Overall power investment around the world is set to decline in 2020 by an estimated 10% as a result of the Covid-19 pandemic. This marks a dramatic break from the situation at the start of the year, when company expectations, capital expenditure planning and ongoing capacity expansion activities suggested a rise of around 2%. Power investment reflects ongoing capital expenditures on projects under construction. As such, this decline is influenced not just by the new capacity additions and refurbishments expected this year, but also spending on assets that would be delivered in the years ahead. Government policies will play a critical role in smoothing the impact, and – as noted in past WEI editions – over 95% of power investments are incentivised by regulations and contracts. 

Some parts of power investment are more exposed, particularly fossil-based generation, as lower demand and electricity prices create less need for new capacity and add pressure on  margins. Investment in new coal-fired plants has already fallen sharply in recent years and is set to decline by over 11%, with cuts concentrated in Asia. Nevertheless, investment activity in China (see next page) may put a floor under further reductions in 2020.

The effects on investment in gas-fired generation arise mainly from delays in gas-rich emerging economies, like the Middle East and North Africa (MENA) region where spending drops by about one-third, given high public-sector participation in the sector, lower expected revenues from commodities and limited fiscal space. We estimate a reduction in total fossil-based power investment of 15% globally compared to 2019.

Higher shares of renewables have been dispatched during the lockdown because of low operating costs and priority access to networks: this, along with long-term contracts, has helped to support revenues. However, investment in new renewables capacity is affected as lockdowns and mobility restrictions affect production, shipping and construction schedules, as well as shifting demand expections and policy and procurement measures. We estimate an overall reduction of 10% in spending on renewable power compared with 2019.

Among renewables, distributed PV has been hit hard as households and corporates cut back on spending, and installation activities face the highest disruption from lockdowns. The effect on utility-scale wind and solar PV projects is lower, and spending is also influenced by continued cost reductions, especially in solar PV. Nonetheless, final investment decisions (FIDs) for utility-scale solar and wind in Q1 2020 declined to Q1 2017 levels. Investment in longer-lead time technologies, offshore wind and hydropower, is set to rise supported by ongoing projects around the world, and completion of two mega hydro projects in China, though there are risks of delays in some regions.

Nuclear investment is set to decline given some impact to development schedules, but long associated lead times make spending less volatile.

Investment in grids, which has been declining in a number of countries, is set to fall again, by around 9% in 2020; despite its regulated nature. The impact will be larger in developing countries as most of the investment in networks is financed by state-owned utilities that were in weak financial position before the crisis, and will likely worsen, driven by more limited fiscal capacity from governments and higher financing costs as sovereign risks increase (see Energy Financing and Funding section). That said, grid spending falls less than generation, spurred by ongoing upgrades in some markets (e.g. United States, Europe) to support resiliency and reliability and new support in China.

Power investment in China, the world’s largest market, is set to continue its downward trend in 2020 as the country faces its first recession in decades, with reduced spending in all technologies. Though lockdowns were mostly lifted by April and industrial production resumed, energy investment in China has already been dampened by the disruption to investment activity and supply chains.

Investment in China is nonetheless likely to be less affected, in relative terms, than in other regions, as recent signals provide a buffer. These include an upward revision in State Grid’s investment plan for 2020 and a slight year-on-year increase in investment of major power companies in Q1. Spending in coal power may also see a lower percentage drop (compared to other regions of the world and the annual reduction in recent years), as more regions got a green light for construction and 8 GW of coal-fired capacity was approved in March 2020 (a similar amount to the coal-fired FIDs in China for the whole of 2019). Renewables continue to account for the largest share of investment, and decline less than in other parts of the world, as spending on solar PV and wind largely holds up.

Expectations for a robust year for renewables in Europe and the United States, based on prevailing project pipelines, have been reversed by the historic recession, and capital spending in the power sector is now set to decline in 2020. Solar PV and onshore wind see negative impacts, especially distributed PV, but offshore wind grows. Some large European- and US-based utilities have so far maintained a degree of financial resilience – with electricity prices largely hedged in 2020, and increased profits in some cases from continuing operations in Q1 – helping to provide support for grid spending.

