In Norway, the increase in power prices observed in the second half of 2021 has once again opened up the debate on interconnectors. The recently published coalition agreement (“Hurdal platform”) addresses questions around interconnectors and market integration with Continental Europe. The extent to which recent power price developments have shaped the coalition agreement is unclear. However, the search is on for something to blame for high prices.
What is to blame?
What is to blame? Or, less judgementally, what explains the price increase? As mentioned, power prices are high across Europe, so this is not a Nordic phenomenon. On the contrary, much of the price increase in Europe, which is also affecting the Nordics, is explained by:
- A surge in gas prices due to cold conditions that have reduced gas reservoirs, a surprisingly gas hungry Asia and reduced gas flows to Europe from both Norway and Russia
- A surge in carbon prices due to an expected tightening of the EU-ETS cap in light of the Fit-for-55 package
- A surge in coal prices due to an increase in transport costs and bottlenecks in transportation, and
- Low wind and hydro output in many European countries, which has increased the need for thermal generation (and hence gas and coal demand)
At the same time, two new interconnectors to Norway have recently been commissioned.
What matters most for the Nordics? To answer that question, we have used our power market simulation model, TheMA, to simulate outcomes in 2021 under different assumptions. We have estimated prices for 2021 assuming that gas prices, carbon prices and interconnection were kept at their levels as of 2019 (2020 was an unusual year due to the impact of COVID-19). We then tested each individual price driver, for example estimating power prices for 2021 assuming gas prices as in 2019.
The estimated price effects are shown in the figure below. Note that these numbers refer to the average prices for all of 2021, so the 2021 price is lower than the current market price.
The first thing to note is that strong growth in electricity supply within the Nordics during the last couple of years would have reduced the Nordic System price by around 15 EUR/MWh relative to 2019, assuming a normal hydrological year and no changes in fuel or CO2 prices or levels of interconnection.
However, this downward price pressure has been almost exactly offset by changes in fuel and CO2 prices. Furthermore, these changes in thermal generation costs are the largest single contribution to rising prices in the Nordic power market.
That said, greater interconnector capacity between Norway and other countries has also contributed to higher power prices. NordLink, the interconnector between Norway and Germany, became fully operational early in 2021 and NSL, the interconnector between Norway and Great Britain, just started commercial operations. Connecting Norway more tightly with Germany and Great Britain has affected power prices in the Nordics. We estimate that the effect on the Nordic System Price for 2021 has been an increase of around 6 EUR/MWh. Although the price effect is very modest in central and northern Norway, the effect on prices in southern Norway (NO2), where these interconnectors make land, may be as high as 13 EUR/MWh this year. As a result, the new interconnectors have exacerbated internal price differences within the Nordic market.
It is worth noting that, assuming an interconnector is fully exporting in both cases, it makes no difference to prices in Norway whether the price on the other end of the interconnector is 100 EUR/MWh or 1000 EUR/MWh. Water values will be the same in both cases. The financial gain from the price differential accrues to the interconnector owners, namely TSOs like Statnett and National Grid.
For the Nordic region, and in particular Norway, the hydrological balance has also pushed up prices in 2021 as this has turned out to be a dry year. Despite a large hydrological surplus from last year, we reached almost record-low reservoir levels this fall. The situation has improved in recent weeks thanks to greater precipitation. This should serve as a reminder to market participants that market conditions can turn quickly. In 2020, we saw prices well below 5 EUR/MWh over long periods due to the large hydrological surplus, now we see prices in the triple digits.
Weather, again!
Last year, following extreme weather conditions, we had a special Insight highlighting the importance of the weather on power prices. Once again, the weather has proved an important driver for prices in the Nordics. This has also been true for the Continent, where the impact of weather should not be underestimated. A lack of wind has increased the need for thermal generation and a cold first half to 2021 depleted gas reservoirs. The increasing sensitivity of the power sector to weather conditions is also reflected in the weather simulations we present as part of our long-term market reports (Low Nordic power prices: Don’t blame Corona, blame the weather!).
One might suspect that we will not experience years with similar price levels when the share of gas- and coal-fired generation in the power system is reduced. Unfortunately, we will have to live with this price risk at least for the next decade. We simulated the year 2030 under two scenarios, one using our base assumptions and one assuming cold weather, little precipitation, little wind and fuel and CO2 prices as they have been in 2021. In Germany, prices in 2030 are 66 EUR/MWh and 107 EUR/MWh respectively under these scenarios. In the Nordics, prices are 56 EUR/MWh and 113 EUR/MWh respectively. Note that under the low precipitation scenario, the challenging hydrological conditions result in prices that are even higher in the Nordics than those in Germany (assuming that we do not have a hydrological surplus in 2029 that can be used in 2030).
Overall, market participants would be well advised to dress for the weather!
