Time to Re-think European Energy Policy

Alexander Wilson

03 Feb 2022

Many electricity markets in Europe are at a critical point.

France’s nuclear fleet is beginning to age, with hopes pinned on the troubled Flamanville 3 project for the next generation of nuclear power.

Britain is in a similar situation with its nuclear fleet, and along with the coal exit, winter capacity margins look very tight as this decade progresses.

Germany and Belgium are closing perfectly functional nuclear plants leaving Germany in particular reliant on coal.

The largest power consumption in Europe is by Germany with most of its domestic electricity is obtained from coal plants. In the transition from fossil fuels the country has installed a significant amount of wind generation. This introduced issues of intermittency and a poor internal transmission infrastructure connecting renewable generation in the north of the country with industrial demand in the south has created problems with its neighbours.

In 2017 after complaints from transmission operators in Poland and the Czech Republic whose grids were being overwhelmed by German power flows, Germany was forced to separate its single bidding zone. On windy days, Germany is a major power exporter but on still days it depends on imports.

93% of Norway’s electricity generation is from hydro. Currently reservoir levels are far below the 20-year median, and at times have been close to 20-year lows. This has resulted in Norwegian electricity prices rising by multiples, creating affordability problems both for households and industry.

In response to the rapidly rising prices in January, the Norwegian government said it would reimburse households for 80% of all electricity costs above NOK 700 /MWh (€70 /MWh) for the rest of winter.

The majority of households in Norway buy their electricity on floating tariffs, where prices change with the daily variations in wholesale prices, making them more exposed to market volatility than customers in countries that provide fixed, long-term tariffs.

Sweden also has problems - The new interconnectors between Norway and Germany and the UK have led Swedish system operator, Svenska Kraftnat, to reduce its cross-border capacity to Norway in December 21. No one was surprised when Norway retaliated by reducing exports.

Denmark and Finland also rely on imports and these capacity reductions also affect their markets. Both countries want an end the exemption that allow TSOs to make such import/export capacity reductions.

As increasing levels of interconnection pull electricity towards the markets with the least excess domestic capacity, prices rise across the continent. This is where problems are starting to emerge – power market trading under market coupling is intended to flow seamlessly from markets with higher capacity margins to markets with lower capacity margins. As more markets rely on wind, increasing tensions are created on days when it’s not so windy.

It is relatively easy to subsidise renewable generation into existence, so it has been given priority, but investments in transmission, storage and low carbon baseload generation (nuclear) which are needed to efficiently manage this new renewable generation capacity is deficient.

To make matters worse, the economics of gas generation are declining, as utilisation levels drop, in some cases pushing efficient gas plants out of the market altogether, for example the Calon CCGTs in the UK.

It is hard to imagine that the situation can continue much longer without a major rethink. The market needs the agility and the flexibility to revise a greater harmonization of European countries’ energy policies in a timely fashion.