A number of major utilities in these two markets have remained optimistic and have maintained their capital spending plans for 2020. Despite this early signalling, a number of uncertainties persist, and it is likely that signs of economic stress become more apparent through the course of the year, as lockdowns affect deployment targets and revenues. Smaller companies with weaker financial standing and tighter margins are likely to be more affected, with many such actors not providing spending guidance at all. First quarter results of power equipment companies point to intensifying challenges for this segment, as delays and increased logistic costs affect revenues and profits in several of the main players, on the back of already tight profit margins arising from fierce competition and trade tensions affecting supply chains. As such, our estimates for overall power spending are less optimistic than the announcments of the largest utilities would suggest.

Regions that rely heavily on public funding are also likely to see deep cuts in spending, such as India and countries in Africa and Southeast Asia. Enabling environments for investment in most of these countries carry a number of risks that can challenge project bankability, though those with strong policies see spending support. The Indian government is taking measures to buffer the investment shock, including extensions for project commissioning, maintaining renewable auctions and trying to boost private capital. In some countries, recent government announcements point to growing investment uncertainties. For example, investment expectations for Mexico and Brazil – the two largest markets in Latin America – have deteriorating, as Brazil is postponing all transmission and renewable auctions and Mexico is slowing down the connection of renewables.

Physical restrictions and new uncertainties over equipment demand caused delays and disruptions to renewable supply chains in early 2020, and may continue. Solar PV module manufacturing was idled in China and other locations in Asia as restrictions initially took hold. In Europe, some 20 wind turbine facilities stopped operating in March, mostly in Spain and Italy, with factories in India also stopping production. Longer duration of these disruptions, and their spread to additional locations like Southeast Asia, could derail renewables progress by further delaying the completion of many projects globally.

China has an outsize impact on solar and wind supply chains; it accounted for two-thirds of PV module shipments in 2019. Conditions have eased there, with most factories back up and running by April, though operating margins remain tight on the back of low prices and oversupply – global shipments exceeded project additions by more than 10% in 2019 – and plants requiring time to ramp up production.

The picture in some other countries has also appeared to ease. In some US states, PV manufacturing is deemed an “essential business”, allowing operation during restrictive periods. By mid-April, operations resumed for some European wind plants. In general, manufacturer service and maintenance businesses have remained up and running.

Many challenges remain for the industry. Before the crisis, equipment manufacturers faced financial pressures (see Energy Financing and Funding section), with tighter margins stemming in part from competitive bidding and lower renewables prices. In 2019, India’s major wind equipment company defaulted on its bonds and is undergoing a large debt restructuring.

Given the uncertainties, some governments and utilities are delaying procurement, which means reduced order books and cash flow for suppliers, though they may be able to focus on repowering existing assets and adopting more flexible payment terms. Consolidation pressure on smaller manufacturers with weaker balance sheets may accelerate. Larger players may weather the storm with cost-cutting. This may also raise questions over research and development budgets and efforts to advance turbine and module designs, for which there has been good spending progress in recent years (see R&D section).

Global power sector investment, at below USD 760 billion in 2019, was down by less than 2% compared with 2018, driven mainly by a strong drop in capital spending on electricity networks, which offset the increase in nuclear power and small increase in renewables.

In 2019, China continued to account for more than a quarter of the overall investment, though its spending dropped as a result of lower spending in grids, coal power and solar PV projects. On the other hand, the United States and Europe saw strong increases. The US growth was driven by a big increase in wind power and networks. In Europe, fossil fuel and nuclear power drove spending upwards.

Global spending on coal-fired power plants dropped by 6% in 2019, reaching a decade low. The main reduction occurred, once again, in China (although FIDs in China picked up in 2019). Despite the falling trajectory, the size of the global coal fleet continues to grow as more capacity entered into operation than retired.

Gas-fired power spending reversed its recent trend and increased in 2019, reaching levels similar to 2014‑15. Spending continued to slow in two of the largest markets, the United States and MENA (following a considerable slowdown in FIDs in 2017‑18), and increased mainly in Europe and Russia.

