Between 62% and 68% of final electricity demand originated in the industrial sector and the commercial and public services sector in the past 30 years, suggesting a close relationship between economic activity and electricity consumption. Although the industrial sector only accounts for around 28% of global GDP, compared to services at 67%, it comprised 42% of final electricity demand in 2018, while services stood at just 22%.

In the past 15 years electricity demand has almost stagnated in developed economies, seeing 0.4% average annual growth despite economic activity growing on average by 1.6% per year. In emerging and developing economies, 5.4% average annual economic growth during the same period was accompanied by an annual 5.7% increase in electricity demand on average. In total, this means that 93% of the worldwide net growth in electricity demand from 2005 to 2019 originated in emerging and developing economies – and 58% in China alone.

The majority of the additional global electricity consumption during 2005‑18 was used by industry (39%), followed by residential (22%), and the commercial and services sector (15%). The industrial sector also recorded the highest average annual rate of growth in electricity consumption (3.1%) compared to 2.8% and 2.3% in the residential sector and commercial and services sector respectively.

In 2009 – the most recent global economic recession before 2020 – global real GDP decreased by 0.1% and electricity demand dropped by 0.6% (net 103 TWh). While demand in emerging and developing economies continued to grow by 3.6%, it fell by 3.8% in developed economies. With a decline of 3.5%, industrial electricity demand dramatically reversed in comparison to the average 2005-18 growth rate. Demand growth in the commercial and services sector slowed to 0.6%, and only the residential sector continued to grow significantly (2.3%).

A larger drop in global demand was prevented by China and India, where consumption continued to grow by 7.2% (238 TWh) and 7.4% (50 TWh) respectively.

The strong rebound in global electricity demand in 2010 (up 7.2%, 1 340 TWh) was headed by China (up 13.1%, 460 TWh), the United States (up 4.6%, 182 TWh), Japan (up 7.8%, 82 TWh) and India (up 9.1%, 65 TWh). In total, developed economies grew by 4.8%, while electricity demand in emerging and developing economies in 2010 exceeded 2009 by 10.2%.

In 2020, due to the nature of measures taken against Covid-19, the commercial sector has been particularly affected, with the drop in global electricity demand expected to be around 2% and GDP 4.4% down. Relative electricity consumption fell less than GDP (in 2009 this was the reverse) due to the lower electricity intensity of the commercial sector compared to industry.

In 2021 electricity demand is anticipated to grow by 3% (around 700 TWh), slower than the projected 5.2% real GDP growth. In total, this means global demand would be higher than in 2019.

Two-thirds of the additional demand is expected in the Asia Pacific region. Most of the growth is concentrated in China and India, expected to grow by 5.2% (350 TWh) and 3.6% (40 TWh) respectively compared to 2020. Both countries have already recorded significant growth rates towards the end of 2020 compared to 2019 demand. Also in Southeast Asia electricity demand in 2021 is expected to significantly exceed demand in 2019. Southeast Asia, one of the fastest-growing regions in electricity demand terms in recent decades, is expected to return to previous growth rates and add 5.4% of demand in 2021 compared to 2020.

In the United States only a slight recovery of around 1% is expected, after a fall of 3.6% in 2020. Although demand is expected to grow by 2.3% in Europe, this still means it would be 2% lower than in 2019.

The greatest uncertainty for electricity demand in 2021 is the further development of the Covid-19 pandemic, the measures taken by governments to prevent it spreading and the availability, speed of distribution and effectiveness of vaccines. This will significantly affect the commercial and services sector, which was hit hard by repeated lockdown measures towards the end of 2020. Additionally, economic prospects depend on government stimulus packages and their success in triggering new investment and supporting businesses that have experienced economic pressure in 2020.

The expected sharp recovery in gas prices in the United States and Europe (Henry Hub and TTF respectively) would diminish the competitive advantage of gas-fired power plants vis-à-vis coal-fired generation. In the United States coal-fired power generation is expected to recover by 12% y-o-y, driven partly by higher electricity demand (up 1% y-o-y) and lower output from gas-fired power plants, declining by 8% y-o-y. In Europe gas- and coal-fired power generation are expected to remain stable, declining only marginally by less than 1% as most of the market space from recovering demand is expected to be captured by nuclear power generation and renewables.

