IEA (2020), Electricity Market Report - December 2020, IEA, Paris https://www.iea.org/reports/electricity-market-report-december-2020, License: CC BY 4.0
Global renewable electricity capacity additions were 11% lower in the first half of 2020 than in the same period in 2019. Solar PV expansion was down by 17% and wind by nearly 8%. Hydropower capacity, in contrast, increased in the first half of 2020, driven by large-scale projects in China. Despite initial delays, available data indicate that in most countries new installation activity ramped up after restrictions were eased, compensating for previous lags.
In the first quarter of 2020 capacity additions slowed for all technologies except hydro, by 25% for both solar PV and wind compared with 2019. China was the main factor for wind and solar PV, as Covid-19 measures led to labour shortages and consequently reduced construction activity. New wind installations declined by 50% and solar PV by 25% in the first three months of the year. With lockdown measures being eased, capacity additions in China picked up again, headed by utility-scale PV, wind and large hydropower plants.
In the United States policy deadlines dictated wind and solar PV expansion, resulting in almost twice the renewable capacity additions in the first half of 2020 than in the same period last year. This was mainly due to wind developers rushing to commission projects to meet federal tax incentive deadlines. During the same period, growth in renewable capacity in India slowed significantly before the nationwide lockdown was imposed at the end of March. This resulted largely from the persistent challenges of utilities’ poor financial health and project delays.
In Europe new renewable capacity additions were lower in the first half of 2020 than in 2019, increasing in the second quarter with the easing of lockdowns and movement restrictions. In Germany the installation of ground-mounted PV installations slowed, but then recovered rapidly in May and June, outpacing 2019 installations during the same period. In Italy capacity additions rebounded to pre-pandemic levels in May, after a 90% decline from February to April. In the Netherlands the pace of combined wind and solar installations slowed during March and April, but recovered again in June.
The ASEAN region installed nearly 60% less capacity from January to June this year than during the same period in 2019 – mostly due to the unrepeated strong growth last year in Viet Nam, when developers rushed to complete PV projects before policy deadlines. Lockdown measures slowed construction activities in Thailand and Indonesia.
Despite delays in the first half of the year, renewables are on track to achieve a new record of net capacity additions (198 GW, 4% higher than in 2019).
In 2020 global solar PV net capacity additions are expected to reach 107 GW, 1% lower compared to 2019. Despite the slowdown, global solar PV capacity will exceed wind capacity for the first time, claiming second place among renewables behind hydropower. Deployment remains sluggish for distributed PV applications in large markets such as China and the United States, although activity in most European markets, Australia and Brazil has not seen a significant slowdown. Still, the share of distributed applications in total PV deployment is expected to decline to 37%, the lowest since 2017.
Annual net wind capacity additions are expected to reach around 65 GW (of which about 5 GW are offshore wind), 8% more than in 2019. Covid-19 measures led to construction activity slowing from February to April due to supply chain disruption and logistical challenges in many countries. The offshore wind sector has been only mildly affected.
After six years of consecutive declines, net global hydropower additions are expected to increase in 2020, topping 18 GW, driven by an uptick in large project activity in China and large projects in Laos, India, Nepal, Viet Nam and Indonesia.
Nuclear power sees significant growth in new capacity in 2020, as new units in China, India, Russia, Belarus, Korea, Slovakia (potentially delayed to early next year) and the United Arab Emirates add over 8 GW of new capacity, most of it late in the year. This more than offsets the closure of units in France, Sweden and the United States, which will remove about 5 GW from service.
Coal-fired generation capacity in 2020 remains flat at 2 125 GW, but could decline if some of the expected new plants are delayed or retirements are brought forward. If this occurs, 2020 would be the first year this century in which coal capacity declines.
