Europe

Figure 1.25. Annual change in gas-to-power demand in key European countries, 2017–18

Source: IEA (2019d), Monthly Gas Statistics (database), www.iea.org/statistics/monthly/#gas.

European gas demand fell in 2018, primarily driven by lower gas burn for power generation amidst higher nuclear availability in France, higher hydropower generation in southern Europe, and more coal and hydro generation in Turkey.

In the first quarter of 2019 gas-fired power generation has again been on the rise in Europe. This has been largely driven by fuel economics increasingly favouring gas versus coal burn in the power sector. European natural gas prices have halved from their highs in September 2018, from USD 10/MBtu to below USD 5/MBtu by late March 2019. This has been driven by a number of factors, including lower-than-expected LNG demand especially in China and Japan and above-average temperatures in both Europe and Northeast Asia through the 2018/19 winter, as well as a high level of gas in European storage sites at the end of the heating season. During the same period, coal prices have been decreasing at a much slower pace, with the ARA Rotterdam price falling by 28% from an average of USD 100/tonne in September 2018 to USD 72/tonne in March 2019. Moreover, the price for European emission allowances doubled from EUR 11 (Euros) per tonne of CO2 equivalent (tCO2-eq) in March 2018 to EUR 22/tCO2-eq in March 2019, further weighing on the fuel economics of coal-fired power plants.

Figure 1.26 shows that, considering these price dynamics, gas-fired power plants with an average electrical efficiency of 55% became more cost-competitive than coal-fired power plants whose average efficiency was 38% (or below) in the first quarter of 2019.

Preliminary data suggest that this combination of factors has resulted in coal-fired generation declining by 30 TWh y-o-y, whilst gas-fired output rose by 15 TWh. However, different dynamics have been at play in individual countries such as Turkey, where both gas and coal-fired generation decreased in the first quarter of 2019 amidst higher hydro output (8 TWh increase y- o-y). However, Turkey’s gas-fired generation has been displaced to a much greater extent (down 10 TWh) compared to coal and lignite (down 1 TWh), as natural gas has continued to lose its cost-competitiveness in power generation. Natural gas prices in Turkey did not decline in the same way as in northwest Europe, a result of their high degree of interlinkage with oil prices. In fact, gas prices on the Turkish gas hub continued to increase between September 2018 and March 2019. A further factor affecting the inter-fuel competition between natural gas and

lignite within the power sector is the depreciation of the Turkish lira, weakening by almost 60% vis-à-vis the US dollar since January 2018.13 Moreover, Turkey does not have an emissions pricing system that could have a negative impact on the economics of coal-fired power generation.

Figure 1.26. Gasversus coal-fired power generation costs, 2014–18

EUR/MWh

30

20

Gas-fired generation

is more competitive

10

Note: MWh = megawatt hour.

The graph shows the difference between the electricity generation costs of coal-fired and gas-fired power plants. When the difference is negative, it means that coal-fired power plants are more cost-competitive.

With gas prices plummeting below USD 5/MBtu and emission prices holding steady above

EUR 20/tCO2-eq, gas-fired generation increased its cost-competitiveness during the first quarter of 2019.

With French nuclear and southern European hydro expected to remain at typical levels, electricity demand growing slowly and renewables on the increase, gas for power generation has little room to grow in 2020–22. This rapidly changes through the second part of the forecast period because of the nuclear and coal-fired power plant closures announced by several countries and companies in the region (see Table 1.7).

It is important to note that such closures will not directly translate into additional gas demand, as some of the market space is expected to be captured by the continuous build-up of the renewables fleet. A higher share of intermittent renewables in the power mix might incentivise further investment in flexible peaking generation capacity (such as CCGTs, reciprocating gas engines and gas turbines). This forecast expects natural gas demand for power generation to increase by an average 0.6% per year for the coming five years.