In 2021 energy customers saw their bills mount, as sanctions on Russia, including a halt on its oil and gas exports across Europe, coincided with other factors to drive up power prices. The burden did not fall equally on consumers: some business and domestic customers were able to take advantage of options such as onsite generation or long-term contracts on favourable terms. It also did not fall equally on the energy sector. Upstream energy companies benefitted from the rise in gas prices, as customers and traders sought to secure cargoes from sources other than Russia, whether that was to fuel gas- fired power stations, heat homes and businesses, or fill storage capacity.
Some energy utilities with retail and domestic customers saw their rates capped by governments who needed to ensure both user groups could buy the power they needed, meaning the utilities relied on government to make up the shortfall. While some electricity generators without input costs, such as wind generators, were able to benefit from the high market prices, gas users saw their fuel costs rise dramatically.
The hardest hit were utilities who had to go to the market to fulfil electricity supply contracts. In years of low wind that burden might have been on renewable energy generators. In 2022, the impact was hardest on Europe’s key nuclear generator, EDF.
The company struggled for most of the year with unplanned outages across its fleet as it tried to remedy stress corrosion cracking. At the start of December it still had five nuclear reactors (5.3 GW in total) out of service until the end of the 2022 and it later delayed those restarts until February (Flamanville 1) and March (Penly 1).
Over the year, nuclear power output in France totalled 279 TWh in 2022, which meant it was down 81.7TWh on 2021. EDF was also hit by low water levels, which reduced income from its hydropower business.
The cost to the company was more than the loss of income from those shut down plants. EDF had no choice but to go to the market to replace the power it would have generated, and do it when prices were very high. Between January and September 2022, spot electricity prices averaged €297/MWh, compared with around €70/ MWh for the period in previous years. Overall, the financial impact took a €29.1bn toll on earnings before interest, taxes, depreciation, and amortisation (Ebitda), although consumers responded to initiatives to lower consumption as well as relatively warm weather going into winter. Demand was 5.7 TWh lower than expected. Similarly, but at smaller scale, Ebitda was down 7.2% in Belgium (to €118m) because EDF Belgium had to buy power at high prices to compensate for low nuclear output.
The loss of generation from EDF’s nuclear plants also hit its neighbouring countries. They are accustomed to rely on stable nuclear power volumes from France. But the EU’s regular report on European Energy Markets noted that in 2022 exports from France to Spain “practically disappeared”, while flows from Spain to France rose. In general, it said, French outages drove up electricity prices in France, “changing France’s traditional net exporter into a net importer role, not only from Spain but also from other Member States and the United Kingdom”. Flows between France and Belgium, Spain, Italy, Switzerland and Germany all saw a switch towards more power flowing into France more often. In Germany that was helped by the decision to allow the three remaining reactors (Isar 2, Neckarwestheim 2 and Emsland) to remain in operation until April 2023, to secure the security of supply during the winter season.
There were two areas of EDF’s business that alleviated the negative impact of its nuclear outages. They were the exceptional performance of EDF Trading in a highly volatile market and better nuclear output in the UK.
In 2022 EDF Trading increased its Ebitda to €6.407bn, up from €1.2bn the year before, “in a period of very high volatility across all commodity markets”.
In the UK, nuclear output amounted to 43.6 TWh, a year-on-year increase of 1.9 TWh despite the shutdowns of Hunterston B in January and Hinkley Point B in August (both after 46 years of life). UK sales increased by 61.3% from €10.1bn to €16.1bn – a reverse of the situation in 2021, when EDF Energy had to buy power at the start of the rise in prices to compensate for low generation levels, resulting in a loss of €21m. The company credited good fleet availability and a lighter maintenance programme than in 2021.
The market continues to reward flexibility, and that means companies like Centrica (see box) and Vattenfall, below, are increasing their investment in flexible assets. With Framatome in its portfolio, EDF has to take a lead on new nuclear construction.
The company updated the market on the Flamanville project in December 2022, when it said the planned date for fuel loading had been delayed from Q2 2023 to Q1 2024 and the estimated cost had increased from €12.7bn to €13.2bn.
The nuclear utility also highlighted two significant steps with its European neighbours. It has signed a Framework Cooperation Agreement for Nuclear New Build in Finland and Sweden with Fortum. It has submitted an initial bid to Czech operator ČEZ and its project company Elektrárna Dukovany for one EPR1200 reactor for the Dukovany site in the Czech Republic. It also recently reaffirmed its offer based on the EPR technology to support the ambitions of the Polish Nuclear Power Programme to deliver up to 9 GWe of nuclear output by 2043.
Vattenfall looks to nuclear for long-term
Another nuclear generator also saw a shift in its business in 2022. Vattenfall’s wind business (which also includes some solar) was almost as important for the company’s earnings as was its longstanding nuclear and hydropower segment. The nuclear portfolio decreased last year as its German nuclear plants closed for good and it too had ongoing maintenance issues to manage. But it also suffered because it was unable to gain from high power market prices because of lack of transmission capacity in Sweden.
Vattenfall’s wind farms are offshore of Denmark and Sweden, as well as onshore in the UK. Wind generation from 3 GW of capacity at 50 wind farms rose slightly from 11.2 TWh in 2021 to 12.2 TWh, but Ebitda jumped from SEK13,451bn (€1.21bn) in 2021 to SEK22,508bn (€2bn) as a result of higher electricity prices on the Continent and new capacity coming online.
Vattenfall’s nuclear and hydro business remained steady overall. Generation from nuclear power declined (-0.8 TWh), owing to lower availability caused by the delayed restart of Ringhals 4. The work on repairing the damaged pressure regulator at Ringhals 4 is ongoing “at high pace”, the company said and the reactor is planned to restart on 19 March. That outage was partly offset by Forsmark, which reached record levels of generation in 2022 with 25.5 TWh delivered.
