The great electrification: The power of the sun in the EU

[1] In this article, we use “solar” to refer specifically to solar photovoltaic.

In recognition of that role, the EC originally set a target of more than 320GW of solar PV capacity by 2025 in the EU solar energy strategy. That milestone has been comfortably exceeded: The EU’s solar fleet stood at roughly 406GW by the end of 2025. Looking ahead, the strategy aims for almost 600GW by 2030, highlighting how rapidly solar’s importance in the European power system has grown. The question is whether the system can absorb that expansion quickly enough?

In practical terms, solar is already supplying a meaningful share of Europe’s electricity demand. Its contribution rose from around 5% of EU generation in 2020 to 11% in 2024 and roughly 13% in 2025. This represents an unusually rapid shift for a system-scale infrastructure technology. It also signals that solar is no longer a niche technology within the power mix, but an increasingly foundational part of Europe’s electrification pathway.

The solar rollout therefore plays an important role in reducing the EU’s exposure to fossil fuels. According to our own calculations, solar generation in 2025 has saved 572 terawatt hour (TWh) of gas imports, equivalent to EUR 23bn at the average Q1 2026 title transfer facility (TTF) price, assuming gas power plant efficiency of 60%. This represents around 22% of the EU’s total gas imports in 2025, according to Eurostat.[2]

Are fossil fuel dependencies being replaced by clean-tech dependencies?

In 2025 the EU imported EUR 11bn worth of solar panels, of which 98% were sourced from China, according to Eurostat. So while solar helps reduce Europe’s exposure to imported fossil fuels and supports a more electrified energy system with greater domestic generation, it also introduces a new strategic reliance on global clean-tech supply chains. Europe remains dependent on foreign production of modules, batteries, and critical materials, meaning that geopolitics can still shape the cost and pace of solar deployment. However, this dependency differs in nature from reliance on fossil fuels. If panel imports were disrupted, the impact on electricity generation would not be immediate: Installed solar capacity would continue producing power throughout its long operational lifetime. The main short-term risk, therefore, is not to existing generation, but to the rollout of additional capacity.

[2] Based on a conversion rate of 12.54 megawatt hour (MWh) per metric ton of gas.

Solar targets and rollout across EU and national plans

To understand possible scenarios for solar rollout, we explore the numbers behind the Clean Energy Technology Observatory, CETO scenario developed by the European Commission's Joint Research Centre (JRC).[3]

According to the CETO scenario, to achieve the EU’s current climate targets in a cost-efficient manner, would require expanding installed PV capacity by a factor of approximately 3.8x by 2040, relative to today’s levels (see figure 3). When benchmarked against historical deployment trends (such as the cumulative capacity trajectory reported by SolarPower Europe) it becomes clear that this target requires both scale and sustained momentum. Specifically, the EU would need to maintain the rollout pace observed over the last two years to deliver the required solar asset base by 2040.

[3] For a detailed explanation of CETO see our earlier report: “The great electrification: Insights, gaps, and investment implications through scenario analysis.”

Figure 4 provides a reality check on the EU-level targets by benchmarking developments across the five largest economies in the euro area. Since 2020, all analyzed markets have experienced a broadly similar acceleration in installed PV capacity, forming the empirical basis on which most national energy and climate plans (NCEPs)[4] have been constructed.

[4] National energy and climate plans are comprehensive strategic planning documents required by the European Commission. They outline exactly how each EU member state intends to achieve the EU's binding energy and climate targets.

While NECPs primarily focus on the pathway to 2030 targets, Germany provides additional visibility beyond this horizon. Its renewable energy act (EEG) defines a quantified long-term expansion trajectory, with installed PV capacity expected to reach 400GW by 2040. For the other countries analyzed, NECP targets are largely consistent with the growth momentum observed up to 2024. Although explicit 2040 targets are generally not defined, the trajectories in Spain, France and Italy suggest continued expansion aligned with broader EU decarbonization objectives, provided that current deployment rates and market conditions are sustained. The Netherlands represents a notable exception. Its NECP reflects increasing system-level constraints, particularly grid congestion, which are expected to limit further expansion and prevent a continuation of the rapid growth seen in recent years.

From an investment perspective, sustaining the growth trajectory observed through 2024 would imply a sustained period of elevated capital deployment across the solar sector. However, this outlook depends on the durability of supportive policy frameworks and on continued progress in grid expansion, system integration, and market design, all of which directly influence underlying financing conditions and risk‑return profiles.

Across the EU, policy frameworks for solar have mainly focused on support, typically delivered through instruments such as contracts for difference, certificate schemes, feed-in tariffs, or market premiums. In most cases, these mechanisms are allocated through competitive auctions, allowing member states to tailor support to their national energy strategies.

For the purposes of this article, however, the focus is on the economics of unsubsidized utility-scale solar, assessing their viability under market conditions without direct policy support.

