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The efficient placement of solar and wind power capacity is as important as increasing the quantity of deployment in Europe
 
Introduction
Renewable energy is central to the European Union’s climate and energy strategy. The United States’ war against Iran and the resulting spike in global energy prices has led to the EU’s second energy crisis within five years, showing once again the continent’s dependence on imported fossil fuels and the importance of domestically produced renewable energy.
Wind¹ and solar are the EU’s most important renewable energy sources: in 2025, they generated together around 30 percent of all electricity (wind contributed around 17 percent and solar around 13 percent). They were followed by hydro with 12 percent and bioenergy with around 6 percent (Ember, 2026). Recent modelling (see Rodrigues et al, 2026) finds solar photovoltaic (PV) and onshore wind will be the backbone of a cost-efficient, decarbonised EU economy².
Achieving the current EU renewable target³ will require continued, large-scale investment in solar and wind capacity across Europe. Yet these targets are only one part of the challenge: deploying renewables without understanding the importance of location and timing can create technical and economic challenges for the energy system. For instance, concentrating generation during the same hours and regions could not only waste electricity but also strain local grids which, in the long term, would drive down revenues through low wholesale prices (‘cannibalisation’), which diminishes incentives for new investments in renewables. 
This Analysis takes stock of how renewable resources vary across Europe, where renewables are being deployed, how the ‘cannibalisation effect’ already depresses market value in certain countries and how power-system flexibility and market design can increase the economic value of renewables. 
It argues that future renewable deployment must increasingly account for the timing and location of generation, so that renewables add as much economic value as possible. With the upcoming discussion on renewable targets for 2040, the EU has a chance to place a greater focus on efficiency.
Europe’s wind and solar resources are complementary, both technologically and geographically
At the aggregate level, Europe shows remarkable complementarity between sunshine and wind-speed patterns at the aggregate geographical and temporal levels. This is evident through ‘capacity factors’⁴, which measures the proportion of a power plant’s utilised capacity (Figure 1).
Comparing Spain and Germany illustrates seasonal patterns in wind and solar: differing resource endowments between the countries and wind’s greater variability. Germany shows lower year-round solar PV capacity factors than Spain, especially in winter. In both countries, combined solar and wind generation is remarkably stable year-round, showing the complementarity of the two sources.
Figure 1: Average daily capacity factors in Germany and Spain (2015-2024)
Germany
Spain
^{Source: Bruegel based on ENTSO-E. Note: ‘Combined’ treats solar PV and wind as a single technology; because small solar PV capacities are underreported, solar PV capacity factors are likely to be biased upwards.}
This effect is even more pronounced at the EU level: combining wind and solar resources across regions with complementary generation profiles reduces variability and improves system efficiency (López Prol et al, 2024), highlighting a key benefit of integrating European national energy markets⁵.
Solar and wind capacity is not always installed where they create the most economic value
Solar radiation and wind resources are unevenly distributed throughout Europe⁶. Solar power is strongest in the south, in summer and follows a diurnal cycle with a strongly correlated patterns between countries. Wind power, by contrast, is strongest in the north, along coastlines and in winter, and is less correlated across countries, with no clear cycle. 
Solar PV installations in countries such as Bulgaria, Spain and Greece typically achieve average capacity factors of 12 percent to 14 percent (Figure 2). In comparison, capacity factors are much lower in less sunny countries, such as Norway and Sweden. For onshore wind, countries such as Ireland, Norway, Finland and Portugal achieve average capacity factors above 30 percent.
Figure 2: Average yearly capacity factor (2024)
^{Source: Bruegel based on ENTSO-E and Ember. Note: in the EU, there is no publicly available, consistent data on generation capacities by technology, country, or year, or on the corresponding annual electricity production. Accordingly, this analysis of empirical capacity factors combines data from different sources and should be interpreted as indicative estimates.}
While resource endowments, such as wind speed and sunshine intensity, primarily drive capacity factors, actual deployment and generation do not always follow this logic. Despite a positive association between solar radiation in a country and the share of electricity generated by solar PV in the electricity mix, there is still strong variation in the amount of installed solar PV capacity and the generated electricity at various levels of solar radiation (Figure 3).
