Relying on interconnectors for imports carries risks

Britian’s latest subsea interconnector, the 1.4 GW Viking Link with Denmark began commercial operations at the end of December. Initially its capacity will be limited to 800 MW until internal grid reinforcement in Denmark is completed, since if it ran at full capacity the link would risk overloading the Danish network in the West Jutland region. Expansion of the 400 kV grid along Denmark’s west coast will enable Viking to operate at full capacity, with the first part of the West Coast Link from the German border to Endrup expected to open in Q1 2025. Analysts at S&P Global Commodity Insights forecast net flows to average around 500 MW from Denmark to Britain until February 2025. The Viking Link is the longest subsea power cable in the world at 765 km.

“Great news today as the new Viking Link interconnector starts to transport energy between Denmark and the UK, under the North Sea. The 475-mile cable is the longest land and subsea electricity cable in the world and will provide cleaner, cheaper more secure energy to power up to 2.5 million homes in the UK. It will help British families save £500 million on their bills over the next decade, while cutting emissions,”
– Claire Coutinho, Secretary of State for Energy Security and Net Zero

The news of yet another interconnector between GB and other nations has been widely celebrated, but is it really such good news? Regular readers will know I am sceptical that interconnectors can be relied upon to deliver imports when needed. Under Capacity Market rules, interconnectors only need to be operational during times of system stress – they do not need to be importing, and there are no mechanisms to force imports if the capacity has been sold to market participants for the purposes of exporting (although exports can be stopped). If both markets at each end of the cable have simultaneous system stress then, technically, there would be price competition between them to secure imports, but in reality it is expected that system operators would intervene to float the cable, meaning power would not flow in either direction.

Back in 2020 I looked at the behaviour of our interconnectors with the Continent and found that during periods of high GB winter demand, the country often exports electricity: Britain exported electricity to Continental Europe during 13% of the hours with the top 5% of demand since the beginning of Winter 2020, while exports accounted for 16% of all hours over that period. (Considering Winter 2019, which was less affected by covid effects, Britain exported electricity to the Continent in 18% of all hours and 12% of the hours with the highest 5% of demand.)

I have updated this analysis for 2022 and 2023 and found that across the two years, Britain exported in 23% of the top 5% of hours with the highest demand (I sorted all the hours in the period by demand, highest to lowest and then looked at the top 5% of hours to determine the levels of imports and exports – in 23% of these hours, GB was exporting).

For 2023-23 I also looked at wind output in GB and also its connected markets (France, Belgium, Netherlands, Norway and Denmark) as well as Germany. Although there were no flows between GB and either Denmark or Germany during the period, the supply and demand balance in these countries impacts both the connected countries and GB, and therefore I included them in the analysis.

In the past couple of months I have been providing a client with daily market updates for GB, looking at demand, imports and wind generation. What I noticed was that during periods of high wind generation in December and January, GB also attracted significant electricity imports, however during the cold spell when wind generation was lower, imports were also lower and exports higher. So, I decided to see whether this was part of a wider trend. Taking my two year dataset, I considered the times when wind generation was high (above one standard deviation from the mean) or low (below one standard deviation from the mean).

In 11% of hours there was high wind in both GB and the other countries, and in 13% of hours wind was low in all countries – that is significant, as 13% is close to one day per week. During 8% of hours it was windy in all countries and GB imported, and in 5% of hours it was not windy in all countries and GB exported. GB exported in 7% of hours when it had low wind generation and received imports in 13% hours when it had high wind generation (regardless of the wind levels in the other countries).

The data don’t entirely support the anecdotal evidence of the past couple of months, but nor do they suggest that interconnectors provide reliability in times of high GB demand. It’s likely that the high volume of overall exports in 2022-23 was due to the specific challenges in France and Norway during 2022 when large parts of the French nuclear fleet were offline due to the stress corrosion problem and Norway faced 20-year reservoir lows in its hydro-dominated electricity system.

But the French fleet is aging and this was the second time in six years that a systemic problem had taken large parts of the fleet out of action. The French nuclear regulator has indicated it may not be the last time. Meanwhile, while Norway’s reservoirs may not see such lows again for some time, the country has gone notably lukewarm on exporting electricity since it opened its interconnectors with Britain and Germany in 2021. Not only has the country amended its Energy Act to allow it to restrict exports if it is experiencing domestic system stress, it has proposed a further amendment to allow restrictions in case of potential domestic shortages.

“We must have control that we have enough power in Norway. The bottom line for this is our own security of supply. We must be sure that we always have enough water in our reservoirs. There must always be electricity in the socket and we must have enough power for our industry,”
– Jonas Gahr Støre, Prime Minister of Norway

In addition, the Norwegian Finance Minister, Trygve Slagsvold Vedum, has said two of the interconnectors between Norway and Denmark (Skagerrak 1 and 2) should not be replaced when they reach the end of their lives in the next year or so. While Energy Minister Terje Aasland, takes a different view, each minister appears to reflect the position of their party (the current Norwegian Government is a coalition between Vedum’s Centre Party and Aasland’s Labour Party). This comes after Norway refused to licence the proposed 1.4 GW NorthConnect interconnector between Norway and Scotland last year. Norway is also considering taxing electricity exports in a bid to keep domestic electricity prices down. 70% of Norwegians believe that high power prices in the country are caused by cross border power cables, creating political opposition to greater interconnection with neighbouring countries.

”The [Norwegian] Centre Party believes there is no reason to renew the licenses. This is our clear primary position. We believe the time is over for large, new offshore cables,”
– Trygve Slagsvold Vedum, Norwegian Finance Minister

In addition to concerns over the economic and political risks of interconnectors, there are also physical risks. Since the start of the Ukraine war, the focus has been on deliberate acts of sabotage after the Nord Stream and Balticconnector gas pipes, however there have also been instances of accidental damage to subsea power cables, notably four of the eight cables of IFA-1 which were damaged by a ship’s anchor in 2016.

The overall expected availability of interconnectors is captured in the Capacity Market de-rating factors. The Government took a more conservative approach than had been recommended by National Grid ESO and the Panel of Technical Experts (“PTE”) which scrutinises the annual Electricity Capacity Reports (“ECR”) by National Grid ESO.

“Interconnector analysis has always been challenging. Firstly, because of their nature: they are transmission links but inject energy resources into the GB network like generators. Secondly, because an assessment of their contribution under stress events is quite hypothetical as there is an absence of sufficient historical evidence on flows under stress. As a consequence, the resource contribution and derating factor analysis is essentially model-based,”
– Panel of Technical Experts: Report on the National Grid ESO Electricity Capacity Report 2023

According to the PTE, the data analysis in the 2023 ECR shows that interconnector imports are modelled to be less than 40% of the total interconnector capacity for over 15% of tight hours. However, 80% of total capacity is available for around 70% of GB tight hours. France has a greater correlation of tight hours with GB than any of the other markets.

Each year the vulnerability of the GB power system grows as reliable thermal and nuclear generation is replaced with intermittent renewable generation, primarily wind. However, wind lulls can both coincide with periods of high system demand (anti-cyclonic weather systems characterised by cold, still weather in winter and hot, still weather in summer) and can be extensive, lasting for days or even weeks, certainly beyond the capacity of any currently existing batteries to back up. So far, there has not been a system stress event, triggering delivery under Capacity Market rules, but each year the risk of that increases, however, the performance of interconnectors in such an event is, as the PTE recognises, is entirely “hypothetical”.

A combination of high weather correlation, political sensitivities and physical risks could all threaten the ability of Britain to attract imports at times of need. Relying on interconnectors could prove to be a huge gamble and one we only know we have lost when it is too late.