With the current “EU Energy Outlook 2060”, Energy Brainpool shows long-term trends in Europe. The European energy system will change dramatically in the coming decades. In addition to climate change and an outdated power plant fleet, current geopolitical tensions are also forcing the European Union and many countries to change their energy policies. What do these developments mean for power prices, revenue potential and risks for photovoltaics and wind?
The European Commission presented a reform proposal on the European electricity market design in mid-March 2023, after turbulent energy markets last year. An important aspect of this proposal is that the Commission will continue to use the merit order principle to determine the power price. This shows that the calculation of power price scenarios, which are calculated on the basis of a fundamental model, still represent a coherent and resilient method to map the level of future power prices.
In addition, the Commission‘s proposal also aims to strengthen the resilience of renewable energies to energy price shocks. Prospectively, so-called Contracts for Difference (CfDs) in public tenders as well as national guarantee systems for Power Purchase Agreements (PPAs) in bilateral trade supposed promote investments in renewable energies and protect them from the volatility of the power price.
In the proposal, the politicians also call for more investment in energy storage and demand-side response solutions. These measures would reshape the energy market in the medium to long term. As a result, the evaluation of market developments, assets and contracts, investment decisions, PPAs or business models are constantly changing.
The “EU Energy Outlook 2060” from Energy Brainpool illustrates commodity prices, power plant expansion and power demand, as well as power prices up to the year 2060. This gives an impression of the possible evolution of the future energy market. Additionally, it shows the developments in Energy Brainpool‘s Central scenario for the EU 27, including Norway, Switzerland and the UK. In general, the current developments in the individual countries can vary significantly. In order to be able to make well-founded decisions, a detailed modelling of the individual national markets and the country-specific influencing factors is essential, including sensitivity analyses.
Energy Brainpools Power Price Scenarios
Currently, Energy Brainpool offers four power price scenarios. Figure 1 shows the various trends in those scenarios. The differences relate to the assumptions on the development of commodity prices as well as the power plant fleet and the flexible electricity demand.
The “Central” scenario
In the “Central” scenario, it is assumed that Europe will completely stop importing Russian pipeline gas by 2027 at the latest due to the current tensions with Russia. As a result, the price of natural gas in Europe is determined by the world market price for LNG. In the long run, synthetic fuels and especially “green” hydrogen will replace fossil natural gas. To the extent natural gas is still used for power generation after 2040, the price will have to fall accordingly as the CO2 price rises in order to remain competitive.
In the scenario, it is assumed that the energy system will be strongly decentralised with a significant expansion of renewables. The goal is to reduce the general dependence on the import of fossil fuels in the medium run and to end it as quickly as possible. This process is accompanied by an increase in the flexible demand for electricity. In addition to the increasing production of hydrogen by electrolysers, heating is fully decarbonised until 2060 by further expanding the deployment of heat pumps. By 2060, the share of electric vehicles and trucks in Europe increases to 95 percent.
The “Tensions” scenario
The “Tensions“ scenario assumes that the current tensions between Russia and the west will continue and intensify in the coming years. Consequently, Europe stops the imports of Russian pipeline gas as early as possible. As a result, the price of natural gas is based on the world market price for LNG. European consumers are competing for LNG with Asian markets. This also leads to a high natural gas price level in the medium run.
At the same time, there is an increase in CO2 prices compared to the “Central” scenario. This should generate additional revenue to refinance public debt and promote technological development in the use of hydrogen. In certain countries, for example in Germany, the scenario assumes a slower expansion of renewables than in the “Central scenario”, due to skilled labour shortages and a lack of political support.
The “Relief” scenario
In the “Relief” scenario, the relationship between Europe and Russia is expected to ease off again in the coming years. Thus, imports of Russian pipeline gas will continue in the medium run. Nevertheless, there is the political will in Europe to limit the fossil fuel dependence on Russia and therefore less natural gas is imported than before the Ukraine war. Moreover, the expansion targets for renewables, which were set during the crisis, are kept in place.
GoHydrogen: A hydrogen energy world
With the EU Green Deal, there is for the first time a clear target at European level to achieve Europe-wide climate neutrality by 2050. While the goal is thus given, the ways to get there are still unclear. With “GoHydrogen”, we have developed a scenario of how this profound transformation of the energy system can be designed against this background.
