Alongside the European Coal and Steel Community, Germany, Switzerland, France, Italy and the Low Countries started to hook up their electricity grids in the 1950s. By trading electricity, especially Alpine hydro power, they could reduce the coal needed for power generation and put it to use in industrial plants. The development of nuclear power and North Sea oil and gas in the 1970s and ‘80s gave further impetus to the European grid, with French and German nuclear plants and British, Dutch and Norwegian gas plants providing cheap exportable power. Now, climate change and the rise of renewables are forcing Europe to go further and faster in integrating electricity markets.
Renewable energy has two characteristics that make European grid integration important. First, countries have different endowments of territory suitable for renewables. The shallow North Sea is a critical wind power resource for north-western Europe but not all countries have access to the basin. The Iberian peninsula and north African countries are sunnier and less populated than northern Europe, making the export of solar power a win-win for everyone. Second, wind and solar power are weather-dependent. Cloudy or calm conditions can be dealt with by using batteries, pumped storage and other power sources, such as nuclear, ‘green’ hydrogen (hydrogen can be made using renewable power, making it ‘green’) and gas-fired plants with carbon capture and storage. But periods of low generation can also be offset by electricity trade, because when the North Sea is becalmed, the Baltic may not be, and power can flow from one region to the other.
However, there are several drawbacks to electricity trading, which is why authorities have been slow to build interconnectors. Interconnectors allow electricity to flow from countries (or, as we shall see, internal price regions called ‘bidding zones’) where generation is abundant and prices low to countries where generation is not sufficient to meet demand, and prices are high. That means that prices rise in the low-price country as electricity flows out, and prices fall in the high-price country as electricity flows in.
These price effects have recently had political implications: Norway has seen prices rise substantially as it exports hydropower to Britain, Denmark and Germany in periods of Dunkelflaute – cloudy, windless days in winter, when renewables generation collapses. High gas prices have also pushed up electricity prices via interconnectors, even in countries like Norway that use little gas for power generation. Norwegian political parties have started to compete on the issue, with Labour and the Centre party saying they want to turn off the interconnector with Denmark when it comes up for renewal in 2026, and to renegotiate contracts for new interconnectors with Germany and the UK.
Interconnectors expose countries to the price effects of each other’s energy policies, which is why Norway – and Sweden, which has also struggled with periods of high prices – are vacillating about further integration of the European grid. Angela Merkel’s decision to phase out nuclear power, the reduction in Russian gas imports after Putin’s brutal invasion of Ukraine, the UK’s relatively high gas consumption, and Denmark’s extremely high share of wind in generation, have all exposed Norway to higher prices in becalmed periods in winter.
Sometimes the politics are difficult for a second reason – because imported electricity can imperil the finances of domestic plants. Until recently, France had been resistant to more interconnectors with Spain, because it would mean opening its market to cheap Spanish solar power. Commentators in Spain – and other countries – have suspected France is trying to protect its state-owned nuclear power industry. That – as well as bureaucratic planning and ‘NIMBYism’ (residents saying ‘not in my back yard’ to solar farms on their doorstep) – has constrained Spain’s expansion of solar power, despite its abundant sun and relatively sparsely populated land. Thankfully, France’s position seems to be shifting, as it became a net electricity importer while several plants in its ageing nuclear fleet had to be closed for servicing in 2023, and as its nuclear plants are re-engineered to allow their electricity output to become ‘dispatchable’, falling during periods of high renewables output and rising on cloudy, windless days. More cables are now in the planning stages, but it took six years to agree the cost-sharing arrangements for building a new subsea interconnector. Spain’s interconnectors only amount to 3 per cent of installed generation capacity, against an EU target of 15 per cent by 2030.
The final problem is that interconnectors are expensive and take a long time to build. Planning also takes a long time, because of protests against pylons, assessments of environmental impact and finding sites for plants to convert power for domestic use. Typical lead times are around a decade, compared to five years for a wind power plant and less for solar.
All of these difficulties explain why, despite good progress on interconnection over the last two decades, the pan-European grid is now being developed too slowly. According to ENTSO-E, the institution of national grid operators that includes 36 countries inside and outside the EU, planned interconnectors in 2030 will fall short by a third of what’s needed to minimise the costs of the European electricity system, and by a fifth in 2040.
How, then, could progress be accelerated?
About the Author
John Springford is an associate fellow at the Centre for European Reform.