Renewable power spending, at around USD 310 billion in 2019, grew by 1%. There was increased spending on wind power in the United States, a sector that has been growing fast given good resources, policy support (e.g. production and investment tax credits) and demand from corporate power purchase agreements (see Energy Financing and Funding section). Spending increased slightly in India, driven by higher investment in wind. China’s renewable power spend edged down in 2019 as an increase in hydropower was not large enough to offset lower solar PV (after a reduction in financial incentives). Spending in Europe also edged down, due to wind, even as corporate buying activity increased. Investment in distributed solar PV and battery storage comprised half of total spend in these technologies.

Nuclear power investment edged up again, as several projects started construction in 2018 and four additional ones did so in 2019. This was an important driver of growth in Europe given the two reactors of Hinkley Point that started construction during the period.

A 7% drop in spending in electricity networks was the main reason for the overall fall in global power investment in 2019. This was mainly due to an 11% drop in China’s investments, mostly driven by regulatory changes and reduced grid tariffs, outweighing continuous growth in the United States (which reached the top place for network investments for the first time in a decade). In addition, global spending in transmission reduced to USD 90 billion, below the USD 100 billion level that was surpassed between 2016 and 2018. Investment in battery storage dipped for the first time, by 12% to USD 4 billion in 2019%, though partly due to falling costs.

The overall share of power investment in developing economies dropped to the lowest level since 2013. This was mainly due to the rise in spending in Europe and the United States during the last years – which has also reduced the gap with the largest market (China).

Global FIDs for coal-fired generation, at below 17 GW in 2019, dropped for the fourth year in a row—the lowest level since 1980, despite an increase in China. Pressure from civil society, more stringent environmental regulation and decreasing availability of finance (see Energy Financing and Funding section) for new coal-fired power is pushing this downward trend. The majority of the 2019 FIDs for coal-fired plants (almost 90%) were once again in higher efficiency plants, with only a very small portion in inefficient subcritical projects, mainly in Indonesia.

Nevertheless, net additions of coal-fired plants in 2019 rose for the first time in five years, driven by an uptick in newly commissioned plants in China and, to a lesser extent, in India. Additions in China were a result of various factors, including: support to industrial and economic activity, utilities’ expansion targets and domestic generation plans (linked with issues around security of supply). This growth also came in the face of weakening electricity demand and falling utilisation rates for the existing fleet (which are likely to carry through in 2020), intensifying the risks of overcapacity.

Over 250 GW were retired globally between 2011 and 2019, two-fifths in the United States and almost a fourth in China. The United Kingdom and Germany accounted for an additional 15%. Most of the plants retired were subcritical but as countries face increasing pressure to improve air quality and environmental standards, some more efficient plants are also being retired. A relatively low gas price environment also helped accelerate this trend.

The average size of plants retired was highest in the United Kingdom, while China, India and – until mid-2010s – the United States retired smaller plants (on average), mostly below 200 MW. Except for China, where the average age was 20 years old, most countries retired plants that were at least 40 years old. In the United States, plants operated between 45 and 60 years before being retired, though there seemed to be a trend towards decommissioning younger plants.

More retirements have been announced for the coming years but the global coal power fleet is set to continue expanding, given a large existing construction pipeline. There are some 130 GW of projects under construction that are expected to start operation between 2020 and 2023; taking anticipated retirements into account, this would mean net growth in the global coal fleet of around 40 GW. There continues to be a geographical mismatch between retirements and additions, but there are some new signals coming from countries which until now had been mainly adding capacity. For example, the government of Indonesia announced in early 2020 that it will replace coal-fired plants aged 20 years or older. According to IEA analysis, if this were to be implemented, it would translate to around 7 GW of coal-fired plants being retired.

Lower expected electricity demand and prices in 2020 would likely delay capital spending in coal-fired plants further, given a lower need for new firm capacity. However, pressure to stimulate economic growth in emerging Asia may challenge this. For example, in March 2020, China announced 8 GW of coal-fired capacity approved, a level similar to the overall capacity approved in 2019, and more than 2018. The government also lowered the restrictions to build new coal-fired plants for the third consecutive year, giving a green light for construction in more regions of the country.

Overall, FIDs for the main sources of large-scale dispatchable power – coal, gas, nuclear and hydropower – fell to 86 GW, an 8% reduction compared with 2018 and almost 60% lower than in 2010. This is the lowest level in a decade.