Markets in OECD Asia should benefit from lower oil-indexed gas prices. However, the drop is unlikely to be enough to trigger a market-based coal-to-gas switch. In Japan both coal- and gas-fired power generation are expected to decline, by 3% and 7% respectively, amid higher nuclear power generation. In Korea gas-fired power generation is expected to increase by close to 6%, supported by recovering electricity demand as well by the start of the third phase of the carbon emission scheme, whilst coal-fired power output is expected to drop by almost 7%.

With the expected recovery of electricity demand in 2021, it appears likely that fossil fuel-based generation will be able to regain some of the ground it lost in 2020. Coal in particular is expected to see a relatively large recovery in absolute terms – but having suffered great losses in 2020, this means still being more than 2% down compared to 2019. Whereas a large comeback in Europe is unlikely due to strong competition from renewables, globally coal is expected to recover about half of its losses in 2020 due to increasing gas prices.

Renewable energy, mainly solar PV and wind, is expected to claim further market share, growing by 17% and 11% respectively. In total, renewables are approaching a collective global market share of 29% (up one percentage point).

Although the absolute growth of low-carbon electricity generation is expected to exceed fossil-fuel based growth in 2021, global emissions could rise again. After the approximately 5% emissions reduction in 2020 compared to the previous year, emissions are projected to increase by around 2% compared to 2020.

An anticipated increase in coal-fired electricity generation is expected to cause additional emissions, especially in China and the United States. In the case of China, this is due to a continued strong growth of electricity demand which is served by coal-fired power plants. In the United States increasing gas prices could cause a fuel switching from gas to coal.

With the increasing share of renewables in the generation mix, their dependence on weather conditions increasingly affects electricity markets around the world. Not only do variable renewables fluctuate from hour to hour, but also annual capacity factors can differ significantly between years. This is the case for wind, solar PV and hydropower plants. Reservoirs, for example, are very flexible in their short-term production, but are dependent on water inflow over longer periods.

We analysed data from seven countries and found that compared against an average year, hydro generation varies within wider ranges than wind and solar. This is especially notable in Spain, where annual hydropower generation, normalised for capacity changes, has oscillated between 55% and 148% of the average in the period between 1991 and 2019.

Solar generation fluctuates within smaller ranges than wind and hydro. Spain (97-103%), Japan (94-106%), Italy (93-106%) and France (92-107%) show the lowest variability from the baseline. Of the evaluated countries, wind stands between solar and hydro in terms of annual variability. The United States (90-105%) and Japan (95-107%) vary the least while the United Kingdom presents the highest variability (85-112%).

In Germany wind, solar PV and hydro are projected to reach a combined capacity of 134 GW in 2021. This could mean a total generation from these sources of between 186 TWh and 246 TWh, or 38% to 51% of projected electricity demand in 2021.

Due to the annual variability of certain renewable energy sources, the residual demand that has to be covered by non-renewable generation depends on the characteristics of the individual weather year.

Countries with higher shares of wind, solar PV and hydro generation tend to have a higher relative uncertainty regarding residual demand – depending on the individual composition of renewables and national weather characteristics. Depending on the year’s weather, residual demand in Spain may be between 9% lower and 10% higher in 2021 than given average weather conditions. With hydro, wind and solar PV expected to cover 46% of demand, Spain has the highest share of renewables in the sample. For the United States, Japan, and France, at the lower end of the range of renewables share in the sample, residual demand uncertainty is lower than 4% in both directions.

The variability of annual renewable generation has a direct impact on the need of future electricity systems for long-term storage – especially in the context of a very high share of renewables and zero-emission targets.

Additionally, conventional generation technologies are directly impacted. Although some of the variability of renewables might be balanced through trade in interconnected systems, a year with unfavourable weather conditions will, in most systems, result in additional generation from coal- or gas-fired power plants – resulting in additional CO₂ emissions.

High levels of renewable generation can result in lower electricity market prices and lower market share for conventional power plants, thereby reducing their revenues. To balance these risks between the supply side and the demand side, appropriate market mechanisms need to be in place to allow for efficient hedging.