Record carbon prices in Europe are failing to price coal out of Germany's base-load merit order this winter, as a shortage of natural gas means there is limited scope for utilities to switch to cleaner alternatives at short notice.
The supply of EU emissions trading system (ETS) allowances, natural gas and coal have all tightened in Europe this year, creating a intense positive feedback loop in the power sector.
Rising carbon prices, all things being equal, provide an incentive to burn gas instead of coal for power, but a shortage of gas this year has supported gas prices at levels that fully offset the positive impact of rising carbon prices on gas' competitiveness against coal. This has created upward pressure for power prices, which have increased to cover the rising carbon costs that cannot be mitigated or lessened by coal-to-gas switching, supporting margins for coal-fired power plants this winter and boosting the demand outlook for power-sector coal burn.
The potential for firm and so relatively more carbon-intensive coal-fired power generation this winter is in turn creating additional support for carbon prices, closing the loop of an upward cycle that has characterised European generation fuels markets this year.
Carbon prices exist to correct a market failure — they allocate a financial cost to a negative externality that was previously unaccounted for — in this case, the environmental cost of emitting CO2 from generating electricity.
But setting a financial cost that is equal to the environmental cost of the externality is difficult. Rather than setting this price directly itself, the EU indirectly sets the price through a cap-and-trade market-based system, with the supply of emissions allowances (EUAs) gradually reduced over time.
This reduction in EUA supply — and the likelihood of further reductions in the future as part of the bloc's "Fit for 55" plan to cut emissions by at least 55pc by 2030 from 1990 levels — has supported carbon prices this year, with allowances exceeding €60/t of CO2 equivalent for the first time at the end of August.
At current prices, the cost of carbon accounts for around €50/MWh, or 51pc of the marginal generation cost of a 42pc efficient coal-fired power plant in Germany. In early 2018, the carbon component was around €27/MWh, or 20pc of the marginal generation cost (see chart).
Wholesale power prices are a function of the generation costs for the marginal power plants needed to meet electricity demand, which are usually coal or gas-fired plants, and so power prices have risen this year in tandem with firming carbon and fuel costs.
This means carbon is increasingly being priced into the wholesale electricity market, going some way towards correcting the market failure that uncosted emissions represent. The previously unaccounted environmental cost of carbon is now being at least partly covered through a financial cost incurred by generators.
While the main goal of carbon prices is to ensure that the negative externality of emissions bears a financial cost, the mechanism can have other consequences that may be desirable or undesirable.
An implicit goal of carbon pricing is to encourage a shift towards cleaner sources of generation, since it is assumed that market participants will act to reduce the negative externality that they are responsible for in order to avoid the financial cost it now incurs.
In this sense, high carbon prices are a signal to accelerate investment in carbon-free generation capacity such as a solar and wind — although this may take some time to bear fruit — and to switch from more carbon-intensive fuels such as coal and lignite to cleaner fuels such as gas. Fuel switching like this could be more immediate if there is already spare gas-fired capacity to use and natural gas supply to consume, as there was in Europe last year.
The existence of a carbon price, and any strength in the carbon market, serves to lift the fuel-switching price for natural gas, which is the theoretical gas price at which generation costs for coal and gas-fired plants of specific efficiencies would be at parity. When the real market price for gas is above or below this level, the fuel is, respectively, uncompetitive or competitive with coal for power generation, based on prevailing coal and carbon prices at the time.
Since coal-fired generation is more carbon-intensive than gas-fired generation, the carbon price always represents a positive component of the fuel-switching price for natural gas. Rising carbon prices lift fuel-switching prices for natural gas and — assuming that gas and coal prices remain unchanged — make gas-fired generation relatively more competitive than coal.
In early 2018, the carbon component of the fuel-switching price of gas for a 55pc efficient gas-fired plant competing with a 42pc coal-fired unit was around €2/MWh, or 12pc of the total. This rose to €8.20/MWh, or 44pc, by the start of this year, and so far this month is €14.90/MWh, or 36pc, of the fuel-switching price (see chart).
Coal prices — the second component of the price for switching to gas — are also trading at more than a decade-high, resulting in an unprecedented fuel-switching price for gas of more than €41/MWh so far this month. But despite such a high fuel-switching price, the actual price of gas is even higher still, at around €51/MWh.
This is because of a shortage of gas in Europe, driven by unusually low inventories and relatively weak pipeline gas and LNG imports, which has significantly reduced availability for the power sector and kept prices supported at a level that makes it uncompetitive with coal.
German gas-fired generation fell by 5.9GW in August from a year earlier to 2.4GW, while coal-fired generation climbed by 690MW to 3.3GW. Coal-fired generation has averaged 7.2GW so far in September.
If rising carbon costs fail to trigger a shift towards less-emissions intensive generation, the carbon cost that is borne by the final consumer will be greater than it otherwise would be. This shows up another potential consequence of carbon pricing, namely that higher carbon costs could, when passed through to the consumer in higher prices, cut overall power demand.
To the extent that this may drive more efficient power demand — consumers insulating their homes for example — the consequence may be considered desirable. But if surging carbon prices make electricity prohibitively expensive for households and businesses and cut demand altogether, their impact may be significantly less palatable, since lower power demand could dent household living standards and economic output more generally.
The current situation marked by supply tightness across the carbon, gas and coal markets is creating a tension between two separate priorities — effectively pricing the environmental cost of unabated carbon emissions and ensuring affordable energy to support the wider economy.
What does this mean for coal?
Surging coal and carbon prices this year have failed to damage implied margins for winter coal-fired generation, which have continued to rise. The fourth-quarter 2021 and first-quarter 2022 clean dark spreads for 42pc efficient coal-fired base-load generation in Germany reached highs of €17.80/MWh and €25.60/MWh, respectively, last week.
The front fourth-quarter clean dark spread has not been higher at any point for at least the past six years (see chart).
The increasing profitability of coal-fired generation this winter suggests that the fuel remains an important backstop in the European power sector that may still be called upon when cleaner alternatives such as gas are not available, no matter what the carbon price.
But forward margins beyond the winter remain under pressure, with summer clean dark spreads for 42pc efficient coal-fired plants negative and spreads for even the highest efficiency coal-fired units negative for calendar 2024 and beyond because of the recent surge in carbon prices. This is a signal to retire existing capacity, meaning less coal-fired power is likely to be available in the future in the event of similar supply crunches, creating the potential for further power price volatility, depending on the speed at which renewable capacity is scaled up.
Some 8.4GW of German coal-fired capacity has already been awarded in phase-out tenders, 4.8GW of which had a 1 July deadline to stop burning coal, with a further 1.5GW to stop from 8 December. Availability is currently scheduled to climb from around 12GW in October to a peak of 14.7GW over November-February this winter.
German daily generation from coal peaked at 13.7GW last winter and averaged 6.6GW over November-February.