Among these sources, FIDs for gas-fired generation were the only ones to see an increase (for the first time since 2015), to over 55 GW. The strongest growth was in the United States, where gas generation, supported by low prices, is teaming up with renewables to displace coal: some 5% of the US coal power fleet retired in 2019. The MENA region also saw considerable growth, particularly in the Gulf Cooperation Council countries. China’s investment decisions fell to below 10 GW, even as they remained high in comparison with approvals in recent years, supported by broader targets to increase gas use. In the past decade, the share of FIDs has risen for combined-cycle plants, compared with smaller gas turbines typically used for peaking applications. This stems from a focus on meeting large-scale demand (and replacement) needs, but it may also reflect increased battery storage deployment to provide short-term system flexibility.

FIDs for the largest sources of low-carbon dispatchable generation (hydropower and nuclear) also fell to a combined total of 14 GW, the lowest level this decade. The drop in FIDs for hydropower, also a record low, stemmed from fewer approvals for pumped storage in China. Chinese regulation does not allow transmission and distribution companies to include pumped hydro assets as part of their regulated asset base (used to estimate the tariff these companies charge). With lower electricity demand in 2019, and lower demand expected in 2020, there is also less need for pumped hydro to balance peaks. However, the downward trend in Chinese hydropower investment may reverse in the coming months. State Grid of China started building a new pumped hydro dam in early 2020 after putting a halt to installations during most of 2019.

FIDs for nuclear also decreased, with only four new plants starting construction, the biggest one the second reactor of Hinkley Point in the United Kingdom, which started construction in December 2019. Outside of a few markets with strong policy support, construction starts for nuclear projects continue to lag, with persistent project development challenges in some markets, and in some cases local opposition.

FIDs for utility-scale renewables decreased in spending terms (i.e. nominal USD terms) by 2% in 2019, despite divergences between technologies. Utility-scale solar PV FIDs decreased by 20% as they faced higher regulatory uncertainty and more competitive pressure in developing markets such as China and India. However, while onshore wind FIDs remained flat, offshore wind FIDs increased by 70% and hit a record of USD 40 billion, with investors showing high appetite in China, Chinese Taipei, Germany and the United Kingdom.

Data from the first quarter of 2020 show that FIDs for utility-scale renewables (excluding large hydropower) contracted to first-quarter 2017 levels, with downturns in onshore wind (year-on-year reduction of 50%) and solar PV (down by 20%). This reflects some risk-aversion to financing projects in the near-term given lower demand and wider uncertainties that emerged with the Covid-19 pandemic, and is consistent with a parallel fall in global power sector project finance transactions during that period (see Energy Financing and Funding section).

Understanding the energy impact of power investments is important to assess their contribution to meeting long-term goals. In 2019, the global expected generation from low-carbon power investments outpaced electricity demand growth for the first time in five years. Part of this stemmed from weaker demand, which had the lowest growth in a decade, and a sharp reversal from the trend in 2018. Demand growth was around 30% lower in China, while India saw no growth for the first time in ten years; declines were also registered in the United States and Europe. Part of this reduction in demand may have been temporary (e.g. an exceptional monsoon in India reducing electricity needs for irrigation) but there are considerable downside risks to electricity demand in 2020 given the Covid-19 pandemic. The IEA estimates a drop in global electricity demand of 5% globally in 2020.

At the same time, the expected output from low-carbon power investments rose, largely due to a higher contribution from new solar PV and wind. Here, too, there are significant caveats to this picture, with a slowing of spending from short- and medium-term impacts related to the current crisis.

Current investment levels are not aligned with a sustainable pathway. Compared with the average annual investments projected in the IEA SDS, power sector spending in 2019 was about 35% short of the level required a decade from now. There is a continued need for capital reallocation to meet energy security and sustainability goals, to bring in more low-carbon power and to ensure that renewable-rich systems can operate with sufficient system flexibility.

The largest projected growth in investment to align with such a pathway would be required in solar PV and wind, on average an extra USD 160 billion of spending each year. Electricity networks would require an extra USD 150 billion from today’s levels, in addition to a higher level of capital for other renewables and nuclear.

