The German power market – a tale of two stories08 Oct, 2012
Germany is the hub of the European power market
RWE has recently commissioned the first of several large new thermal power plants in Germany. The 2.2GW lignite plant in Neurath near Cologne cost a hefty €2.6bn and boasts a relatively high 43% efficiency and ramping flexibility. But this plant and approximately 11GW of other new thermal capacity that are under construction in Germany face tough conditions in which to recover a reasonable return on investment.
The environment for investment returns and security of supply in Germany is a tale of two conflicting stories. Robust government feed in tariffs have supported unprecedented investment in renewable capacity, but this has driven down thermal plant margins. At the same time, new build and subdued demand have resulted in substantial overcapacity, but this has been overshadowed by serious transmission infrastructure stress. Germany sits at the heart of the European power market. The resolution of its capacity and security of supply issues will shape the evolution of power markets across Europe.
The current overcapacity situation in the German power market stems from aggressive renewable targets and support mechanisms. The government is assertively pursuing targets of a 50% renewable electricity share by 2030 and an 80% share by 2050. Diagram 1 shows the rapid acceleration in solar (~25GW) and wind (close to 30GW) capacity that has resulted from the government’s feed in tariff policy.
Given the growth in renewables and subdued demand, the sudden closure of 5GW of nuclear plant after the Fukushima disaster has had a little impact in alleviating the overcapacity situation. It has however had a much more pronounced impact on transmission stress which we address below. But first to the impact on generation returns…
Spreads tell the story
The impact of overcapacity in the German market can best be seen via the margins earned by gas and coal plant, shown in Diagram 2.
Both dark and spark spreads have trended lower since the onset of the financial crisis. However there has been a marked divergence in the fortunes of coal and gas plant, with the collapse of carbon prices and relatively weak coal prices supporting a recovery in coal plant margins since 2011. Carbon market weakness has a pronounced impact on the level of German power prices given the importance of coal plant in setting marginal prices.
While falling German power prices are not a problem for consumers or politicians, they are a major issue for thermal plant owners and investors. At current market spreads it is very difficult for 10-15GW of older thermal capacity (particularly gas) to cover its fixed costs. That problem will only become more pronounced in 2013 when plant owners will need to pay for 100% of their carbon allowances.
As we have set out previously, policy to support renewable generation is creating a two-tier market:
- Low carbon generation market: consisting of generators with low/zero variable costs whose return is driven by government policy mechanisms (e.g. feed in tariffs)
- Thermal market: where thermal generator load factors and spreads are eroded by renewable capacity, with older plant struggling to cover fixed costs and no investment signal for new plant.
These issues are not unique to the German market but can be seen across Europe. They are being felt most strongly in the UK where scheduled plant closures in the middle of this decade look increasingly likely to precipitate a capacity crunch, the focus of an Ofgem report last week.
The advantage that Germany has over a market like the UK in the current environment is that its substantial overcapacity situation provides a buffer against thermal plant closures and a stagnation in new build. Germany can also rely on high levels of interconnection with neighbours who are rich in flexible generation capacity (e.g. Nordic and Alpine hydro and Dutch gas capacity).
You could be forgiven for thinking that all was well in Germany as long as you are not a thermal plant owner. But Germany’s healthy capacity margin is overshadowed by some large transmission network issues.
The main development of wind has been in the windier North of Germany and this northern focus is set to increase as offshore wind becomes more dominant. While this is to some extent offset by heavier solar development in the south, solar contributes little to evening peak load (although it is interesting to note that the increase in daytime solar output has significantly reduced the peak/offpeak price spread).
The recent nuclear closures are heavily skewed to the south as are the likely closures of thermal plant over the next few years. The south is also home to much of Germany’s larger industrial load. So in theory Germany should easily be able to manage its peak demand (of around 80GW) on a net basis across the system. However the uncomfortable reality is that there are a number of transmission bottlenecks that are causing system stress. These are focused on the two main (eastern and western) transmission corridors that carry power from the north to the south. This is evident in the rapidly increasing number of renewable generation curtailments that German system operators are being forced to make to alleviate transmission issues.
The European Network of Transmission System Operators (ENTSO-E) estimates €30bn of investment will be required to reinforce the western and the eastern transport corridors over the next decade. They also emphasise the role of government policy in facilitating this, not just in Germany but co-ordinated across neighbouring countries. The price signals for transmission investment are less transparent than for power plant investment. But it is large scale investment in transmission capacity that is needed in Germany over the next decade to keep the lights on.