As with most coal-related issues, the story of coal capacity varies considerably between advanced economies and those which are emerging and developing. While no new plants have been planned in Europe or the United States for some time (Datteln 4 was commissioned in Germany in 2020 following delays in construction), decommissioning of coal plants is accelerating. Austria and Sweden, having closed their last coal plants, joined Belgium as EU countries where coal power generation is in the past. Over 20 GW will be decommissioned in the European Union and the United Kingdom in 2020, headed by Germany, Spain (which had closed about half of its total coal capacity by the end of June) and the United Kingdom. France confirmed its closure date of 2022, and Italy’s is 2025. Portugal brought forward its coal phase-out date by two years to 2023. Most EU countries are planning to close all coal plants by 2030, except Poland, the Czech Republic, Germany and a few others. Germany has passed an act to phase out coal-fired power plants, which will see them all closed by 2038, and possibly even by 2035.
In the United States, where 49 GW were retired between 2011 and 2019, an additional 10 GW have been retired in 2020. By contrast, in Japan 2 GW have been commissioned, with 7.4 GW under construction.
In the emerging and developing world, where plants are three decades younger on average, decommissioning is unusual except as replacement for capacity in China and, to a lesser extent, India. New construction, on the other hand, has slowed not only as a result of Covid-19, but also as a consequence of the headwinds that coal-fired generation has been facing for several years. China sees the most additions, with the commissioning of around 30 GW, in line with 2019. In India only a small number of new plants were commissioned, resulting in 2 GW of additional coal-fired generation capacity (with around 35 GW under construction). In the ASEAN region close to 5 GW of capacity additions are expected, as some plants have been delayed by Covid-19.
But even if capacity remains stable in 2020, it was a year in which many countries around the world reconsidered the role of coal. Korea, Japan, the Philippines, Viet Nam, Egypt and Bangladesh are just a few of the countries that have changed their vision of the role of coal power generation in the future. Lower electricity demand driven by the Covid-19 crisis, lower costs for renewables and low gas prices – as well as the reduction in air pollution that came with lower coal-based electricity generation in 2020 – have changed the perception in many countries that coal is the only way to have affordable, dispatchable and secure electricity. Difficulties in financing and growing international pressure against coal are also playing a role. As a result, the combination of renewables plus gas is gaining ground in many jurisdictions.
In contrast to coal, global natural gas power plant capacity continued to expand in 2020, with over 40 GW of new capacity expected to be commissioned, primarily driven by the Middle East, the United States and China.
With over 500 GW of capacity, the United States has by far the largest gas-fired power plant fleet in the world (about 28% of the global total). Capacity continued to expand in 2020 – uninterrupted for the past 20 years. New capacity additions amounted to 7 GW by the end of September, with California, New York and Louisiana accounting for almost 60% of the newly commissioned capacity. An additional 0.65 GW is under construction and is expected to be commissioned by the end of the year. Plant retirements are set to exceed 2 GW, with over 40% of them in California.
The Middle East has just over 220 GW of gas-fired capacity, set to expand as electricity demand is rising rapidly and the region strives to diminish its reliance on oil-fired power generation. In 2020 gas-fired power capacity has continued to expand, led by Iran, Iraq and Saudi Arabia. This includes the giant 3 GW Rumaila power plant under construction near Basra in Iraq. The first two phases of its construction were completed by June 2020, bringing 1.5 GW of generation capacity online, while the remaining two phases involving an additional 1.5 GW of capacity are scheduled for commissioning by 2022.
Gas-fired capacity additions in Asia are led by China, accounting for almost half of the region’s incremental capacity in 2020. China’s gas-fired power capacity stood at 90 GW at the end of 2019 and around 5 GW were added in the first three quarters of the year. In total, close to 6 GW of capacity is expected to come online in 2020.
In Europe just over 1 GW of gas-fired capacity was added in 2020, the largest being the Stalowa Wola (450 MW) combined-cycle gas turbine plant in Poland. The completion of the 430 MW Iernut CCGT plant in Romania is facing delays due to the Covid-19 outbreak and is now expected to be commissioned by the end of 2020. Moreover, Units 4 and 5 of the Irsching gas-fired power plant in Germany (with a total capacity of 1.4 GW) returned to commercial service in October 2020 amidst improving market conditions, after being mothballed in 2016.
