Asia Pacific regional overview

The Asia Pacific region saw a diverse range of electricity sector experiences in 2020, particularly in relation to the impact of the Covid-19 pandemic. The effects of containment measures on electricity demand were seen first in China, with the first three months of the year showing marked declines in demand. In April to May, as demand was already recovering in China, the largest decreases in electricity demand were seen in other countries such as India, Japan and Australia.

While the extent of the health crisis has varied greatly between countries, and differing degrees of containment measure have remained in effect at national and local levels, all countries saw demand recover following their strict confinement periods as many economic activities resumed. However, most also saw overall demand decline in 2020 relative to 2019, with some exceptions such as China and Viet Nam.

Estimated relative and absolute y-o-y change in electricity demand in selected Asia Pacific countries, 2020


Across the region coal is quite dominant in the generation mix, while renewables are playing an increasing role as countries advance their clean energy ambitions, with China, Japan and Korea all announcing ambitious net-zero carbon targets for 2050-60. In most countries coal-fired generation was most affected by demand reductions caused by Covid-19 containment measures. Gas-fired generation also saw an overall reduction relative to 2019, while renewables maintained or increased their share.

Estimated supply changes in the Asia Pacific region, 2019 and 2020



China is the world’s second-largest economy and accounted for 16% of global GDP and 24% of energy demand in 2019. China also accounts for 28% of the world’s electricity generation and is the only major economy to see an increase in electricity demand this year.

China was the first country affected by Covid-19, with the impact on electricity demand starting in January 2020 when strict confinement was first implemented. Economic activity experienced severe disruption during the lockdown between January and March, with the trough in February, which led to a significant drop in electricity demand. In the first quarter electricity demand dropped by around 8%, with the largest decline of 11% in February compared to the same period in 2019, weather adjusted. 

Year-on-year change in monthly electricity demand in China, with and without adjustment for weather differences, 2020


China was also the first country to begin recovery as normal activities gradually resumed from the second half of March and electricity demand began to pick up. Economic stimulus measures were also implemented by approving new investment in infrastructure, which drives electricity consumption. From April to October electricity demand was higher than the same period in 2019, with an increase of 6% for the month of October 2020 (weather corrected). The China Electricity Council is expecting the total demand in 2020 to be 2-3% greater than 2019.

The reduction in electricity demand particularly affected coal-fired generation, which experienced a decline of close to 10% during the confinement compared to 2019. This has also resulted in a decline in coal demand. By contrast, wind and solar PV generation increased by 20% year-on-year in the first quarter of 2020.

Electricity generation began to pick up after the confinement as electricity demand recovered. Coal is the main source of electricity in China, making up almost 64% of total generation, with an installed capacity of around 1 060 GW in 2020. China continues to add coal capacity at a rate of around 30 GW or 3% of current capacity per annum in recent years. However, in the context of the policy objective of reducing air pollution, these additions are increasingly selective and are dominated by plants close to coal mines or mining hubs. China is the world’s largest consumer of coal-fired electricity and in 2020, for the first time ever, will produce over half of the world’s total.

Coal also began to generate more than last year from April on, with the highest increase of 9% in May and 6% in August. But low-carbon sources are also increasing their share of the electricity supply. Nuclear generation is expected to increase by around 6% to reach a share of 5%, and renewables to reach a share of 28%, up around 1.5 percentage points compared to last year.

These increases in low-carbon generation result in a lower market share for fossil fuels. Although coal and gas-fired generation remain almost the same in absolute terms, their aggregated share in the mix is set to fall by almost two percentage points to around 66% in 2020.

2020 is also expected to see the first operation of the national-level emissions trading scheme in China. The first regional pilot was launched in 2013 under the 12th five-year plan, and eight regional pilots are now active. The national-level scheme was announced in the 13th five-year-plan, to be gradually implemented in three phases from 2017, with the aim to start the third operational phase by the end of 2020. The previous phases focused on constructing market infrastructure, collecting data, training and simulating allowance options and trading. In contrast, the third phase will begin operation of the scheme, starting with the power sector, including allowance trading for compliance purposes. The initial focus will be on supporting efficiency improvements at fossil fuel power plants. In the future the scope will gradually be extended to other energy-intensive sectors.

The 14th five-year-plan is currently being finalised, which will guide the development of the energy sector in China to 2025 and beyond. The post-Covid-19 stimulus measures to drive investment in electricity infrastructure include power generation assets, ultra-high-voltage transmission and EV charging stations. The recent announcement to the UN General Assembly of China’s intention to reach net-zero carbon emissions by 2060 will also play a key role in the 14th five-year plan.


The impact of Covid-19 on the Indian electricity sector and electricity demand has been significant. India began a nationwide lockdown on 25 March 2020, which was relaxed progressively between the end of May and end of June. Since then local restrictions have been in place in line with local government decisions.