Comparing current trends with projections in the SDS, emerging economies would need to boost spending on renewables, while at the same time supporting other areas of power system flexibility and decarbonisation, such as through flexible operation of thermal plants, fossil fuels with CCUS, grids, energy storage and demand response. Investments in China present the highest divergence. India, Southeast Asia and sub-Saharan Africa would need to more than double renewable investments. Nuclear would likewise see increased investment, particularly in China, with additional annual spending of USD 10 billion, and India, with an additional USD 5 billion.

In advanced economies, the gap is smaller for solar PV and wind, but they would still require uplifts of 20-30% in Europe and the United States. Hydro, other renewables and nuclear remain as key technologies to guarantee security of supply and to meet sustainability goals. However, 2019 spending on these technologies was well short of SDS projections, by USD 10 billion for investments in nuclear for Europe and by USD 20 billion in hydro and other renewables for the United States.

While capital expenditures for renewable power increased moderately in 2019, by 1%, driven by onshore wind and hydro outweighing a decline in solar PV, capital costs for some technologies have continued to decrease. For example, utility-scale solar PV installation costs decreased by over 10%, continuing a trend of declines due to supportive policies (e.g. expansion of competitive auctions) and higher deployment in lower-cost and large markets such as India. A given level of investment buys much more renewables than in the past. The expenditure needed for 1 MW of renewables in 2012 enables the construction of 1.5 MW today.

Decreasing capital costs have helped to reduce overall levelised costs of electricity (LCOEs) for solar PV and onshore wind, along with other factors such as the improvement in average load factors. For wind projects, for example, larger turbines and increased hub heights mean wind farms are able to produce a greater amount of power with a smaller number of turbines. This trend is also driving reductions in operation and maintenance costs, favoured by efficiency gains from digitalisation.

Financing costs are also a critical component of LCOEs and reduced WACCs have been vital to scale up renewable deployments globally. For example, applying a standard average real WACC of 8% to a US solar PV project in 2019 produces an LCOE of around USD 80/MWh in 2019. The LCOE for the same project with access to lower-cost financing (4% on average) is just over USD 50/MWh. Actual required returns depend a lot on the degree of associated market risk.  Involvement of public finance has been key to reduce the cost of capital in emerging markets, such as India, which on average face higher financing costs (given higher country, technology and revenue risks).

On the debt side, financing terms have improved globally. This is due to lower base interest rates (driven by accommodative monetary policy and lending competition) and lower debt risk premia (from a maturing renewables industry and the risk reduction role of supportive government policies and ambitious goals). For example, evidence shows that lower risk perceptions contributed to improved availability and pricing of project debt finance in India for utility-scale solar PV and wind projects over 2014‑18 (CEEW and IEA, 2019). Debt risk premia fell by 75-125 basis points for both technologies over the period, with banks willing to lend for longer tenors. On the equity side, expected returns on equity have also lowered globally, as supportive policies and growing market experience helped reduce investor risk perceptions.

The upshot is that LCOEs for newly commisioned utility-scale solar PV and onshore wind plants have fallen to around USD 35/MWh to USD 55/MWh in China, Europe, India and the United States (assuming low cost financing). Even lower prices have also emerged in competitive auctions for capacity to be commissioned in the years ahead, e.g. prices below USD 20/MWh in Brazil, Mexico, Portugal, Qatar and the United Arab Emirates.

Central banks are likely to keep interest rates low to stimulate growth. Yet some emerging countries may face challenges as sovereign risks increase and there are signs that commercial banks may raise margins on project lending to compensate for higher liquidity costs. Uncertainty can also mean more difficulties to mobilise equity globally. We expect a lower annual drop in indicative LCOEs in 2020 with financing costs staying level or potentially rising as a result of new risks.

Wind repowering refers to the refurbishment or upgrading of wind turbine system components with the latest and more advanced equipment. Taking advantage of technological improvements, repowering enables not only to increment the nameplate capacity of an existing wind farm, but also to enhance load factors and to reduce operation and maintenance costs. This is mainly driven by larger turbines and increased hub heights that allow production of a greater amount of power with a smaller number of turbines

More than 10% of total spending in onshore wind has been devoted to repowering in the United States and Europe in the last three years. However, as more and more turbines reach the end of their useful life (20-25 years), global repowering is expected to steadily rise and get close to USD 10 billion per year, two to three times higher than the 2017‑19 annual levels.