The significant global fall in electricity demand in 2020 affected generation technologies to different extents. While the increase in renewable generation of about 6.6% was the largest ever in absolute terms, fossil fuel and nuclear generation felt the impact of declining electricity consumption.
Wind and solar PV electricity generation continued to grow by more than 10% and 20% respectively, now being responsible for more than 9% of global electricity supply (around 8% in 2019). With 16% of total global production, hydropower plants still constitute by far the largest source of renewable electricity generation. In total, renewables grew by around 7% and provided 28% of global electricity, up around two percentage points compared to 2019.
The rise in renewable generation and the fall in demand resulted in a squeeze on other generation technologies, namely coal, gas and nuclear power.
Coal-fired generation was affected the most. Global coal power generation is expected to drop by more than 5% in 2020, the largest decrease ever. This comes on the heels of a 3% fall in 2019 and brings coal-fired generation back to levels last seen in 2012. Due to a mild winter, gas prices in the United States and the European Union were already low when power demand plummeted as a result of measures to contain the Covid-19 pandemic. The strongest impacts were felt in the European Union, where we expect a decline in coal-fired power generation of more than 20%, and in the United States (a 19% decline). Coal-fired generation is on track to fall by 3% in Japan and by 10% in Korea, where term contracts ensure more stability in the mix. In India coal power generation will gain some ground in the last quarter after a double-digit decline in the first half of the year, to end with a 5% drop. In contrast, coal-fired power generation in China and in Southeast Asia is expected to stay about the same as in 2019.
Gas-fired generation, although not immune from the squeeze, is on track to fall by about 2% in 2020, as in many markets it has been able to outcompete coal to retain its market share. Natural gas prices, already low before the pandemic, fell much more quickly than those of coal. Even in Asia, where LNG prices are commonly linked to the price of oil, the fall in oil prices has gradually improved gas’s competitive position. In addition, in those markets where carbon pricing is relevant, particularly the European Union, the cost of carbon has given gas a further edge.
Nuclear power was affected by the squeeze, its output declining by around 4% compared to 2019. Much of the demand squeeze took place in the first half of the year, but less capacity was available all year as plant closures in France, Sweden, Germany, Switzerland and the United States occurred in late 2019 and early 2020. Japan’s output in 2020 is also down significantly mainly due to the removal from service of two units early in the year to install backup control centres. China was the main exception to the trend as nuclear output increased by about 6%, reflecting new capacity coming into service.
Oil, which accounts for only 3% of global electricity generation, was also affected by the shrinking market space for thermal generation and saw declines in many markets, partly offset by some increases in the Middle East.
Falling electricity consumption combined with the growth in renewable output weighed on thermal power generation across key energy markets in 2020. This has been accompanied by increasingly fierce competition between coal and gas for a rapidly shrinking market space.
The particularly mild 2019/20 winter in the northern hemisphere – the second warmest since records began – and the imposition of Covid-19-related lockdowns in the second quarter of 2020 depressed natural gas prices to multi-decade lows across key gas-consuming regions. Importantly, gas prices fell more steeply than coal benchmarks, which increased the cost-competitiveness of gas-fired power generation vis-à-vis coal-fired plants.
In the United States gas prices at Henry Hub fell by 29% y-o-y and averaged at USD 1.9/MBtu during the first three quarters – their lowest price level for that period since 1995. During the same period, the main US coal benchmarks declined in a range of 5-25% y-o-y. As gas prices fell more steeply, coal-fired power generation plummeted by about 23% as it not only bore the brunt of falling electricity consumption (down 3.9% y-o-y), but has been increasingly losing market space to gas-fired power plants, a trend ongoing since 2012. Gas-fired plants increased their output by 4.4% y-o-y and, as a result, saw their share of power generation for US electricity supply rise to 40% during the first three quarters.