Solar deployment and technical potential in Europe

Across Europe, solar deployment is spread across three main segments: residential, commercial and industrial (C&I), and utility-scale, each serving a different role in the system.

In recent years, deployment has shifted toward utility-scale projects, which now dominate new capacity additions, while the share of residential solar has declined from its peak during the energy crisis. This shift reflects both cost advantages at scale and the growing role of large projects in shaping market dynamics, particularly during midday when solar output is highest.

Neither solar resource availability nor land availability for solar deployment are among the key constraints on utility-scale PV deployment. As demonstrated in this Energy Strategy Review, using just 1.4% of the EU’s land suitable for solar installations could generate up to three times the EU’s electricity demand in 2016 (a level broadly comparable to that of 2024). Similarly, SolarPower Europe estimates that only 0.26% of total EU land would be sufficient to meet current electricity demand. In practice, however, the realistically deployable area depends on several factors beyond theoretical land availability that are not captured in such assessments, most notably the power system’s ability to integrate and transport the generated electricity. Nevertheless, these estimates illustrate that solar resource potential and land are unlikely be the primary bottlenecks in the electrification of the EU energy supply.

Moreover, solar expansion does not necessarily require additional land: considering only existing rooftop surfaces across the EU, a study by the Joint Research Centre indicates that up to 40% of the EU’s projected 2050 electricity demand could be met through solar PV. The combined technical potential of available land and rooftop capacity suggests that neither solar resource availability nor land constraints are likely to limit the EU’s climate and competitiveness objectives related to PV deployment. While expanding solar capacity may offer clear economic benefits, scaling solar to become a cornerstone of the EU energy system will require addressing structural challenges.

The core challenge for solar is simple: It only generates electricity when the sun is shining. That creates a structural mismatch between supply and demand, with peak solar output typically occurring around midday, while electricity demand tends to rise in the mornings and toward dusk (see figure 7). As solar electricity penetration increases, the system will need more grid capacity, storage to shift power across time, and more flexible demand to smooth peaks in demand and supply. These measures help maximize the use of solar output and minimize curtailments. Greater system flexibility can also help prevent local congestion as the share of solar-generation continues to grow. This dynamic also weighs on revenues.

Solar cannibalization and declining capture prices

Capture prices refer to the average price that solar generators receive for the electricity they sell. Because solar electricity production is concentrated in daylight hours it enters the market at low – or even negative – prices, particularly when they benefit from production subsidies or revenues from selling Guarantees of Origin.[5] This dynamic pushes down wholesale prices precisely during solar hours, reducing the price that solar generators themself capture. This effect is known as cannibalization of solar.

Self-consumption in residential and commercial buildings increases the challenge by reducing the volume of electricity demanded in the market. This effect is not marginal, as the residential and commercial segments account for a significant share of the installed solar capacity (see figure 5). This dynamic is referred to as demand destruction (see box 1).

[5] Guarantees of Origin are electronic certificates that certify that a specific amount of electricity has been generated from renewable energy sources and have an economic value for companies seeking to meet their climate and environmental, social and governance (ESG) targets.

The trend is clearly visible across European markets (see figure 8). Capture rates, defined as the ratio between the price solar generators receive for their electricity and the average wholesale electricity price, have declined materially in most countries in recent years. In Spain, Germany, and the Netherlands, capture rates have fallen from levels close to or above 90% to 100% of baseload in the early 2020s to roughly 50% to 60% by 2025-2026, indicating a sharp erosion in realized revenues. France shows a similar pattern, albeit with greater volatility, dropping from above-parity levels at times to around 55% to 65%. By contrast, Italy has been more resilient, with capture rates still closer to 80% to 90%, suggesting lower solar penetration and a better alignment between generation and demand. These conditions have supported a strong pipeline. According to PV magazine Italy recorded 3,670 PV connection applications totaling 144GW in 2026, despite a slight decline since August 2025, while the number of ready-to-build projects rose to 210, representing 9.34GW.

Source: power.kyos.com, RaboResearch 2026

This decrease in capture rates across markets reflects differing levels of solar penetration and other low-cost renewables across markets. In systems with a high share of solar, the problem is most acute: Generation is highly synchronized across assets, leading to recurring periods of oversupply during sunny hours. In some cases, this results in prices falling to very low or even negative levels,[6] limiting the revenues that producers can generate with a growing share of output.

[6] In addition to solar incentives that can lead to negative bids (with these incentives arising from factors such as production subsidies, revenues from Guarantees of Origin, or minimum prices from auctions) fossil fuel and nuclear power plants may also bid negative prices to maintain operations for efficiency purposes and continue selling their power output.

The implications for investors are significant. Utility-scale solar projects typically require capture prices of at least EUR 40/MWh[7] to remain economically viable on a merchant basis.[8] When capture prices fall persistently below this level, as is now often the case in the markets shown in figure 9, the business case for new solar projects weakens considerably. Under these conditions, projects increasingly depend on power purchase agreements (PPAs), policy support, or hybridization with storage through co-location to maintain profitability.