Wind repowering could surge even faster if properly incentivised by regulation or economics. For instance, India has more than 10 GW of wind turbines with less than 1 MW capacity in very good resource sites. Repowering of these with the latest turbines would more than quadruple the energy generation of these sites. In the United States, investments in repowering in 2017‑19 were more than ten times higher the equivalent needed to refurbish the ageing plants.

Repowering may also become an increasingly attractive option for developers reluctant to commit large upfront capital to greenfield developments in light of the current crisis.

In 2019, investment in electricity grids declined for the third consecutive year, by 7% compared with 2018 levels, falling under USD 280 billion. Most of this decline stemmed from a sharp reduction in China, which more than outweighed strong growth from the United States, which took the top spot for grid investment for the first time in a decade. Nevertheless, there are questions over how these trends may play out in 2020, with utilities facing potentially reduced needs to connect new generation and funding constraints; on the other hand, public incentives to increase infrastructure investment in the wake of the Covid-19 pandemic may potentially offer support to spending.

Global spending in transmission reduced by 10% to USD 90 billion. China and India drove this trend. Investment in China’s transmission decreased by nearly USD 10 billion, as there was a higher focus on the upgrading of rural power grids and the construction of distribution networks. In India, despite a big push to strengthen inter- and intrastate transmission capacity in the last five years, the pace of buildout slowed in 2019 by USD 2 billion. In addition, several renewable projects on the pipeline are facing higher uncertainties and delays, so there was less pressure on the need for transmission connectivity.

Capital spending in distribution decreased, too, but at a smaller rate (6%). On the one hand, investments in the United States grew for the fifth consecutive year, driven by ongoing focus of regulators and utilities on improving grid resilience and reliability. On the other hand, distribution investment declined worldwide except for Europe and China, where they remained stable. This was driven by lower growth rates for electricity demand.

As grids are becoming more digital, distributed and smart, investment depends less on traditional equipment and more on new drivers. Smart meters, utility automation and EV charging infrastructure, at USD 40 billion, now make up more than 15% of total spending. While spending on smart meters and utility automation remained flat in 2019, that for EV charging infrastructure rose to more than USD 5 billion, with utilities, oil and auto companies, and governments announcing new expansion plans. For instance, China Southern Power Grid recently announced plans to invest more than USD 3 billion over the next four years in charging infrastructure.

By virtue of these digital infrastructure investments, electricity systems have augmented their resiliency and ability to operate with greater shares of variable renewables, as demonstrated during recent periods of much lower demand (IEA, 2020a). Such investments are supporting new business models by aggregators to integrate small-scale renewables, demand response, and other distributed resources into power grids, when regulatory conditions and market design are appropriate (see Energy Financing and Funding section). They can also facilitate the integration of power systems with more localised networks for heat supply as an another source of flexibility (see Energy End Use and Efficiency section).

The current trajectory of grid spending is at risk of falling short of that needed to support growing renewables and electrification. Overall global grid spending would need to rise by some 50% over the next decade to meet long-term sustainability goals. Spending on digital grids would need to surge, too.

China’s investments in electricity grids accelerated their downward trend and dropped by 11% in 2019, mainly driven by regulatory changes and reduced grid tariffs. Average purchase-sale spreads for grid companies (i.e. the difference between the price at which transmission companies purchase electricity from generators and the price they obtain for selling it, including lines losses) decreased by 10% between 2016 and 2018. This reduction has been incentivised by both the Power Sector Reform of 2016 (which aimed to provide more transparency with regard to network costs) and public measures that sought to reduce the power retail tariff. Furthermore, some intra-provincial and long-distance transmission line tariffs have also been revised down.

Grid investment in the United States increased by 12%, following a continuous upward trend in the last decade. Higher activity was required to upgrade ageing infrastructure, digitalise, electrify sectors such as transport or heat, and secure the grid against natural disasters and cyberattacks. Higher costs have also played a role: transmission costs have steadily increased by an annual rate of 3% since 2011. Poles, towers, fixtures, conductors and devices continue to be the principal drivers of transmission line costs.