In the future, hydrogen will be used as a substitute for fossil natural gas in Europe – this is the central statement in the “GoHydrogen” scenario for a future energy supply. Hydrogen advances to become one of the main energy carriers, as its utilisation potential is fully exploited in the most important energy sectors. Hydrogen technologies will play a key role in numerous applications: Fuel cell trucks, climate-neutral steel from the direct reduction process, feedstock use in the chemical industry and hydrogen-based heating systems.
This results in a Europe-wide hydrogen demand of over 2,200 TWhGCV by 2050, with up to 50% covered by domestic (European) hydrogen production (predominantly by electrolysers). It is assumed that the electrification rate will increase for certain applications such as private transport, provision of industrial process heat and heat supply for buildings. This leads to a significant increase in the total electricity demand, including the consumption of the electrolysers.
The annual Europe-wide electricity demand by 2050 is assumed to be over 5,700 TWh. This corresponds to almost a doubling of today’s electricity consumption. Mainly, the increase in electricity demand will be met by a strong expansion of renewable generation plants such as onshore and offshore wind turbines as well as solar plants, but also by the addition of “H2-capable” gas turbines.
In terms of hydrogen imports, regions such as MENA, sub-Saharan Africa, Australia and South and North America offer great export potential. The MENA countries are in a key position due to convertible natural gas pipelines and geographical proximity to Europe. More information on the “GoHydrogen” scenario can be found in a new whitepaper (https://www.energybrainpool.com/services/white-paper.html).
The Development of commodity prices
In the short run, current developments on the futures markets are taken into account for fuel and CO2 prices. Compared to the record highs in mid-2022, fuel prices have fallen significantly again in the last six months. Figure 2 shows an example of the course of the future price for natural gas (TTF) for the delivery year 2024. Nevertheless, gas and hard coal prices will fall slightly in the coming years, as can be seen in Figure 4.
The development of medium- and long-term commodity prices for hard coal, oil and EUAs from 2030 to 2060 is based on the Announced Pledges Scenario (APS) of the IEA’s World Energy Outlook (WEO) 2022 (IEA, 2022) . In the APS, only the emission reductions to which governments have already committed in the form of “pledges” will be realised.
For natural gas, it is assumed in the “Central” scenario that the European natural gas price will be oriented towards the world market price for LNG in the medium run. As probably the most important import source for Europe, US LNG is assumed to set the price. The export price for U. S. LNG historically corresponds to the U. S. natural gas benchmark price (Henry Hub). In addition, there is a surcharge for transportation within the U. S. and a fee for liquefaction of natural gas for transportation as LNG.
In addition, to determine the price of U. S. LNG in the European market, it is important to take into account the costs for freight and regasification in Europe. Figure 3 shows the composition of the cost components based on the Henry Hub Price Forward Curve. It also shows the median assumptions for liquefaction, freight, and regasification costs. The natural gas price is 22.60 EUR2021/MWh, considering the exchange rate and inflation assumptions. This price is set in the scenario for the years 2030 to 2040. It corresponds almost to the level forecasted by the World Energy Outlook 2022 for the price of natural gas in Europe for 2030.
In the long-term, hydrogen will replace fossil natural gas in its end uses. Specifically, this will be produced by electrolysis from electricity or imported. We assume that this type of “green“ hydrogen will be traded on the world market and undercut the “clean gas price” from 2040 at the latest. The “clean gas price” consists of the price for natural gas plus the EUA price multiplied by the natural gas emission factor of 0,2 tCO2/MWhth. This increases the price pressure on natural gas after 2040. Natural gas is slowly being displaced.
This leads to the commodity price paths shown in Figure 4. In this scenario the prices for gas and hard coal decrease continuously until 2030, compared to today’s level. Until 2060, the coal price then remains at a nearly constant level, while the price of gas declines steadily after 2040. In 2060, the price for CO2 rises to just under EUR 180 EUR/tCO2.
What will the European power plant fleet of the future look like?
In the past, fossil generation capacities in particular dominated the power plant fleet in Europe. Many of the power plants on the market have already reached an advanced age and will have to be replaced by 2050. Only those power plants that are already in the construction process are exempt from this.