Following the start of the lockdown, weather-corrected electricity demand relative to the same period in 2019 initially fell by 17%, followed by a further decline to reach a 28% reduction by the end of March. From the end of May electricity demand began to recover, reaching 2019 levels by early August, and showing year-on-year growth into September and October. Total electricity demand for 2020 is anticipated to be down 2% from last year, with a rebound expected in 2021. 

Weather-corrected year-on-year comparison of demand in India to 18 November 2020


Cross-border imports in financial year 2019/20 were 7 TWh from Bhutan. Total losses on the transmission and distribution networks in India, including non-technical losses, fell from their 2001 high of 33% to 21% in 2018, which is still significantly higher than other emerging economies such as Brazil at 16% or China at 7%, or the world average of 8.5%.

India’s power system is undergoing a transformation towards cleaner electricity, driven by a national-level renewables target of 175 GW by 2022 and a national renewables ambition of 450 GW by 2030. However, as of 2020 conventional generation still dominates India’s capacity mix, with coal and lignite making up 205 GW (55%) and gas representing 25 GW (7%) of 373 GW total capacity. There is an embedded capacity surplus of around 10% on the basis of the 2020 annual peak demand of 177 GW (as of September 2020) and considering non-firm capacity, losses and outages (60-90 GW). Renewables (including small hydro, biomass, waste, solar PV and wind) represent the second-largest source at over 88 GW (24%) followed by large hydro at over 45 GW (12%). There are numerous new coal-fired power plants planned in the short term, while a few states, such as Gujarat, have committed to no new coal power plants beyond 2021.

In 2020, around 70% of India’s electricity is set to be generated by coal-fired power plants, while renewables including hydro are also playing a significant role (23%). 2020 also sees a 4% fall in conventional generation relative to 2019, mainly driven by a decline in coal-fired generation. Gas-fired generation increases by 10%, fuelled by a sharp rise in spot LNG imports and prices below USD 3 per MBtu, while gas plant capacity factors remain low. As demand fell earlier in 2020, renewable energy generation continued because of its “must-run” status and played a larger role in the electricity mix. The daily share of national generation from renewables combined (excluding large hydro) went up to 12% on 31 March, one of the highest levels of recent years. Meanwhile conventional supply including coal declined, in line with the drop in overall industrial demand.

Between 2016 and 2019 solar PV and wind generation increased from 4% to 12% of annual electricity generation. At state level the picture is very diverse. Andhra Pradesh, Gujarat, Karnataka, Rajasthan, Tamil Nadu and Telangana have a higher share of solar and wind, reaching 25%, and are already facing significant system integration challenges. These include solar and wind curtailment in Karnataka and Tamil Nadu, restrictions on coal generation and congestion on medium- and high-voltage transmission lines during periods of high solar and wind generation across all states. On an hourly basis solar and wind have reached levels of 60-70% of generation in both Karnataka and Tamil Nadu.

End-user industrial electricity prices in India at USD 99/MWh are significantly higher than residential prices at USD 69/MWh on a nominal basis. This is due to significant government support to vulnerable household and agricultural users through cross-subsidisation from industry. High industrial prices drive large numbers of industrial users in India to seek the benefit of open-access contracts, with prices that are on average 20% to 30% lower than utility prices. Electricity affordability is still a significant issue in India in 2020, again highlighted by Covid-19. Residential prices based on purchasing power parity are very high in international comparison, despite being subsidised and significantly lower than industrial prices.

The Indian wholesale power market is the most significant in South Asia and the ASEAN region. India has had competitive power markets since 2008, although only a fairly small share of all electricity is traded through power exchanges. Over 95% of the electricity that was traded in 2019 was sold on the India Energy Exchange (IEX), and the remainder on Power Exchange India Limited (PXIL).

Covid-19 and the related fall in demand had a significant impact on the electricity wholesale trade. Firstly, wholesale prices in 2020 have been approximately 20-29% lower than the previous year at INR 2.5/kWh on average (in the range of INR 2-4/kWh) in the day-ahead market between March and September. Secondly, the traded volume has increased compared to the previous year; this increase stood at around 44% in September 2020 for all market segments. The increase in volume has been driven by multiple factors: utilities prefer short-term trade as opposed to business-as-usual three to nine month contracts in light of unforeseeable demand patterns; additionally, utilities offer their surplus volumes due to lower electricity demand for sale on the market; and finally, driven by lower prices, some utilities have replaced their contracted generation with cheaper market purchases.

