Increase in fossil-fired thermal generation


Subsequent to declines in hydropower and nuclear generation in 2019, fossil-fired thermal power plants were run more often, and output increased by 9.8% year-on-year. Production at gas-fired thermal power plants surged (+23.8%) and accounted for the lion’s share of the increase, while coal-fired generation plummeted (-71.9%). Oil-fired generation rose (+26.5%) chiefly at facilities connected to the distribution grids, notably in Corsica, where hydropower generation decreased sharply due to low water reserves.

Closer look

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Fossil-fired and renewable generation in 2019


Fossil-fired thermal generation was highest in January, February and November. These plants were fired up less often in December, notably because wind power output was high (more than 4.7 TWh).

Gas-fired plants accounted for the majority of fossil fuel thermal generation, producing more than 5.8 TWh in January, 4.5 TWh in February and 5.1 TWh in November. Output from fossil-fired plants was also significant during the summer peak in July.

Coal generation was much lower than in 2018, and concentrated in January (426 GWh), November (474 GWh) and December (253 GWh). There was a direct correlation between this decline and the sharp drop in the gas price over the year, which favoured gas-fired plants, and a rise in the price of EU emissions allowances.

 

Closer look

Coal-fired power plants in 2019

In 2017, the French government announced that it would shut down the country’s last coal-fired plants by 2022. Article 3 of the energy-climate law introduced a mechanism that caps emissions and thus the amount of time coal-fired plants can operate in mainland France after 1st January 2022. This was one of the targets set out in the Multiannual Energy Programme unveiled early in 2019.
The four coal-fired plants in question, the ones still in service in France, are the Cordemais, Le Havre, Saint-Avold and Gardanne facilities.
They represent installed capacity (five generating units) of 3 GW, or about 2.2% of total installed capacity in France.

The hours of operation of coal-fired plants decreased sharply in 2019. Output fell to 1.6 TWh, about 3.5 times below the 2018 level, and capacity availability decreased from an average 1,815 MW in 2018 to 1,674 MW in 2019. This decline was primarily a reflection of a contraction in the economic space for the technology (see below) and, to a lesser degree, of strikes that affected production at the different coal plants in France.

Output from coal-fired plants:

From February on, coal plants were fired up much more infrequently, though production resumed temporarily during heatwave periods in the second half of July, partly to make up for a drop in nuclear generation linked to maintenance schedules and environmental restrictions that kicked in due to high temperatures and drought conditions. The coal plants were once again fired up in late November and early December, in response to a rise in demand and a nuclear plant availability rate that remained low at the beginning of winter, notably when the reactors at Cruas were unexpectedly unavailable.

Coverage of demand during peak periods declined sharply between 2018 and 2019. Coal plants contributed much less to meeting peak needs during the year, with an average coverage rate of 0.20% in 2019 compared with 1.18% in 2018.

On a typical day in 2019, coal plant output reached an average low of 137 MW at 3:00 am and a high of 211 MW at 6:00 pm, when demand increases around the evening peak. Generally speaking, the plants do not totally stop production when demand slumps, in order to be available for the morning ramp and the evening peak.

 

Operations:

Producers of electricity strive to cover their fixed and variable costs. Consequently, a coal plant is typically not run unless it can at least cover its variable costs, which depend mainly on how much it pays for fuel and emissions allowances. Under current market conditions, the variable costs of a coal power producer in France seem high in terms of the European economic dispatch order (base-load, then semi-base load then peak). Coal plants are semi-base load resources designed to operate for a fairly long period in order to cover their relatively high fixed costs. As the carbon price increases, they gradually become the most expensive semi-base load plants to operate within the merit order. The shorter the amount of time they operate, the more difficult it becomes for them to cover their fixed costs.

 

Influencing factors

Various technical and economic factors determine when coal plants are used: the coal price, the price of carbon emissions credits, and the euro/dollar exchange rate.

  • Price of emissions allowances up sharply

Generators that produce CO2, are required to purchase permits to offset those emissions. Because coal gives off large quantities of CO2, the price of permits is a key determinant in the operation of a coal plant. In July 2019, the price of an emissions allowance reached a record high of €29.8 per tonne. If a generator fails to cover its production, each tonne of CO2 emitted but not covered by equivalent allowances costs, in addition to the coverage requirement, a penalty of at least €100 per tonne. The steady increase in the carbon price in 2018 and 2019 has caused a dramatic surge in the variable costs of coal plants.

Platts data

    • Gas price down sharply

    The CO2 emission factor is almost twice as high for coal as for gas plants (0.986 t/MWh for coal units vs. between 0.352 t/MWh and 0.583 t/MWh for various gas-fired generation technologies, according to Ademe data). Though the coal price did decline in 2019, the gas price fell even more sharply, making gas more competitive than coal for an equivalent level of service in terms of generating flexibility. Electricity production from natural gas thus increased by more than 22% relative to 2018.

    Platts data

    • €/$ exchange rate

    The €/$ exchange is another economic factor that determines whether coal plants run. Coal is purchased in dollars but electricity is sold in euros. The ratio has been trending lower since the second half of 2018, making coal even less competitive relative to other generation resources.

    Marginal costs of coal plants

    In theory, prices on the day-ahead market are set for a given time of day, based on the variable cost of the marginal technology (i.e. the one supplying the last MW).

    Every time the average marginal cost is below or close to the day-ahead price, it corresponds to when coal power plants are operating. This is when producers can generate a profit on electricity sales.

     

    The chart below shows the average marginal cost of coal power plants in France:

Coal power plants in 2019

After the government announced that the last five coal-fired plants would be shut down by 2022, RTE, through its Generation Adequacy Report, set out the conditions that would have to be met to maintain the same level of security of supply in France.

The coal power plants at Le Havre and Cordemais are currently being operated by the incumbent utility, EDF.
EDF has indicated that it will close the Le Havre plant on 1st April 2021. It added that Cordemais could be operated at 10% of the current level (between 200 and 500 hours a year) between 2022 and 2024, and possibly until 2026, but not beyond that year. EDF intends to gradually convert it to a coal and biomass facility.
In July 2019, Uniper sold the Saint-Avold and Gardanne plants to EPH.

 

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