At the same time, the results of European climate policy also flow into the design of the European power plant fleet. Almost all EU states where electricity is still generated from coal today have decided to phase out coal. In this way they want to limit the negative effects of the high CO2 emissions. Established as well as proven technologies are available for the future: Gas-fired power plants, renewable energies and, in some markets, nuclear power plants.
Wind power and photovoltaics in particular still have a lot of growth potential. Thanks to the sharp drop in costs, these technologies are now competitive. The increasing number of PPA-based projects, especially for solar plants, clearly shows this. This is also being pushed further. As a result, renewables will come under increasing economic pressure in the coming decades due to the cannibalisation effect of the plants among themselves.
In the Central scenario, the share of these “variable renewable energy sources” (vRES) increases to approximately 77 percent of total supply by 2050 (see Figure 5). Consequently, their often-simultaneous electricity generation is lowering the hourly power price more frequently and to a higher degree. All renewable technologies together account for 85 percent of the power plant fleet.
In terms of dispatchable fossil generation capacities, gas-fired power plants will be the main additions at the European level in the future. Compared to coal-fired power plants, they have lower emissions. The latter will continue to lose importance even with carbon capture and storage (CCUS). Instead of fossil natural gas, hydrogen and other synthetic gaseous fuels can be burned in modern gas turbine power plants that are H2-capable.
As a result, gas turbines and combined-cycle power plants will no longer be considered fossil-fuel powered generators in the long term, but will be counted among the “emission-free” power plants, at least in part. It can therefore be assumed that gas-fired power plants will remain an important technology for electricity generation in the future. With natural gas and nuclear plants, the share of zero-emission generation increases to 99 percent by 2050.
Coal-fired power plant capacity decreases by more than 81 percent by 2050, and by more than 92 percent by 2060. The installed capacity of nuclear power is expected to decrease by 19 percent by 2050, after the German power plants have been shut down. In total, the share of generation capacity of dispatchable, thermal power plants (including natural gas) is reduced from currently about 40 percent to about 15 percent. This has a significant impact on the power price structure, which is increasingly characterised by vRES.
Why does electricity demand increase until 2060?
As shown in Figure 6, total electricity demand increases by approximately 64 percent by 2050 and by approximately 71 percent by 2060. Electricity demand increases primarily due to:
- the national hydrogen strategies and expansion of hydrogen applications (e. g. dissemination of fuel cell technology in the transport sector and increased use of hydrogen in the steel production and chemical industries),
- the growing degree of electrification of various energy services for households (especially through the spread of heat pumps and other electric heat applications for the provision of hot water and space heating),
- as well as the rise of electric mobility.
The European Commission’s projects that most of the economic growth will take place in the tertiary service sector, which also requires more electricity. Higher efficiency can prevent electricity consumption in the industrial sector from increasing significantly.
Coal-fired power plants are producing less and less electricity, decreasing by about 73 per cent by 2030 and by about 92 per cent by 2050. Until 2050, however, annual electricity generation from gas-fired power plants will remain almost constant.
In 2050, renewable energies account for 76 percent of electricity generation. Wind and solar power plants account for the largest share, at around 61 percent. Dispatchable renewables, such as biomass power plants or reservoirs, supply the remaining amount of electricity. Another 18 percent of the electricity generated is also produced without emissions, either in nuclear power plants (11 percent) or in gas-fired power plants by burning green hydrogen (7 percent). This brings the share of emission-free generation in 2050 to just 94 percent.
Development of average power prices
What factors will affect the development of the baseload price, i.e. the unweighted average price for electricity on the day-ahead spot market over all hours of a year, from 2030 to 2050? Particularly relevant are the prices for commodity and CO2, the expansion of renewable energies and the development of power demand.
In the coming years, power prices are shaped by the currently high price level on the futures markets. From 2030 onwards, power prices will increase due to rising CO2 prices and the increasing, especially flexible, demand for electricity. However, continuously higher feed-ins from wind and photovoltaic power plants dampen this development. As a result, there is an increasing number of hours with low power prices and, in countries with support systems for renewable energies or pronounced “must run” capacities, often negative prices. As a result, real power prices decrease only slightly between 2030 and 2060. They show a significant decline and a subsequent increase from around 2040.