In Europe spot prices on TTF fell by 45% y-o-y in the first three quarters of 2020, to an average of USD 2.5/MBtu – their lowest level since the Dutch gas hub was established in 2003. In contrast, Rotterdam coal, the benchmark for European coal, saw its price fall by 24% and carbon prices traded just 4% below last year’s average. As a consequence of these price dynamics, similar to the United States, coal- and lignite-fired power plants in the European Union and the United Kingdom were most affected by the 6% y-o-y decline in power consumption. Their combined output plummeted by close to 25% in the first three quarters of 2020. In contrast, gas-fired power generation fell more moderately, by 6% y-o-y. After the heavy losses during the first half of the year (down 10%), gas-fired power generation returned to positive growth during the third quarter – largely at the expense of coal- and lignite-fired power plants. However, the sharp recovery in gas prices since the beginning of June has started to erode the competitive position of gas-fired power plants since September.
The largest contributor to additional gas burn in the European power sector was Turkey, where gas-fired power generation rose by an impressive 11% y-o-y, despite overall electricity consumption declining by 1.3%. This has been primarily driven by lower output from lignite-fired power plants (down 20%) as some units had been halted for not complying with environmental regulations. Altogether, gas-fired power generation accounted for 58% of thermal generation in Europe during the first three quarters.
In India total electricity consumption fell by 5% in the first three quarters of the year. Amid this overall decline, gas-fired generation increased by 10% y-o-y, while coal- and lignite-fired generation dropped by 9% – in absolute terms significantly more than gas’s gain. Growing gas-fired generation was fuelled by a sharp rise in spot LNG imports during the first nine months. At well below USD 3/MBtu, imported spot LNG proved highly competitive vis-à-vis coal in power generation, especially in the western part of India near the existing import terminals.
China’s thermal generation fell by 0.3% y-o-y in the first three quarters of 2020, while overall electricity consumption increased by 1.3% y-o-y during the same period. Against the trend in thermal generation, gas-fired electricity supply increased by around 1%. However, this expansion has mainly been driven by new gas-fired capacity additions and guaranteed operating hours under China’s “fair dispatch” model, as the transition to a competitive wholesale electricity market with economic dispatch is at a relatively early stage. A purely market-driven coal-to-gas switch would require an average carbon price of around USD 45 per tCO2-eq, although the required carbon price varies widely by region due to the differences in relative fuel costs across China.
This year’s OPEC+ agreement imposed an initial 9.7 mb/d oil production cut between May and July before tapering down to 7.7 mb/d in the remainder of 2020. It put significant pressure on associated gas production in a number of OPEC producers in the Middle East. The squeeze on associated gas availability coincided with peak electricity demand in the summer, which was further accentuated this year as record temperatures and Covid-19-related travel restrictions lifted air-conditioning demand across the region. This combination of lower gas availability and increased electricity demand led to a resurgence of oil use – including direct crude burning – in power generation in the majority of Middle Eastern OPEC producers.
Kuwait, which reports the most detailed electricity data, illustrates this dynamic well. Total electricity output rose by 1% y-o-y in the third quarter of the year (following a 3% y-o-y decline in the first half of 2020) as travel restrictions prompted residents to stay at home during the hot summer season. This, in turn, boosted air-conditioning needs and pushed peak power demand to an all-time high in July. Gas burn in the electricity and water desalination sector fell by 7% as OPEC+ production cuts squeezed associated gas output, while the power sector use of crude oil and oil products increased by 11% in the first nine months.
Saudi Arabia, the biggest electricity producer in the Middle East, also experienced steep declines in associated gas production following the implementation of the OPEC+ oil production cuts. These reportedly offset incremental non-associated output from the recently completed Fadhili gas processing plant. Limited gas availability left oil burning to meet increased electricity demand, which was further boosted by travel restrictions during the peak summer months. Direct crude burning (which is the least desirable fuel source and has been subject to concerted government efforts to phase it out from power generation) was up by 7% y-o-y in the first nine months of the year, while the use of heavy fuel oil increased by 2% over the same period.
The United Arab Emirates, which uses only minimal amounts of oil in its predominantly gas-fuelled generation fleet, responded to record-high peak summer demand by breaching its oil production quota in August (a rare occurrence in one of OPEC’s most compliant members) in an effort to boost associated gas production to meet rising power needs.
