IEA (2020), Electricity Market Report - December 2020, IEA, Paris https://www.iea.org/reports/electricity-market-report-december-2020, License: CC BY 4.0
As a consequence of the Covid-19 pandemic and the subsequent preventive measures and economic recession, electricity demand decreased significantly throughout the region. Region-wide demand is expected to decline by 3.5% in 2020 and of the five largest countries in the region, Brazil is expected to see the greatest drop at around 4%. The United States declines by 3.6%, while Mexico (2.5%), Canada (2.2%) and Argentina (1.5%) are expected to decline less severely.
Hydropower is estimated to account for 21% of electricity generation in the region in 2020. This share rises to 57% in Central and South America, with the North American countries expecting a 13% share.
Gas-fired generation accounts for a 33% share of the region’s electricity generation, while coal and nuclear both have a 15% share, wind 8% and solar 2%.
The change in the generation mix in 2020 shows a steep decline for coal of around 230 TWh, mainly due to decreased economic competitiveness with natural gas, as well as continued deployment of renewables.
Electricity demand slows while gas gains in power generation
Overall electricity demand in the United States fell by 3.8% from January to August 2020 compared to the same period last year, from 2 792 TWh to 2 712 TWh. Commercial and industrial demand fell by 6.4% and 9.2% respectively, while residential demand increased by 2.4% to 1 000 TWh. The overall decline was driven by both the coronavirus-related slowdown in economic activity and the relatively mild winter heating season.
Heating degree days decreased by 10.2% in the first 8 months of 2020, declining in every region of the country, but particularly in the Midwest (12.2%) and West South Central (17.0%). This was somewhat offset by a stronger summer cooling season, with cooling degree days increasing by 5.8% in the first 8 months of 2020, including increases of 21.3% in New England and 13.1% in the Mid-Atlantic states.
Owing to the decline in overall consumption and the rise in renewable generation output, the share of fossil fuel-based generation fell from 62.4% in the first eight months of 2019 to 60.2% in the same period of 2020. Generation from wind and solar sources increased by 14.4% and 24.8% respectively. Generation from hydropower (down 0.2%) and nuclear plants (down 2.0%) was relatively flat. Coal has seen the steepest drop of 24%, from 664 TWh to 505 TWh. The share of coal in US power generation fell from 23.8% to 18.6% as a result.
Natural gas-fired generation increased from 1 055 TWh to 1 109 TWh, a gain of 5.1%. The share of natural gas in the power mix thus increased from 37.8% to 40.9%. Low domestic natural gas prices, caused in part by the reduction in global demand for LNG, increased the competitiveness of natural gas plants compared to coal. The price of Henry Hub gas, the US benchmark, fell to USD 1.33/MBtu in early September, but has risen steadily in response to renewed LNG demand to USD 3.06/MBtu in early November.
Natural gas is also showing strength relative to coal in terms of generation investment. Net additions to natural gas capacity were around 5 GW in January to August 2020 compared to a net decrease of 5.8 GW in coal capacity.
California faces adequacy challenge
California experienced rolling blackouts on 14 and 15 August 2020, the first since the western energy crisis of 2001, as record temperatures drove demand and contributed to challenging operating conditions for both conventional thermal and variable renewable generation. Demand on 14 August reached 46.78 GW, which was above the one in five year forecasted peak load from the California ISO (CAISO) and 10 GW higher than the previous week. Supply, particularly imports, was reduced by the presence of high temperatures and loads, and unfavourable wind patterns throughout the western United States. Significant gas-fired units were also forced out of service. As a result, 1 000 MW of firm load was shed between 6:36 pm and 7:56 pm on 14 August and 470 MW was shed between 6:25 pm and 6:47 pm on 15 August. While this amounts to less than 0.1% of the energy served over the two-day period, the 1 500 MWh of total unserved load represents about 400 000 unit hours of air conditioning, or about USD 15 million in lost load.
In the subsequent weeks CAISO needed to rely on significant voluntary load reductions, called flex alerts, on seven occasions to the end of September to avoid shedding further load, matching the total number of flex alerts issued between 2002 and 2019.
California cites climate change-induced weather patterns, alongside insufficient resource planning targets and certain day-ahead market practices (such as under-scheduling of load by utilities, which led to CAISO exporting energy during critical hours), as the main causes of the rolling blackouts in their preliminary report. The IEA has also issued a commentary that addresses the causes and potential solutions, recommending that California, and other regions likely to face similar circumstances, update their planning framework to incentivise adequacy and flexibility, strengthen regional co-operation to ensure the availability of remote supplies and integrate resilience to extreme weather events into their processes.