A PPA is a long-term contract under which a buyer agrees to purchase electricity at a fixed or pre-defined price (or price range). This structure provides revenue certainty for developers, insulating them from declining capture prices and the increased volatility observed in day-ahead markets. PPAs have emerged as a key tool to mitigate the risks associated with uncertain, declining, and more volatile merchant revenues and can effectively “lock in” a price, thereby supporting revenue visibility. However, PPA pricing is also beginning to reflect expectations of lower capture rates. As a result, while PPAs reduce exposure to merchant risk, they do not eliminate the underlying impact of solar oversupply. A more structural solution would be to shift generation to periods of higher demand and prices, for example through co-location with battery storage.

[7] This threshold is based on the average levelized cost of electricity (LCOE) across France, Germany, Italy, the Netherlands, and Spain.

[8] Under a merchant model, projects earn revenues by selling power into the electricity market at prevailing prices, without direct subsidy support.

Adding storage to solar PV can improve capture prices, mitigate curtailment, and potentially add revenue streams

Co-locating solar PV with batteries is a promising strategy to strengthen the financing and investment case of solar PV. Charging the co-located battery during low-price, peak solar hours and discharging when demand and power prices are higher can help protect solar projects from low capture prices and curtailment. Essentially, adding storage to solar PV transforms a weather-dependent profile into a dispatchable and potentially firmer profile (see figure 11). Adding a battery does not only improve a solar project’s position in merchant markets but can also strengthen its negotiating position in PPAs. According to BloombergNEF, solar-plus-storage projects can negotiate a 30% to 40% premium compared to stand-alone solar projects.

Besides increasing solar capture prices, adding a battery to solar PV can create additional revenue streams, depending on plant configuration and market regulation. For example, it enables electricity trading and participation in ancillary services markets, similar to a stand-alone battery energy storage system (BESS). This can improve the profitability of a solar-plus-storage project.

The EU co-location market is still relatively small with under 2.5GW of solar-plus-storage capacity currently online. However, the sector is gaining momentum as batteries have become cheaper, cannibalization and curtailment issues persist, and the market is maturing. By 2030, we expect solar-plus-storage capacity to reach between 10GW and 15GW. The current project pipeline already exceeds 10GW, of new solar-plus-storage capacity of which 4GW has secured financing and is likely to come online over the next three years. Key enablers of an accelerated growth in co-located projects include targeted support schemes, greater regulatory clarity for operating co-located BESS, growing expertise in solar-plus-storage business models, and more predictable grid access timelines.

Meeting the higher capacity projections in the CETO scenario by 2040 would require the EU to add roughly 800GW of new solar capacity over the next 14 years. On an annual basis, that is broadly in line with the approximately 65GW added in recent years. The challenge is therefore less about a dramatic acceleration and more about sustaining very high deployment rates over a prolonged period leading up to 2040. At the same time, the challenge is also economic. In most major EU power markets, capture prices have been declining as solar penetration rises but demand has stagnated, eroding project revenues and weakening the case for further build-out.

Without a large-scale rollout of batteries and other flexibility solutions (or a significant grow in demand during peak solar generation hours) solar deployment is likely to slow, with expansion constrained by the market’s ability to absorb and remunerate midday electricity. Foresight scenarios broadly suggest that EU electricity demand could increase by about 900TWh to 1,100TWh by 2040, driven by electrification. A systemic shift, equivalent to roughly 30% of current EU consumption of about 2800TWh.[9] In this context of mismatched generation and demand, solar growth is primarily constrained by system integration rather than generation economics.

However, the already solid market evidence of large-scale deployment of battery storage could materially alter this outlook. Batteries enhance grid flexibility, mitigate curtailment, and enable higher penetration of variable generation. Under a scenario of strong battery expansion, solar capacity could increase significantly beyond levels currently constrained by the mismatch between generation and demand during peak solar generation hours. Even in such a scenario, adding up to around 800GW of additional solar capacity would represent the upper end of plausible outcomes – optimistic, but not infeasible. In that context, battery storage is no longer an optional complement but a critical enabler of continued solar growth. In practical terms, storage helps turn solar from a low-cost but time-constrained source into more continuous, around-the-clock electricity supply. Solving this challenge is fundamental to unlocking solar’s true potential, enabling the delivery of cheap, homegrown electricity to EU consumers.

[9] Actual electricity consumption is hard to estimate given the growing share of self-consumed solar generation and other behind-the-meter technologies.

Note: Hyperlinks refer to source documents available only in the original language.

Germany: EEG 2023 (market premium; auction-based support schemes)
The Netherlands: Belastingdienst (VAT exemption); SDE++ regulation and government
France: Code de l’énergie (purchase obligations; market premium schemes)
Italy: Gestore dei Servizi Energetici (Scambio sul Posto; support mechanisms)
Spain: Real Decreto 244/2019 (self-consumption, net billing and compensation arrangements)