Figure 3: Correlation between solar share in electricity mix (2025) and solar potential across European countries
^{Source: Bruegel based on Joint Research Centre (2026) and Ember. Notes: bubble size represents each country’s total electricity generation in 2025. Solar potential is based on Joint Research Centre (2026) estimates, which assume a given share of eligible non-artificial land is available for utility-scale solar deployment and a specified land-use efficiency. Country-level solar potential is recalculated by aggregating the GWh/km² values of NUTS2 regions.}
Some locations offer greater opportunities for deployment
Due to differences between the geographic distribution of renewable energy potential and the actual deployment of generation capacity, a useful method for assessing where additional renewable capacity provides the greatest economic benefit is the average price a technology actually fetches for the electricity it produces in the wholesale market: this is called the ‘market value’.
For solar PV, most eastern European countries, as well as Italy, show very high market values (Figure 4). This indicates that wholesale electricity prices are high when solar PV plants are generating electricity, and that additional solar PV capacity would be especially valuable during those periods in these countries. The electricity is likely to be generated by an additional solar PV plant, rather than by expensive fossil fuels. Onshore wind power enjoys relatively high market values throughout most of Europe. As with solar PV, eastern European countries and Italy show the highest market values.
Figure 4: Market values in euros (2025)
^{Source: Bruegel based on ENTSO-E.} 
Countries with already low electricity prices have low market values for both solar PV and onshore wind. The Nordics, due to their abundant hydro, wind, and nuclear power capacity; and France, because of nuclear power, are examples of this ⁷.
Higher shares of renewables lead to falling economic values 
While increasing renewable capacity is essential for decarbonising the electricity system, additional renewables entering the market affect market prices. When a large amount renewable electricity is generated at the same time, electricity prices tend to decline, a phenomenon called ‘cannibalisation’ (Joskow, 2011; Hirth, 2013; Clò et al, 2015), which matters most where generation is strongly correlated within and across countries, as is the case for solar PV. Capture rates⁸, the share of a technology’s market value to the average wholesale price, illustrate this well: technologies that generate electricity when wholesale prices are high, and so realise high market values, show high capture rates.
Cannibalisation creates several problems: it weakens incentives to deploy additional capacity, can raise government spending where subsidies are calculated as the gap between market price and a strike price and simultaneous generation by renewables can strain local electricity grids.
Figure 5 shows how Germany’s and Spain’s solar PV and onshore wind capture rates fall, with solar PV more affected, as generation shares increase. From 2015-2025, as the generation relative to load (total electricity demand) exceeded 20 percent, capture rates fell as low as 20 percent, which means solar PV units earned just a fifth of the average wholesale price that month. Onshore wind’s capture rate is more stable, reflecting its lower correlation within and between countries.
Figure 5: Monthly generation share vs capture rates in Germany and Spain (2015-2025)
^{Source: Bruegel based on ENTSO-E.}
The economic value of renewable technologies depends not only on where and how much capacity is installed, but on how well the electricity generated can be integrated into the system, sometimes termed ‘flexibility’. An extreme indicator of growing cannibalisation and insufficient flexibility in the energy system is the number of hours when the wholesale price is zero or negative (Figure 6).
Figure 6: Number of zone-hours in which the wholesale price is negative (2015-2025)
^{Source: Bruegel, based on ENTSO-E. Note: for visibility, the figure shows explicitly only the ten bidding zones with the highest count of negative hours in 2025. Other zones with a count above 100 included in ‘Other’ are SE4, SE3, CZ, PL, SK, HU, SI, DK2, HR, EE, PT, RO, LT, BG, LV, NO-NO4 and GR in 2025.Source: Bruegel, based on ENTSO-E. Note: for visibility, the figure shows explicitly only the ten bidding zones with the highest count of negative hours in 2025. Other zones with a count above 100 included in ‘Other’ are SE4, SE3, CZ, PL, SK, HU, SI, DK2, HR, EE, PT, RO, LT, BG, LV, NO-NO4 and GR in 2025.}
Figure 6 shows a high degree of variation between countries. Germany had 573 hours of negative prices in 2025 and has experienced this for several years; in 2015 it already had 111. Spain had 625 hours of negative prices in 2025, making it the zone with the third-largest number; in contrast to Germany, however, Spain did not record a single hour of negative prices in the last decade, only experiencing it for the first time in 2024, with 247 hours. Finally, Italy had not experienced a single hour of negative prices until 2025, which could also be interpreted as another indication of its comparatively weak renewable deployment.
Conclusion: The growing importance of timing and flexibility for renewable deployment
A growing body of academic literature shows that Europe’s geography enables a decarbonised energy system primarily based on renewables. While additional renewable energy is indispensable, discussions about transition costs have become more prevalent. The old energy system’s costs were driven primarily by fuel expenses, hence operating costs; the future system, built mainly on renewables and other non-fossil sources, will instead be driven by investment costs. Therefore, it is crucial to manage the location, technology choice and timing of the future renewables build-out to maximise efficiency and keep costs in check.
