Historical development of global electricity demand

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%.

Final electricity demand by sector in emerging and developing economies, 1990-2018


Final electricity demand by sector in advanced economies, 1990-2018


Electricity demand expected to rebound in 2021

Electricity demand and real GDP growth in emerging and developing economies, 1990-2021


Electricity demand and real GDP growth in advanced economies, 1990-2021


Global electricity demand expected to recover in 2021

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.

Estimated electricity demand growth by region, 2020 and 2021


Development of input prices: Steady coal and volatile gas

Following the steep fall in spot gas prices during the first half of 2020, the key benchmarks in the United States and Europe started to recover in the third quarter and climbed 0.5% and 20% above last year’s respective price levels in October and November. At the beginning of December forward curves suggested that in 2021 Henry Hub will average over 35% above 2020 price levels, at USD 2.8/MBtu. In contrast, coal prices are expected to remain steady, hovering slightly below this year’s price levels.

In Europe TTF is expected to trade 60% above this year’s price levels in 2021, while Rotterdam coal is set to gain 20% year-on-year (y-o-y). Carbon prices are expected to average almost 20% above 2020 levels. In contrast with spot gas prices, oil-indexed gas prices – especially relevant for LNG importers in the Asia Pacific region – are expected to decline by close to 20% y-o-y, while Newcastle coal is set to gain 15% compared to 2020.

Fuel and emission costs in the European Union, Mar 2019 to Nov 2021


Fuel costs in the United States, Mar 2019 to Nov 2021


Fuel costs in Asia, Mar 2019 to Nov 2021


Recovering spot gas prices limit the competitiveness of gas-fired generation in 2021

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%.

Generation costs of coal- and gas-fired power plants in the European Union, Jan 2019 to Sep 2021


Generation costs of coal- and gas-fired power plants in the United States, Jan 2019 to Sep 2021


Generation costs of coal- and gas-fired power plants in Asia, Jan 2019 to Sep 2021


Renewables lead capacity additions in 2021

After net additions of renewable capacity reached a new record of almost 200 GW in 2020, total capacity is expected to grow by around 218 GW in 2021, almost 10% more than 2020. The strong growth is driven by projects delayed this year going ahead in 2021 (several governments have granted extensions to implementation deadlines) and newly financed capacity. Additionally, distributed solar PV is expected to slowly pick up again due to economic recovery and policy support. Renewable capacity additions are led by solar PV and wind, responsible for around 54% and 31% of net additions respectively.

The majority of solar PV net capacity additions are expected in China, making up around one-third (38 GW) of the global total – more than double the expected additions in the United States, which accounts for another 15% of the total. Further major absolute additions are expected in Europe (21 GW), India (11 GW) and Japan (7 GW).

Although being surpassed by solar PV in installed capacity terms, wind turbines remain the fastest-growing form of renewable energy in terms of generation, with around 68 GW of net additional capacity in 2021 (of which 89% is onshore). The majority of additions take place in China (39%), Europe (21%) and the United States (16%). In 2021 offshore wind capacity additions are expected to reach a record level of 7 GW, led by China with more than half of the total. The first large-scale offshore wind project is expected to become operational in Chinese Taipei.

Around 13 GW of nuclear power units are scheduled to start operating in 2021. Out of the 13 units, three are located in China and two in India. After the United Arab Emirates commissioned its first nuclear unit in 2020, the second unit of the Barakah power plant is scheduled for 2021 – with two more units planned for the two subsequent years. After a construction start in 2005, the Olkiluoto 3 unit in Finland is expected to be connected to the grid at the end of 2021, with commercial operation starting early in 2022. In the United States 5.5 GW of nuclear capacity is expected to retire in 2021, while in Germany three out of the remaining six units are due to be decommissioned at the end of next year – the remaining three will follow at the end of 2022.