In 2020 the power market has reached two historical milestones:

  • June 2020 saw the launch of the real-time power market in India, filling an important gap by providing real-time corrections (an hour ahead) for intermittent and variable generation such as solar and wind. The market has already seen significant trading volume and a large number of participants just a few months after market launch. The price volatility of the real-time market has been greater than that of the day-ahead market, but on average prices are typically lower, at INR 2.36/kWh on average, and prices show a trend towards convergence with the day-ahead market.
  • August 2020 marked the launch of the “Green Market” on the IEX, where green electricity is traded at a premium (compared to the regular day-ahead market) at INR 3.4/kWh (within the range of INR 3-3.8/kWh) for clients looking to fulfil their Renewables Purchase Obligations through market purchases.


Overall electricity consumption in Japan has been declining over the past decade despite electrification in the residential, commercial and services sectors. Since the accident at the Fukushima Daiichi nuclear power station following the Great Japan Earthquake of 2011 and the rolling outages following it, all sectors have accelerated their energy conservation activities. These included measures such as higher set temperatures for air conditioning, reduced lighting and use of LED bulbs, as well as increased focus on energy efficiency. A relatively larger decrease in 2019 can be attributed to a mild winter and summer, resulting in reduced heating and cooling demand respectively, compared with 2018.

Y-o-y change in annual demand in Japan, 2014 2019

2014 2015 2016 2017 2018 2019
 -1.6% -2.5%   0.0% 1.6%   -2.0% -5.5%

Annual electricity demand by sector in Japan, 1990-2018


The further effects of the Covid-19 pandemic on power demand in Japan have been limited. A state of emergency was declared by the government on 7 April 2020 and continued until 25 May. This state of emergency entailed a request from the government to refrain from activities that involve human contact, applying first to large cities and then expanded nationwide. There were no mandatory transport restrictions or closure of businesses.

A relatively sharp decrease in demand was seen during this period, with an almost 10% year-on-year decrease in the month of May, followed by gradual recovery in the following months. The industrial sector saw a larger decrease; however, this was partially offset by an increase in residential demand due to increased working from home and reduced travel and leisure activities outside the home. Summer cooling demand increased the demand for electricity in August, September and October.

Later in the year, ongoing Covid-19 preventative measures may have actually increased electricity consumption, due to recommendations to use air ventilation and air conditioning indoors. Teleworking and use of water for handwashing and home cooking may also have affected power demand.

The overall generation mix in Japan is dominated by gas and coal with an increasing role for renewables. A sharp reduction in nuclear generation is expected in 2020, down 23% year-on-year. This is driven by the shutdown of some reactors that require work to meet new anti-terrorism safety measures coming into effect this year, such as Kyushu Electric’s Sendai 1 and 2 reactors, which ceased operations on 16 March and 20 May respectively. Sendai 1 is expected to resume operations on 26 November this year, while Sendai 2 is scheduled to return to operations one month later.

Due to reduced overall demand, and despite a small decline in total coal-fired generation of around 3%, coal is set to retain a constant share of the generation mix in 2020 (around 32%). The share of gas is expected to fall to around 32% (down almost two percentage points), with a relative decline of around 9%. Only renewables generation has seen an absolute increase, over 9% in 2020 relative to last year, bringing it to a share of around 21% of the mix. This is due largely to ongoing deployment and the government targeting 22-24% of energy from renewables by 2030. In addition, in October of 2020 in his speech at the Diet, Japan’s Prime Minister Suga announced Japan’s ambition to achieve net-zero emissions by 2050. 


While electricity demand in Korea did not go through the same drastic decline as others thanks to its relatively successful management of the pandemic, the industry-heavy economy is set to contract by 1.9% in 2020 and with it electricity demand is on track to decline by an even greater amount, over 3%.

Coal-fired generation in 2020 is expected to see the largest year-on-year decline among fuels at 10%, with its share of the generation mix falling from 40% last year to 38% this year. This is both due to the economic fallout of the global pandemic and the government’s mandated shutdown of 28 coal-fired power plants during March. The shutdown order is part of the government’s continued push for green policies since taking office. This September, President Moon Jae-in announced a plan to shut down 30 additional coal power plants by 2034, in line with the country’s ambition to cut greenhouse gas emissions and promote eco-friendly energy sources.

Nuclear power generation has held up relatively well, with a more than 4% year-on-year increase expected and its share rising from 25% to 27% in 2020. Despite a strong domestic backlash against new additions to the nuclear power fleet, long-planned nuclear generation capacity (5.6 GW) is already under construction and likely to be completed in the next couple of years. Natural gas also played a large role in power generation, replacing much coal-fired power in the winter period and on track to increase its share slightly to 27% this year (up one percentage point).

Renewables also increase their share, to around 6% from 5% last year. According to the government’s 9th Basic Plan for Electricity Supply and Demand, released in May, a large amount of both natural gas and renewable generation capacity is set to be added up to 2034, with a target to increase renewables to 40% of the generation mix by 2034.