Iraq reported a sharp 60% y-o-y rise in direct crude burning amid an estimated 4% increase in electricity generation during the January to September period.
Iran, which has been exempt from the OPEC+ production cuts, reported that electricity consumption increased by 5% y-o-y in the first nine months of the year. Gas burn in the power sector rose by 6%, while the combined use of diesel and heavy fuel oil shot up by nearly 30% to compensate for lower hydro availability over the same period.
Reduced electricity demand in most markets and increasing solar and wind power, or variable renewable energy (VRE) supply, has meant that the share of variable generation has increased rather dramatically in 2020, more than any single year in history. Many regions broke new records in hourly VRE infeed levels during lockdown including Italy, Germany, Belgium, Hungary and eastern parts of the United States.
From an operational perspective, critical system conditions are often associated with periods of very high demand, low generation availability (VRE, hydro or thermal), or both. Conversely, periods of high VRE generation and low demand can also expose systems to stress as a result of the high share of variable generation and reduced contribution of conventional generators.
While most systems worldwide did not experience reliability issues, the Covid-19 lockdowns were a stress test that did expose systems to new operational and planning challenges.
Increased VRE penetration caused greater variability in the net demand profile – demand minus variable renewable generation – which affects the flexibility requirements needed to meet minimum net demand and the system ramp. In some instances, depending on the market design, this led to increases in balancing payments to generators, reducing the benefit of lower market prices. In the United Kingdom, for example, balancing costs increased by 96% compared to the previous year. In France, coal power plants were restarted to address the flexibility issues after lockdown. The reduced demand during lockdowns in countries with high VRE resulted in a lower minimum demand during the day. For example, in Italy the average minimum weekday net load during lockdown fell by close to 10 GW relative to the same period in 2019.
In most systems, demand fluctuations during the day during lockdown were dampened because of lower demand rise in the morning. However, for some systems the decrease in midday demand can also lead to a greater ramp from a very low minimum during the day into the evening peak, which can be more pronounced in systems with a considerable share of solar PV. Some systems with higher solar, such as Germany and California, experienced steeper hourly ramps than during the equivalent period in 2019. However, these issues during lockdown periods have been manageable.
Lower demand during lockdown also played a role in curtailment in some regions. There can be multiple drivers for renewables curtailment, including inflexible power plants and grid congestion, and it can be aggravated by reduced demand. For example, in April 2020 the California system operator (CAISO) curtailed a record amount of renewables at over 318 GWh, 67% higher than in 2019 and reaching 7% of variable renewable generation in that month. The monthly VRE share reached a record high of 29% in April 2020, driven by weekly load falling by around 8% compared to last year at midday when solar output peaks. In addition, California added 1 GW of wind and solar PV from May 2019 to March 2020, contributing to the increase in VRE output.
During Covid-19 containment measures, some systems also saw new record lows in minimum net load and reduced synchronous generation, but no system reportedly had issues with low inertia or frequency management as a result. However, systems like that of Great Britain, where coal-fired generation has been declining for several years, had to advance new procurement schemes for flexibility services to cope with such situations. Procurement of flexibility services can include a range of market products that expand on ancillary service products, incentivising more flexible operation (e.g. fast ramping products) or compensating for declining system inertia (e.g. fast frequency response).
On 3 April 2020, during the Covid-19 crisis, India’s population responded to Prime Minister Modi’s appeal to “Challenge the darkness of Covid-19” and switched off their lights for nine minutes at 9 pm. The national system operator POSOCO successfully managed the demand reduction event together with the regional and state-level system operators. This event highlighted the flexibility of India’s electricity system, which successfully accommodated a total reduction in all-India demand of 26% within half an hour and the challenging ramp down and up resulting from this. Despite a demand reduction of 31 GW versus an anticipated 12‑14 GW, the co‑ordinated response between state and national dispatch centres enabled the event to be managed smoothly, with hydropower in particular playing a key role in providing the needed flexibility.
In most countries where partial or total lockdowns were implemented to limit the expansion of the pandemic, electricity demand decreased quickly and significantly – by between 15% and 30% after a few weeks of population confinement. This has significantly affected the electricity mix in those countries.
