Back on September 17th, we posted a blog focusing on the very low hydro reservoir levels in the Norway-South area at the time, alongside the impacts of strong demand for increased imports – required to cover both consumption and demands for exports on the new UK interconnector. In this blog, EQ will look closer at recent development and the outlook for the winter in Norway-South.
The hydrological balance has improved significantly since September, with hydro reservoir levels in Norway-South increasing by nearly 10% after a very wet October. The Nordpool North area (SE1+2, No3+4) has been even wetter than Norway-South (NO1+2+5), which has contributed to the hydrological balance across the entire Nordpool area improving from -27 TWh to -4 TWh.
Despite this, November 8th saw hourly spot prices in Norway-South close to 300 €/MWh due to low wind power in both Nordpool and Germany. More generally, we know that the Norway-South area is still exposed to potentially very high peak prices this winter due to the all-time high Continental power market alongside the increased border capacity from NO2 towards UK and Germany.
Power balance outlooks Norway-South
Every week, EQ updates the power balance outlooks for Norway-South in our weekly Nordic Overview Webinar. The calculations for this are based on updated figures for hydropower production, normal wind and CHP production and normal consumption.
Current reservoir levels in Norway-South are such that we expect to see normal levels of hydropower production this winter, leaving reservoirs filled to 13% capacity by mid-April. This will result in an average net export of 461MW until the end of Q1-22.
This is evident in the exchange chart below, where the net Norway-South curve is shown together with the UK-curve and net exchange from the other connectors. We assume that the UK-prices will be higher than the CWE-prices, so the Continental exchange will equalize the power balance in Norway-South as the UK-cable runs at max export.
We see from the exchange chart how the other connectors (NL/DK1/DE/SE3/NO3) together need to import 461 MW until the end of Q1 as an average. The table below shows our assumptions for flows on the UK, NO3 and SE3 connectors. The SE3 flow is based on average flows for the 2021 winter period.
The price effect of this base load net imports from NL/DE/DK1 depends on how the Norway-South system is able cover the export capacity on these borders during peak hours. If we assume 3000MW as maximum capacity towards NL/DE/DK1, this will mean about 2400MW of imports during the off-peak periods when importing 461 MW as baseload/weekly average.
How peak load export conditions come out will be crucial for prices in Norway-South during the winter. The German Q1 peak price is currently trading at around 200 €/MWh, while the off peak is calculated to be about 140 €/MWh. By comparison, the NO2 price for Q1 is currently traded at about 100 €/MWh, so there is a large upside in the Norway-South prices if max export towards NL/DE/DK1 is not fulfilled regularly during the winter.
Peak hour outlook for Norway-South
As an example, we have selected the balance for peak hours during week 5 2022. This is compared to week 5 2021 which was very cold. For week 5 2022, we have made 3 scenarios: normal temperatures (-3.8 deg C in NO1), a cold week (-7.4 deg C in NO1) and a mild week (-0.2 Deg C), see table below. Notice that we have reduced the max hydropower production by about 700 MW from 2021 due to lower reservoir levels. In the cold week scenario, we have selected 50% of normal wind power and consumption levels in accordance to calculated temperature sensitivities. In the mild scenario we assume 150% of normal wind power.
In the normal week 5 scenario, we estimate a 2736MW surplus in Norway-South on the basis of the max hydropower output. This is reduced to 1431MW in the cold scenario and increased to 4040MW in the mild and windy scenario.
So, what about the expected exchange conditions on the different interconnectors from Norway-South for these different scenarios?
EQ’s forecasts of how the peak load export flow will be distributed on the different interconnectors is shown in the table below:
We see from the table that it will not be possible to reach available export capacity towards DE, NL or DK1 in a normal scenario. This means that Norway-South will be importing DE peak prices even a normal winter scenario.
In the cold scenario, we assume a zero net-flow towards DE/NL/DK1 if SE3-flow is prioritized and DE peak prices will be imported to Norway-South. Only during mild scenarios do we see that max available capacity and bottlenecks on the cables southbound will be reached. In these cases, we may see significant lower prices in Norway-South than on the Continent.
In the chart below, you see the hourly profiles for week 5. The max-peak scenario means the NL/DE/DK1-cables are at their maximum available levels. In such a case we see that about 2000MW of production capacity is lacking at peak-hours.
These calculations clearly show the weather dependency on peak-prices this winter (and future winters too) for Norway-South after the strongly increased border capacity in recent years.
From the temperature graph below, we estimate that there is between 15%-20% probability that Norway-South will avoid German peak-prices during January and February, evident on the duration curve. For nearly 50% of the weeks covered, we will most likely see a direct coupling between Germany and Norway-South during peak hours.
We have not chosen to make detailed price-estimates based on this simplified view, however if we were to base them on current market prices and the latest spot prices, the peak period prices could vary between 100 €/MWh and 300 €/MWh this winter for Norway-South. Single hour prices might be even higher. It should also be noted that Germany will reduce their production capacity by 4000MW (nuclear) and 1500MW (coal-fired capacity) from Jan 1st 2022, which brings an upside potential for even higher single hour prices.
The border capacities from Norway-South have been increased by about 3500MW since 2015 (DK1 = + 700MW (2015), DE 1400MW (2021), UK 1400MW (2021)). This represents nearly 25% of the normal peak load workday consumption. This blog shows that the production capacity in the area is not able to support a max-flow situation, with bottlenecks on all these new connectors occurring simultaneously during peak load periods under normal weather conditions. Calculations show that Norway-South is lacking about 2000 MW production capacity this winter to avoid importing Continental peak prices by normal weather conditions.
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