In Europe, investments have remained stable at nearly USD 50 billion, with an increase in spending going to support upgrading and refurbishment of the existing grid, as the role of variable renewables and electrification have grown. This is evidenced by a slower pace in transmission and distribution network expansion since 2015, while investments in digital grid infrastructure have risen steadily.

Despite this slowdown, actual investment spending has remained robust as the focus shifts to new digital infrastructure. Electric vehicle charging infrastructure surpassed 170 000 units in 2019 and smart meters are reaching the roll-out target of 80% market penetration of the European Union by 2020. Investments have also aimed to integrate variable renewables, as solar PV and wind have increased that share in the energy mix from 10% in 2015 to almost 15% in 2019.

Furthermore, a continuous improvement of market coupling schemes both regionally (more markets integrated) and temporally (more time-scale products including some ancillary services) have also led to higher efficiency and better utilisation of existing grid assets. However, the ambitious European Green Deal targets – which will likely surpass the present European Union target of 32% share of renewables in gross final energy consumption by 2030 and aim to speed the pace to carbon neutrality by 2050 – will require much higher investments and greater efforts at integration, not just with the power sector, but with transport and heating systems as well. Offshore wind, in particular, is to play a pivotal role in the future low-carbon power system of Europe, with investments in enabling grid infrastructure potentially increasing tenfold from current levels under targets being considered.

Investment in battery storage declined for the first time, by 13%, though remained above USD 4 billion in 2019. Spending on grid-scale batteries decreased by nearly 15%, while investments in behind-the-meter storage decreased by 5%, as costs continued to fall rapidly.

Globally, average costs continued to come down as battery pack prices fell and developers continued to reduce balance-of-system costs (e.g. mounting equipment, cabling and labour). The trend diverged between segments, with an 8% reduction registered for grid-scale battery storage and a nearly 15% drop in costs for behind-the-meter applications. Greater cost reductions for behind-the-meter were achieved as the market gained traction, improving efficiencies in engineering and construction, reaching higher standardisation around system design, taking advantages of maturing supply chains and increasing competition with new entrants. However, behind-the-meter batteries remain around twice as expensive as grid-scale ones on a USD-per-kilowatt-hour basis (under USD 350/kWh for a four-hour battery versus USD 700/kWh for a two-hour one).

Among markets for grid-scale storage, 2019 spending decreased in almost every region, except for Australia and the Middle East (the latter pushed by several sodium sulphur batteries developed in the United Arab Emirates). In Korea, fires reported at energy storage systems in 2018 led to higher safety and regulatory standards, whereas in China, regulation uncertainty resumed in batteries not being considered as networks fixed assets, thus grid companies losing interest in using batteries as replacements for other network investments. Deployment surpassed the 1 GW barrier for a second consecutive year. Half of this new capacity was devoted to hybrid battery storage projects (coupled with power generation assets). Within these, almost 300 MW of battery storage was coupled with solar PV and 115 MW with wind. The rest was coupled with thermal power and other renewables.

Grid-scale battery investments in 2020 are expected to decline in response to a broader slowing of power activity, but this pause is likely to be shortlived given their growing role in system security and flexibility. Some large projects have been recently announced, such as from Southern California Edison, who signed contracts to procure 770 MW or Solar Partners XI, LLC project in las Vegas which aims to develop a 690 MW solar PV plant paired with a battery of 380 MW.

Global behind-the-meter battery storage spending partly reflects the market for distributed solar PV, for which investment slowed in 2019. Investments in China and Korea both nearly halved mainly driven by lower costs, as new entrants and manufacturers are entering the market. Activity was also hit in Korea as investigations into 2018 fires concluded in mid-2019, leading to stronger safety measures. Still, in the United States, spending on batteries nearly doubled, as supported by California’s funding for resilience applications serving wildfire-threatened parts of the state. In 2020, global spending is likely to slow, in line with fewer consumer installations of distributed resources.

In terms of performance, discharge duration hours (the ratio between energy storage capacity [kWh] and rated power [kW]) for grid-scale batteries increased for a fifth consecutive year and reached a level of 1.8 hours, 60% higher than 2015. This trend is supported by more projects moving beyond short-term applications, such as frequency control, to include a wider spectrum of services, such as energy arbitrage, firm capacity or renewables integration, which also enhance the sources of remuneration (see Energy Financing and Funding section).