In late September the government finalised the rules for Phase 3 of the Korean Emissions Trading Scheme, which runs from 2021 to 2025. The scheme began in January 2015 with three phases of trading (Phase 1: 2015-17; Phase 2: 2018-20; and Phase 3: 2021-25), with the aim of reducing greenhouse gas emissions. According to the latest rules, the total allowance for the third phase rises to 609.7 MtCO2-eq/yr from 509.2 MtCO2-eq/yr in Phase 2, partly due to the addition of the transport and construction sectors. For the power sector, allowances have been increased from 37% to 39%, equivalent to 235 MtCO2-eq/yr in 2021-23 and 217 MtCO2-eq/yr in 2024-25. In Phase 3, 90% will be allocated for free, down from 97% in Phase 2.

Changes in power sector allocations – in addition to low gas prices in the spot market this year – are likely to further narrow the gap in fuel costs between coal and gas in the medium term, in favour of gas. This new scheme is in line with the government's green agenda. In October President Moon Jae-in announced that the country will commit to achieving carbon neutrality by 2050, putting an emphasis on reducing reliance on coal-fired power generation. The government is likely to announce new electricity policies in the 9th long-term power plan (to be released late this year), providing greater incentives for coal-to-gas switching in the country's power mix.


Electricity demand has been relatively flat in Australia for the past decade despite economic and population growth, with 2018 and 2019 seeing small year-on-year increases of 1.1% and 1.6% respectively.

With the first case of Covid-19 in Australia identified in late January and initial cases of community transmission in early March, nationwide lockdown measures were introduced from mid-March with Australian borders closed to all non-residents from 20 March. Nationwide restrictions within Australia were eased from early May on, although a second outbreak in Victoria resulted in new containment measures in that state from early July, which were further tightened in August, and only began to be gradually eased from mid-September.

Despite the significant economic impact of Covid-19 restrictions, the effect on electricity demand in Australia was relatively minor, with a substantial decline in commercial demand largely compensated by an increase in residential demand. For the National Electricity Market, which makes up around 80% of all Australian electricity demand, first quarter demand was down by around 4% on the same quarter in 2019. However, the Australian Energy Market Operator assessed this to be largely due to reduced daytime cooling requirements, with no substantial impact from lockdown measures introduced late in the quarter. Second quarter demand, by contrast, was the most affected, with a 2% fall in demand relative to the same quarter in 2019. The market operator considers this as arising from Covid-19 containment measures, with other factors such as weather causing a very slight mitigation of the decline. In the third quarter Covid-19 effects on demand were mainly confined to Victoria due to its second lockdown. All-Australia electricity demand for 2020 is expected to see a decline of between 3 and 4% year-on-year.

Generation capacity in Australia is still dominated by fossil fuels and particularly coal, although with increasing renewables in the mix – driven by federal renewables targets as well as state-level policies. As Australia has now met the federal-level Large-scale Renewable Energy Target, utility-scale deployment is expected to decline while distributed solar continues to be driven by the small-scale target and state-level feed-in tariff schemes. 

Projected annual generation by technology in Australia, 2019 and 2020


Following this continued deployment, the share of total renewables including hydropower in 2020 is set to rise to 24%, up from 19% last year. Coal continues its ongoing decline, falling by around two percentage points to around 56% of total generation. Due to the very low fuel cost of brown coal-fired power stations in Australia, the increasing renewables share has mainly affected black coal-fired generation, although the closure of the Hazelwood power station in 2017 resulted in a drop in brown coal’s share. Brown coal-fired generation for 2020 is set to increase slightly relative to last year, likely due to recovery from extended outages at Loy Yang station during 2019.

The issue of electricity system reliability and security has received considerable attention in Australia in recent years, triggered by a series of events including the Basslink interconnector failure in 2015, a state-wide blackout in South Australia on 28 September 2016, and severe heatwaves provoking load-shedding events in February 2017 in several states and again in Victoria in 2019.

In 2017 the Council of Australian Governments requested an extensive review into how to ensure reliability and security of the power system during the energy system transformation. The proposals were accepted by the council in July 2017, contributing to a process of ongoing reform including a strengthened risk management framework and fine-tuning of the energy market design.

In the context of an increasing share of renewables, the market operator is currently undertaking a multi-year plan to maintain system security in a future market with a high share of renewable resources, starting with a Renewables Integration Study released earlier this year. Market reforms are also being undertaken to increase the contribution of flexible resources such as demand response and batteries. For example, in July 2020 the Australian Energy Market Commission announced that five‑minute settlement windows for spot prices in the National Electricity Market are to be implemented from 21 October 2021, which is expected to increase opportunities for battery storage.