Due to the increased addition of wind and photovoltaic (PV) plants in many countries, the average power price has fallen slightly between 2030 and 2050, compared to the last edition of the EU Energy Outlook published in November 2022.
Large deviations are noticeable between different European countries. The ranges of variation in Figure 7 illustrate this. Countries with a low expansion of renewable energies experience a stronger increase in power prices due to the development of commodity prices.
If we look at power prices on a monthly basis, the seasonality and volatility of the electricity market can be seen (see Figure 8). For winter, the analyses show rising prices due to the temperature sensitivity of electricity demand. In contrast, power prices are usually significantly lower in summer. In the future, seasonal price differences will increase, as the rising share of solar power generation amplifies this effect.
Below, figure 9 shows the corresponding development of average power prices in the respective scenarios.
What revenues can wind power plants achieve?
The sales value is the average volume-weighted power price that wind and PV plants can achieve on the spot market over the course of the year. Only generation hours with positive power prices are taken into account in the calculation (including 0 EUR/MWh). By contrast, the sales volume indicates the share of the electricity quantities generated in these hours in the total generation quantity.
The product of the sales value and the sales volume is the capture price. In contrast to the sales value, the capture price is the average annual revenue on the electricity market for the entire generation quantity. This also applies in hours with negative power prices. These key figures make it possible to realistically assess the revenue potential of fluctuating, renewable energies on the electricity market.
As Figure 10 shows, both the market value and the capture price for wind turbines initially decline slightly from 2030 onwards due to increasing capacities. The parallel generation by a higher number of plants reduces the power prices in these hours (cannibalisation effect). From 2040 onwards, there is a moderate increase again, due to the rising flexible electricity demand. On average in the EU, there is almost no decrease in the sales volumes, but in some countries, such as Germany, there is a very significant decline.
The high number of hours, in which, despite the high share of renewable energies, dispatchable fossil power plants set the price, enable positive revenue streams. The range of the capture prices shows how different the country-specific average revenue opportunities of wind power plants are.
What revenues can photovoltaic (solar) systems achieve?
The development of the average sales value and capture price of photovoltaic systems falls more sharply than wind after 2035 (see Figure 11). The reason for this is the significant expansion of PV capacities, especially in Germany, in conjunction with the pronounced cannibalisation effect for PV. In hours when a lot of solar power is generated – especially in the daytime hours in summer – power prices as well as revenues decline.
Similar to wind, the sales volumes remain almost constant on average in the EU. In some countries, however, there are significant decreases at times. The wide fluctuation in solar sales values across the countries shows just how much the revenue opportunities vary. However, in a sunny country, high revenues are possible even with low sales volumes. The reason for this is that plants are better utilised.
Increase in price volatility in detail
In the scenario, many factors lead to a significant increase in price volatility over time. Figure 12 shows the price volatility with a series of boxplots. Specifically, the boxplots describe the annual baseload prices and the hourly price quantiles for each year.
On the one hand, the generation cost of dispatchable, fossil-fuel power plants are increasing due to rising natural gas and CO2 prices. On the other hand, the expansion of fluctuating, renewable energies has a price-reducing effect. As a result, extreme prices occur more frequently and become a normal part of the power price structure of the day-ahead market.
Authors: Josephine Steppat, Alex Schmitt, Huangluolun Zhou
 EU, 2021: EU reference scenario 2020: Energy, transport and GHG emissions – trends to 2050 [online] https://op.europa.eu/en/publication-detail/-/publication/96c2ca82-e85e-11eb-93a8-01aa75ed71a1/language-en/format-PDF/source-219903975 [last accessed 16/11/2022].
 IEA, 2022: World Energy Outlook [online] https://www.iea.org/reports/world-energy-outlook-2022 [last accessed 16/11/2022].
 entso-e, 2022 [online] https://tyndp.entsoe.eu/ [last accessed 16/11/2022].
 US Office of Fossil Energy and Carbon Management, 2022 [online] https://www.energy.gov/fecm/listings/lng-reports [last accessed 16/11/2022].
 Therefore see white paper “Assessment of electricity market revenues of fluctuating renewable energy plants“.