Gas-fired electricity generation is making a comeback in Europe and doing so at the expense of coal and lignite, resulting in significant reductions in carbon dioxide emissions.
In the first six months of 2019, gas-fired power plants produced 10.7% more electricity in Germany than in the first half of 2018. In June, German gas-fired generation was 62% higher year on year at 3.7 TWh, while generation from lignite and hard coal plants fell 38% and 41% to 7 TWh and 2.6 TWh respectively.
Although it depends on the efficiency of a particular plant, lignite-fired power produces about 1 to 1.2 tons of carbon dioxide per MWh of electricity generated, in comparison with 0.35 to 0.40 tons for a Combined Cycle Gas Turbine (CCGT). A hard coal plant produces roughly twice the carbon dioxide of a CCGT.
This means that switching to gas from hard coal and lignite has a dramatic impact on power sector greenhouse gas emissions. German power sector carbon emissions in June fell by a third year on year, according to data from the ISE Fraunhofer Institute.
The return of gas-fired generators is a significant turnaround. CCGTs have been hard hit by the boom in wind and solar energy over the last decade, owing to the relatively high cost of gas compared with hard coal and lignite.
As more renewable electricity was generated from wind, solar and biomass, gas generators were the first to be forced out of the market. Many German gas-fired plants saw only a few hours of operation throughout the year.
Now, however, the trend appears to be changing, with a healthy increase in gas-fired generation and a consequent drop in carbon emissions.
The causes of this transformation are both short and long term. They lie in policy developments within Europe, but also reach far across the world to Asia and the United States.
The winter of 2018/19 was relatively mild, which reduced gas demand for heating in Europe. This meant that gas storage facilities were still fairly full in the spring. As many utilities have long-term take-or-pay contracts for gas supplies, they need storage space to be free in the autumn. This in turn means existing gas in storage must be put on the market. With demand relatively low, this pushed down gas prices, making gas-fired electricity generation more profitable.
However, there has been a more significant and fundamental change in gas markets over recent years – the growth of Liquified Natural Gas (LNG). The LNG market grew 8.3% in 2018 to reach 313.8 million metric tons per annum (mtpa), with a marked increase in the amount of gas traded on a spot or short-term basis.
Of particular significance has been the entrance to the LNG market of the US as an exporter. The country’s first LNG train came on-stream in 2016 and capacity has risen fast since then. New plant already under construction and approved by the US authorities suggests that US LNG export capacity will continue to grow with the US overtaking Qatar and Australia as the largest LNG exporter by 2024, according to the International Energy Agency.
The International Gas Union estimates that last year, the US accounted for more than half of the 92 mtpa of new LNG capacity under construction worldwide.
The Chinese-US trade war is also having an impact. In response to US tariffs on Chinese imports to the US, China imposed a tariff of 10% on US LNG coming into China, which was then raised to 25% on June 1. This additional expense in the world’s fastest growing LNG market incentivises US LNG exporters to look for sales into Europe and other non-Chinese markets.
Unlike pipeline gas, LNG can move anywhere to countries which have LNG regasification terminals, in effect connecting the European, Asian and US gas systems.
This is where the mild 2018/19 winter again comes into play. The world’s three biggest LNG importers are all in North Asia: Japan, China and South Korea. Along with Europe this means that the vast majority of global LNG demand is located in the northern hemisphere. If the northern hemisphere winter is mild, then LNG demand in Asia stalls and the LNG heads for Europe.
Although Germany currently does not have any regasification capacity, other European countries do, which, in recent years, has been heavily under-utilised.
LNG imports from around the US and elsewhere have flooded into Europe this year, bringing down gas prices at the main European trading hubs — the Netherlands Title Transfer Facility and the UK’s National Balancing Point — to ten-year lows. This has had a knock-on effect reducing gas prices in Germany and at other European gas hubs as LNG competes with Europe’s supplies of pipeline gas.
However, that is still only part of the story. There is another reason why gas-fired power stations have made it back onto the market – the rising price of carbon allowances under the EU’s Emissions Trading Scheme (ETS). The price of carbon dioxide emissions has risen from below €5/mt in 2017 to nearly €30/mt this year.
As CCGTs produce much less carbon dioxide than their coal or lignite competitors, they have to buy fewer carbon allowances. The effect on the relative profitability of coal plant versus gas thus becomes ever more pronounced as the carbon price rises.
The reason for the sharp rise in ETS carbon prices is a number of policy reforms at the EU level to the way in which the system operates, the overall effect of which is to tighten the supply of carbon allowances available on the market.
Gas-fired generators are thus benefitting from a double bonus – a sharp drop in fuel costs and a relative gain in carbon costs versus coal and lignite. This is boosting the number of hours a year when it is profitable to generate electricity from gas.
And, as higher gas plant utilisation is coming at the expense of coal and lignite, it is providing a highly desirable reduction in power sector greenhouse gas emissions.
‘Fuel switching’ is growing slowly but steadily and is expected to play an important role in meeting European climate change mitigation targets.
In some countries, such as the UK, the decline of coal-based power generation has been accelerated by additional policy measures. The UK introduced a carbon price floor from April 2013, which, as it was raised, had a similar but earlier impact on fuel switching as the more recent rise in ETS carbon prices. The UK also adopted a target of zero coal-fired generation by 2025, which provided a clear opportunity for gas-fired generation.
Whether these emissions busting trends continue depends on a variety of factors, not least the weather. While LNG production is on a steep upward curve, so too is LNG demand led by China. A cold northern hemisphere winter in 2019/2020 would almost certainly see spot LNG prices rise and LNG flows redirected to markets in the Pacific basin. A reconciliation between the US and China over trade would also likely mean the removal of Chinese tariffs on US LNG exports.
Equally, while ETS reform has pushed up carbon prices significantly over the last 18 months, how carbon prices perform over the longer term is uncertain. As the least efficient and most polluting coal plants are pushed out of the market, demand for carbon allowances will fall, potentially tempering gas generators’ relative advantage over coal.
But, for the moment at least, the outlook for gas-fired generation has certainly brightened and gas-for-coal switching is having an immediate beneficial impact on European power sector emissions.
How long the fuel switch trend will last is hard to predict. In summer in particular, gas – due to the large supply and limited demand for heating purposes in that season – will probably continue to play a bigger role in the future than it has in the past.
It remains to be seen whether the fuel switch trend intensifies over the next few years. This depends on many factors – in particular on further developments in the European carbon emissions trading scheme and trends in the European and, more recently, worldwide LNG gas market.