In China and India, where coal dominates the electricity mix, its share has decreased to the benefit of renewables because of the declining demand. In India the share of coal has consistently stayed under 70% between initial lockdown and September. Furthermore, the share of renewables in the mix jumped from 18% to 23% in the week after the first lockdown measures were enacted, and has stayed above 20% since then. Its fluctuations reflect renewables’ seasonal availability: in June and August their share rose above 30%, driven by strong winds and hydro generation. In September and October electricity demand was back on its path of growth seen before Covid-19 and the generation mix was comparable to 2019, reflecting seasonal trends.
In China under confinement, as electricity demand decreased a large reduction in coal-fired power generation occurred. Reductions were pronounced in February and March, as significant lockdowns spanned both months, and the share of renewables grew above 25%. After lockdown measures started being eased in late March, the coal share recovered slightly while renewables maintained a high share in the mix. In June and July renewables resumed the expansion of their share of the mix, rising above 30%, driven by growing hydroelectricity generation from additional capacity and heavy rains. Since August the trends of coal and renewables generation have adapted to the availability of hydro.
In the United States natural gas has remained the leading source of electricity in 2020, keeping almost consistently above 40% of the mix and being less affected by variations in demand than coal. From March onwards as the first confinement measures were put in place and demand decreased, the coal share dropped to 15% of the mix, outpaced by renewables, which rose above 20%. From June onwards as the stringency of the response to Covid-19 softened and demand increased, natural gas consolidated its leading position, oscillating around 45% of the mix. Coal rallied in response to growing demand. Coal and nuclear outpaced renewables generation, which decreased in the wake of the seasonal decline in wind and hydro. In September a significant temperature drop led to a decrease in cooling demand, and total generation fell to lower levels than in 2019, affecting coal power production. In October, total generation levels were on par with 2019, and the electricity mix trends (increase of wind, decrease of natural gas) seasonal.
In the European Union renewables together form the leading source of electricity. With lockdown, the fall in electricity demand and higher renewable production caused by favourable weather conditions drove non-renewable generation down. From February to the first week of July weekly renewable production was consistently higher than fossil fuel generation and the share of renewables in the mix stayed above 40%. However, it shifted markedly in July as a result of lower wind production. The drop in electricity demand and historically low nuclear production levels from January to August 2020 led to nuclear’s share of the generation mix remaining largely static. Several units extended outages due to the delays caused by lockdowns, and efforts to avoid maintenance and allow continuous supply of power during the winter. During the same period, coal power output was also lower to accommodate both lower demand levels and phasing-out targets in most of the European Union. In September and October nuclear power output rose gently towards seasonal averages, while coal-fired production levels increased and are equivalent to 2019 levels. Renewable production rose in late September and throughout October due to strong wind conditions. Higher renewable and nuclear production levels have pushed demand for natural gas in the electricity mix down – in late October the share of natural gas in the electricity mix was as low as during lockdown and on a par with coal.
Coal is by far the largest contributor to CO2 emissions associated with electricity generation. Responsible for around 72% of the activity’s emissions globally, it outpaces gas (22%) and oil (5%) by far. At a regional level these shares vary significantly: in Asia Pacific and Southeast Asia, fuel-based carbon emissions predominantly stem from burning coal (89% and 73% respectively), whereas gas-based electricity generation is by far the main source of emissions in the Middle East (63%), Eurasia (57%), and Central and South America (45%).
Central and South America has the lowest CO2 intensity of electricity generation, benefiting from the large share of renewable energy – primarily hydro (57% of total generation). Particularly carbon intensive is electricity generation in the Asia Pacific and Southeast Asia regions.
The carbon intensity of supply dropped significantly in many countries in 2020: as demand decreased due to the global pandemic, but renewable energy generation continued to grow in many regions, fossil-fuelled production lost market share. This resulted in an estimated 3% reduction in the carbon intensity of production. Total electricity-related emissions dropped by 5%. Especially remarkable was the drop in the European Union (17%) and North America (10%) due to a combination of lower demand, intense coal-to-gas competition and growing renewable generation.