Overall, nuclear generation was 39.6 TWh, slightly down from 40.4 TWh the previous year, while hydro generation was 40.5 TWh, a shade down on 40.8 TWh in 2021. But in contrast to the high earnings from the wind business, Ebitda in nuclear and hydro fell from SEK40,312m (€36m) to SEK28,193m (€25m). The decrease is partly attributable to lower achieved electricity prices in the Nordic countries due to major price differences between price areas in Sweden. In recent years, the differences in electricity prices between the areas have grown wider as a result of bottlenecks in the transmission grid, which prevents the electricity from reaching southern regions.
With its attractive return, it is no surprise that in the next few years Vattenfall is investing in wind, with a plan to quadruple its present capacity by 2030. Upcoming investment of SEK50bn (€4.5bn) will see the largest share, SEK38bn (€3.4bn), invested in wind power. Vattenfall will also invest in electricity grids and expansion of district heating operations. Other growth investments include charging infrastructure, solar and battery projects and heat energy solutions.
The company is supportive of plans for new nuclear in Sweden but that is further ahead. It said, “We welcome the fact that the energy issue is given high priority on the public agenda and that nuclear power is once again viewed as a natural part of the Swedish energy mix. All fossil-free energy sources are needed, and we are looking forward to participating in bridging the existing gap between supply and demand in fossil-free energy.”
New nuclear stake? Centrica is not persuaded
As the UK government tries to interest third parties in investing in Sizewell C, it is worth considering the attitude of its existing third party nuclear investor, UK energy company Centrica.
Centrica has undergone several changes of strategy this century as successive chief executives have tried to give more structure to its sprawling mix of activities, which stretch from gas exploration and production to retail sales as the British Gas brand. For much of this period the company tried to find a buyer for its 20% stake in the UK’s nuclear fleet. When the stake was acquired in 2009, then chief executive Sam Laidlaw said: “We believe nuclear energy is an essential component in ensuring clean, secure energy for the UK and we are proud to be part of our country’s nuclear renaissance.” His successor Iain Conn put the stake up for sale in 2018, saying he hoped to dispose of it within two years, but no buyer came forward.
In 2021 Centrica gave up on the sale and last year it was rumoured that chief executive Chris O’Shea (still in post) might add to the company’s nuclear holdings by joining a consortium of owners of the planned plant at Sizewell C.
The company’s latest results suggest that rumour was ill-founded: although the company current nuclear interest had a bumper year, it aims to use the cash – and earnings from the recent elevated gas prices – to invest in other areas in the energy transition.
Nuclear paid off for Centrica in 2022. The year saw the end of generation at Hunterston B in January and Hinkley Point B in August, but improved plant reliability meant output was up
slightly, up by 5% (from 8342 GWh to 8714 GWh). However the price achieved was up 200% year on year (from £46.6/MWh in 2021 to £140/MWh), and nuclear’s reported adjusted operating profit was £724m (€826m), compared with a loss of £38m (€43m) in 2021.
The company should continue to see good returns for its nuclear sales from the remaining years of the AGR fleet (the units are due to close between 2024 and 2028) and Sizewell B. It has sold 5.0 TWh of nuclear electricity forward for 2023 at an average price of £203/MWh (€233/MWh) and 1.4 TWh forward for 2024 at an average price of £240/MWh (€274/MWh). It expects that prices will remain elevated and its large customers will see arrangements to hedge prices “rolling off”, so it expected to capture higher prices. Earnings will be affected by a government- imposed windfall tax (the so-called Electricity Generator Levy), which applies a 45% tax rate to revenues generated over £75/ MWh (€86/MWh) from 1 January 2023 to 31 March 2028. Currently the company pays a 34% tax on its nuclear earnings but it is taxed at 59% on its much larger gas business.
With cash in hand from its gas and nuclear businesses the company is looking at investment in the future but currently it does not have new nuclear in its planning. Instead it is planning to leverage its experience in volatile markets, as it expects huge investment in intermittent renewable technologies such as wind and solar. The market rewards Centrica sees is the opportunity in battery storage, gas peaking generation, solar, hydrogen and carbon capture utilisation and storage (CCUS).
Hinkley Point C faces cash shortfall
There is a shortfall in funding the UK’s flagship nuclear power project, Hinkley Point C, EDF said in its 2022 results presentation.
The project has been hit by rising inflation. In May last year the project completion cost was estimated to be in the range of £25bn to £26bn bn (€28.5–€29.7bn). But that is in 2015 terms, which brings it to £31-32bn (€35.4–€36.5bn) based on the inflation indexes available at end-2021. Based on inflation indexes as of
30 June 2022, the estimated nominal cost at completion could reach £32.7bn (€37bn). In addition, the May 2022 review did not include the schedule and cost of electromechanical works and
of final testing and EDF said in February at its annual results presentation that “the main civil and electromechanical works performance were less than expected in 2022. Mitigating actions to recover the impact of 3-6 months are underway.”
Although the “start of electricity generation” for unit 1 is targeted for June 2027, EDF says there is a risk of further delay of the two units of 15 months.
EDF said its agreements with CGN include a compensation mechanism between both shareholders in case of overrun of the initial budget or delays. This mechanism was triggered in January 2023. It said the project’s total financing needs now “exceed the contractual commitment of the shareholders”, and shareholders will be asked to provide additional equity, which will probably be needed in the second half of 2023. But EDF said, “The probability that CGN will not fund the project after it has reached its committed equity cap is high. In the event that CGN would not allocate voluntary equity, the EDF Group would be required to contribute in place of CGN.” CGN owns 33.5% of the project.
Author: Janet Wood, an expert author on energy issues