Several policy considerations arise from this analysis:
References
Astier, N. and F.A. Wolak (2026) ‘Nuclear operations with a high penetration of renewables: The case of France’, NBER working paper, 34662, available at https://doi.org/10.3386/w34662 
Clò, S., A. Cataldi and P. Zoppoli (2015) ‘The merit-order effect in the Italian power market’, Energy Policy 77: 79-88, available at https://doi.org/10.1016/j.enpol.2014.11.038 
Ember (2026) ‘Electricity Data Explorer’, Dataset, available at https://ember-energy.org/data/electricity-data-explorer/
Hirth, L. (2013) ‘The market value of variable renewables’, Energy Economics, 38: 218-236, available at https://doi.org/10.1016/j.eneco.2013.02.004 
Joint Research Centre (2026) ENSPRESO – Solar – PV and CSP, available at https://doi.org/10.2905/JRC.MGH4XBG
Joskow, P.L. (2011) ‘Comparing the costs of intermittent and dispatchable electricity generating technologies’, American Economic Review, 101(3): 238-241, available at https://doi.org/10.1257/aer.101.3.238
Kittel, M. and W.P. Schill (2026) ‘Multi-threshold time series analysis enables characterization of variable renewable energy droughts in Europe’, Communication Earth & Environment 7: 242, available at https://doi.org/10.1038/s43247-026-03251-2 
López Prol, J., F. De Llano Paz, A. Calvo-Silvosa, S. Pfenninger and I. Staffell (2024) ‘Wind-solar technological, spatial and temporal complementarities in Europe: A portfolio approach’, Energy 292: 130348, available at https://doi.org/10.1016/j.energy.2024.130348 
Rodrigues, R., R. Pietzcker, J. Sitarz, A. Merfort, R. Hasse, J. Hoppe … and G. Luderer (2026) ‘2040 greenhouse gas reduction targets and energy transitions in line with the EU Green Deal’, Nature Communications 17(1): 3417, available at https://doi.org/10.1038/s41467-026-71159-8
Roth, A., S. Tagliapietra and G. Zachmann (2026) ‘Better coordination for a more efficient European energy system’, Policy Brief 02/2026, Bruegel, available at https://doi.org/10.64153/DIXT8619 
Former Bruegel Research Analyst
Bruegel Affiliate Fellow
Bruegel Senior Fellow
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Throughout this piece, wind power refers only to onshore wind power and leaves offshore aside.
Other renewable and non-fossil resources could play important roles but will most likely not dominate the overall electricity mix: hydro (limited expansion potential and environmental concerns), biomass (environmental concerns and limited land availability), tide (technical limitations) and geothermal (limited availability).
For targets, see the European Commission website ‘Renewable Energy Directive’, undated, https://energy.ec.europa.eu/topics/renewable-energy/renewable-energy-directive-targets-and-rules/renewable-energy-directive_en#the-directive-and-its-targets.
The capacity factor describes how much of a technology’s maximum technical output potential (installed capacity) is used over a specific period. For instance, if a solar power plant with an installed capacity of 1 megawatt (MW) generates 0.5 megawatt-hours (MWh) of electricity in a given hour, its capacity factor in that hour is 0.5.
Despite the complementarity of wind and solar at the EU level, periods of low availability of both wind and solar exist (so-called renewable energy droughts or ‘Dunkelflaute’) in which generation from wind and solar can be very low for extended periods. For more details, see Kittel and Schill (2026).
Capacity factors are also determined by grid constraints: if electricity grids are overloaded and cannot handle the amount of electricity, renewable energy installations might be forced to shut down (‘curtailment’), which decreases their capacity factor because their actual output remains below their potential output.
For France, Astier and Wolak (2026) show that nuclear output adjusts downward when wind and solar generation increase, but that this flexibility faces limits when reactors reach minimum output constraints, contributing to negative prices in hours of abundant renewable generation.
Here, we define capture rate as the share of a technology’s market value to the average wholesale price. The capture rate indicates whether the wholesale price a technology earns – the market value – is below or above the average. For instance, if a technology’s market value in a specific period is €50/MWh, yet the average wholesale price is €100/MWh, its capture rate is 0.5; hence, it was able to ‘capture’ only half of the average wholesale price.
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