Many of the largest electricity-consuming countries have been able to achieve significant improvements in emission intensity during the past two decades. China, starting with the highest carbon intensity in 2000, was able to cut emissions by 35%. The United States and Canada are both down by 44%, Germany by 45%. Germany particularly improved in 2020 (down 10 percentage points) due to a significant reduction in coal-fired generation.
To achieve clean energy transitions, countries are implementing a suite of policies that work together towards the decarbonisation of the electricity sector. National policy objectives and constraints, alongside local power market structures, shape each jurisdiction’s particular policy mix. In addition to fuel taxes, and efficiency and renewable support measures, they can also incorporate market mechanisms. For example, Japan implemented an innovative non-fossil fuel certificate trading framework in 2020, which also includes renewable and low-carbon energy sources not covered by Japan’s feed-in tariff. This year is also notable for the first implementation stages of China’s emissions trading system, covering its power sector. An increasing number of countries and jurisdictions are introducing carbon pricing instruments. These comprise carbon taxes, emissions trading systems or hybrids of the two, and can be an effective complementary policy in the arsenal of instruments that governments can use to decarbonise their electricity sector, alongside other low-carbon, sector-specific policies. The electricity sector is included in the overwhelming majority of carbon pricing instruments.
Carbon pricing introduces a price signal for the cost of carbon emissions with two main impacts. First, it provides a signal for investment decisions, including in the long term. Second, it impacts the merit order of electricity dispatch, which can lead to a shift from high- to lower-carbon generation sources. The use of carbon pricing is growing, albeit from a low base. Reflecting historical energy competitiveness and affordability concerns, power markets are regulated to various degrees and in ways that can impact the desired effect of carbon pricing. The degree and form of these effects will vary in different market contexts; for example, effects on dispatch will be strongest where economic dispatch and liquid wholesale markets prevail. In the United Kingdom the introduction of a carbon price floor in addition to the EU emissions trading system allowance price has substantially contributed to the reduction of the share of electricity supplied by coal, from 39% in 2012 to only 5% in 2018.
2020 has so far recorded some notable developments in carbon pricing instruments that cover the electricity sector around the world. The national emissions trading system of China is set to begin during 2020 and 2021, and will initially cover electricity and heat generation from coal- and gas-fired power plants. When operational it will be by far the world’s largest emissions trading system, alone covering more than 14% of global CO2 emissions from fossil-fuel combustion.
At the beginning of 2020 the EU emissions trading system linked with the Swiss emissions trading system, and started implementing the regulatory provisions on carbon leakage, free allocation and auctioning ahead of the next trading phase starting in 2021.
The US Regional Greenhouse Gas Initiative (RGGI), a power sector cap-and-trade programme operational since 2008 in some states in the northeastern United States, experienced further growth in the past year. The state of New Jersey rejoined the initiative in 2020 and Virginia is set to join as well in 2021, increasing the emissions covered by RGGI by 36%.
The New Zealand emissions trading scheme underwent significant legislative changes in 2020, including an updated purpose for the scheme (to support Paris Agreement and domestic mitigation targets), the introduction of a rolling cap on emissions aligned with emissions budgets, and the introduction of auctioning with the simultaneous phase-down of industrial free allowance allocation.
The Korea emission trading scheme also announced in 2020 important changes for its third phase starting in 2021, which include a stricter emissions cap in line with the country’s 2030 GHG emissions target, an increase in auctioning of allowances and various measures to boost market liquidity.
In line with its impacts on the energy sector more broadly, Covid-19 had impacts on both pricing and trading systems, including extending the deadlines for compliance obligations and suspended market transactions. Carbon price declines in the EU emissions trading system were not sustained for long, likely due to a combination of factors including the use of the market stability reserve and an overall policy context of more ambitious GHG targets. Indeed, a notable trend in 2020 was the announcement of net-zero targets by many countries, including the European Union, China, Japan and Korea. This may impact the design and operation of their climate policies generally, and for some countries their emission trading systems in particular.