Carbon price drives generating fuel switch
Coal pays for its greater carbon intensity in a rising European CO2 price environment
Calculating the gross profit from a power plant, before the advent of carbon pricing, was a fairly straightforward affair. The difference between the electricity price and the cost of fuel—adjusted for either the thermal efficiency of a particular plant or, for a more generic situation, industry standards for coal and gas-fired stations' efficiency—was all you needed to work out.
Since 2005, Europe's power industry has had to pay for a majority of its CO2 emissions and this has triggered a change in profit calculations. It means that coal faces stiffer competition from cleaner-burning natural gas, with the strength of the competition increased by higher CO2 prices and vice versa.
The so-called "dirty" dark spread (coal) and dirty spark spread (gas) for year-ahead forward sales of German power in 2018 and 2019 (see chart 1) are examples of the simple equation discussed above, without the inclusion of the cost of EU emissions allowances (EUAs).
Coal-fired power in Europe can clearly still earn greater profits than gas-fired as long as the cost of carbon is not taken into account. And, in many countries globally, the dirty dark/spark differential is still a relevant measure, since there is no cost placed on greenhouse gas emissions. Even within the EU ETS, generators may be able to access some free allowances—for combined heat and power (CHP) plants, in some eastern EU countries where there are exceptions for modernising ageing thermal plants, or from shifting unused industrial allowances from other assets in a wider utility portfolio.
However, for the majority of generation within the EU ETS system that has to pay for CO2 emitted, the cost of these emissions must be factored in, and thus the picture changes significantly. Chart 2 shows the so-called "clean" dark" and clean spark spreads—that is, the relative profits from burning coal or gas at the same plants, but this time including the cost of EU carbon allowances. Thermal efficiency for a gas plant is assumed at 50pc, around average for a late '90s/early '00s combined-cycle gas turbine (CCGT), and 36pc for coal, representing some of Europe's oldest coal plant.
Coal margins are disproportionately affected by the price of carbon since burning coal releases almost twice as much CO2 into the atmosphere and therefore requires the utility to buy nearly twice as many EUAs.
Between 2011 and early 2018, European carbon prices languished at levels below €10/t CO2e, with consequently little influence on utilities' choice of whether to burn coal or gas. But a 200pc rally in 2018 brought carbon prices to around €25/t CO2e, altering generation economics to the extent that coal is becoming marginalised in a number of European power markets.
Some of the shift towards gas-fired power in Europe is due to the relative price performance of coal and gas. Over the last nine months, Rotterdam-delivered API2 coal and Dutch TTF gas prices have tumbled by 48pc and 62pc respectively (see chart 3), as European coal demand has faltered and a glut of LNG shipments has depressed the European gas market.
At the same time, year-ahead German power has decreased much less. Fuel prices falling further than power has contributed to improved margins for both gas and coal. But while coal prices have fallen the furthest in absolute terms in the last 18 months, and even largely matched gas weakness this year, coal's greater carbon intensity has still impacted its competitiveness against gas, particular in a rising CO2 market.
Carbon's 2018 price rally (see chart 4) has been generally attributed to anticipation of a drop in the supply of allowances after the EU approved a measure that will remove surplus EUAs from the market starting this year. The EU approval of the Market Stability Reserve in November 2017 triggered a surge of speculative buying by investors, as well as by materially impacted utilities, and drove the market to 11-year highs in April this year.
The impact of the soaring carbon price on European gas and coal power margins for year-ahead can best be shown by comparing the climate spread—the difference between coal and gas power margins, to the EUA price over the period 2018-19 (see chart 5).
The climate spread shows a marked move from positive (favouring coal) to negative (favouring gas) at the same time that the EUA price reached the mid-€20s/t CO2e in late November 2018. Since then, there has been a gradual recovery in coal-fired margins for year-ahead generation.
However, the picture is very different for prompt and month-ahead generation, where gas-fired power will earn around €7.50/MWh in July, while a coal-fired unit will lose €2.25/MWh. This approximately €9/MWh advantage for gas over coal has resulted in a large-scale shift to gas-fired power in Germany.
The difference reflects considerably lower prompt prices for power, gas and coal due to oversupply and modest demand. And, while carbon has been a major factor in the year-ahead and later markets, it is the falling fuel and power prices that have had the most impact in the prompt markets.
The decision to switch off coal plants and ramp up gas units depends on other factors too, including the costs of bringing an idled plant back into the market, how quickly it can be brought on line to respond to changes in profitability, and whether government policy affects the long-term outlook.
But it is clear that in the last 18 months, carbon has become a major influence in the shift away from coal and towards gas and renewables. With EU policymakers considering a "net zero" emissions target for 2050, the supply of carbon allowances is likely to shrink faster than it has to date, and rising CO2 prices will crimp coal-fired generation margins even more, ushering in greater use of gas for as long as there is room for any thermal generation in Europe.