In 2021 global coal generation capacity is expected to reach as much as 2 140 GW, predominantly driven by 30 GW of new capacity expected in the People’s Republic of China (hereafter, “China”). Coal capacity outside China is not anticipated to change much, with new capacity in Asia offset by retirements in Europe and North America. In 2021 India, Japan, Indonesia, Viet Nam and Bangladesh are set to commission a number of coal-fired plants that are currently in the final stages of construction, although it is difficult to make an accurate estimate as projects have been delayed by the Covid-19-induced crisis. Unit 1 of the Hassyan plant in the United Arab Emirates will become the first coal power plant in the Middle East outside Israel.

Coal power plant retirements continue in Europe and North America in 2021. In the United States, after 10 GW being decommissioned in 2020, another 3 GW are planned for retirement in 2021, although the final figure could be higher if some units scheduled for 2022 close earlier. In Europe decommissioning will continue in Spain, the United Kingdom, Germany and in particular Italy, where the units Brindisi 2 (600 MW), Fusina (1 600 MW) and La Spezia (600 MW) are expected to close by early 2021, while others could follow soon. After the closure of the Pego and Sines coal-fired power plants, Portugal will follow Belgium, Austria and Sweden to end coal power generation in the country. Overall, over 12 GW are expected to be retired in Europe in 2021.

Natural gas power plant capacity is expected to continue to rise by just over 30 GW in 2021. In the United States just over 7 GW of new capacity is scheduled, with Texas and Ohio accounting for over half of the incremental capacity. In terms of technology, combined cycles account for over 50% and combustion turbines for over 40%. Almost 0.4 GW of gas-fired capacity is set to retire.

In the Middle East 7 GW of capacity is expected to be added, mainly driven by plant developments in Iran, Saudi Arabia and the United Arab Emirates. In Asia gas-fired capacity continues to expand by over 10 GW, with China and Malaysia accounting for almost two-thirds of the incremental capacity.

In Europe 0.9 GW of gas-fired generation capacity is expected to be commissioned in 2021, including the Żerań co-generation plant (490 MW) in Poland and the Landivisiau CCGT plant (446 MW) in Brittany, France.

Electricity supply and related emissions in 2021

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.

Projected global change in power supply, 2020 and 2021


Projected global change in CO2 emissions, 2020 and 2021


Annual renewable generation can vary significantly

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.

Variability of annual generation of wind, solar PV and hydropower in selected countries


The variability of renewables affects residual demand

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.

Residual demand variability for different shares of wind, solar PV and hydro generation in selected countries, 2021


Power systems need to adapt to the seasonal variability of renewables

Wind and solar PV show a greater variability on a monthly basis than on a yearly basis, driven by changing weather conditions throughout the year. Hydropower plants with reservoirs can be dispatched flexibly and are frequently used as seasonal storage; thus they are less dependent on short-term weather influences.

The monthly generation patterns of wind and solar PV are similar for the analysed countries of France, Germany, Italy, Spain and the United Kingdom. Solar PV mostly generates reliably during the summer months. In the case of Germany, between 48% and 54% of annual generation takes place in the four months from May to August, and 69% to 75% in the sunny half of the year (April to September).

Wind generation shows a U-shaped pattern indicating higher productivity in the cold season – with similar variability in monthly generation for on- and offshore wind. Compared to solar PV, the variability of the monthly distribution is much larger. In Germany onshore wind production is on average at its highest in January (12% of the annual total). This share can go down to 5% given unfavourable weather conditions – but also up to 18% given strong winds. In the six months with the highest average production, 54-66% (onshore) and 55-69% (offshore) of the annual total are produced.

The complementarity between wind and solar can be used to reduce the variability of their combined electricity production – but some monthly variability of renewables generation is inevitable. While demand-side response is a promising option for short-term balancing of generation and demand, flexibility options like seasonal storage and the use of hydrogen are needed to integrate large shares of renewables into the energy system.

Monthly generation of offshore wind in Germany


Monthly generation of solar PV in Germany


Monthly generation of offshore wind in Germany

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