from GlobalData noted “volatility in material supply chains and prices could impede growth” of the battery storage market, adding that “cost perceptions in price-sensitive markets” could also deter investment.
Battery storage costs on the rise
Enormous demand for Li-ion batteries in IT devices and EVs has spurred enormous investment in technological innovation and large-scale manufacture. This helped to push prices from $1,200/kWh in 2010 to $132/kWh in 2021 – an 89% fall, according to BNEF.
That trend has now gone into reverse. The cost of lithium is up more than 900% since the start of 2021, while energy, freight and labour costs have all risen following the Covid pandemic and the war in Ukraine. BNEF researchers found that quotes for system prices for a four-hour battery to be commissioned next year in the US ranged from $250/kWh to $400/kWh, compared with an average of $227/kWh reported in 2021.
Taylor at IRENA says that costs for utility-scale systems have risen 10–30% since last year. The picture is more nuanced for residential installations, he says, with very competitive markets such as Germany recording small price falls. In less competitive markets, such as Italy and France, prices have risen, he adds.
A recent study from the Massachusetts Institute of Technology (MIT), The Future of Energy Storage, finds that “cost and limits on the availability of key materials… have set a floor on Li-ion battery costs and may constrain future deployment”.
Those cost pressures have yet to make their way down the value chain, but supply chain constraints have already begun to bite. In the US, utility-scale deployments were down 18% last year compared with BNEF’s projections. Research by consultancy Wood Mackenzie for trade group American Clean Power tells a similar story. It finds that 1.6GW of grid-scale energy storage came online in the last quarter of 2021 – but an additional 2GW of capacity slated to go live in those three months was pushed into 2022.
“The supply chain is currently quite restrictive,” says Braakenburg. “The port of Shanghai is effectively locked down.” He adds that this is unlikely to be a long-term concern.
Similarly, he is sanguine about concerns about commodity prices and availability. He notes that innovation is under way in terms of finding alternatives to Li-ion batteries, at the same time as new sources of lithium itself are being discovered. “In the long run, looking at the entire value chain, I am pretty bullish about getting to the levels of storage that are required,” he says.
Rising costs are a feature across the entire energy complex, notes Robert Stoner, deputy director for science and technology at the MIT Energy Initiative and one of the authors of the MIT study. “There is a lot of energy inflation going on, especially in Europe and in other places that rely on imported natural gas. Gas isn’t a storage mechanism, but it does compete with storage,” he says, adding that natural gas prices have risen considerably more than storage costs.
“Given the skyrocketing fossil fuel prices, the value proposition of renewables plus storage has actually dramatically improved over the past year,” agrees Taylor at IRENA.
Battery storage policy in flux
There is much governments can do to boost deployment of battery storage, says Braakenburg. “In many markets, you are either a generator of power or a consumer. Clearly battery storage is both,” he explains. This can lead to battery storage systems facing two sets of grid connection charges, for example. Enabling battery systems to ‘stack’ revenues – earning income from a variety of different applications – can also support deployment.
Short-duration battery storage is, in many markets, already able to earn investors attractive returns without the need for government subsidy, points out Grant Brennan, a director in EY’s energy and infrastructure corporate finance team in London. “Outside of ancillary services, which is a finite market, the battery storage investment case relies on price volatility and short-term supply and demand volatility… When you have got a high penetration of renewables, there is always going to be volatility,” he explains. He sees a potential risk of governments distorting the market with support programmes that result in unintended consequences such as “some irrational pricing” in the UK’s Enhanced Frequency Response market.
Kou at BNEF sees a role for strong policy signals. “Clean energy goals with energy storage carve outs or energy storage targets can help boost deployments," she says. "These types of top-down policies nudge utilities to plan for energy storage in their long-term resource plans and provide developers with the confidence to continue deploying in markets through current supply chain constraints.”
Of particular importance to investors and developers is greater visibility on the extent and type of battery storage that will be required. However, Brennan notes that system operators are sometimes playing “catch-up” to provide that visibility, due to the market evolving so quickly. “National Grid [in the UK] has got decades of experience operating a system with baseload coal, gas and nuclear," he says. "It had the necessary tools to manage volatility; with decarbonisation and high penetration of renewables, we now have a different type of supply-side volatility.”
Some markets, meanwhile, are likely to be able to benefit from low labour costs and fast project development cycles. The MIT study looked at the prospects for energy storage deployment in India, and its modelling found significant potential for renewables plus storage to compete with coal-fired capacity, reducing overall system costs and emissions, even in the absence of a significant carbon price.
Technology looks to the long term
The MIT research used Li-ion technology as the baseline, given the level of understanding of its costs and likely cost trajectory, says Stoner, but as the energy transition advances longer-duration storage will be required. While Li-ion batteries will continue to dominate short-duration storage of below four hours, costs mean that they are unlikely to become competitive for long-duration storage of greater than 12 hours.
Stoner notes that alternative technologies such as iron-air batteries are “very cheap to build and very expensive to ship”, given their size and weight. This will favour domestic, in-country production, a trend that is already under way in other clean energy technologies including Li-ion batteries.
The MIT project also began analysing some novel energy storage applications including repurposing ageing coal-fired plants as “thermal batteries”. While renewables can outcompete new coal-fired plants, those that have repaid their capital investment are very cheap to operate and “hard to eliminate from the system”. One way to do so would be to draw excess power from the grid to heat a medium such as firebricks or molten salt, which could be used to drive their turbines and produce power during peak periods. Stoner says the initial analysis has shown that the economics, in certain circumstances, “is pretty favourable”. The team is now doing “a more rigorous analysis” of specific plants, with results expected later this year, he adds.
Given the lack of maturity and need for long-duration storage, as renewable energy penetration grows different types of government support and regulation will be needed, say market observers.
Edwards at Cornwall Insight notes that, because such systems would be arbitraging energy between weeks or months, rather than hours or days, their economics are more like gas storage infrastructure or electricity interconnectors. “They might benefit from funding structures, like contracts for difference or a cap-and-floor mechanism,” he says.
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The former has successfully incentivised offshore wind in the UK, paying operators if power prices are below a reference price but with the government receiving payments if power prices are higher. Ofgem, the UK energy market regulator, introduced a cap-and-floor regime for interconnectors, which similarly offered a guaranteed return in exchange for setting a cap on the maximum revenue the operator could earn.
Taylor at IRENA notes that there are plenty of other technologies that could enter the storage race. These include hydrogen, using bioenergy power plants to meet peak demand rather than as baseload generation, and relying on demand-side technologies to store energy. “The increasing electrification of heat gives you the potential to use water tanks with heat pumps as low-cost thermal energy stores,” he says.
Stoner at MIT notes that extensive and sophisticated system modelling is necessary to ensure the appropriate volumes of storage are developed, and in the right places. While fuel-based generation plants can be ramped up and down to manage changes in demand, renewables typically cannot.
“Minimising the amount of storage needed by planning carefully and taking into account all these variable factors [introduced by renewables] is very important for the overall costs of the system,” Stoner concludes.