Brazil’s power system is characterised by its abundance of hydropower generation, which along with other clean energy technologies make it one of the least carbon-intensive power systems globally. In the first 10 months of 2020, hydropower, nuclear, wind, solar PV and biomass accounted for close to 90% of total generation, up 2% on the same period in 2019. This has been driven mainly by a proportional increase in hydropower generation, marginal increases in solar PV and wind generation and the response to the Covid-19 pandemic.
In the first 10 months of 2020 overall electricity demand decreased by 2.9% compared to 2019. In Brazil public health measures are implemented independently by the states and municipalities. Nevertheless, a common timeframe of response can be seen across the country, spanning from the second week of March to roughly the end of July. During this period, electricity demand across the whole system was 6% lower than in 2019, with the largest decreases taking place in the Northeast region (7.7%) and the Southeast-Central-West region (7.1%).
The drop in electricity demand and subsequent recovery are reflected in the weekly baseload price, which has been on average 15% lower than in 2019. Baseload, mid-merit and peak-load prices in the North and Northeast regions during the period of public health measures remained at roughly the same levels as in 2019. By contrast, weekly prices in the South and Southeast-Central-West regions, which account for most electricity demand in the country, have shown the greatest decrease compared to 2019. The average baseload price was 36% lower in the period between January and mid-July, and 67% lower during the strictest period of measures. For both the South and Southeast-Central-West power regions, prices started increasing in the week starting 18 April, while for the Northern region prices only started increasing along with electricity demand in the week starting 16 June 2020.
As regards the year-on-year changes in generation by technology, solar PV has seen the greatest increase. Solar PV output in the first 10 months of 2020 was 26% higher than in the same period in 2019, particularly driven by the rapid increase in installed capacity under the country’s net-metering scheme. Nevertheless, solar PV is still expected to contribute only slightly over 1% of total generation in 2020.
Electricity demand in Mexico at the start of 2020 was slightly higher than in 2019. This pattern, however, was reversed with the onset of the public health measures to deal with Covid-19 and the corresponding drop in commercial and industrial activity. The decrease in overall electricity supply, as well as recent developments in the country’s power sector, have contributed to reshaping Mexico’s generation mix in 2020.
Compared to the same period in 2019, electricity demand between 1 January 2020 and 30 September 2020 was around 2% lower. The decrease was most pronounced during the strictest period of lockdown measures spanning from 30 March to 31 May. Electricity generation during this period was down around 8% compared to the previous year. However, the loosening of restrictions and eventual uptick in industrial activity led to a system peak load of around 46.2 GW, which took place on 27 August, being only 2.7% lower than the 2019 peak.
Regarding the generation mix, Mexico’s power system is still dominated by gas-fired generation, which constituted 53% and 58% of total generation in the first 10 months of 2019 and 2020 respectively. New solar PV generation coming online has also led to a significant increase in solar generation of 62% relative to last year. However, variable renewables’ – solar PV and wind – share of generation only increased from 7.5% of generation in the first 10 months of 2019 to 10% in the same period in 2020.
In the first 10 months of 2020 coal-fired generation decreased compared to 2019, from 7.3% to 4.1% in the same period.
Canada’s electricity demand is expected to decrease by about 2.2% in 2020. From a generation perspective, about two-thirds of this decrease has been offset by increased net exports to the United States. Renewables (including hydro, biomass, wind and solar PV) are expected to be slightly higher this year thanks mainly to higher hydro and wind output. Natural gas-fired generation is expected to be down slightly (2 TWh) compared to last year’s levels, with nuclear power also down (5 TWh or 5%) as more units undergo refurbishment. Coal-fired generation is likely to see a decline of around 12% or 6 TWh. Most of this decline in coal is taking place in the province of Alberta, where lower demand, competitive natural gas, increased wind and carbon pricing are putting sustained pressure on the fuel.
Some parts of Canada have seen significantly higher peak demand in 2020. On 14 January at 6 pm, before the pandemic, Alberta set a new record for provincial demand of 11 698 MW during a cold spell when temperatures were -30°C. Despite having good wind generation resources, which over the previous 30 days had averaged a 42% capacity factor, on this day the output from wind farms averaged just 5% as the weather was both very cold and very calm. In Ontario summer peak demand was higher than it had been for nine years, thanks a combination of hot weather and suspension of a key demand response programme in response to the pandemic.
Investment in Canadian low-carbon electricity capacity continued in 2020. A major nuclear refurbishment is underway in Ontario, with the first unit (Darlington 2) returning to service after a 40-month outage and two others (Darlington 3 and Bruce 6) beginning multi-year outages. Muskrat Falls, a new 824 MW hydro facility in Labrador, produced its first electricity and will enter into service in 2021 – as will the Keeyask project (700 MW) in Manitoba and the 4th unit of the La Romaine project in Quebec. A major hydro project under construction in British Columbia (Peace River Site C, 1 100 MW) faces significant delays to address geological challenges that have arisen.